MAMMOTH ENERGY SERVICES, INC. - Quarter Report: 2018 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, 2018



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

FOR THE TRANSITION PERIOD FROM TO

Commission File No. 001-37917

Mammoth Energy Services, Inc.

(Exact name of registrant as specified in its charter)




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

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

(405) 608-6007

(Registrant’s telephone number, including area code)

______________________________

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

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




Large accelerated filer	o	Accelerated filer	ý

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 1, 2018, there were 44,714,296 shares of common stock, $0.01 par value, outstanding.

MAMMOTH ENERGY SERVICES, INC.

TABLE OF CONTENTS





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

PART I. FINANCIAL INFORMATION		1
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	1
	Condensed Consolidated Balance Sheets	1
	Condensed Consolidated Statements of Comprehensive Income (Loss)	2
	Condensed Consolidated Statements of Changes in Equity	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Unaudited Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	41

PART II. OTHER INFORMATION		42
Item 1.	Legal Proceedings	42
Item 1A.	Risk Factors	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Other Information	44
Item 6.	Exhibits	45

SIGNATURES		46

GLOSSARY OF OIL AND NATURAL GAS AND ELECTRICAL INFRASTRUCTURE TERMS



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



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



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

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, 2017 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:


•	business strategy;


•	pending or future acquisitions and future capital expenditures;


•	ability to obtain permits and governmental approvals;


•	technology;


•	financial strategy;


•	future operating results; and


•	plans, objectives, expectations and intentions.

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

The forward-looking statements contained in this report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors, which are difficult to predict and many of which are beyond our control. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to many factors including those described in Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2017 and Item 2. "Management's Discussion and Analysis of Financial Condition and Results of Operations" and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

iii

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,
	2018			2017
CURRENT ASSETS	(in thousands)
Cash and cash equivalents	$	10,447		$	5,637
Accounts receivable, net	243,913			243,746
Receivables from related parties	46,338			33,788
Inventories	12,189			17,814
Prepaid expenses	12,030			12,552
Other current assets	1,112			886
Total current assets	326,029			314,423

Property, plant and equipment, net	365,757			351,017
Sand reserves	74,682			74,769
Intangible assets, net - customer relationships	7,436			9,623
Intangible assets, net - trade names	6,296			6,516
Goodwill	99,811			99,811
Deferred income tax asset	16,829			6,739
Other non-current assets	4,245			4,345
Total assets	$	901,085		$	867,243
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	151,509		$	141,306
Payables to related parties	2,228			1,378
Accrued expenses and other current liabilities	42,919			40,895
Income taxes payable	62,272			36,409
Total current liabilities	258,928			219,988

Long-term debt	39,000			99,900
Deferred income tax liabilities	31,897			34,147
Asset retirement obligation	3,124			2,123
Other liabilities	3,999			3,289
Total liabilities	336,948			359,447

COMMITMENTS AND CONTINGENCIES (Note 16)

EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 44,714,296 and 44,589,306 issued and outstanding at March 31, 2018 and December 31, 2017, respectively	447			446
Additional paid in capital	509,265			508,010
Retained earnings	57,547			2,001
Accumulated other comprehensive loss	(3,122		)	(2,661		)
Total equity	564,137			507,796
Total liabilities and equity	$	901,085		$	867,243

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

MAMMOTH ENERGY SERVICES, INC.

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



	Three Months Ended March 31,
	2018			2017^(a)
REVENUE	(in thousands, except per share amounts)
Services revenue	$	408,659		$	27,092
Services revenue - related parties	49,088			32,962
Product revenue	25,040			3,372
Product revenue - related parties	11,462			11,540
Total revenue	494,249			74,966

COST AND EXPENSES
Services cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $24,575 and $15,838, respectively, for the three months ended March 31, 2018 and 2017)	290,979			45,461
Services cost of revenue - related parties (exclusive of depreciation, depletion, amortization and accretion of $0 and $0, respectively, for the three months ended March 31, 2018 and 2017)	1,792			430
Product cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $2,314 and $1,362, respectively, for the three months ended March 31, 2018 and 2017)	33,330			12,607
Selling, general and administrative	38,082			6,413
Selling, general and administrative - related parties	429			324
Depreciation, depletion, amortization and accretion	26,908			17,237
Total cost and expenses	391,520			82,472
Operating income (loss)	102,729			(7,506		)

OTHER (EXPENSE) INCOME
Interest expense, net	(1,237		)	(397		)
Other, net	(28		)	(184		)
Total other (expense) income	(1,265		)	(581		)
Income (loss) before income taxes	101,464			(8,087		)
Provision (benefit) for income taxes	45,918			(3,106		)
Net income (loss)	$	55,546		$	(4,981	)

OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment, net of tax of $186 and $20, respectively, for the three months ended March 31, 2018 and 2017	(461		)	228
Comprehensive income (loss)	$	55,085		$	(4,753	)

Net income (loss) per share (basic) (Note 12)	$	1.24		$	(0.13	)
Net income (loss) per share (diluted) (Note 12)	$	1.24		$	(0.13	)
Weighted average number of shares outstanding (basic) (Note 12)	44,650			37,500
Weighted average number of shares outstanding (diluted) (Note 12)	44,884			37,500

(a) Financial information has been recast to include results attributable to Sturgeon Acquisitions LLC ("Sturgeon"). See Note 4.

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)




							Retained			Additional
	Common Stock			Members'			Earnings			Paid-In
	Shares	Amount		Equity			(Deficit)			Capital		AOCL			Total
	(in thousands)
Balance at January 1, 2017	37,500	$	375	$	81,739		$	(56,323	)	$	400,206	$	(3,216	)	$	422,781
Net income of Sturgeon prior to acquisition	—	—		640			—			—		—			640
Stingray acquisition	1,393	14		—			—			25,748		—			25,762
Sturgeon acquisition	5,607	56		(82,379		)	—			78,313		—			(4,010		)
Equity based compensation	89	1		—			—			3,743		—			3,744
Net income	—	—		—			58,324			—		—			58,324
Other comprehensive income	—	—		—			—			—		555			555
Balance at December 31, 2017	44,589	$	446	$	—		$	2,001		$	508,010	$	(2,661	)	$	507,796
Equity based compensation	125	1		—			—			1,255		—			1,256
Net income	—	—		—			55,546			—		—			55,546
Other comprehensive loss	—	—		—			—			—		(461		)	(461		)
Balance at March 31, 2018	44,714	$	447	$	—		$	57,547		$	509,265	$	(3,122	)	$	564,137

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,
	2018			2017^(a)
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	55,546		$	(4,981	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Equity based compensation	1,256			570
Depreciation, depletion, accretion and amortization	26,908			17,237
Amortization of coil tubing strings	565			492
Amortization of debt origination costs	100			151
Bad debt expense	25,527			(41		)
Gain on disposal of property and equipment	(184		)	(79		)
Deferred income taxes	(12,117		)	(3,801		)
Changes in assets and liabilities, net of acquisitions of businesses:
Accounts receivable, net	(25,722		)	(4,357		)
Receivables from related parties	(12,550		)	(4,842		)
Inventories	5,060			(466		)
Prepaid expenses and other assets	294			77
Accounts payable	8,302			13,302
Payables to related parties	851			451
Accrued expenses and other liabilities	1,636			733
Income taxes payable	25,851			(28		)
Net cash provided by operating activities	101,323			14,418

Cash flows from investing activities:
Purchases of property and equipment	(35,176		)	(31,110		)
Purchases of property and equipment from related parties	(598		)	—
Proceeds from disposal of property and equipment	286			369
Net cash used in investing activities	(35,488		)	(30,741		)

Cash flows from financing activities:
Borrowings from lines of credit	31,000			—
Repayments of lines of credit	(91,900		)	—
Repayments of equipment financing note	(72		)	—
Net cash used in financing activities	(60,972		)	—
Effect of foreign exchange rate on cash	(53		)	11
Net change in cash and cash equivalents	4,810			(16,312		)
Cash and cash equivalents at beginning of period	5,637			29,239
Cash and cash equivalents at end of period	$	10,447		$	12,927

Supplemental disclosure of cash flow information:
Cash paid for interest	$	1,442		$	254
Cash paid for income taxes	$	32,184		$	701
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in trade accounts payable	$	16,558		$	9,346

(a) Financial information has been recast to include results attributable to Sturgeon. See Note 4.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization and Nature of Business

Mammoth Energy Services, Inc. (the “Company,” “Mammoth Inc.” or “Mammoth”), together with its subsidiaries, is an integrated, growth-oriented energy services company serving companies engaged in the exploration and development of North American onshore unconventional oil and natural gas reserves as well as government-funded utilities, private utilities, public investor owned utilities and co-operative utilities engaged in energy infrastructure. 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”) (collectively known as the “Predecessor Interest”) 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.

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.

At March 31, 2018 and December 31, 2017, Mammoth Holdings (and certain of its affiliates), Gulfport and Rhino owned the following share of outstanding common stock of Mammoth Inc.:



	At March 31, 2018			At December 31, 2017
	Share Count	% Ownership		Share Count	% Ownership
Mammoth Holdings	25,009,319	55.9	%	25,009,319	56.1	%
Gulfport	11,171,887	25.0	%	11,171,887	25.1	%
Rhino	336,447	0.8	%	568,794	1.3	%
Outstanding shares owned by related parties	36,517,653	81.7	%	36,750,000	82.5	%
Total outstanding	44,714,296	100.0	%	44,589,306	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. The Company's infrastructure services include electric utility contracting services focused on the repair, upgrade, maintenance and construction of transmission and distribution networks. The Company’s infrastructure services also provide storm repair and restoration services in response to hurricane, ice or other storm-related damage. The Company's natural sand proppant services include the distribution and production of natural sand proppant that is used primarily for hydraulic fracturing in the oil and gas industry. The Company's contract land and directional drilling services provides drilling rigs and directional tools for both vertical and horizontal drilling of oil and natural gas wells and salt water disposal wells. The Company also provides other services, including coil tubing units used to enhance the flow of oil and natural gas, flowback, cementing, equipment rentals and remote accommodations.

All of the Company’s operations are in North America. The Company operates its oil and natural gas businesses in the Permian Basin, the Utica Shale, the Eagle Ford Shale, the Marcellus Shale, the Granite Wash, the SCOOP, the STACK, the Cana-Woodford Shale, the Cleveland Sand and the oil sands located in Northern Alberta, Canada. The Company operates its energy infrastructure services in the northeast, southwest and midwest portions of the United States and Puerto Rico. The Company's oil and natural gas business depends in large part on the conditions in the oil and natural gas industry and, specifically, on the amount of capital spending by its customers. Any prolonged increase or decrease in oil

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

and natural gas prices affects the levels of exploration, development and production activity, as well as the entire health of the oil and natural gas industry. Changes in the commodity prices for oil and natural gas could have a material effect on the Company’s results of operations and financial condition. The Company’s business also depends on infrastructure spending on maintenance, upgrade, expansion and repair and restoration. Any prolonged decrease in spending by electric utility companies or delays or reductions in government appropriations could have a material adverse effect on the Company’s results of operations and financial condition.


2.	Basis of Presentation and Significant Accounting Policies

Basis of Presentation

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

On June 5, 2017, the Company acquired Sturgeon Acquisitions LLC ("Sturgeon") and Sturgeon's wholly owned subsidiaries Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC. Prior to its acquisition of Sturgeon, the Company and Sturgeon were under common control and it is required under GAAP to account for this common control acquisition in a manner similar to the pooling of interest method of accounting. Therefore, the Company's historical financial information for all periods included in the accompanying financial statements has been recast to combine Sturgeon with the Company as if the acquisition had been effective since the date Sturgeon commenced operations. Refer to Note 4 - Acquisitions for additional disclosure regarding the acquisition of Sturgeon.

Accounts Receivable

Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses. The Company grants credit to customers in the ordinary course of business and generally does not require collateral. Most areas in which the Company operates provide for a mechanic’s lien against the property on which the service is performed if the lien is filed within the statutorily specified time frame. Customer balances are generally considered delinquent if unpaid by the 30th day following the invoice date and credit privileges may be revoked if balances remain unpaid.

The Company regularly reviews receivables and provides for estimated losses through an allowance for doubtful accounts. In evaluating the level of established reserves, the Company makes judgments regarding its customers’ ability to make required payments, economic events and other factors. As the financial conditions of customers change, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event the Company was to determine that a customer may not be able to make required payments, the Company would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made of their uncollectability.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Following is a roll forward of the allowance for doubtful accounts for the year ended December 31, 2017 and the three months ended March 31, 2018 (in thousands):



Balance, January 1, 2017	$	5,377
Additions charged to expense	16,206
Additions other	179
Deductions for uncollectible receivables written off	(25		)
Balance, December 31, 2017	21,737
Additions charged to expense	25,541
Deductions for uncollectible receivables written off	(14		)
Balance, March 31, 2018	$	47,264

In October 2017, Cobra Acquisitions LLC ("Cobra"), one of the Company's subsidiaries, entered into a contract with the Puerto Rico Electric Power Authority ("PREPA") to perform repairs to PREPA’s electrical grid as a result of Hurricane Maria. At March 31, 2018 and December 31, 2017, the Company reviewed receivables due from PREPA and made specific reserves consistent with Company policy which resulted in additions to allowance for doubtful accounts totaling $25.4 million and $16.0 million, respectively, for the three months ended March 31, 2018 and year ended December 31, 2017.

Additionally, the Company has made specific reserves consistent with Company policy which resulted in additions to allowance for doubtful accounts totaling $0.1 million and $0.2 million, respectively, for the three months ended March 31, 2018 and year ended December 31, 2017. The Company will continue to pursue collection until such time as final determination is made consistent with Company policy.

Concentrations of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents in excess of federally insured limits and trade receivables. Following is a summary of our significant customers based on percentages of total accounts receivable balances at March 31, 2018 and December 31, 2017 and percentages of total revenues derived for the three months ended March 31, 2018 and 2017:



	REVENUES				ACCOUNTS RECEIVABLE
	Three Months Ended March 31,				At March 31,		At December 31,
	2018		2017		2018		2017
Customer A^(a)	64	%	—	%	52	%	56	%
Customer B^(b)	12	%	59	%	16	%	12	%


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


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

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.

New Accounting Pronouncements

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. The Company plans to adopt this ASU effective January 1, 2019 utilizing the modified retrospective method of adoption. This new leasing guidance will impact

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.	Revenues

Adoption of ASC 606 "Revenues from Contracts with Customers"

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

On January 1, 2018, the Company adopted ASU 2014-09 and its related amendments (collectively, "ASC 606") using the modified retrospective method applied to contracts which were not completed as of January 1, 2018. Revenues for reporting periods beginning after January 1, 2018 are presented under ASC 606, while prior period amounts continue to be reported under previous revenue recognition guidance. While ASC 606 requires additional disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact on the measurement or recognition of the Company's revenues.

The adoption of ASC 606 represents a change in accounting principle. After evaluation of all contracts not completed as of January 1, 2018, the Company determined the cumulative effect of adopting ASC 606 was immaterial, and as such, has not recorded an adjustment to the opening balance of retained earnings on January 1, 2018.

Revenue Recognition

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



	Three Months Ended
	March 31, 2018			March 31, 2017
Revenue:
Pressure pumping services	$	101,138		$	40,640
Infrastructure services	325,459			—
Natural sand proppant services	51,015			15,597
Contract land and directional drilling services	15,230			10,751
Other services	22,895			8,850
Eliminations	(21,488		)	(872		)
Total revenue	494,249			74,966

Pressure Pumping Services

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

Infrastructure Services

Infrastructure services are typically provided pursuant to master service agreements, repair and maintenance contracts or fixed price and non-fixed price installation contracts. Pricing under these contracts may be unit priced, cost-plus/hourly (or time and materials basis) or fixed price (or lump sum basis). The Company accounts for infrastructure services as a

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

single performance obligation satisfied over time. Revenue is recognized over time as work progresses based on the days completed or as the contract is completed.

Natural Sand Proppant Services

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

Certain of the Company's sand supply agreements contain a minimum volume commitment related to sand purchases whereby the Company charges a shortfall payment if the customer fails to meet the required minimum volume commitment. These agreements may also contain make-up provisions whereby shortfall payments can be applied in future periods against purchased volumes exceeding the minimum volume commitment. If a make-up right exists, the Company has future performance obligations to deliver excess volumes of product in subsequent months. In accordance with ASC 606, if the customer fails to meet the minimum volume commitment, the Company will assess whether it expects the customer to fulfill its unmet commitment during the contractually specified make-up period based on discussions with the customer and management's knowledge of the business. If the Company expects the customer will make-up deficient volumes in future periods, revenue related to shortfall payments will be deferred and recognized on the earlier of the date on which the customer utilizes make-up volumes or the likelihood that the customer will exercise its right to make-up deficient volumes becomes remote. If the Company does not expect the customer will make-up deficient volumes in future periods, the breakage model will be applied and revenue related to shortfall payments will be recognized when the model indicates the customer's inability to take delivery of excess volumes. During the three months ended March 31, 2018, the Company did not recognize any material revenue or liabilities related to shortfall payments.

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

Contract Land and Directional Drilling Services

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

Other Services

The Company also provides coil tubing, pressure control, flowback, cementing, equipment rentals and remote accommodations services, which are reported under other services. These services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted or hourly basis. Performance obligations for these services are satisfied over time and revenue is recognized as the work progresses based on the measure of output. Jobs for these services are typically short-term in nature and range from a few hours to multiple days.

Practical Expedients

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

Performance Obligations and Contract Balances

As of March 31, 2018 and January 1, 2018, the Company had contract liabilities totaling $15.0 million, which are included in Accrued expenses and other current liabilities in the Condensed Consolidated Balance Sheets, and did not have any contract assets. Revenue recognized in the current period from performance obligations satisfied in previous periods was a nominal amount for the three months ended March 31, 2018. As of March 31, 2018, the Company had unsatisfied performance obligations totaling $86.4 million, which will be recognized over the next three years.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


4.	Acquisitions

(a) Description of Stingray Acquisition

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

The 2017 Stingray Acquisition closed on June 5, 2017. Pursuant to the Stingray Contribution Agreements, Mammoth issued 1,392,548 shares of its common stock for all outstanding equity interests in SR Energy and Cementing. Based upon a closing price of Mammoth's common stock of $18.50 per share on June 5, 2017, the total purchase price was $25.8 million.

At the acquisition date, the components of the consideration transferred were as follows (in thousands):



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

(1)See Summary of acquired assets and liabilities below



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

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


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


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


⁽³⁾	Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

acquisition is attributable to assembled workforces and future profitability based on the synergies expected to arise from the acquired entities.


⁽⁴⁾	Long-term debt assumed was paid off subsequent to the acquisitions.

Since the acquisition date, the businesses acquired have provided the following activity (in thousands):



	2018						2017
	SR Energy			Cementing			SR Energy			Cementing
Revenues^(a)	$	8,890		$	2,851		$	11,572		$	7,500
Net loss^(b)	(481		)	(478		)	(1,626		)	(1,963		)


a.	Includes intercompany revenues of $0.7 million for SR Energy in 2018 and $0.6 million and a nominal amount for SR Energy and Cementing in 2017


b.	Includes depreciation and amortization expense of $1.5 million and $0.6 million, respectively, for SR Energy and Cementing in 2018 and $3.4 million and $4.1 million, respectively, for SR Energy and Cementing in 2017

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



	Three Months Ended March 31, 2017
Revenues	$	8,753
Net loss	(613		)

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the 2017 Stingray Acquisition. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the 2017 Stingray Acquisition been completed on January 1, 2017. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the Company. The Company recognized $0.2 million of transaction related costs during the year ended December 31, 2017 related to this acquisition.

(b) Description of Chieftain Acquisition

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

On the acquisition date, the $36.3 million in cash consideration consisted of the following components (in thousands):



	Total
Property, plant and equipment ⁽¹⁾	$	23,373
Sand reserves ⁽²⁾	20,910
Total assets acquired	$	44,283

Asset retirement obligation	1,732
Total liabilities assumed	$	1,732
Total allocation of purchase price	$	42,551
Bargain purchase price ^{(3, 4)}	(6,231		)
Total purchase price	$	36,320

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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


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


⁽³⁾	Amount reflected in Condensed Consolidated Statements of Comprehensive Loss reflected net of income taxes of $2.2 million.


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

Since the acquisition date, the Chieftain Assets have provided the following activity (in thousands):



	2018		2017
Revenues^(a)	$	19,735	$	22,847
Net income^(b)	5,791		5,520

a.Includes intercompany revenues of $8.8 million and $12.3 million, respectively, for 2018 and 2017

b.Includes depreciation, depletion, amortization and accretion of $1.0 million and $2.8 million, respectively, for 2018 and 2017

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



	Three Months Ended March 31, 2017
Revenues	$	—
Net loss	(698		)

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

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

The acquisition of Sturgeon closed on June 5, 2017. Pursuant to the Sturgeon Contribution Agreement, Mammoth issued 5,607,452 shares of its common stock for all outstanding equity interests in Sturgeon. Based upon a closing price of Mammoth's common stock of $18.50 per share on June 5, 2017, the total purchase price was $103.7 million.

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

For the year ended December 31, 2017, $1.3 million of transaction related costs were expensed.

(d) Acquisition of Higher Power

On April 21, 2017, the Company completed its acquisition of Higher Power for total consideration of $3.3 million in cash to the sellers plus up to $0.8 million in contingent consideration to be paid in equal annual installments over the next three years subject to contractual conditions. As of March 31, 2018, $0.3 million and $0.5 million of the contingent consideration are reflected in the accrued expenses and other current liabilities and other liabilities, respectively.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

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



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


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

From its acquisition date through March 31, 2018, Higher Power has provided the following activity (in thousands):



	2018		2017
Revenues^(a)	$	55,156	$	39,571
Net income^(b)	22,373		5,127

a.Includes intercompany revenues of $51.5 million and $27.4 million, respectively for 2018 and 2017

b.Includes depreciation and amortization expense of $1.1 million and $2.0 million, respectively, for 2018 and 2017

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



	Three Months Ended March 31, 2017
Revenues	$	2,226
Net loss	(163		)

(e) Acquisition of 5 Star

On July 1, 2017, the Company completed its acquisition of 5 Star for total consideration of $2.4 million in cash to the sellers. Mammoth funded the purchase price for 5 Star with cash on hand and borrowings under its credit facility. The acquisition of 5 Star added to the infrastructure component of the Company's business.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the fair value of 5 Star as of July 1, 2017 (in thousands):



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

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


⁽¹⁾	Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Identifiable intangible assets will be amortized over 10 years.


⁽²⁾	Goodwill was the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill recorded in connection with the acquisition is attributable to assembled workforces and future profitability expected to arise from the acquired entity.

From its acquisition date through March 31, 2018, 5 Star has provided the following activity (in thousands):



	2018		2017
Revenues^(a)	$	37,745	$	25,216
Net income^(b)	16,624		4,191

a.Includes intercompany revenues of $34.4 million and $16.0 million, respectively, for 2018 and 2017

b.Includes depreciation and amortization expense of $0.5 million and $0.8 million, respectively, for 2018 and 2017

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



	Three Months Ended March 31, 2017
Revenues	$	3,314
Net loss	(164		)


5.	Inventories

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



	March 31,		December 31,
	2018		2017
Supplies	$	8,069	$	9,437
Raw materials	224		219
Work in process	197		2,370
Finished goods	3,699		5,788
Total inventory	$	12,189	$	17,814

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


6.	Property, Plant and Equipment

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



		March 31,		December 31,
	Useful Life	2018		2017
Pressure pumping equipment	3-5 years	$	196,428	$	190,211
Drilling rigs and related equipment	3-15 years	135,410		132,260
Machinery and equipment^(a)	7-20 years	115,019		97,569
Buildings	15-39 years	45,138		45,992
Vehicles, trucks and trailers^(b)	5-10 years	62,168		54,055
Coil tubing equipment	4-10 years	28,068		28,053
Land	N/A	11,794		11,317
Land improvements	15 years or life of lease	9,614		9,614
Rail improvements	10-20 years	8,865		5,540
Other property and equipment	3-12 years	13,613		12,687
		626,117		587,298
Deposits on equipment and equipment in process of assembly		20,062		20,348
		646,179		607,646
Less: accumulated depreciation^(c)		280,422		256,629
Property, plant and equipment, net		$	365,757	$	351,017


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


b.	Included in vehicles, trucks and trailers are assets under capital leases totaling $2.0 million and $1.0 million, respectively, at March 31, 2018 and December 31, 2017.


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

Proceeds from customers for horizontal and directional drilling services equipment damaged or lost down-hole are reflected in revenue with the carrying value of the related equipment charged to cost of service revenues and are reported as cash inflows from investing activities in the statement of cash flows. For the three months ended March 31, 2018 and 2017, proceeds from the sale of equipment damaged or lost down-hole were $0.2 million and $0.3 million, respectively, and gains on sales of equipment damaged or lost down-hole were $0.2 million and $0.2 million, respectively.

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



	Three Months Ended March 31,
	2018		2017
Depreciation expense^(a)	$	24,398	$	14,967
Depletion expense	87		2
Amortization expense	2,408		2,268
Accretion expense	15		—
Depreciation, depletion, amortization and accretion	$	26,908	$	17,237


a.	Includes depreciation expense for assets under capital leases totaling $0.1 million and $0.1 million, respectively, for the three months ended March 31, 2018 and 2017.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


7.	Intangible Assets and Goodwill

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



	March 31,			December 31,
	2018			2017
Customer relationships	$	35,795		$	35,795
Trade names	8,793			8,793
Less: accumulated amortization - customer relationships	(28,359		)	(26,172		)
Less: accumulated amortization - trade names	(2,497		)	(2,277		)
Intangible assets, net	$	13,732		$	16,139

Amortization expense for intangible assets was $2.4 million and $2.3 million, respectively, for the three months ended March 31, 2018 and 2017. The original life of customer relationships range from 4 to 10 years with a remaining average useful life of 2.6 years. The original life of trade names range from 10 to 20 years with a remaining average useful life of 8.2 years.

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



	Amount
Remainder of 2018	$	6,278
2019	1,168
2020	1,168
2021	1,162
2022	1,140
Thereafter	2,816
	$	13,732

Goodwill was $99.8 million at March 31, 2018 and December 31, 2017. Changes in the goodwill for the year ended December 31, 2017 and the three months ended March 31, 2018 are set forth below (in thousands):



Balance, January 1, 2017	$	88,727
Additions - 2017 Stingray Acquisition (Note 3)	10,193
Additions - Higher Power Acquisition (Note 3)	643
Additions - 5 Star Acquisition (Note 3)	248
Balance, December 31, 2017	99,811
Additions	—
Balance, March 31, 2018	$	99,811

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


8.	Accrued Expenses and Other Current Liabilities

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



	March 31,		December 31,
	2018		2017
Deferred revenue	15,019		15,210
Accrued compensation, benefits and related taxes	15,593		11,552
Financed insurance premiums	3,263		4,876
Insurance reserves	3,695		2,942
State and local taxes payable	2,080		2,126
Other	3,269		4,189
Total	$	42,919	$	40,895

Financed insurance premiums are due in monthly installments, are unsecured and mature within the twelve month period following the close of the year. As of March 31, 2018 and December 31, 2017, the applicable interest rate associated with financed insurance premiums was 2.75%.


9.	Debt

Mammoth Credit Facility

On November 25, 2014, Mammoth entered into a revolving credit and security agreement with a syndicate of banks that provides for maximum borrowings of $170 million. The facility, as amended in connection with the IPO, matures on November 25, 2019. Borrowings under this facility are secured by the assets of Mammoth, inclusive of the subsidiary companies. The maximum availability of the facility is subject to a borrowing base calculation prepared monthly. Concurrent with the execution of the facility, the initial advance was used to repay all the debt of the Company then outstanding. Interest is payable monthly at a base rate set by the lead institution’s commercial lending group plus an applicable margin. Additionally, at the Company's request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches at set increments of $0.5 million. The LIBOR rate option allows the Company to select interest periods from one, two, three or six months. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit. The deferred loan costs associated with this facility are classified in other non-current assets. The weighted average interest rate for borrowings outstanding under the credit facility was 4.49% as of March 31, 2018.

At March 31, 2018, there were outstanding borrowings under the credit facility of $39.0 million, leaving an aggregate of $123.7 million of borrowing capacity under the facility, after giving effect to $6.5 million of outstanding letters of credit. At December 31, 2017, there were outstanding borrowings under the credit facility of $99.9 million, leaving an aggregate of $62.8 million of borrowing capacity under the facility, after giving effect to $6.5 million of outstanding letters of credit.

The Mammoth facility also contains various customary affirmative and restrictive covenants. Among the various covenants are specifically identified financial covenants placing requirements of a minimum interest coverage ratio (3.0 to 1.0), maximum leverage ratio (4.0 to 1.0), and minimum availability ($10 million). As of March 31, 2018 and December 31, 2017, the Company was in compliance with its covenants under the facility.

Sturgeon Credit Facility

On June 30, 2015, Sturgeon entered in to a three-year $25.0 million revolving line of credit secured by substantially all of the assets of Sturgeon (“the Sturgeon revolver”). Advances under the Sturgeon revolver bore interest at 2% plus the greater of (a) the Base Rate as set by the lender's commercial lending group, (b) the sum of the Federal Funds Open Rate plus one half of one percent and (c) the sum of the Daily LIBOR rate. Additionally, at Sturgeon’s request, advances could be obtained at LIBOR plus 3%. The LIBOR rate option allowed Sturgeon to select interest periods from one, two, three or six month LIBOR futures spot rates. The Sturgeon revolver was terminated on June 6, 2017.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


10.	Other Liabilities

Other liabilities included the following (in thousands):



	March 31,			December 31,
	2018			2017
Capital lease obligations	$	3,174		$	2,015
Equipment financing arrangement	1,509			1,605
Other	500			500
Total	5,183			4,120
Less: Current portion of capital lease and equipment financing obligations included in accrued expenses and other current liabilities	(1,184		)	(831		)
Total Other Liabilities	$	3,999		$	3,289

The Company leases vehicles and other equipment under capital leases with varying terms and expiration dates through 2020. The weighted average implied interest rate under our capital leases as of March 31, 2018 and December 31, 2017 was 15.7% and 19.1%, respectively. Additionally, the Company entered into a five-year equipment financing arrangement maturing in 2022 that bears interest at 4.6% as of March 31, 2018. Principal and interest on capital leases and the equipment financing arrangement are paid monthly. Aggregate future payments under the Company's non-cancelable capital leases and equipment financing arrangement as of March 31, 2018 are as follows (in thousands):



2018	$	1,083
2019	1,994
2020	1,105
2021	442
2022	360
Total future minimum payments	4,984
Less interest payments	(301		)
Present value of future minimum payments	$	4,683


11.	Income Taxes

The components of income tax (benefit) expense attributable to the Company for the three months ended March 31, 2018 and 2017, are as follows (in thousands):



	Three Months Ended March 31,
	2018			2017
Foreign current income tax expense	$	58,047		$	585
Foreign deferred income tax benefit	(10,120		)	(6		)
U.S. current income tax benefit	(12		)	—
U.S. deferred income tax benefit	(1,997		)	(3,685		)
Total	$	45,918		$	(3,106	)

The Company's effective tax rate was 45% and 39%, respectively, for the three months ended March 31, 2018 and 2017. The increase in the effective tax rate is primarily due to a higher tax rate in Puerto Rico, where most of our income was generated during the three months ended March 31, 2018, compared to the United States tax rate. No income was generated in Puerto Rico during the three months ended March 31, 2017. Additionally, the Company's effective tax rate can fluctuate as a result of, among other things, state income taxes, permanent differences and changes in pre-tax income.

A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgments regarding future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

is required. During the three months ended March 31, 2018, the Company recorded a change in valuation allowance of $34.4 million related to foreign tax credits that are not expected to be utilized.

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the “Tax Act”). As a result, the Company recorded a provisional amount for effects of the Tax Act totaling $31.0 million during the fourth quarter of 2017. The Company continues to evaluate the impact of the Tax Act and no revisions were recorded to the provisional amount during the three months ended March 31, 2018. The Company expects to complete its detailed analysis of the effects of the Tax Act no later than the fourth quarter of 2018.


12.	Earnings (Loss) Per Share

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



	Three Months Ended March 31,
	2018		2017
Basic earnings (loss) per share:
Allocation of earnings:
Net income (loss)	$	55,546	$	(4,981	)
Weighted average common shares outstanding	44,650		37,500
Basic earnings (loss) per share	$	1.24	$	(0.13	)

Diluted earnings (loss) per share:
Allocation of earnings (loss):
Net income (loss)	$	55,546	$	(4,981	)
Weighted average common shares, including dilutive effect^(a)	44,884		37,500
Diluted earnings (loss) per share	$	1.24	$	(0.13	)


^a.	No incremental shares of potentially dilutive restricted stock awards were included for the three months ended March 31, 2017 as their effect was antidulitive under the treasury stock method.


13.	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 $5.6 million. For the Non-Employees Member awards, the unrecognized cost, which represents the fair value of the awards as of March 31, 2018 was $101.0 million.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


14.	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, 2018	640,632		$	19.44
Granted	59,485		21.13
Vested	(123,076	)	21.23
Forfeited	—		—
Unvested shares as of March 31, 2018	577,041		$	19.21

As of March 31, 2018, there was $9.6 million of total unrecognized compensation cost related to the unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately 2.0 years.

Included in cost of revenue and selling, general and administrative expenses is stock-based compensation expense of $1.3 million and $0.6 million, respectively, for the three months ended March 31, 2018 and 2017.


15.	Related Party Transactions

Transactions between the subsidiaries of the Company and the following companies are included in Related Party Transactions: Gulfport; Grizzly Oil Sands ULC (“Grizzly”); El Toro Resources LLC (“El Toro”); Cementing and SR Energy (collectively, prior to the 2017 Stingray Acquisition, the “2017 Stingray Companies”); Everest Operations Management LLC (“Everest”); Elk City Yard LLC (“Elk City Yard”); Double Barrel Downhole Technologies LLC (“DBDHT”); Caliber Investment Group LLC (“Caliber”); Dunvegan North Oilfield Services ULC (“Dunvegan”); Predator Drilling LLC (“Predator”); and T&E Flow Services LLC (“T&E”).

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



		REVENUES					ACCOUNTS RECEIVABLE
		Three Months Ended March 31,					At March 31,		At December 31,
		2018		2017			2018		2017
Pressure Pumping and Gulfport	(a)	$	38,546	$	31,746		$	26,367	$	25,054
Muskie and Gulfport	(b)	11,462		11,541			9,509		1,947
Panther Drilling and Gulfport	(c)	56		1,042			14		872
Cementing and Gulfport	(d)	2,828		—			2,058		2,255
SR Energy and Gulfport	(e)	6,953		—			7,758		3,348
Panther Drilling and El Toro	(f)	345		—			135		—
Redback Energy and El Toro	(g)	—		124		—	—		—
Coil Tubing and El Toro	(h)	360		—			360		—
Bison Drilling and Predator	(i)	—		—			83		234
Other Relationships		—		49			54		78
		$	60,550	$	44,502		$	46,338	$	33,788


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.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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


d.	Cementing performs well cementing services for Gulfport.


e.	SR Energy performs rental services for Gulfport.


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


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


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


i.	Bison Drilling provides equipment rentals to Predator, an entity in which Wexford owns a minority interest.



		COST OF REVENUE				ACCOUNTS PAYABLE
		Three Months Ended March 31,				At March 31,		At December 31,
		2018		2017		2018		2017
Cobra and T&E	(a)	$	1,275	$	—	$	50	$	457
Higher Power and T&E	(a)	509		—		563		3
Panther and DBDHT	(b)	—		128		—		77
The Company and 2017 Stingray Companies	(c)	—		237		—		—
Other		8		65		8		218
		$	1,792	$	430	$	621	$	755

		SELLING, GENERAL AND ADMINISTRATIVE COSTS
The Company and Everest	(d)	$	31	$	58	$	16	$	19
The Company and Wexford	(e)	183		234		109		150
The Company and Caliber	(f)	201		—		58		1
Other		14		32		—		2
		$	429	$	324	$	183	$	172

		CAPITAL EXPENDITURES
Cobra and T&E	(a)	$	374	$	—	$	323	$	66
Higher Power and T&E	(a)	1,198		—		1,101		385
		$	1,572	$	—	$	1,424	$	451
						$	2,228	$	1,378


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


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


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


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


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


f.	Caliber leases office space to Mammoth.


16.	Commitments and Contingencies

Lease Obligations

The Company leases real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2062.

Minimum Purchase Commitments

The Company has entered into agreements with suppliers that contain minimum purchase obligations. Failure to purchase the minimum amounts may require the Company to pay shortfall fees. However, the minimum quantities set forth in the agreements are not in excess of currently expected future requirements.

Capital Spend Commitments

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Aggregate future minimum payments under these obligations in effect at March 31, 2018 are as follows (in thousands):



Year ended December 31:	Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments
Remainder of 2018	$	16,556	$	20,183	$	25,656
2019	15,651		—		11,436
2020	13,474		—		—
2021	10,911		—		—
2022	8,285		—		—
Thereafter	6,340		—		—
	$	71,217	$	20,183	$	37,092

For the three months ended March 31, 2018 and 2017, the Company recognized rent expense of $4.5 million and $2.0 million, respectively.

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



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

The Company has insurance coverage for physical partial loss to its assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks. The Company has also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. As of March 31, 2018 and December 31, 2017, the policies require a deductible per occurrence of up to $0.3 million. The Company establishes liabilities for the unpaid deductible portion of claims incurred relating to physical loss to its assets, employer's liability, automobile liability, commercial general liability and workers’ compensation based on estimates. As of March 31, 2018 and December 31, 2017, the policies contained an aggregate stop loss of $2.0 million. The Company also self-insures its employee health insurance. The Company has coverage on its self-insurance program in the form of a stop loss of $0.2 million per participant and an aggregate stop-loss of $5.8 million for the calendar year ending December 31, 2018. These estimates may change in the near term as actual claims continue to develop. As of March 31, 2018 and December 31, 2017, accrued insurance claims were $3.7 million and $2.9 million, respectively.

Pursuant to certain customer contracts in our infrastructure services segment, the Company warrants equipment and labor performed under the contracts for a specified period following substantial completion of the work. Generally, the warranty is for one year or less. No liabilities were accrued as of March 31, 2018 and December 31, 2017 and no expense was recognized during the three months ended March 31, 2018 or 2017 related to warranty claims. However, if warranty claims occur, the Company could be required to repair or replace warrantied items, which in most cases are covered by warranties extended from the manufacturer of the equipment. In the event the manufacturer of equipment failed to perform on a warranty obligation or denied a warranty claim made by the Company, the Company could be required to pay for the cost of the repair or replacement.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 January 26, 2017, a collective action lawsuit alleging that Pressure Pumping failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Ryan Crosby vs. Stingray Pressure Pumping, in the United Stated District Court for the Southern District of Ohio Eastern Division. The Company is evaluating the background facts at this time and is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

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

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

Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 92% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes discretionary matching contributions of up to 3% of an employee’s compensation and may make additional discretionary contributions for eligible employees. For the three months ended March 31, 2018, the Company paid $1.6 million in contributions to the plan. The Company did not make contributions to the plan during the three months ended March 31, 2017.


17.	Reporting Segments

As of March 31, 2018, our revenues, income before income taxes and identifiable assets are primarily attributable to four reportable segments. The Company principally provides energy services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and natural gas producers and electric infrastructure services to government-funded utilities, private utilities, public investor-owned utilities and co-operative utilities.

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

As of March 31, 2018, the Company’s four reportable segments include pressure pumping services ("Pressure Pumping"), infrastructure services ("Infrastructure"), natural sand proppant services ("Sand") and contract land and directional drilling services ("Drilling").

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Columbia and Alberta, Canada. The contract land and directional drilling services segment provides vertical, horizontal and directional drilling services in the Permian Basin in West Texas.

The Company also provides coil tubing services, pressure control services, flowback services, cementing services, equipment rental services and remote accommodation services. The businesses that provide these services are distinct operating segments, which the CODM reviews independently when making key operating and resource utilization decisions. None of these operating segments meet the quantitative thresholds of a reporting segment and do not meet the aggregation criteria set forth in ASC 280 Segment Reporting. Therefore, results for these operating segments are included in the column labeled "All Other" in the tables below. Additionally, assets for corporate activities, which primarily include cash and cash equivalents, inter-segment accounts receivable, prepaid insurance and certain property and equipment, are included in the All Other column. Although Mammoth LLC, which holds these corporate assets, meets one of the quantitative thresholds of a reporting segment, it does not engage in business activities from which it may earn revenues and its results are not regularly reviewed by the Company's CODM when making key operating and resource utilization decisions. Therefore, the Company does not include it as a reportable segment.

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



Three months ended March 31, 2018	Pressure Pumping		Infrastructure		Sand			Drilling			All Other			Eliminations			Total
Revenue from external customers	$	96,579	$	325,459	$	36,503		$	15,228		$	20,480		$	—		$	494,249
Intersegment revenues	4,559		—		14,512			2			2,415			(21,488		)	—
Total revenue	101,138		325,459		51,015			15,230			22,895			(21,488		)	494,249
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	66,612		194,076		33,330			14,475			17,608			—			326,101
Intersegment cost of revenues	15,402		1,791		4,286			162			105			(21,746		)	—
Total cost of revenue	82,014		195,867		37,616			14,637			17,713			(21,746		)	326,101
Selling, general and administrative	2,663		31,851		1,644			1,253			1,100			—			38,511
Depreciation, depletion, amortization and accretion	13,986		2,407		2,316			4,355			3,844			—			26,908
Operating income (loss)	2,475		95,334		9,439			(5,015		)	238			258			102,729
Interest expense	504		76		80			395			182			—			1,237
Other expense	12		2		(13		)	40			(13		)	—			28
Income (loss) before income taxes	$	1,959	$	95,256	$	9,372		$	(5,450	)	$	69		$	258		$	101,464
As of March 31, 2018:
Total assets^(a)	$	291,070	$	225,922	$	200,068		$	88,821		$	191,523		$	(96,319	)	$	901,085


a.	Total assets included in the All Other column include Mammoth LLC corporate assets totaling $88.1 million, of which $74.4 million are inter-segment accounts receivable which are eliminated in consolidation.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Three months ended March 31, 2017	Pressure Pumping		Infrastructure			Sand			Drilling			All Other			Eliminations			Total
Revenue from external customers	$	40,453	$	—		$	14,912		$	10,751		$	8,850		$	—		$	74,966
Intersegment revenues	187		—			685			—			—			(872		)	—
Total revenue	40,640		—			15,597			10,751			8,850			(872		)	74,966
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	28,707		86			12,608			10,953			6,144			—			58,498
Intersegment cost of revenues	685		—			187			—			—			(872		)	—
Total cost of revenue	29,392		86			12,795			10,953			6,144			(872		)	58,498
Selling, general and administrative	1,777		48			2,058			1,293			1,561			—			6,737
Depreciation, depletion, amortization and accretion	9,158		—			1,363			4,968			1,748			—			17,237
Operating income (loss)	313		(134		)	(619		)	(6,463		)	(603		)	—			(7,506		)
Interest expense	128		—			133			217			(81		)	—			397
Other expense	3		—			14			164			3			—			184
Income (loss) before income taxes	$	182	$	(134	)	$	(766	)	$	(6,844	)	$	(525	)	$	—		$	(8,087	)
As of March 31, 2017:
Total assets	$	229,231	$	—		$	131,437		$	97,839		$	172,005		$	(115,089	)	$	515,423


a.	Total assets included in the All Other column include Mammoth LLC corporate assets totaling $106.4 million, of which $94.1 million are inter-segment accounts receivable which are eliminated in consolidation.


18.	Subsequent Events

Subsequent to March 31, 2018, the Company entered into rail car, property and equipment lease agreements with aggregate commitments of $12.0 million.

Subsequent to March 31, 2018, the Company ordered additional capital equipment with aggregate commitments of $20.1 million and additional coil tubing string totaling $3.7 million.

Subsequent to March 31, 2018, subsidiaries in the Company's infrastructure segment entered into air charter agreements with aggregate commitments of $6.1 million, housing service agreements with aggregate commitments of $3.8 million and a medical service agreement with aggregate commitments of $0.2 million for services in Puerto Rico.

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

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

Overview

We are an integrated, growth-oriented energy service company serving (i) companies engaged in the exploration and development of North American onshore unconventional oil and natural gas reserves and (ii) government-funded utilities, private utilities, public investor owned utilities, or IOUs, and co-operative utilities, or Co-Ops, through our energy infrastructure business. 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, infrastructure services, natural sand proppant services, contract land and directional drilling services and other energy services, including coil tubing, flowback, cementing, equipment rental and remote accommodations. Our pressure pumping services division provides hydraulic fracturing services. Our infrastructure services division provides construction, upgrade, maintenance and repair services to the electrical infrastructure industry. Our natural sand proppant services division mines, processes and sells proppant used for hydraulic fracturing. Our contract land and directional drilling services division provides drilling rigs and crews for operators as well as rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. In addition to these service divisions, we also provide coil tubing services, pressure control services, flowback services, cementing services, equipment rentals and remote accommodations. We believe that the services we offer play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources as well as maintaining and improving electrical infrastructure. Our complementary suite of services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

On November 24, 2014, Mammoth Energy Holdings LLC, or Mammoth Holdings, Gulfport Energy Corporation, or Gulfport, and Rhino Exploration LLC, or Rhino, contributed to Mammoth Energy Partners LP, or the Partnership, their respective interests in the following entities: Bison Drilling and Field Services, LLC, or Bison Drilling; Bison Trucking LLC, or Bison Trucking; White Wing Tubular Services LLC, or White Wing; Barracuda Logistics LLC, or Barracuda; Panther Drilling Systems LLC, or Panther Drilling; Redback Energy Services LLC, or Redback Energy Services; Redback Coil Tubing LLC, or Redback Coil Tubing; Muskie Proppant LLC, or Muskie Proppant; Stingray Pressure Pumping LLC, or Pressure Pumping; Stingray Logistics LLC, or Logistics; and Great White Sand Tiger Lodging Ltd., or Lodging. Upon completion of these contributions, Mammoth Holdings, Gulfport and Rhino beneficially owned a 68.7%, 30.5% and 0.8% equity interest, respectively, in the Partnership.

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

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

On June 5, 2017, we acquired Sturgeon Acquisitions LLC, or Sturgeon, and Sturgeon's wholly owned subsidiaries Taylor Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC. Prior to the acquisition, we and Sturgeon were under common control and, in accordance with generally accepted accounting principles in the United States, or GAAP, we

have accounted for this acquisition in a manner similar to the pooling of interest method of accounting. Therefore, our historical financial information for all periods included in this Quarterly Report on Form 10-Q has been recast to combine Sturgeon's financial results with our financial results as if the acquisition had been effective since Sturgeon commenced operations.

First Quarter 2018 Highlights

Executed Two Amendments to our Contract with PREPA

On October 19, 2017, our wholly owned subsidiary Cobra Acquisitions LLC, or Cobra, entered into an emergency master services agreement with PREPA for repairs to PREPA’s electrical grid as a result of Hurricane Maria. During the first quarter of 2018, we executed two amendments to the contract, increasing the total contract value to $945.4 million from $200.0 million originally. At March 31, 2018, we had approximately 1,000 people, and approximately 600 pieces of equipment, deployed in Puerto Rico. See "Industry Overview - Energy Infrastructure Industry" for additional information regarding our contract with PREPA and other aspects of our infrastructure business.

Upgrades to Sand Facilities

During the first quarter of 2018, we completed the expansion of our Taylor sand facility in Jackson County, Wisconsin. We added an additional 150 ton per hour natural gas fired fluid bed dryer as well as four additional high capacity screeners. These upgrades added rated production capacity of 1.3 million tons per year, bringing our total annual rated production capacity to 5.2 million tons per year.

Additionally, we are currently in the process of upgrading our 90 ton per hour natural gas fired rotary dryer to a 200 ton per hour natural gas fired fluid bed dryer at our Piranha sand facility in Barron County, Wisconsin. This upgrade will add rated production capacity of 0.5 million tons per year. Once this expansion project is complete, our annual company-wide rated production capacity is expected to be 5.7 million tons per year and our annual company-wide functional production capacity is expected to be 4.4 million tons per year.

During the first quarter of 2018, our total sand production was 0.7 million tons, comprised of 0.4 million tons at our Piranha facility, 0.2 million tons at our Taylor facility and 0.1 million tons at our Muskie facility in Pierce County, Wisconsin.

As reported in our Annual Report on Form 10-K for the year ended December 31, 2017, our estimated proven mineral reserves for our Taylor and Piranha properties as of December 31, 2017 were estimated by John T. Boyd, our external mining and geological consultants. John T. Boyd will update our reserve estimates annually, making necessary adjustments for operations at each location during the year and additions or surveying, drill core analysis and other tests to confirm the quantity and quality of the reserves. To opine as to the economic viability of our reserves, John T. Boyd reviewed our financial cost and revenue per ton data at the time of the proven reserve determination. Our 2017 average monthly sales prices ranged from approximately $17 to $43 per ton free on board mine. Based on its review of our cost structure and its extensive experience with similar operations, John T. Boyd concluded that it is reasonable to assume that we will operate under a similar cost structure over the remaining life of our reserves. Based on these assumptions, and taking into account possible cost increases associated with a maturing mine, John T. Boyd concluded that our current operating margins are sufficient to expect continued profitability throughout the life of our reserves.

Industry Overview

Oil and Natural Gas Industry

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

Demand for most of our oil and natural gas products and services depends substantially on the level of expenditures by companies in the oil and natural gas industry. The levels of capital expenditures of our customers are predominantly driven by

the oil and natural gas prices. Over the past several years, commodity prices, particularly oil, has seen significant volatility with pricing ranging from a high of $110.53 per barrel on September 6, 2013 to a low of $26.19 per barrel on February 11, 2016. During early 2017, oil prices stabilized around the $50 per barrel level and started a gradual upward trend which continued into the first quarter of 2018, where oil prices averaged $62.96.

We anticipate demand for our oil and natural gas services and products will continue to be dependent on commodity prices. If commodity prices stabilize at current levels or continue to increase, we expect to experience further increases in demand for our services and products, particularly in our completion and production, natural sand proppant and contract land and directional drilling businesses. Decreases in commodity prices, however, may result in a reduction in the demand for our drilling, completion and other products and services.

During the first quarter of 2018, constraints in the rail system adversely impacted frac sand deliveries in certain of our service areas. While we were able to meet the frac sand demands of all of our customers for whom we supply sand in conjunction with our pressure pumping services, customers that utilize our pressure pumping services, but supply their own sand or last-mile trucking did not always have frac sand when needed. As a result, while revenue from our pressure pumping services division increased 149% in the first quarter of 2018 as compared to the same period in 2017, utilization of a portion of our pressure pumping fleet was adversely impacted by idle time waiting for sand deliveries to arrive. We anticipate that these rail system constraints will be alleviated later in 2018.

Energy Infrastructure Industry

In 2017, we expanded into the electric infrastructure business, offering both commercial and storm restoration services to government-funded utilities, private utilities, IOUs and Co-Ops. Since we commenced operations in this line of business, substantially all of our infrastructure revenues has been generated from storm restoration work, including revenue from PREPA due to the damage by Hurricane Maria. Our contract with PREPA, as amended during the first quarter of 2018, provides for 2018 revenue of approximately $745 million for services estimated to be performed through mid-2018. Cobra intends to seek additional repair and restoration work for PREPA’s electric grid as well as work rebuilding and modernizing PREPA’s electric grid once the repair and restoration phase is complete. However, there can be no assurance that Cobra will be successful in securing any additional work. Further, PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA's ability to meet its payment obligations under the contract will be largely dependent upon funding from the Federal Emergency Management Agency or other sources. In the event PREPA does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contract, terminates the contract or curtails our services prior to the end of the contract term, our financial condition, results of operations and cash flows could be materially and adversely affected. In addition, government contracts are subject to various uncertainties, restrictions and regulations, including oversight audits by government representatives and profit and cost controls, which could result in withholding or delayed payments to us or efforts to recover payments already made.

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

Natural Sand Proppant Industry

In the natural sand proppant industry, demand growth for frac sand and other proppants is primarily driven by advancements in oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing, as well as overall industry activity growth. Demand for proppant declined in 2015 and throughout most of 2016 with reduced well completion activity; however, we believe that demand for proppant will continue to grow over the long-term, as it did throughout 2017. In 2017, several new and existing suppliers announced planned capacity additions of frac sand supply, particularly in the Permian Basin. We expect frac sand supply to lag growth in demand over the coming months and quarters. While planned capacity may exceed the expectations for frac sand demand, the collectively available industry capacity is constrained due to (i) availability of the grades of sand that are currently in demand, (ii) general operating conditions and normal downtime and (iii) logistics constraints. The industry is expected to add significant capacity over the next 12 to 18 months, particularly in the Permian Basin; however, we do not expect such supply to be available in the volume grades or timeframe needed to efficiently meet the increasing demand. We believe that the coarseness, conductivity, sphericity, acid-solubility and crush-resistant properties of our Northern White sand reserves and our transportation infrastructure afford us an advantage over many of our competitors and make us one of a select group of sand producers capable of delivering high volumes of frac sand that is optimal for oil and natural gas production to all major unconventional resource basins currently producing throughout North America.

During the first quarter of 2018, the constraints in the rail system, as mentioned above, adversely impacted frac sand deliveries from our Taylor sand facility in Jackson County, Wisconsin. As a result, we estimate production at our Taylor facility was 28% lower during the first quarter of 2018 than it would have been in the absence of these constraints. We anticipate that these rail system constraints will be alleviated later in 2018. Production at our Piranha facility was not impacted by these rail constraints.

Results of Operations

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017



	Three Months Ended
	March 31, 2018			March 31, 2017
	(in thousands)
Revenue:
Pressure pumping services	$	101,138		$	40,640
Infrastructure services	325,459			—
Natural sand proppant services	51,015			15,597
Contract land and directional drilling services	15,230			10,751
Other services	22,895			8,850
Eliminations	(21,488		)	(872		)
Total revenue	494,249			74,966

Cost of revenue:
Pressure pumping services (exclusive of depreciation and amortization of $13,977 and $9,128, respectively, for the three months ended March 31, 2018 and 2017)	82,014			29,392
Infrastructure services (exclusive of depreciation and amortization of $2,401 and $0, respectively, for the three months ended March 31, 2018 and 2017)	195,867			86
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $2,314 and $1,362, respectively, for the three months ended March 31, 2018 and 2017)	37,616			12,795
Contract land and directional drilling services (exclusive of depreciation of $4,354 and $4,965, respectively, for the three months ended March 31, 2018 and 2017)	14,637			10,953
Other services (exclusive of depreciation and amortization of $3,843 and $1,745, respectively, for the three months ended March 31, 2018 and 2017)	17,713			6,144
Eliminations	(21,746		)	(872		)
Total cost of revenue	326,101			58,498
Selling, general and administrative expenses	38,511			6,737
Depreciation, depletion, amortization and accretion	26,908			17,237
Operating income (loss)	102,729			(7,506		)
Interest expense, net	(1,237		)	(397		)
Other expense, net	(28		)	(184		)
Income (loss) before income taxes	101,464			(8,087		)
Provision (benefit) for income taxes	45,918			(3,106		)
Net income (loss)	$	55,546		$	(4,981	)

Revenue. Revenue for the three months ended March 31, 2018 increased $419.3 million, or 559%, to $494.2 million from $75.0 million for the three months ended March 31, 2017. The increase in total revenues is primarily attributable to the expansion of our service offerings to include infrastructure services in the second half of 2017, which generated revenues of

$325.5 million during the three months ended March 31, 2018, representing 78% of the overall increase. Additionally, pressure pumping services revenue increased $60.5 million, representing 14% of the overall increase, due to six pressure pumping fleets operating during the three months ended March 31, 2018 compared to three pressure pumping fleets operating during the three months ended March 31, 2017.

Revenue derived from related parties was $60.6 million, or 12% of our total revenues, for the three months ended March 31, 2018 and $44.5 million, or 59% of our total revenues, for the three months ended March 31, 2017. Substantially all of our related party revenue is derived from Gulfport under our four-year pressure pumping and sand contracts expiring in September 2018. We are in discussions with Gulfport regarding extending these contracts beyond the current expiration date, but have not entered into any definitive agreements to do so. If we do not extend these contracts, we believe we will be able to sell these products and services to other customers at comparable terms and, as a result, we do not believe that any such expiration would have a material adverse effect on our operations or financial condition. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $60.5 million, or 149%, to $101.1 million for the three months ended March 31, 2018 from $40.6 million for the three months ended March 31, 2017. Revenue derived from related parties was $38.5 million, or 38% of total pressure pumping revenues, for the three months ended March 31, 2018 compared to $31.8 million, or 78% of total pressure pumping revenues, for the three months ended March 31, 2017. Substantially all of our related party revenue is derived from Gulfport under a four-year contract expiring in September 2018. Inter-segment revenues, consisting primarily of revenue derived from our sand segment, totaled $4.6 million and $0.2 million, respectively, for the three months ended March 31, 2018 and 2017.

The increase in our pressure pumping services revenue was primarily driven by the startup of our fourth, fifth and sixth pressure pumping fleets in June, August and October 2017, respectively, in the SCOOP/STACK and Permian Basin, which contributed revenues of $41.0 million during the three months ended March 31, 2018. Additionally, the number of stages completed increased to 1,672 for the three months ended March 31, 2018 from 860 for the three months ended March 31, 2017.

Infrastructure Services. Infrastructure services division revenue was $325.5 million for the three months ended March 31, 2018. We began offering electric utility infrastructure services in the second half of 2017 through the formation of Cobra and the acquisitions of Higher Power and 5 Star. We generated $318.4 million, or 98% of total infrastructure services revenue, from our contract with PREPA for repairs to Puerto Rico's electrical grid as a result of Hurricane Maria. For additional information regarding our contract with PREPA and our infrastructure services, see "Industry Overview - Electrical Infrastructure Industry" above.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $35.4 million, or 227%, to $51.0 million for the three months ended March 31, 2018, from $15.6 million for the three months ended March 31, 2017. Revenue derived from related parties was $11.5 million, or 22% of total sand revenues, for the three months ended March 31, 2018 and $11.5 million, or 74% of total sand revenues, for the three months ended March 31, 2017. Substantially all of our related party revenue is derived from Gulfport under a four-year contract expiring in September 2018. Inter-segment revenues, consisting primarily of revenue derived from our pressure pumping segment, totaled $14.5 million, or 28% of total sand revenues, for the three months ended March 31, 2018 and $0.7 million, or 4% of total sand revenues, for the three months ended March 31, 2017.

The increase in our natural sand proppant services revenue was primarily attributable to a 187% increase in tons of sand sold from approximately 255,865 tons for the three months ended March 31, 2017 to 735,584 tons for the three months ended March 31, 2018. Additionally, we acquired a wet and dry plant and sand mine located on approximately 600 acres in New Auburn, Wisconsin through our purchase of the assets of Chieftain in May 2017. These assets contributed revenues of $19.7 million to our natural sand proppant division for the three months ended March 31, 2018.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $4.5 million, or 42%, from $10.8 million for the three months ended March 31, 2017 to $15.2 million for the three months ended March 31, 2018. Revenue derived from related parties, consisting primarily of directional drilling revenue from El Toro Resources LLC, was $0.4 million, or 3% of total drilling revenues, for the three months ended March 31, 2018 and $1.0 million, or 10% of total drilling revenues, for the three months ended March 31, 2017.

The increase in contract land and directional drilling revenue was primarily attributable to our directional drilling services, which accounted for $2.0 million, or 45% of the total increase as a result of increased utilization. Our land drilling services accounted for $1.3 million, or 30%, of the operating division increase as a result of an increase in average day rates from approximately $14,400 for the three months ended March 31, 2017 to approximately $16,541 for the three months ended March 31, 2018. The average rig count remained consistent at an average of five rigs for each respective period. Our rig moving services accounted for $1.1 million, or 25%, of the operating division increase. The increase in our rig moving services was driven by the increase in drilling activity.

Other Services. Other revenue, consisting of revenue derived from our coil tubing, pressure control, flowback, cementing, equipment rental and remote accommodation businesses, increased $14.0 million, or 157%, to $22.9 million for the three months ended March 31, 2018 from $8.9 million for the three months ended March 31, 2017. Revenue derived from related parties, consisting primarily of equipment rental and cementing revenue from Gulfport, was $10.1 million, or 44% of total other revenues, for the three months ended March 31, 2018 and $0.2 million, or 2% of total other revenues, for the three months ended March 31, 2017. Inter-segment revenues, consisting primarily of revenue derived from our infrastructure and pressure pumping segments, totaled $2.4 million for the three months ended March 31, 2018. Our other services did not generate intersegment revenues for the three months ended March 31, 2017.

Stingray Cementing and Stingray Energy, which we acquired in June 2017, contributed revenues of $11.7 million for the three months ended March 31, 2018. Revenues from our other well services increased $2.3 million for the three months ended March 31, 2018 compared to three months ended March 31, 2017 primarily due to increases in utilization.

Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, increased $267.6 million from $58.5 million, or 78% of total revenue, for the three months ended March 31, 2017 to $326.1 million, or 66% of total revenue, for the three months ended March 31, 2018. The increase was primarily due to an expansion of our service offerings into the infrastructure services business, which represented a $194.0 million increase in cost of revenue, as well as an increase in pressure pumping division costs of $52.6 million, primarily related to the addition of three new fleets, and an increase in natural sand proppant division costs of $24.8 million, primarily due to an increase in tons of sand sold during the three months ended March 31, 2018 compared to 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, exclusive of depreciation and amortization expense, increased $52.6 million, or 179%, to $82.0 million for the three months ended March 31, 2018 from $29.4 million for the three months ended March 31, 2017. The increase was primarily due to the expansion of services into the SCOOP/STACK and Permian Basin with the addition of three fleets, which accounted for $38.9 million, or 74%, of the increase. As a percentage of revenue, our pressure pumping services division cost of revenue, exclusive of depreciation and amortization expense of $14.0 million and $9.1 million for the three months ended March 31, 2018 and 2017, was 81% and 72%, respectively, for the three months ended March 31, 2018 and March 31, 2017. The increase in costs as a percentage of revenue was primarily due to an increase in cost of goods sold as we began selling sand as part of our service package to customers in the mid-continent region.

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, was $195.9 million and $0.1 million, respectively, for the three months ended March 31, 2018 and 2017. The largest components of our cost of revenue include labor-related costs, including contract labor, and travel, meals and lodging expense. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $2.4 million, was 60% for the three months ended March 31, 2018. The infrastructure services division did not recognize any revenue during the three months ended March 31, 2017.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased $24.8 million, or 194%, from $12.8 million for the three months ended March 31, 2017 to $37.6 million for the three months ended March 31, 2018, primarily due to an increase in cost of goods sold as a result of a 187% increase in tons of sand sold in the 2018 period. As a percentage of revenue, cost of revenue, exclusive of depreciation, depletion and accretion expense of $2.3 million and $1.4 million for the three months ended March 31, 2018 and 2017, was 74% and 82%, respectively, for the three months ended March 31, 2018 and March 31, 2017. The decrease is primarily due to a 14% increase in price per ton of sand sold.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue, exclusive of depreciation expense, increased $3.7 million, or 34%, from $11.0 million for the three

months ended March 31, 2017 to $14.6 million for the three months ended March 31, 2018, primarily due to an increase in repairs and maintenance expense, labor-related costs and increased utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue, exclusive of depreciation expense of $4.4 million and $5.0 million for the three months ended March 31, 2018 and 2017, was 96% and 102%, respectively, for the three months ended March 31, 2018 and March 31, 2017. The decrease was primarily due to higher day rates.

Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, increased $11.6 million, or 188%, from $6.1 million for the three months ended March 31, 2017 to $17.7 million for the three months ended March 31, 2018, primarily due to the acquisition of Stingray Cementing and Stingray Energy in June 2017. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $3.8 million and $1.7 million for the three months ended March 31, 2018 and 2017, was 77% and 69%, respectively, for the three months ended March 31, 2018 and 2017. The increase is primarily the result of increased equipment rental expense and labor-related costs as a percentage of revenue.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $31.8 million, or 472%, to $38.5 million for the three months ended March 31, 2018, from $6.7 million for the three months ended March 31, 2017. The increase is primarily attributable to a $25.6 million increase in bad debt expense and a $4.7 million increase in compensation and benefits.

Depreciation, Depletion, Amortization and Accretion. Depreciation and amortization increased $9.7 million, or 56%, to $26.9 million for the three months ended March 31, 2018 from $17.2 million for the three months ended March 31, 2017. The increase was primarily attributable to $38.3 million of capital additions being placed into service during the three months ended March 31, 2018.

Operating Income (Loss). Operating income increased $110.2 million to $102.7 million for the three months ended March 31, 2018 compared to an operating loss of $7.5 million for the three months ended March 31, 2017. The increase was primarily the result of an expansion of our service offerings into the infrastructure business, which accounted for 87%, or $95.5 million, of the overall increase in operating income. Operating income from our sand division increased $10.1 million, or 9% of the overall increase, primarily due to an increase in the sales price per ton of sand sold.

Interest Expense, Net. Interest expense, net increased $0.8 million, or 212%, to $1.2 million during the three months ended March 31, 2018, from $0.4 million during the three months ended March 31, 2017. The increase in interest expense, net was attributable to an increase in average borrowings during the three months ended March 31, 2018.

Other Expense, Net. Non-operating charges, net resulted in expense of a nominal amount and $0.2 million for the three months ended March 31, 2018 and 2017. Both periods were primarily comprised of loss recognition on assets disposed of during the period.

Income Taxes. We recorded income tax expense of $45.9 million on pre-tax income of $101.5 million for the three months ended March 31, 2018 compared to an income tax benefit of $3.1 million on pre-tax loss of $8.1 million for the three months ended March 31, 2017. Our effective tax rate was 45% for the three months ended March 31, 2018 compared to 39% for the three months ended March 31, 2017. The increase in effective tax rate is primarily due to a higher tax rate in Puerto Rico, where most of our income was generated during the three months ended March 31, 2018, compared to the United States tax rate. No income was generated in Puerto Rico during the three months ended March 31, 2017.

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, depletion, accretion 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 industries depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly

titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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

Consolidated



	Three Months Ended
	March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017
Net income (loss)	$	55,546		$	(4,981	)
Depreciation, depletion, accretion and amortization expense	26,908			17,237
Acquisition related costs	(46		)	1,247
Equity based compensation	1,256			570
Interest expense	1,237			397
Other expense, net	28			184
Provision (benefit) for income taxes	45,918			(3,106		)
Adjusted EBITDA	$	130,847		$	11,548

Pressure Pumping Services



	Three Months Ended
	March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2018		2017
Net income	$	1,959	$	182
Depreciation and amortization expense	13,986		9,158
Equity based compensation	418		271
Interest expense	504		128
Other expense, net	12		3
Adjusted EBITDA	$	16,879	$	9,742

Infrastructure Services



	Three Months Ended
	March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017
Net income (loss)	$	47,299		$	(134	)
Depreciation and amortization expense	2,407			—
Acquisition related costs	(8		)	—
Equity based compensation	457			—
Interest expense	76			—
Other expense, net	2			—
Provision for income taxes	47,957			—
Adjusted EBITDA	$	98,190		$	(134	)

Natural Sand Proppant Services



	Three Months Ended
	March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017
Net income (loss)	$	9,372		$	(766	)
Depreciation, depletion, accretion and amortization expense	2,316			1,363
Acquisition related costs	(38		)	1,038
Equity based compensation	186			70
Interest expense	80			133
Other (income) expense, net	(13		)	14
Adjusted EBITDA	$	11,903		$	1,852

Contract Land and Directional Drilling Services



	Three Months Ended
	March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017
Net loss	$	(5,450	)	$	(6,844	)
Depreciation and amortization expense	4,355			4,968
Acquisition related costs	—			22
Equity based compensation	107			112
Interest expense, net	395			217
Other expense, net	40			164
Adjusted EBITDA	$	(553	)	$	(1,361	)

Other Services^(a)



	Three Months Ended
	March 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017
Net income	$	2,107		$	2,581
Depreciation and amortization expense	3,844			1,748
Acquisition related costs	—			187
Equity based compensation	89			117
Interest expense, net	182			(81		)
Other expense, net	(13		)	3
(Benefit) provision for income taxes	(2,038		)	(3,106		)
Adjusted EBITDA	$	4,171		$	1,449

(a) Includes results for our coil tubing, pressure control, flowback, cementing, equipment rentals and remote accommodations services and corporate related activities.

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, cash flows from operations and proceeds from our initial public offering. Our primary use of capital has been for investing in property and equipment used to provide our services and to acquire complementary businesses.

As of March 31, 2018, we had $39.0 million in borrowings outstanding under our revolving credit facility, leaving of $123.7 million of available borrowing capacity under this facility, after giving effect to $6.5 million of outstanding letters of credit.

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



	March 31,			December 31,
	2018			2017
Cash and cash equivalents	$	10,447		$	5,637
Revolving credit facility availability	169,233			169,233
Less long-term debt	(39,000		)	(99,900		)
Less letter of credit facilities (environmental remediation)	(3,582		)	(3,582		)
Less letter of credit facilities (insurance programs)	(2,486		)	(2,486		)
Less letter of credit facilities (rail car commitments)	(455		)	(455		)
Net working capital (less cash)^(a)	56,654			88,798
Total	$	190,811		$	157,245


a.	Net working capital (less cash) is a non-GAAP measure and is calculated by subtracting Total current liabilities of $258.9 million and Cash and cash equivalents of $10.4 million from Total current assets of $326.0 million.

At May 1, 2018, we had an aggregate of $33.5 million in borrowings outstanding under our revolving credit facility, leaving an aggregate of $129.2 million of available borrowing capacity under this facility, which is net of letters of credit of $6.5 million. At May 1, 2018, we had cash on hand totaling $20.4 million.

Liquidity and Cash Flows

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



	Three Months Ended
	March 31,
	2018			2017
Net cash provided by operating activities	$	101,323		$	14,418
Net cash used in investing activities	(35,488		)	(30,741		)
Net cash provided by (used in) financing activities	(60,972		)	—
Effect of foreign exchange rate on cash	(53		)	11
Net change in cash	$	4,810		$	(16,312	)

Operating Activities

Net cash provided by operating activities was $101.3 million for the three months ended March 31, 2018, compared to $14.4 million for the three months ended March 31, 2017. The increase in operating cash flows was primarily attributable to the increase in net income as a result of the expansion of services with our infrastructure business and in our pressure pumping business.

Investing Activities

Net cash used in investing activities was $35.5 million for the three months ended March 31, 2018, compared to $30.7 million for the three months ended March 31, 2017. 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 (in thousands):



	Three Months Ended
	March 31,
	2018		2017
Pressure pumping services^(a)	$	7,866	$	28,665
Infrastructure services^(b)	15,778		—
Natural sand proppant services^(c)	5,700		175
Contract and directional drilling services^(d)	3,618		2,269
Other^(e)	2,812		1
Total capital expenditures	$	35,774	$	31,110

a. Capital expenditures primarily for pressure pumping equipment for the three months ended March 31, 2018 and 2017.

b. Capital expenditures primarily for trucks and other equipment for the three months ended March 31, 2018.

c. Capital expenditures primarily for plant upgrades for the three months ended March 31, 2018 and 2017.

d. Capital expenditures primarily for upgrades to our rig fleet for the three months ended March 31, 2018 and 2017.

e. Capital expenditures primarily for equipment for our rental business for the three months ended March 31, 2018.

Financing Activities

Net cash provided by financing activities was $61.0 million for the three months ended March 31, 2018, compared to zero for the three months ended March 31, 2017. Net cash used for financing activities was primarily attributable to net repayments under our revolving credit facility of $60.9 million for the three months ended March 31, 2018.

Effect of Foreign Exchange Rate on Cash

The effect of foreign exchange rate on cash was ($0.1) million and a nominal amount for the three months ended March 31, 2018 and 2017, respectively. The change was driven primarily by a favorable (unfavorable) shift in the weakness (strength) of the Canadian dollar relative to the U.S. dollar for the cash held in Canadian accounts.

Working Capital

Our working capital totaled $67.1 million and $94.4 million, respectively, at March 31, 2018 and December 31, 2017. Our cash balances were $10.4 million and $5.6 million, respectively, at March 31, 2018 and December 31, 2017.

Our Revolving Credit Facility

We are party to a $170.0 million revolving credit and security agreement, dated as of November 25, 2014 as subsequently amended, with PNC Capital Markets LLC, as lead arranger, PNC Bank, National Association, as the administrative and collateral agent, and the lenders from time-to-time party thereto. Our revolving credit facility matures on November 25, 2019. Borrowings under our revolving credit facility are secured by our and our subsidiaries’ assets. The maximum availability for future borrowings under our revolving credit facility is subject to a borrowing base calculation prepared monthly.

Effective as of July 12, 2017, our revolving credit facility was amended, providing us with greater flexibility for permitted acquisitions and permitted indebtedness, increasing the maximum amount credited to the borrowing base for sand inventory and for in-transit inventory and increasing certain default thresholds from $5 million to $15 million.

Interest is payable monthly at a base rate set by the institution’s commercial lending group plus an applicable margin. Additionally, at our request, outstanding balances, are permitted to be converted to LIBOR rate plus applicable margin tranches

at set increments of $500,000. The LIBOR rate option allows us to select interest periods from one, two, and three or six months. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit.

At March 31, 2018, we had outstanding borrowings under our credit facility of $39.0 million bearing a weighted average interest rate of 4.49%. At March 31, 2018, we had availability of $123.7 million under our revolving credit facility, after giving effect to $6.5 million of outstanding letters of credit.

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

Capital Requirements and Sources of Liquidity

During 2018, we currently estimate that our aggregate capital expenditures will be approximately $125.0 million. These capital expenditures include $55.5 million in our infrastructure services segment for assets for an additional 68 crews, $23.9 million in our natural sand proppant services segment primarily related to expansion projects, $21.0 million in our pressure pumping segment for various pressure pumping equipment, $9.8 million in our contract land and directional drilling services segment primarily for rig upgrades, $6.8 million for expansion of our rental equipment business into Oklahoma and $5.7 million for coil tubing equipment. During the first quarter of 2018, our capital expenditures totaled $35.8 million.

We believe that our cash on hand, operating cash flow and available borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next twelve months. However, future cash flows are subject to a number of variables, and significant additional capital expenditures could be required to conduct our operations. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, we continue to pursue our previously announced acquisition strategy to enhance our portfolio of products and services, market positioning and/or geographic presence. In doing so, we regularly evaluate acquisition opportunities. However, we do not have a specific acquisition budget for 2018 since the timing and size of acquisitions cannot be accurately forecasted. Our acquisitions may be undertaken with cash, our common stock or a combination of cash, common stock and/or other consideration. In the event we make one or more additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our revolving credit facility, joint venture partnerships, asset sales, offerings of debt or equity securities or other means. We cannot assure you that this additional capital will be available on acceptable terms or at all. If we are unable to obtain funds we need, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to conduct our operations.

Off-Balance Sheet Arrangements

Lease Obligations

We lease real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2062.

Minimum Purchase Commitments

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

Capital Spend Commitments

We have entered into agreements with suppliers to acquire capital equipment.

Aggregate future minimum lease payments under these agreements in effect at March 31, 2018 are as follows (in thousands):



Year ended December 31:	Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments
Remainder of 2018	$	16,556	$	20,183	$	25,656
2019	15,651		—		11,436
2020	13,474		—		—
2021	10,911		—		—
2022	8,285		—		—
Thereafter	6,340		—		—
	$	71,217	$	20,183	$	37,092

Other Commitments

Subsequent to March 31, 2018, we entered into rail car, property and equipment lease agreements with aggregate commitments of $12.0 million.

Subsequent to March 31, 2018, we ordered additional capital equipment with aggregate commitments of $20.1 million and additional coil tubing string totaling $3.7 million.

Subsequent to March 31, 2018, subsidiaries in our infrastructure segment entered into air charter agreements with aggregate commitments of $6.1 million, housing service agreements with aggregate commitments of $3.8 million and a medical service agreement with aggregate commitments of $0.2 million for services in Puerto Rico.

New Accounting Pronouncements

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. We plan to adopt this ASU effective January 1, 2019 utilizing the modified retrospective method of adoption. This new leasing guidance will impact us in situations where we are the lessee, and in certain circumstances we will have a right-of-use asset and lease liability on our consolidated financial statements. We are currently evaluating the effect the new guidance will have on our consolidated financial statements and results of operations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Interest Rate Risk

We had a cash and cash equivalents balance of $10.4 million at March 31, 2018. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure to changes in the fair value of these investments as a result of changes in interest rates. Declines in interest rates, however, will reduce future income.

At March 31, 2018, we had $39.0 million outstanding under this facility with weighted average interest rate of 4.5%. A 1% increase or decrease in the interest rate at that time would have increased or decreased our interest expense by approximately $0.4 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, 2018, we had $2.9 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 $0.01 million as of March 31, 2018. Conversely, a corresponding decrease in the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

Seasonality

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

Item 4. Controls and Procedures

Evaluation of Disclosure Control and Procedures

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

As of March 31, 2018, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of March 31, 2018, our disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting (as defined in Rules 13a-15(d) and 15d-15(d) under the Exchange Act) that occurred during the quarter ended March 31, 2018 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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 16 of this Report.

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors set forth below and in our Annual Report on Form 10-K (Commission File No. 001-37917) filed with the SEC on February 28, 2018.

Other than set forth below, there have been no material changes to the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

An increase in the supply of raw frac sand could make it more difficult for us to renew or replace our existing contracts on favorable terms, or at all.

If significant new reserves of raw frac sand are discovered and developed, we may be unable to renew or replace our existing contracts at favorable pricing, or at all. Specifically, if frac sand becomes more readily available, our customers may not be willing to enter into long-term contracts, or may demand lower prices, or both, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Further, reduced demand for frac sand could result in railcar over-capacity, requiring us to pay railcar storage fees while, at the same time, continuing to incur lease costs for those railcars in storage, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We face distribution and logistics challenges in our business.

In response to various factors, including fluctuations in oil and natural gas prices, our customers may shift their focus among resource plays, some of which can be located in geographic areas that do not have well-developed transportation and distribution infrastructure systems. Some geographic areas, including the areas in which our sand facilities are located, have limited access to railroads. Any interruption or delay in the railroad access or service may affect our ability to ship and/or the timing of shipment of our frac sand to our customers, which may adversely affect our revenues or result in increased costs, and thus could negatively impact our results of operations and financial condition. Serving our customers in these less-developed areas presents distribution and other operational challenges that may affect our sales and could negatively impact our operating costs. Labor disputes, system constraints, derailments, adverse weather conditions or other environmental events, an increasingly tight railcar leasing market and changes to rail freight systems, among other factors, could interrupt or limit available transportation services, could affect our ability to timely and cost-effectively deliver our frac sand to our customers and could provide a competitive advantage to our competitors located in closer proximity to our customers. Failure to find long-term solutions to these logistics challenges could adversely affect our business, financial condition, results of operations and cash flows.

Increasing transportation and related costs could have a material adverse effect on our business.

Because of the relatively low cost of producing frac sand, transportation expenses and related costs, including freight charges, fuel surcharges, transloading fees, switching fees, railcar lease costs, demurrage costs and storage fees, comprise a significant component of the total delivered cost of frac sand sales. The relatively high transportation expenses and related costs tend to favor frac sand producers located in close proximity to their customers. As we expand our frac sand production, our need for additional transportation services and transload network access increases. We contract with truck and rail services to move frac sand from our production facilities to transload sites and our customers, and increased costs under these contracts could adversely affect our results of operations. In addition, we bear the risk of non-delivery under our contracts. A significant increase in transportation service rates, a reduction in the dependability or availability of transportation or transload services, or relocation of our customers’ businesses to areas farther from our plants or transloading facilities could impair our ability to deliver our products economically to our customers and our ability to expand into different markets.

MAMMOTH ENERGY SERVICES, INC.

Inaccuracies in estimates of volumes and qualities of our sand reserves could result in lower than expected sales and higher than expected production costs.

John T. Boyd, our independent reserve engineers, prepare annual estimates of our reserves based on engineering, economic and geological data assembled and analyzed by our engineers and geologists. However, frac sand reserve estimates are by nature imprecise and depend to some extent on statistical inferences drawn from available data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of reserves and non-reserve frac sand deposits and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable frac sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:


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


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


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

Any inaccuracy in John T. Boyd’s estimates related to our frac sand reserves and non-reserve frac sand deposits could result in lower than expected sales and higher than expected costs. For example, John T. Boyd’s estimates of our proven reserves assume that our revenue and cost structure will remain relatively constant over the life of our reserves. If these assumptions prove to be inaccurate, some or all of our reserves may not be economically mineable, which could have a material adverse effect on our results of operations and cash flows. If John T. Boyd’s estimates of the quality of our reserves, including the volumes of the various specifications of those reserves, prove to be inaccurate, we may incur significantly higher excavation costs without corresponding increases in revenues, we may not be able to meet our contractual obligations, or our facilities may have a shorter than expected reserve life, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Not applicable.

Item 4. Mine Safety Disclosures

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

Item 5. Other Information

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
3.1	Amended and Restated Certificate of Incorporation of the Company	8-K	001-37917	11/15/2016	3.1
3.2	Amended and Restated Bylaws of the Company	8-K	001-37917	11/15/2016	3.2
4.1	Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company	S-1/A	333-213504	10/3/2016	4.1
4.2	Registration Rights Agreement, dated October 12, 2016, by and between the Company and Mammoth Energy Holdings, LLC	8-K	001-37917	11/15/2016	4.1
4.3	Investor Rights Agreement, dated October 12, 2016, by and between the Company and Gulfport Energy Corporation	8-K	001-37917	11/15/2016	4.2
4.4	Registration Rights Agreement, dated October 12, 2016, by and between the Company and Rhino Exploration LLC	8-K	001-37917	11/15/2016	4.3
10.1	Amendment No. 4 to Emergency Master Service Agreement for PREPA's Electrical Grid Repairs-Hurricane Maria, dated as of January 28, 2018, between the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC.	8-K	001-37917	1/31/2018	10.5
10.2	Amendment No. 5 to Emergency Master Service Agreement for PREPA's Electrical Grid Repairs-Hurricane Maria, dated as of February 28, 2018, between the Puerto Rico Electric Power Authority (PREPA) and Cobra Acquisitions LLC.	10-K	001-37917	2/28/2018	10.34
31.1	Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
31.2	Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.					X
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					X
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.					X
95.1	Mine Safety Disclosure Exhibit					X
101.1	Interactive data files pursuant to Rule 405 of Regulation S-T.


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

MAMMOTH ENERGY SERVICES, INC.

Signatures

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



			MAMMOTH ENERGY SERVICES, INC.
Date:	May 4, 2018	By:	/s/ Arty Straehla
			Arty Straehla
			Chief Executive Officer

Date:	May 4, 2018	By:	/s/ Mark Layton
			Mark Layton
			Chief Financial Officer