Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q



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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 every Interactive Data File required to be submitted 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 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 October 30, 2018, there were 44,755,678 shares of common stock, $0.01 par value, outstanding.

MAMMOTH ENERGY SERVICES, INC.

TABLE OF CONTENTS





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

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	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	53

PART II. OTHER INFORMATION		54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	55
Item 6.	Exhibits	56

SIGNATURES		57

GLOSSARY OF OIL AND NATURAL GAS AND ELECTRICAL INFRASTRUCTURE TERMS



The following is a glossary of certain oil and natural gas industry terms used in this report:
Acidizing	To pump acid into a wellbore to improve a well's productivity or injectivity.
Blowout	An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of salt water, oil, natural gas or a mixture of these. Blowouts can occur in all types of exploration and production operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant open-hole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) down-hole and intervention efforts will be averted.
Bottomhole assembly	The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.
Cementing	To prepare and pump cement into place in a wellbore.
Coiled tubing	A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft. to 23,000 ft. (610 m to 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.

iii

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2017 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:


•	business strategy;


•	pending or future acquisitions and future capital expenditures;


•	ability to obtain permits and governmental approvals;


•	technology;


•	financial strategy;


•	future operating results; and


•	plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this quarterly report, are forward-looking statements. These forward-looking statements may be found in the “Business,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and other sections of this quarterly report. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “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.

MAMMOTH ENERGY SERVICES, INC.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS (unaudited)



ASSETS	September 30,			December 31,
	2018			2017
CURRENT ASSETS	(in thousands)
Cash and cash equivalents	$	19,692		$	5,637
Accounts receivable, net	390,824			243,746
Receivables from related parties	25,335			33,788
Inventories	19,185			17,814
Prepaid expenses	10,969			12,552
Other current assets	652			886
Total current assets	466,657			314,423

Property, plant and equipment, net	434,785			351,017
Sand reserves	72,207			74,769
Intangible assets, net - customer relationships	3,021			9,623
Intangible assets, net - trade names	6,134			6,516
Goodwill	98,308			99,811
Deferred income tax asset	—			6,739
Other non-current assets	4,046			4,345
Total assets	$	1,085,158		$	867,243
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	139,374		$	141,306
Payables to related parties	1,402			1,378
Accrued expenses and other current liabilities	42,605			40,895
Income taxes payable	172,000			36,409
Total current liabilities	355,381			219,988

Long-term debt	—			99,900
Deferred income tax liabilities	33,601			34,147
Asset retirement obligation	3,155			2,123
Other liabilities	1,703			3,289
Total liabilities	393,840			359,447

COMMITMENTS AND CONTINGENCIES (Note 18)

EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 44,755,678 and 44,589,306 issued and outstanding at September 30, 2018 and December 31, 2017, respectively	448			446
Additional paid in capital	529,825			508,010
Retained earnings	164,165			2,001
Accumulated other comprehensive loss	(3,120		)	(2,661		)
Total equity	691,318			507,796
Total liabilities and equity	$	1,085,158		$	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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
REVENUE	(in thousands, except per share amounts)
Services revenue	$	346,368		$	63,113		$	1,210,572		$	119,864
Services revenue - related parties	18,933			56,861			108,632			134,426
Product revenue	14,955			15,276			67,703			29,043
Product revenue - related parties	3,787			14,055			24,979			39,200
Total revenue	384,043			149,305			1,411,886			322,533

COST AND EXPENSES
Services cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $27,810, $79,283, $24,153 and $57,642, respectively, for the three and nine months ended September 30, 2018 and three and nine months ended September 30, 2017)	216,670			89,346			809,932			191,911
Services cost of revenue - related parties (exclusive of depreciation, depletion, amortization and accretion of $0, $0, $0 and $0, respectively, for the three and nine months ended September 30, 2018 and three and nine months ended September 30, 2017)	1,425			9			5,645			701
Product cost of revenue (exclusive of depreciation, depletion, amortization and accretion of $4,183, $10,376, $3,033 and $6,599, respectively, for the three and nine months ended September 30, 2018 and three and nine months ended September 30, 2017)	29,470			25,178			97,917			57,759
Selling, general and administrative (Note 12)	(45,761		)	7,667			56,916			21,473
Selling, general and administrative - related parties (Note 12)	437			355			1,398			986
Depreciation, depletion, amortization and accretion	32,015			27,224			89,718			64,354
Impairment of long-lived assets	4,582			—			4,769			—
Total cost and expenses	238,838			149,779			1,066,295			337,184
Operating income (loss)	145,205			(474		)	345,591			(14,651		)

OTHER (EXPENSE) INCOME
Interest expense, net	(458		)	(1,420		)	(2,654		)	(2,929		)
Bargain purchase gain, net of tax	—			—			—			4,012
Other, net	(400		)	(320		)	(914		)	(707		)
Total other (expense) income	(858		)	(1,740		)	(3,568		)	376
Income (loss) before income taxes	144,347			(2,214		)	342,023			(14,275		)
Provision (benefit) for income taxes	74,835			(1,413		)	174,265			(7,323		)
Net income (loss)	$	69,512		$	(801	)	$	167,758		$	(6,952	)

OTHER COMPREHENSIVE INCOME (LOSS)
Foreign currency translation adjustment, net of tax of ($87), $185, $358 and $812, respectively, for the three and nine months ended September 30, 2018 and three and nine months ended September 30, 2017	327			628			(459		)	1,037
Comprehensive income (loss)	$	69,839		$	(173	)	$	167,299		$	(5,915	)

Net income (loss) per share (basic) (Note 14)	$	1.55		$	(0.02	)	$	3.75		$	(0.17	)
Net income (loss) per share (diluted) (Note 14)	$	1.54		$	(0.02	)	$	3.73		$	(0.17	)
Weighted average number of shares outstanding (basic) (Note 14)	44,756			44,502			44,718			40,526
Weighted average number of shares outstanding (diluted) (Note 14)	45,082			44,502			45,012			40,526
Dividends declared per share	$	0.125		—			$	0.125		—

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)



												Accumulated
							Retained			Additional		Other
	Common Stock			Members'			Earnings			Paid-In		Comprehensive
	Shares	Amount		Equity			(Deficit)			Capital		Loss			Total
	(in thousands)
Balance at January 1, 2017	37,500	$	375	$	81,739		$	(56,323	)	$	400,206	$	(3,216	)	$	422,781
Net income of Sturgeon prior to acquisition	—	—		640			—			—		—			640
Stingray acquisition	1,393	14		—			—			25,748		—			25,762
Sturgeon acquisition	5,607	56		(82,379		)	—			78,313		—			(4,010		)
Stock based compensation	89	1		—			—			3,743		—			3,744
Net income	—	—		—			58,324			—		—			58,324
Other comprehensive income	—	—		—			—			—		555			555
Balance at December 31, 2017	44,589	$	446	$	—		$	2,001		$	508,010	$	(2,661	)	$	507,796
Equity based compensation (Note 15)	—	—		—			—			17,487		—			17,487
Stock based compensation	167	2		—			—			4,328		—			4,330
Net income	—	—		—			167,758			—		—			167,758
Cash dividends declared	—	—		—			(5,594		)	—		—			(5,594		)
Other comprehensive loss	—	—		—			—			—		(459		)	(459		)
Balance at September 30, 2018	44,756	$	448	$	—		$	164,165		$	529,825	$	(3,120	)	$	691,318

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

MAMMOTH ENERGY SERVICES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)



	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$	167,758		$	(6,952	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Equity based compensation (Note 15)	17,487			—
Stock based compensation	4,331			2,648
Depreciation, depletion, accretion and amortization	89,718			64,354
Amortization of coil tubing strings	1,473			2,144
Amortization of debt origination costs	299			299
Bad debt expense	(14,543		)	117
(Gain) loss on disposal of property and equipment	(185		)	126
Gain on bargain purchase	—			(4,012		)
Impairment of long-lived assets	4,769			—
Deferred income taxes	6,418			(8,151		)
Changes in assets and liabilities, net of acquisitions of businesses:
Accounts receivable, net	(132,553		)	(37,440		)
Receivables from related parties	8,453			(12,081		)
Inventories	(2,665		)	(7,878		)
Prepaid expenses and other assets	1,814			2,644
Accounts payable	(5,179		)	30,445
Payables to related parties	24			8
Accrued expenses and other liabilities	(405		)	14,393
Income taxes payable	135,578			(28		)
Net cash provided by operating activities	282,592			40,636

Cash flows from investing activities:
Purchases of property and equipment	(144,898		)	(102,273		)
Purchases of property and equipment from related parties	(4,632		)	—
Business acquisitions	(14,456		)	(42,008		)
Proceeds from disposal of property and equipment	1,213			782
Business combination cash acquired (Note 4)	—			2,671
Net cash used in investing activities	(162,773		)	(140,828		)

Cash flows from financing activities:
Borrowings from lines of credit	77,000			118,850
Repayments of lines of credit	(176,900		)	(24,850		)
Repayments of equipment financing note	(219		)	—
Dividends paid	(5,594		)	—
Repayment of acquisition long-term debt (Note 4)	—			(8,851		)
Net cash (used in) provided by financing activities	(105,713		)	85,149
Effect of foreign exchange rate on cash	(51		)	82
Net change in cash and cash equivalents	14,055			(14,961		)
Cash and cash equivalents at beginning of period	5,637			29,239
Cash and cash equivalents at end of period	$	19,692		$	14,278

Supplemental disclosure of cash flow information:
Cash paid for interest	$	2,726		$	2,300
Cash paid for income taxes	$	32,269		$	840
Supplemental disclosure of non-cash transactions:
Purchases of property and equipment included in accounts payable and accrued expenses	$	21,124		$	13,648
Acquisition of Sturgeon, Stingray Cementing LLC and Stingray Energy Services LLC (Note 4)	$	—		$	23,091

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 company serving both the oil and gas and the electric utility industries in North America and US territories. Mammoth's subsidiaries provide a diversified set of drilling and completion services to the exploration and production industry including pressure pumping, coil tubing, natural sand and proppant services as well as trucking, drilling, cementing, water transfer among others. In addition, its infrastructure division provides transmission, distribution and logistics services to various public and private owned utilities throughout the US and Puerto Rico.

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

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.

On June 29, 2018, Gulfport and MEH Sub LLC ("MEH Sub"), an entity controlled by Wexford, (collectively, the "Selling Stockholders") completed an underwritten secondary public offering of 4,000,000 shares of the Company’s common stock at a purchase price to the Selling Stockholders of $38.01 per share. The Selling Stockholders granted the underwriters an option to purchase up to an aggregate of 600,000 additional shares of the Company's common stock at the same purchase price. This option was exercised, in part, and on July 30, 2018, the underwriters purchased an additional 385,000 shares of common stock from the Selling Stockholders at the same price per share. The Selling Stockholders received all proceeds from this offering.

At September 30, 2018 and December 31, 2017, Wexford, Gulfport and Rhino beneficially owned the following shares of outstanding common stock of Mammoth Inc.:



	At September 30, 2018			At December 31, 2017
	Share Count	% Ownership		Share Count	% Ownership
Wexford	21,986,251	49.1	%	25,009,319	56.1	%
Gulfport	9,824,671	22.0	%	11,171,887	25.1	%
Rhino	104,100	0.2	%	568,794	1.3	%
Outstanding shares owned by related parties	31,915,022	71.3	%	36,750,000	82.5	%
Total outstanding	44,755,678	100.0	%	44,589,306	100.0	%

Operations

The Company's infrastructure services include electric utility contracting services focused on the repair, upgrade, maintenance and construction of transmission and distribution networks. The Company’s infrastructure services also provide storm repair and restoration services in response to natural disasters including hurricanes, ice or other storm-related damage. The Company's pressure pumping services include equipment and personnel used in connection with the completion and early production of oil and natural gas wells. The Company's natural sand proppant services include the

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, aciziding, equipment rentals, crude oil hauling, water transfer and remote accommodations.

All of the Company’s operations are in North America and in the Caribbean. During the periods presented, the Company has operated 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 primarily 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 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 and the variable interest entity ("VIE") for which the Company is the primary beneficiary. All material intercompany accounts and transactions have been eliminated.

This report has been prepared in accordance with the rules and regulations of the Securities and Exchange Commission, and reflects all adjustments, which in the opinion of management are necessary for the fair presentation of the results for the interim periods, on a basis consistent with the annual audited consolidated financial statements. 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 or goods sold. 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 condition of customers changes, circumstances develop, or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event the Company was to determine that a customer may not be able to make required payments, the Company would increase the allowance through a charge to income in the period in which that determination is made.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

If it is determined that previously reserved amounts are collectible, the Company would decrease the allowance through a credit to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once a final determination is made regarding their uncollectability.

Following is a roll forward of the allowance for doubtful accounts for the year ended December 31, 2017 and the nine months ended September 30, 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	(14,541		)
Deductions for uncollectible receivables written off	(1,839		)
Balance, September 30, 2018	$	5,357

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 December 31, 2017 and through June 30, 2018, the Company reviewed receivables due from PREPA and made specific reserves consistent with Company policy which resulted in additions to the allowance for doubtful accounts totaling $16.0 million and $53.6 million, respectively, for the year ended December 31, 2017 and six months ended June 30, 2018. During the three months ended September 30, 2018, the Company received payment from PREPA for the amount reserved at December 31, 2017 of $16 million. As a result, the Company reversed the 2017 and 2018 additions to the allowance for doubtful accounts from PREPA. The Company expects to receive payment for the 2018 amounts once the Company files its 2018 Puerto Rico tax return and pays any taxes due as calculated by the return. The Company expects that the Puerto Rico 2018 tax return will be filed in mid-2019 and that the taxes due as a result of the 2018 Puerto Rico tax return will be paid in the first quarter of 2019.

Additionally, the Company has made specific reserves consistent with Company policy which resulted in additions to allowance for doubtful accounts totaling $1.4 million and $0.2 million, respectively, for the nine months ended September 30, 2018 and year ended December 31, 2017. The Company will continue to pursue collection until such time as final determination is made consistent with Company policy.

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 September 30, 2018 and December 31, 2017 and percentages of total revenues derived for the three and nine months ended September 30, 2018 and 2017:



	REVENUES								ACCOUNTS RECEIVABLE
	Three Months Ended September 30,				Nine Months Ended September 30,				At September 30,		At December 31,
	2018		2017		2018		2017		2018		2017
Customer A^(a)	57	%	—	%	63	%	—	%	62	%	56	%
Customer B^(b)	6	%	47	%	9	%	54	%	6	%	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, amounts receivable or payable to related parties, and long-term debt. The carrying amount of cash and cash equivalents, trade receivables, receivables from related parties and trade payables approximates fair value because of the short-term nature

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

of the instruments. The fair value of long-term debt approximates its carrying value because the cost of borrowing fluctuates based upon market conditions.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02 “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 2016-02 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 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 in the process of implementing a new lease accounting system in connection with the adoption of this ASU and are continuing to evaluate the impact this new guidance may have on the Company's consolidated financial statements and results of operations.

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


3.	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 Company's primary revenue streams include pressure pumping services, infrastructure services, natural sand proppant services, contract land and directional drilling services and other services, which includes coil tubing, pressure control, flowback, cementing, acidizing, equipment rentals, crude oil hauling, water transfer and remote accommodations services. See Note 19 for the Company's revenue disaggregated by type.

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-

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

term in nature and range from a few hours to multiple days. Generally, revenue is recognized over time upon the completion of each segment of work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and personnel.

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

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

Infrastructure Services

Infrastructure services are typically provided pursuant to master service agreements, repair and maintenance contracts or fixed price and non-fixed price installation contracts. Pricing under these contracts may be unit priced, cost-plus/hourly (or time and materials basis) or fixed price (or lump sum basis). The Company accounts for infrastructure services as a single performance obligation satisfied over time. Revenue is recognized over time as work progresses based on the days completed or as the contract is completed. Under certain customer contracts in our infrastructure services segment, the Company warranties equipment and labor performed for a specified period following substantial completion of the work.

Natural Sand Proppant Services

The Company sells natural sand proppant through sand supply agreements with its customers. Under these agreements, sand is typically sold at a flat rate per ton or a flat rate per ton with an 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. As of September 30, 2018, the Company deferred revenue totaling $0.4 million related to shortfall payments. This amount is included in accrued expenses and other current liabilities on the unaudited condensed consolidated balance sheet. If the Company does not expect the customer will make-up deficient volumes in future periods, the breakage model will be applied and revenue related to shortfall payments will be recognized when the model indicates the customer's inability to take delivery of excess volumes. During the three and nine months ended September 30, 2018, the Company recognized revenue totaling $1.2 million and $1.5 million, respectively, related to shortfall payments.

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

Contract Land and Directional Drilling Services

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Other Services

The Company also provides coil tubing, pressure control, flowback, cementing, acidizing, equipment rentals, crude oil hauling, water transfer 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.

Contract Balances

Following is a rollforward of the Company's contract liabilities (in thousands):



Balance, January 1, 2018	$	15,000
Deduction for recognition of revenue	(15,000		)
Increase for deferral of shortfall payments	362
Balance, September 30, 2018	$	362

The Company did not have any contract assets as of September 30, 2018 or January 1, 2018.

Performance Obligations

Revenue recognized in the current period from performance obligations satisfied in previous periods was a nominal amount for the three and nine months ended September 30, 2018. As of September 30, 2018, the Company had unsatisfied performance obligations totaling $141.7 million, which will be recognized over the next 3.3 years.


4.	Acquisitions

(a) Acquisition of WTL Oil

On May 31, 2018, the Company completed its acquisition of WTL Oil LLC ("WTL") for total consideration of $5.5 million in cash to the sellers plus $0.6 million in consideration to be paid upon completion of certain contractual obligations. The seller completed these obligations and the Company paid the additional $0.6 million to the seller during the three months ended September 30, 2018.

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

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



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


a.	Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Non-contractual customer relationships were valued using a "Multi-period excess earnings" method. Identifiable intangible assets will be amortized over 10-20 years.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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



	2018
Revenues	$	3,239
Net loss^(a)	(93		)

a. Includes depreciation and amortization expense of $0.5 million.

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



	Nine Months Ended September 30,
	2018			2017
Revenues	$	5,998		$	2,706
Net (loss) income	(8		)	42

The Company recognized $0.1 million of transaction related costs during the nine months ended September 30, 2018 related to this acquisition.

(b) Acquisition of RTS Energy Services

On June 15, 2018, the Company completed its acquisition of RTS Energy Services LLC ("RTS") for total consideration of $7.6 million in cash to the sellers plus $0.5 million to be paid 90 days after closing subject to contractual conditions. The seller completed these obligations and the Company paid the additional $0.5 million to the seller during the three months ended September 30, 2018.

The Company used cash on hand and borrowings under its credit facility to fund the acquisition. The acquisition of RTS expanded Mammoth's cementing services into the Permian Basin and added acidizing to the Company's service offerings.

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



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

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

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



	2018
Revenues	$	4,868
Net loss^(a)	(985		)

a. Includes depreciation expense of $0.5 million.

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



	Nine Months Ended September 30,
	2018			2017
Revenues	$	14,398		$	15,646
Net (loss) income	(1,841		)	1,303

The Company recognized $0.1 million of transaction related costs during the nine months ended September 30, 2018 related to this acquisition.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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.

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 ^(a)	300
Goodwill ^(b)	248
Total assets acquired	$	4,851

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


a.	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.

From the acquisition date through September 30, 2018, 5 Star provided the following activity (in thousands):



	2018		2017
Revenues^(a)	$	120,318	$	25,216
Net income^(b)	24,571		4,191

a.Includes intercompany revenues of $101.9 million and $16.0 million, respectively, for 2018 and 2017.

b.Includes depreciation and amortization expense of $2.1 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):



	Nine Months Ended September 30, 2017
Revenues	$	12,681
Net income	495

(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 September 30, 2018, $0.3 million and $0.3 million, respectively, of the contingent consideration are reflected in accrued expenses and other current liabilities and other liabilities on the unaudited condensed consolidated balance sheet. Mammoth funded the purchase price for Higher Power with cash on hand and borrowings under its credit facility. The acquisition of Higher Power added an energy infrastructure component to the Company's business, helping to diversify its service offerings.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 ^(a)	643
Total assets acquired	$	4,000

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



	2018		2017
Revenues^(a)	$	178,994	$	39,571
Net income^(b)	32,447		5,127

a.Includes intercompany revenues of $160.1 million and $27.4 million, respectively for 2018 and 2017.

b.Includes depreciation and amortization expense of $4.6 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):



	Nine Months Ended September 30, 2017
Revenues	$	11,619
Net loss	(236		)

(e) Acquisition of Sturgeon

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 was recast to combine the unaudited condensed consolidated statements of operations and the unaudited condensed consolidated balance sheets of the Company for all periods prior to the closing of this acquisition 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.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(f) Acquisition of Chieftain

On March 27, 2017, as amended as of May 24, 2017, the Company entered into a Purchase Agreement with Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, unrelated third party sellers (the "Chieftain Sellers"), following the Company's successful bid in a bankruptcy court auction for 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.

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



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

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


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


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


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


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

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



	2018		2017
Revenues^(a)	$	46,783	$	22,847
Net income^(b)	11,573		5,520

a.Includes intercompany revenues of $12.5 million and $12.3 million, respectively, for 2018 and 2017

b.Includes depreciation, depletion, amortization and accretion of $3.8 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):



	Nine Months Ended September 30, 2017
Revenues	$	4,230
Net loss	(2,458		)

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(g) Acquisition of Stingray

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

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

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



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

a. See Summary of acquired assets and liabilities below



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

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


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


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

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


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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

From the acquisition date through September 30, 2018, SR Energy and Cementing provided the following activity (in thousands):



	2018						2017
	SR Energy			Cementing			SR Energy			Cementing
Revenues^(a)	$	21,740		$	6,141		$	11,572		$	7,500
Net loss^(b,c)	(2,616		)	(5,827		)	(1,626		)	(1,963		)


a.	Includes intercompany revenues of $2.3 million and $0.6 million for SR Energy in 2018 and 2017.


b.	Includes depreciation and amortization expense of $4.0 million and $1.3 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.


c.	Includes non-cash impairment expense of $4.4 million for Cementing in 2018 related to the impairment of intangible assets and goodwill as a result of moving Cementing equipment from the Utica shale to the Permian basin.

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):



	Nine Months Ended September 30, 2017
Revenues	$	27,482
Net loss	(2,550		)

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.


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):



	September 30,		December 31,
	2018		2017
Supplies	$	9,602	$	9,437
Raw materials	141		219
Work in process	4,110		2,370
Finished goods	5,332		5,788
Total inventory	$	19,185	$	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):



		September 30,		December 31,
	Useful Life	2018		2017
Pressure pumping equipment	3-5 years	$	206,461	$	190,211
Drilling rigs and related equipment	3-15 years	138,369		132,260
Machinery and equipment^(a)	7-20 years	159,735		97,569
Buildings	15-39 years	48,269		45,992
Vehicles, trucks and trailers^(b)	5-10 years	120,883		54,055
Coil tubing equipment	4-10 years	28,068		28,053
Land	N/A	14,235		11,317
Land improvements	15 years or life of lease	9,614		9,614
Rail improvements	10-20 years	13,795		5,540
Other property and equipment	3-12 years	15,193		12,687
		754,622		587,298
Deposits on equipment and equipment in process of assembly		14,019		20,348
		768,641		607,646
Less: accumulated depreciation^(c)		333,856		256,629
Property, plant and equipment, net		$	434,785	$	351,017


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


b.	Included in vehicles, trucks and trailers are assets under capital leases totaling $0.3 million and $1.0 million, respectively, at September 30, 2018 and December 31, 2017.


c.	Accumulated depreciation for assets under capital leases totaled $0.5 million and $0.8 million, respectively, at September 30, 2018 and December 31, 2017.

Proceeds from customers for horizontal and directional drilling services equipment damaged or lost down-hole are reflected in revenue with the carrying value of the related equipment charged to cost of service revenues and are reported as cash inflows from investing activities in the statement of cash flows. For the nine months ended September 30, 2018 and 2017, proceeds from the sale of equipment damaged or lost down-hole were $0.9 million and $0.3 million, respectively, and gains on sales of equipment damaged or lost down-hole were $0.8 million and $0.2 million, respectively.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Depreciation expense^(a)	$	28,052	$	24,105	$	79,508	$	56,301
Depletion expense	1,552		682		2,979		1,066
Amortization expense	2,396		2,412		7,186		6,948
Accretion expense	15		25		45		39
Depreciation, depletion, amortization and accretion	$	32,015	$	27,224	$	89,718	$	64,354


a.	Includes depreciation expense for assets under capital leases totaling $0.3 million and $0.3 million, respectively, for the nine months ended September 30, 2018 and 2017.

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

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


7.	Intangible Assets and Goodwill

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



	September 30,			December 31,
	2018			2017
Customer relationships	$	35,585		$	35,795
Trade names	8,943			8,793
Less: accumulated amortization - customer relationships	(32,564		)	(26,172		)
Less: accumulated amortization - trade names	(2,809		)	(2,277		)
Intangible assets, net	$	9,155		$	16,139

Amortization expense for intangible assets was $7.2 million and $6.9 million, respectively, for the nine months ended September 30, 2018 and 2017. The original life of customer relationships ranges from 4 to 10 years with a remaining average useful life of 4.2 years. The original life of trade names ranges from 10 to 20 years with a remaining average useful life of 8.9 years.

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



	Amount
Remainder of 2018	$	1,519
2019	1,129
2020	1,129
2021	1,123
2022	1,102
Thereafter	3,153
	$	9,155

Goodwill was $98.3 million and $99.8 million, respectively, at September 30, 2018 and December 31, 2017. Changes in the goodwill for the year ended December 31, 2017 and the nine months ended September 30, 2018 are set forth below (in thousands):



Balance, January 1, 2017	$	88,727
Additions - 2017 Stingray Acquisition (Note 4)	10,193
Additions - Higher Power Acquisition (Note 4)	643
Additions - 5 Star Acquisition (Note 4)	248
Balance, December 31, 2017	99,811
Additions - WTL Acquisition (Note 4)	1,567
Additions - RTS Acquisition (Note 4)	133
Impairment	(3,203		)
Balance, September 30, 2018	$	98,308

During the three months ended September 30, 2018, the Company moved Cementing's equipment from the Utica shale to the Permian basin. As a result, during the three months ended September 30, 2018, the Company recognized impairment on Cementing's intangible assets, including goodwill, non-contractual customer relationships and trade name of $3.2 million, $1.0 million and $0.2 million, respectively.

Cementing's goodwill was measured using an income approach, which provides an estimated fair value based on anticipated cash flows that are discounted using a weighted average cost of capital rate.

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):



	September 30,		December 31,
	2018		2017
Accrued compensation, benefits and related taxes	$	22,561	$	11,552
State and local taxes payable	9,258		2,126
Insurance reserves	4,280		2,942
Deferred revenue	420		15,210
Financed insurance premiums	925		4,876
Other	5,161		4,189
Total	$	42,605	$	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 September 30, 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, 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.

At September 30, 2018, there were no outstanding borrowings under the credit facility and $162.5 million of available borrowing capacity, after giving effect to $6.7 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 September 30, 2018 and December 31, 2017, the Company was in compliance with the financial covenants under the facility.

On October 19, 2018, the Company and certain of its direct and indirect subsidiaries, as borrowers, entered into an amended and restated revolving credit and security agreement with the lenders party thereto and PNC Bank, National Association, as a lender and as administrative agent for the lenders (the “A&R Credit Agreement”), which amends and restates the revolving credit and security agreement dated as of July 9, 2018, as amended prior to the A&R Credit Agreement, to, among other things, (i) extend the maturity date to October 19, 2023, (ii) increase the maximum revolving advance amount to $185 million, with the ability to further increase the maximum revolving advance amount to $350 million under certain circumstances, (iii) increase the letter of credit sublimit to 20% of the maximum revolving advance amount and (iv) decrease the interest rates applicable to loans.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Outstanding borrowings under the A&R Credit Agreement bear interest at a per annum rate elected by the Company that is equal to an alternate base rate or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.0% to 1.5% per annum in the case of the alternate base rate, and from 2.0% to 2.5% per annum in the case of LIBOR. The applicable margin depends on the amount of excess availability under the A&R Credit Agreement. The A&R Credit Agreement contains various customary affirmative and restrictive covenants including a minimum interest coverage ratio (3.0 to 1.0) and a maximum leverage ratio (4.0 to 1.0). As of October 30, 2018, the credit facility was undrawn.

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.


10.	Other Liabilities

Other liabilities included the following (in thousands):



	September 30,			December 31,
	2018			2017
Capital lease obligations	$	1,638		$	2,015
Equipment financing arrangement	1,362			1,605
Other	250			500
Total	3,250			4,120
Less: Current portion of capital lease and equipment financing obligations included in accrued expenses and other current liabilities	(1,547		)	(831		)
Total Other Liabilities	$	1,703		$	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 September 30, 2018 and December 31, 2017 was 19.6% 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 September 30, 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 September 30, 2018 are as follows (in thousands):



2018	$	228
2019	1,540
2020	689
2021	388
2022	360
Total future minimum payments	3,205
Less interest payments	(205		)
Present value of future minimum payments	$	3,000

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


11.	Variable Interest Entity

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

Dire Wolf's voting rights are not proportional to its obligation to absorb expected returns or losses of Cobra Aviation and all of Cobra Aviation's activities are conducted on behalf of Dire Wolf, which has disproportionately fewer voting rights; therefore, Cobra Aviation meets the criteria of a VIE. Cobra Aviation's operational activities are directed by Dire Wolf's officers and Dire Wolf has the option to terminate the Voting Trust Agreement at any time. Therefore, the Company, through Dire Wolf, is considered the primary beneficiary of the VIE and consolidates Cobra Aviation at September 30, 2018.


12.	Selling, General and Administrative Expense

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
Cash expenses:
Compensation and benefits	$	14,864		$	3,577	$	33,541		$	8,958
Professional services	3,267			1,494		8,835			5,075
Other^(a)	3,701			1,820		9,243			5,700
Total cash SG&A expense	21,832			6,891		51,619			19,733
Non-cash expenses:
Bad debt provision^(b)	(68,333		)	103		(14,543		)	78
Equity based compensation^(c)	—			—		17,487			—
Stock based compensation	1,177			1,028		3,751			2,648
Total non-cash SG&A expense	(67,156		)	1,131		6,695			2,726
Total SG&A expense	$	(45,324	)	$	8,022	$	58,314		$	22,459


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

During the three months ended September 30, 2018, the Company received payment for amounts previously reserved in 2017. As a result, during the three months ended September 30, 2018, the Company reversed bad debt expense of $16.0 million recognized in 2017 and $53.6 million recognized in the first half of 2018. The Company expects to receive payment for the 2018 amounts once the Company files its 2018 Puerto Rico tax return and pays any taxes due as calculated by the return. The Company expects that the Puerto Rico 2018 tax return will be filed in mid-2019.


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


13.	Income Taxes

The components of income tax expense (benefit) attributable to the Company for the three and nine months ended September 30, 2018 and 2017, are as follows (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Foreign current income tax expense (benefit)	$	42,026		$	(101	)	$	167,738		$	506
Foreign deferred income tax expense (benefit)	35,321			18			9,935			(2		)
U.S. current income tax (benefit) expense	(1,515		)	—			109			—
U.S. deferred income tax benefit	(997		)	(1,330		)	(3,517		)	(7,827		)
Total	$	74,835		$	(1,413	)	$	174,265		$	(7,323	)

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company's effective tax rate was 51% and 37%, respectively, for the nine months ended September 30, 2018 and 2017. The increase in the effective tax rate is primarily due to the equity based compensation expense recognized during the nine months ended September 30, 2018 as well as a higher tax rate in Puerto Rico, where most of our income was generated during the nine months ended September 30, 2018, compared to the United States tax rate. No income was generated in Puerto Rico during the nine months ended September 30, 2017. Additionally, the Company's effective tax rate can fluctuate as a result of, among other things, discrete items, state income taxes, permanent differences and changes in pre-tax income.

A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized. To assess that likelihood, the Company uses estimates and judgments regarding future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. During the nine months ended September 30, 2018, the Company recorded a change in valuation allowance of $29.7 million related to foreign tax credits that are not expected to be utilized.

The Company evaluates tax positions taken or expected to be taken in preparation of its tax returns and disallows the recognition of tax positions that do not meet a “more likely than not” threshold of being sustained upon examination by the taxing authorities. During the three months ended September 30, 2018, the Company established a reserve for uncertain tax positions totaling $0.4 million related to the filing of certain state income tax returns on a non-unitary basis.

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 nine months ended September 30, 2018. The Company expects to complete its detailed analysis of the effects of the Tax Act no later than the fourth quarter of 2018.


14.	Earnings (Loss) Per Share

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



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018		2017			2018		2017
Basic earnings (loss) per share:
Allocation of earnings (loss):
Net income (loss)	$	69,512	$	(801	)	$	167,758	$	(6,952	)
Weighted average common shares outstanding	44,756		44,502			44,718		40,526
Basic earnings (loss) per share	$	1.55	$	(0.02	)	$	3.75	$	(0.17	)

Diluted earnings (loss) per share:
Allocation of earnings (loss):
Net income (loss)	$	69,512	$	(801	)	$	167,758	$	(6,952	)
Weighted average common shares, including dilutive effect^(a)	45,082		44,502			45,012		40,526
Diluted earnings (loss) per share	$	1.54	$	(0.02	)	$	3.73	$	(0.17	)


^a.	No incremental shares of potentially dilutive restricted stock awards were included for the three and nine months ended September 30, 2017 as their effect was antidulitive under the treasury stock method.


15.	Equity Based Compensation

Upon formation of certain operating entities by Wexford, Gulfport and Rhino, specified members of management (the “Specified Members”) and certain non-employee members (the “Non-Employee Members”) were granted the right to receive distributions from the operating entities after the contribution member’s unreturned capital balance was recovered (referred to as “Payout” provision).

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

On November 24, 2014, the awards were modified in conjunction with the contribution of the operating entities to Mammoth. These awards were not granted in limited or general partner units. The awards are for interests in the distributable earnings of the members of MEH Sub, Mammoth’s majority equity holder.

On the IPO closing date, the unreturned capital balance of Mammoth's majority equity holder was not fully recovered from its sale of common stock in the IPO. As a result, Payout did not occur and no compensation cost was recorded.

On June 29, 2018, as part of an underwritten secondary public offering, MEH Sub sold 2,764,400 shares of the Company’s common stock at a purchase price to MEH Sub of $38.01 per share. Additionally, the selling stockholders granted the underwriters an option to purchase additional shares of the Company's common stock at the same purchase price. On July 30, 2018, in connection with the partial exercise of this option, MEH Sub sold an additional 266,026 shares of common stock to the underwriters. MEH Sub received the proceeds from this offering. As a result of the June 29, 2018 offering, a portion of the Non-Employee Member awards reached Payout. During the nine months ended September 30, 2018, the Company recognized equity compensation expense totaling $17.5 million related to these non-employee awards. These awards are at the sponsor level and this transaction had no dilutive impact or cash impact to the Company.

Payout for the remaining awards is expected to occur as the contribution member's unreturned capital balance is recovered from additional sales by MEH Sub of its shares of the Company's common stock or from dividend distributions, which is not considered probable until the event occurs. 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-Employee Member awards, the unrecognized amount, which represents the fair value of the awards as of September 30, 2018 was $36.0 million.


16.	Stock Based Compensation

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

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	103,556		27.74
Vested	(149,098	)	21.29
Forfeited	(20,000	)	20.68
Unvested shares as of September 30, 2018	575,090		$	21.56

As of September 30, 2018, there was $7.7 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 1.7 years.

Included in cost of revenue and selling, general and administrative expenses is stock based compensation expense of $1.4 million and $1.0 million, respectively, for the three months ended September 30, 2018 and 2017 and $4.3 million and $2.6 million, respectively, for the nine months ended September 30, 2018 and 2017.


17.	Related Party Transactions

Transactions between the subsidiaries of the Company and the following companies are included in Related Party

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 September 30,				Nine Months Ended September 30,				At September 30,		At December 31,
		2018		2017		2018		2017		2018		2017
Pressure Pumping and Gulfport	(a)	$	15,540	$	46,702	$	87,916	$	119,547	$	21,800	$	25,054
Muskie and Gulfport	(b)	3,787		14,055		24,980		39,201		1,050		1,947
Panther Drilling and Gulfport	(c)	—		944		55		2,938		12		872
Cementing and Gulfport	(d)	977		3,179		5,853		4,082		—		2,255
SR Energy and Gulfport	(e)	1,743		5,768		13,323		7,333		2,185		3,348
Panther Drilling and El Toro	(f)	509		96		854		96		244		—
Redback Energy and El Toro	(g)	—		26		92		184		—		—
Coil Tubing and El Toro	(h)	154		133		514		133		—		—
Bison Drilling and Predator	(i)	—		—		—		—		—		234
Other Relationships		10		13		24		112		44		78
		$	22,720	$	70,916	$	133,611	$	173,626	$	25,335	$	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.


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.	Panther 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.



		Three Months Ended September 30,				Nine Months Ended September 30,				At September 30,		At December 31,
		2018		2017		2018		2017		2018		2017
		COST OF REVENUE				COST OF REVENUE				ACCOUNTS PAYABLE
Cobra and T&E	(a)	$	1,281	$	—	$	4,042	$	—	$	850	$	457
Higher Power and T&E	(a)	144		—		1,603		—		422		3
The Company and 2017 Stingray Companies	(b)	—		—		—		444		—		—
Other		—		9		—		257		—		295
		$	1,425	$	9	$	5,645	$	701	$	1,272	$	755

		SELLING, GENERAL AND ADMINISTRATIVE COSTS				SELLING, GENERAL AND ADMINISTRATIVE COSTS
The Company and Everest	(c)	$	16	$	32	$	102	$	140	$	31	$	19
The Company and Wexford	(d)	267		185		740		583		73		150
The Company and Caliber	(e)	116		137		462		209		—		1
Other		38		1		94		54		—		2
		$	437	$	355	$	1,398	$	986	$	104	$	172

		CAPITAL EXPENDITURES				CAPITAL EXPENDITURES
Cobra and T&E	(a)	$	116	$	—	$	1,247	$	—	$	—	$	66
Higher Power and T&E	(a)	187		—		2,960		—		26		385
		$	303	$	—	$	4,207	$	—	$	26	$	451
										$	1,402	$	1,378

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


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.	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.


c.	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.


d.	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.


e.	Caliber leases office space to Mammoth.

On June 29, 2018, Gulfport and certain entities controlled by Wexford (the "Selling Stockholders") completed an underwritten secondary public offering of 4,000,000 shares of the Company’s common stock at a purchase price to the Selling Stockholders of $38.01 per share. The Selling Stockholders granted the underwriters an option to purchase up to an aggregate of 600,000 additional shares of the Company's common stock at the same purchase price. This option was exercised, in part, and on July 30, 2018, the underwriters purchased an additional 385,000 shares of common stock from the Selling Stockholders at the same price per share. The Selling Stockholders received all proceeds from this offering. The Company incurred costs of approximately $1.0 million related to the secondary public offering during the nine months ended September 30, 2018.


18.	Commitments and Contingencies

Lease Obligations

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

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



Year ended December 31:	Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments^(a)
Remainder of 2018	$	6,871	$	23,018	$	12,479
2019	19,726		—		29,273
2020	16,402		—		19,391
2021	12,634		—		265
2022	9,299		—		—
Thereafter	7,290		—		—
	$	72,222	$	23,018	$	61,408

a. Included in these amounts are sand purchase commitments of $51.9 million. Pricing for certain sand purchase agreements is variable and, therefore, the total sand purchase commitments could be as much as $58.5 million. The minimum amount due in the form of shortfall fees under certain sand purchase agreements was $3.8 million as of September 30, 2018.

For the nine months ended September 30, 2018 and 2017, the Company recognized rent expense of $16.0 million and $7.4 million, respectively.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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):



	September 30,		December 31,
	2018		2017
Environmental remediation	$	3,877	$	3,582
Insurance programs	2,405		2,486
Rail car commitments	455		455
Total letters of credit	$	6,737	$	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 September 30, 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 September 30, 2018 and December 31, 2017, the policies contained an aggregate stop loss of $2.0 million. As of September 30, 2018 and December 31, 2017, accrued claims were $4.3 million and $2.9 million, respectively.

The Company also self-insures its employee health insurance. The Company has coverage on its self-insurance program in the form of a stop loss of $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 September 30, 2018 and December 31, 2017, accrued claims were $3.1 million and $2.1 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 September 30, 2018 and December 31, 2017 and no expense was recognized during the nine months ended September 30, 2018 or 2017 related to warranty claims. However, if warranty claims occur, the Company could be required to repair or replace warrantied items, which in most cases are covered by warranties extended from the manufacturer of the equipment. In the event the manufacturer of equipment failed to perform on a warranty obligation or denied a warranty claim made by the Company, the Company could be required to pay for the cost of the repair or replacement.

In the ordinary course of business, the Company is required to provide bid bonds to certain customers in the infrastructure services segment as part of the bidding process. These bonds provide a guarantee to the customer that the Company, if awarded the project, will perform under the terms of the contract. Bid bonds are typically provided for a percentage of the total contract value. Additionally, the Company may be required to provide performance and payment bonds for contractual commitments related to projects in process. These bonds provide a guarantee to the customer that the Company will perform under the terms of a contract and that the Company will pay subcontractors and vendors. If the Company fails to perform under a contract or to pay subcontractors and vendors, the customer may demand that the surety make payments or provide services under the bond. The Company must reimburse the surety for expenses or outlays it incurs. As of September 30, 2018, outstanding bid bonds and performance and payment bonds totaled $20.0 million and $7.1 million, respectively. The estimated the cost to complete projects secured by the performance and payment bonds totaled $3.6 million as of September 30, 2018. As of December 31, 2017, the Company did not have any outstanding bid bonds or performance and payment bonds.

The Company is routinely involved in state and local tax audits. During 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.

On January 26, 2017, a collective action lawsuit alleging that Stingray Pressure Pumping LLC ("Pressure Pumping") failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Ryan Crosby vs. Stingray Pressure Pumping LLC, in the United Stated District Court for the Southern District of Ohio Eastern Division. The parties

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

reached a settlement of this matter in August 2018. The settlement was paid and did not 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 parties reached a settlement of this matter in September 2018. This matter was covered by insurance and did not have a material impact on the Company’s financial position, results of operations or cash flows.

On June 27, 2018, the Company's registered agent notified the Company that it had been served with a putative class action lawsuit titled Wendco of Puerto Rico Inc.; Multisystem Restaurant Inc.; Restaurant Operators Inc.; Apple Caribe, Inc.; on their own behalf and in representation of all businesses that conduct business in the Commonwealth of Puerto Rico vs. Mammoth Energy Services Inc.; Cobra Acquisitions, LLC; D. Grimm Puerto Rico, LLC; Aseguradoras A, B & C; John Doe; Richard Doe, in the Commonwealth of Puerto Rico Superior Court of San Juan. The plaintiffs allege negligent acts by the defendants caused an electrical failure in Puerto Rico resulting in damages of at least $300 million. The Company believes this claim is without merit and will vigorously defend the action. However, the Company continues to evaluate the background facts and at this time is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company's 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 and nine months ended September 30, 2018, the Company paid $1.1 million and $4.5 million, respectively, in contributions to the plan. The Company did not make contributions to the plan during the three and nine months ended September 30, 2017.


19.	Reporting Segments

As of September 30, 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 September 30, 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 Columbia and Alberta, Canada. The contract land and directional drilling services segment provides vertical, horizontal and directional drilling services primarily in the Permian Basin in West Texas.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company also provides coil tubing services, pressure control services, flowback services, cementing services, equipment rental services, crude oil hauling services, water transfer 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 September 30, 2018	Pressure Pumping		Infrastructure			Sand		Drilling			All Other			Eliminations			Total
Revenue from external customers	$	91,595	$	237,052		$	18,742	$	15,800		$	20,854		$	—		$	384,043
Intersegment revenues	815		—			18,268		139			671			(19,893		)	—
Total revenue	92,410		237,052			37,010		15,939			21,525			(19,893		)	384,043
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	54,023		128,267			29,470		14,104			21,701			—			247,565
Intersegment cost of revenues	18,897		37			546		158			245			(19,883		)	—
Total cost of revenue	72,920		128,304			30,016		14,262			21,946			(19,883		)	247,565
Selling, general and administrative	4,335		(54,200		)	1,618		1,362			1,561			—			(45,324		)
Depreciation, depletion, amortization and accretion	12,665		6,591			4,184		4,327			4,248			—			32,015
Impairment of long-lived assets	143		—			—		—			4,439			—			4,582
Operating income (loss)	2,347		156,357			1,192		(4,012		)	(10,669		)	(10		)	145,205
Interest expense, net	150		159			37		53			59			—			458
Other expense	2		181			199		(5		)	23			—			400
Income (loss) before income taxes	$	2,195	$	156,017		$	956	$	(4,060	)	$	(10,751	)	$	(10	)	$	144,347



Three months ended September 30, 2017	Pressure Pumping		Infrastructure		Sand		Drilling			All Other			Eliminations			Total
Revenue from external customers	$	75,705	$	13,486	$	29,332	$	13,644		$	17,138		$	—		$	149,305
Intersegment revenues	950		—		3,401		—			287			(4,638		)	—
Total revenue	76,655		13,486		32,733		13,644			17,425			(4,638		)	149,305
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	52,961		10,117		25,178		11,598			14,679			—			114,533
Intersegment cost of revenues	3,688		—		905		45			—			(4,638		)	—
Total cost of revenue	56,649		10,117		26,083		11,643			14,679			(4,638		)	114,533
Selling, general and administrative	2,511		886		1,841		1,374			1,410			—			8,022
Depreciation, depletion, amortization and accretion	13,039		1,039		3,034		5,036			5,076			—			27,224
Operating income (loss)	4,456		1,444		1,775		(4,409		)	(3,740		)	—			(474		)
Interest expense, net	592		68		87		570			103			—			1,420
Other expense	120		10		98		39			53			—			320
Income (loss) before income taxes	$	3,744	$	1,366	$	1,590	$	(5,018	)	$	(3,896	)	$	—		$	(2,214	)

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



Nine months ended September 30, 2018	Pressure Pumping			Infrastructure		Sand		Drilling			All Other			Eliminations			Total
Revenue from external customers	$	288,507		$	922,761	$	92,684	$	48,154		$	59,780		$	—		$	1,411,886
Intersegment revenues	6,447			—		48,186		225			4,807			(59,665		)	—
Total revenue	294,954			922,761		140,870		48,379			64,587			(59,665		)	1,411,886
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	182,228			532,532		97,917		43,859			56,958			—			913,494
Intersegment cost of revenues	50,473			2,582		5,851		280			479			(59,665		)	—
Total cost of revenue	232,701			535,114		103,768		44,139			57,437			(59,665		)	913,494
Selling, general and administrative	27,820			17,437		5,049		4,206			3,802			—			58,314
Depreciation, depletion, amortization and accretion	40,480			13,092		10,381		14,031			11,734			—			89,718
Impairment of long-lived assets	143			—		—		187			4,439			—			4,769
Operating income (loss)	(6,190		)	357,118		21,672		(14,184		)	(12,825		)	—			345,591
Interest expense, net	995			341		193		713			412			—			2,654
Other expense	94			513		222		67			18			—			914
Income (loss) before income taxes	$	(7,279	)	$	356,264	$	21,257	$	(14,964	)	$	(13,255	)	$	—		$	342,023



Nine months ended September 30, 2017	Pressure Pumping		Infrastructure		Sand			Drilling			All Other			Eliminations			Total
Revenue from external customers	$	166,082	$	15,195	$	68,244		$	36,867		$	36,145		$	—		$	322,533
Intersegment revenues	1,409		—		4,848			—			372			(6,629		)	—
Total revenue	167,491		15,195		73,092			36,867			36,517			(6,629		)	322,533
Cost of revenue, exclusive of depreciation, depletion, amortization and accretion	117,494		11,829		57,760			34,584			28,704			—			250,371
Intersegment cost of revenues	5,220		—		1,359			45			5			(6,629		)	—
Total cost of revenue	122,714		11,829		59,119			34,629			28,709			(6,629		)	250,371
Selling, general and administrative	6,691		1,241		6,315			4,102			4,110			—			22,459
Depreciation, depletion, amortization and accretion	31,823		1,379		6,603			14,978			9,571			—			64,354
Operating income (loss)	6,263		746		1,055			(16,842		)	(5,873		)	—			(14,651		)
Interest expense, net	1,023		72		573			1,227			34			—			2,929
Bargain purchase gain	—		—		(4,012		)	—			—			—			(4,012		)
Other expense	127		10		252			263			55			—			707
Income (loss) before income taxes	$	5,113	$	664	$	4,242		$	(18,332	)	$	(5,962	)	$	—		$	(14,275	)



	Pressure Pumping		Infrastructure		Sand		Drilling		All Other		Eliminations			Total
As of September 30, 2018:
Total assets^(a)	$	291,492	$	379,934	$	186,437	$	88,507	$	139,032	$	(244	)	$	1,085,158
Goodwill	$	86,043	$	891	$	2,684	$	—	$	8,690	$	—		$	98,308
As of December 31, 2017:
Total assets^(a)	$	297,140	$	205,275	$	190,859	$	88,527	$	243,767	$	(158,325	)	$	867,243
Goodwill	$	86,043	$	891	$	2,684	$	—	$	10,193	$	—		$	99,811


a.	Total assets included in the All Other column include Mammoth LLC corporate assets totaling $25.0 million and $148.8 million, respectively, as of September 30, 2018 and December 31, 2017, of which ($6.2) million and $137.4 million are inter-segment accounts receivable which are eliminated in consolidation.


20.	Subsequent Events

On October 29, 2018, the Company's board of Directors declared a quarterly cash dividend of $0.125 per share of common stock to be paid on November 15, 2018 to stockholders of record as of the close of business on November 8, 2018. Based on the number of shares outstanding at October 30, 2018, the total dividend payable to stockholders on November 15, 2018 will be approximately $5.6 million.

MAMMOTH ENERGY SERVICES, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to September 30, 2018, subsidiaries in the Company's infrastructure segment issued payment and performance bonds and bid bonds totaling $4.1 million and $3.5 million, respectively.

Subsequent to September 30, 2018, a subsidiary in the Company's infrastructure segment entered into an air charter agreement with aggregate commitments of $1.6 million and the Company's pressure pumping subsidiary purchased additional equipment totaling $1.4 million.

Subsequent to September 30, 2018, the Company ordered additional capital equipment with aggregate commitments of $8.1 million.

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

The following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and related notes thereto presented in this Quarterly Report and the consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K. 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 company serving both the oil and gas and the electric utility industries in North America and US territories. Our primary business objective is to grow our operations and create value for stockholders through organic opportunities and accretive acquisitions. Our suite of services includes pressure pumping services, infrastructure services, natural sand proppant services, contract land and directional drilling services and other energy services, including coil tubing, flowback, cementing, acidizing, equipment rental, crude oil hauling, water transfer and remote accommodations. Our pressure pumping services division provides hydraulic fracturing services. Our 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, acidizing services, equipment rentals, crude oil hauling services, water transfer 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. We are exploring several opportunities to expand our business lines including, but not limited to, full service transportation, telecommunications, impacts due to the pending rule changes implemented by the international maritime organization, or IMO, in 2020 and general industrial manufacturing as we shift to a broader industrial focus.

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 prior to and including the date of this acquisition 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.

Third Quarter 2018 Highlights and Recent Developments

Extended Pressure Pumping Services and Sand Supply Agreements with Gulfport

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

The pressure pumping amendment also provided for the initial suspension of pressure pumping services to Gulfport for a period July 1, 2018 through September 30, 2018, during which period Pressure Pumping could use the dedicated frac spreads for other customers. If during the initial suspension period Pressure Pumping’s use of the dedicated frac spreads for other customers does not reach a certain level, then Gulfport agreed to pay costs to Pressure Pumping and Pressure Pumping

agreed to perform services for Gulfport with respect to such amounts. In addition, if during such initial suspension period Pressure Pumping was unable to utilize the dedicated frac spreads for other customers, Gulfport agreed to pay recoupment costs to Pressure Pumping during the period of October 1, 2018 to December 31, 2018. No amounts were deferred to the period between October 1, 2018 and December 31, 2018.

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

Amended and Restated Credit Facility

On October 19, 2018, Mammoth entered into an amended and restated five-year asset backed revolving credit facility led by PNC Capital Markets with a maximum revolving advance amount at closing of $185 million and the potential to increase the facility by up to an additional $165 million. For additional information related to this amended and restated agreement, see "—Liquidity and Capital Resources—Our Revolving Credit Facility" below.

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 third quarter of 2018, where oil prices averaged $69.60.

We anticipate demand for our oil and natural gas services and products will continue to be dependent on the level of expenditures by companies in the oil and natural gas industry and, ultimately, commodity prices. If commodity prices stabilize at current levels or continue to increase, we expect the capital expenditures of our customers to increase, which in turn should increase 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 capital expenditures of our customers and impact the demand for our drilling, completion and other products and services.

We expect the temporary challenges related to customer budget limitations to persist through the end of the year. Based on current feedback from customers, we expect exploration and production companies to take extended breaks in the fourth quarter of 2018 as a result of budget exhaustion. We anticipate that these extended breaks will reduce activity levels and pricing for our services in the fourth quarter of 2018. We will continue to adjust our cost structure to market conditions, but we do not believe it is necessary to significantly reduce costs or infrastructure for a temporary slowdown in activity levels and we are actively maintaining our equipment during this temporary slowdown in activity levels. In 2019, we expect a rebound in activity from second half of 2018 levels as customer budgets are refreshed.

Energy Infrastructure Industry

In 2017, we expanded into the electric infrastructure business, offering both commercial and storm restoration services to government-funded utilities, private utilities, public investor owned utilities and cooperatives. Since we commenced operations in this line of business, substantially all of our infrastructure revenues has been generated from storm restoration work, primarily from PREPA due to damage caused by Hurricane Maria. On October 19, 2017, Cobra and PREPA entered into an emergency master services agreement for repairs to PREPA’s electrical grid. The one-year contract, as amended, provides for payments of up to $945.4 million. On May 26, 2018, Cobra and PREPA entered into a new one-year, $900.0 million master

services agreement to provide additional repair services and begin the initial phase of reconstruction of the electrical power system in Puerto Rico. PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA's ability to meet its payment obligations under the contract will be largely dependent upon funding from the Federal Emergency Management Agency or other sources. In the event PREPA does not have or does not obtain the funds necessary to satisfy its obligations to Cobra under the contracts, terminates the contracts, curtails our services prior to the end of the contract terms or otherwise fails to pay amounts owed to us for services performed, our financial condition, results of operations and cash flows would be materially and adversely affected. In addition, government contracts are subject to various uncertainties, restrictions and regulations, including oversight audits 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 increased since we expanded into the infrastructure business. Our infrastructure teams are working for multiple utilities primarily 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. In Puerto Rico, the reconstruction process is just beginning with significant front-end engineering required prior to the reconstruction of the electric grid. Staffing levels in Puerto Rico have fluctuated between 500 and 600 people over the past 60 days and we anticipate a ramp up in reconstruction projects throughout 2019.

Natural Sand Proppant Industry

In the natural sand proppant industry, demand growth for frac sand and other proppants is primarily driven by advancements in oil and natural gas drilling and well completion technology and techniques, such as horizontal drilling and hydraulic fracturing, as well as overall industry activity growth. Demand for proppant declined in 2015 and throughout most of 2016 with reduced well completion activity; however, we believe that demand for proppant will continue to grow over the long-term, as it did throughout 2017 and the first half of 2018. Over the past 18 months, several new and existing suppliers announced planned capacity additions of frac sand supply, particularly in the Permian Basin. We expect frac sand supply to exceed growth in demand over the coming months and quarters. 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. 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 half of 2018, constraints in the rail system adversely impacted frac sand deliveries from our Taylor sand facility in Jackson County, Wisconsin. As a result, we estimate production at our Taylor facility was 23% lower during the first half of 2018 than it would have been in the absence of these constraints. These rail system constraints were largely alleviated during the third quarter of 2018. Production at our Piranha facility was not impacted by these rail constraints, however, another railroad recently instituted a policy that shifts from utilizing unit trains (100 car dedicated trains specifically set up to move sand in large quantities) to manifest shipments (smaller number of sand cars coupled with other types of loads to make up a full train shipment). This shift to manifest shipments could impede the ability to move sand from our Piranha facility.

Results of Operations

Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017



	Three Months Ended
	September 30, 2018			September 30, 2017
	(in thousands)
Revenue:
Pressure pumping services	$	92,410		$	76,655
Infrastructure services	237,052			13,486
Natural sand proppant services	37,010			32,733
Contract land and directional drilling services	15,939			13,644
Other services	21,525			17,425
Eliminations	(19,893		)	(4,638		)
Total revenue	384,043			149,305

Cost of revenue:
Pressure pumping services (exclusive of depreciation and amortization of $12,657 and $13,009, respectively, for the three months ended September 30, 2018 and 2017)	72,920			56,649
Infrastructure services (exclusive of depreciation and amortization of $6,582 and $1,039, respectively, for the three months ended September 30, 2018 and 2017)	128,304			10,117
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $4,183 and $3,033, respectively, for the three months ended September 30, 2018 and 2017)	30,016			26,083
Contract land and directional drilling services (exclusive of depreciation of $4,325 and $5,032, respectively, for the three months ended September 30, 2018 and 2017)	14,262			11,643
Other services (exclusive of depreciation and amortization of $4,246 and $5,073, respectively, for the three months ended September 30, 2018 and 2017)	21,946			14,679
Eliminations	(19,883		)	(4,638		)
Total cost of revenue	247,565			114,533
Selling, general and administrative expenses	(45,324		)	8,022
Depreciation, depletion, amortization and accretion	32,015			27,224
Impairment of long-lived assets	4,582			—
Operating income (loss)	145,205			(474		)
Interest expense, net	(458		)	(1,420		)
Other expense, net	(400		)	(320		)
Income (loss) before income taxes	144,347			(2,214		)
Provision (benefit) for income taxes	74,835			(1,413		)
Net income (loss)	$	69,512		$	(801	)

Revenue. Revenue for the three months ended September 30, 2018 increased $235 million, or 157%, to $384 million from $149 million for the three months ended September 30, 2017. The increase in total revenue is primarily attributable to a $224 million increase in infrastructure services revenue during the three months ended September 30, 2018, representing 95% of the overall increase.

Revenue derived from related parties was $23 million, or 6% of our total revenues, for the three months ended September 30, 2018 and $71 million, or 47% of our total revenue, for the three months ended September 30, 2017. Substantially all of our related party revenue is derived from Gulfport under pressure pumping and sand contracts. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $15 million, or 21%, to $92 million for the three months ended September 30, 2018 from $77 million for the three months ended September 30, 2017. Revenue derived from related parties was $16 million, or 17% of total pressure pumping revenue, for the three months ended September 30, 2018 compared to $47 million, or 61% of total pressure pumping revenue, for the three months ended September 30, 2017. Substantially all of our related party revenue is derived from Gulfport. Inter-segment revenue, consisting primarily of revenue derived from our sand segment, totaled $1 million for each of the three months ended September 30, 2018 and 2017.

The increase in our pressure pumping services revenue was primarily driven by the startup of our fourth, fifth and sixth pressure pumping fleets in June, August and October 2017, respectively, in the SCOOP/STACK and Permian Basin, which contributed revenue of $34 million during the three months ended September 30, 2018 compared to $25 million during the three months ended September 30, 2017. The number of stages completed decreased slightly to 1,594 for the three months ended September 30, 2018 compared to 1,617 for the three months ended September 30, 2017 primarily due to a decline in utilization.

Infrastructure Services. Infrastructure services division revenue increased $224 million to $237 million for the three months ended September 30, 2018 from $13 million for the three months ended September 30, 2017. We generated $220 million, or 93% 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 contracts with PREPA and our infrastructure services, see "Industry Overview - Electrical Infrastructure Industry" above.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $4 million, or 13%, to $37 million for the three months ended September 30, 2018, from $33 million for the three months ended September 30, 2017. Revenue derived from related parties was $4 million, or 10% of total sand revenue, for the three months ended September 30, 2018 and $14 million, or 43% of total sand revenue, for the three months ended September 30, 2017. Inter-segment revenue, consisting primarily of revenue derived from our pressure pumping segment, totaled $18 million, or 49% of total sand revenue, for the three months ended September 30, 2018 and $3 million, or 10% of total sand revenue, for the three months ended September 30, 2017.

The increase in our natural sand proppant services revenue was primarily attributable to a 26% increase in tons of sand sold from approximately 474,933 tons for the three months ended September 30, 2017 to 598,438 tons for the three months ended September 30, 2018, which was partially offset by a 10% decline in price per ton.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $2 million, or 17%, from $14 million for the three months ended September 30, 2017 to $16 million for the three months ended September 30, 2018. Revenue derived from related parties, consisting of directional drilling revenue from Gulfport and El Toro Resources LLC, or El Toro, was $1 million, or 3% of total drilling revenue, for the three months ended September 30, 2018 and $1 million, or 8% of total drilling revenue, for the three months ended September 30, 2017.

The increase in contract land and directional drilling revenue was primarily attributable to our directional drilling services, which accounted for $2 million, or 105% of the total increase, as a result of increased utilization from 32% for the three months ended September 30, 2017 to 45% for the three months ended September 30, 2018. Our rig moving services accounted for $0.4 million, or 17%, of the operating division increase, primarily due to increased activity. These increases were partially offset by a $1 million decrease in our land drilling services revenue as a result of a decline in average active rigs from five for the three months ended September 30, 2017 to four for the three months ended September 30, 2018, partially offset by an increase in average day rates from approximately $14,800 for the three months ended September 30, 2017 to approximately $17,170 for the three months ended September 30, 2018.

Other Services. Other revenue, consisting of revenue derived from our coil tubing, pressure control, flowback, cementing, acidizing, equipment rental, crude oil hauling, water transfer and remote accommodation businesses, increased $5 million, or 24%, to $22 million for the three months ended September 30, 2018 from $17 million for the three months ended September 30, 2017. Revenue derived from related parties, consisting primarily of equipment rental and cementing revenue from Gulfport, was $3 million, or 13% of total other revenue, for the three months ended September 30, 2018 and $9 million, or 52% of total other revenue, for the three months ended September 30, 2017. Inter-segment revenue, consisting primarily of revenue derived from our infrastructure and

pressure pumping segments, totaled $1 million and $0.3 million, respectively, for the three months ended September 30, 2018 and 2017.

During the second quarter of 2018, we acquired RTS Energy Services LLC, or RTS, a cementing and acidizing business, and WTL Oil LLC, or WTL, a crude oil hauling business. These businesses contributed revenue of $7 million during the three months ended September 30, 2018. During the three months ended September 30, 2018, we started a water transfer business in the mid-continent region, which generated $2 million in revenue. Revenue from our coil tubing, oilfield rental and other services decreased $4 million during three months ended September 30, 2018 compared to three months ended September 30, 2017 primarily due to declines 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 $133 million from $115 million, or 77% of total revenue, for the three months ended September 30, 2017 to $248 million, or 64% of total revenue, for the three months ended September 30, 2018. The increase was primarily due to an expansion of our infrastructure services business, which represented a $118 million increase in cost of revenue, as well as an increase in pressure pumping division costs of $16 million, primarily related to the addition of three new fleets in 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 $16 million, or 29%, to $73 million for the three months ended September 30, 2018 from $57 million for the three months ended September 30, 2017. The increase was primarily due to the expansion of services into the SCOOP/STACK and the Permian Basin with the addition of three fleets in 2017. As a percentage of revenue, our pressure pumping services division cost of revenue, exclusive of depreciation and amortization expense of $13 million for each of the three months ended September 30, 2018 and 2017, respectively, was 79% and 74% for the three months ended September 30, 2018 and 2017, respectively. The increase in costs as a percentage of revenue was primarily due to an increase in cost of goods sold as a result of selling sand with our service package to customers in the mid-continent region.

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, was $128 million and $10 million, respectively, for the three months ended September 30, 2018 and 2017. The increase is due to the expansion of our infrastructure business in late 2017 and 2018. The largest components of our cost of revenue include labor-related costs, including contract labor, and travel, meals and lodging expense. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $7 million and $1 million for the three months ended September 30, 2018 and 2017, respectively, was 54% and 75% for the three months ended September 30, 2018 and 2017, respectively.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased $4 million, or 15%, from $26 million for the three months ended September 30, 2017 to $30 million for the three months ended September 30, 2018, primarily due to an increase in cost of goods sold as a result of a 26% 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 $4 million and $3 million for the three months ended September 30, 2018 and 2017, respectively, was 81% and 80% for the three months ended September 30, 2018 and 2017, respectively.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue, exclusive of depreciation expense, increased $2 million, or 22%, from $12 million for the three months ended September 30, 2017 to $14 million for the three months ended September 30, 2018, primarily due to an increase in directional drilling utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue, exclusive of depreciation expense of $4 million and $5 million for the three months ended September 30, 2018 and 2017, respectively, was 89% and 85% for the three months ended September 30, 2018 and September 30, 2017, respectively.

Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, increased $7 million, or 50%, from $15 million for the three months ended September 30, 2017 to $22 million for the three months ended September 30, 2018, primarily due to the acquisition of RTS and WTL in the second quarter of 2018. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $4 million and $5 million for the three months ended September 30, 2018 and 2017, respectively, was 102% and 84% for the three months ended September 30, 2018 and 2017, respectively. The increase is primarily the result of start-up costs related to RTS, WTL and water transfer business in the mid-continent region as well as an increase in labor-related costs as a percentage of revenue.

Selling, General and Administrative Expenses. Selling, general and administrative expenses, or SG&A, represent the costs associated with managing and supporting our operations. During the three months ended September 30, 2018, we recognized a $68 million credit related to the provision for bad debt. Cash SG&A expense increased $15 million primarily related to costs incurred for the expansion of our infrastructure business. Following is a breakout of SG&A expenses for the periods indicated (in thousands):



	Three Months Ended
	September 30, 2018			September 30, 2017
Cash expenses:
Compensation and benefits	$	14,864		$	3,577
Professional services	3,267			1,494
Other^(a)	3,701			1,820
Total cash SG&A expense	21,832			6,891
Non-cash expenses:
Bad debt provision^(b)	(68,333		)	103
Stock based compensation	1,177			1,028
Total non-cash SG&A expense	(67,156		)	1,131
Total SG&A expense	$	(45,324	)	$	8,022


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

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion increased $5 million, or 18%, to $32 million for the three months ended September 30, 2018 from $27 million for the three months ended September 30, 2017. The increase is primarily attributable to an increase in property and equipment as a result of purchases in the second half of 2017 and in 2018, resulting in increased depreciation expense.

Impairment of Long-Lived Assets. We recorded an impairment of $5 million on various intangible assets during three months ended September 30, 2018 related to the movement of certain cementing equipment from the Utica shale to the Permian basin.

Operating Income (Loss). Operating income increased $146 million to $145 million for the three months ended September 30, 2018 compared to an operating loss of $0.5 million for the three months ended September 30, 2017. The increase was the result of the expansion of our infrastructure services business, which recognized an increase in operating income of $155 million. This increase was partially offset by a $7 million decrease in operating income for our other services, which was primarily due to impairment expense recognized during the three months ended September 30, 2018.

Interest Expense, Net. Interest expense, net decreased $1 million during the three months ended September 30, 2018 compared to the three months ended September 30, 2017 primarily due to a decline in average borrowings outstanding.

Other Expense, Net. Non-operating charges, net resulted in expense of $0.4 million and $0.3 million for the three months ended September 30, 2018 and 2017, respectively. Both periods were primarily comprised of loss recognition on assets disposed of during the periods.

Income Taxes. We recorded income tax expense of $75 million on pre-tax income of $144 million for the three months ended September 30, 2018 compared to an income tax benefit of $1 million on pre-tax loss of $2 million for the three months ended September 30, 2017. Our effective tax rate was 52% for the three months ended September 30, 2018 compared to 40% for the three months ended September 30, 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 September 30, 2018, compared to the United States federal income tax rate as well as the impact of discrete items, state income taxes and permanent differences. No income was generated in Puerto Rico during the three months ended September 30, 2017.

Results of Operations

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017



	Nine Months Ended
	September 30, 2018			September 30, 2017
	(in thousands)
Revenue:
Pressure pumping services	$	294,954		$	167,491
Infrastructure services	922,761			15,195
Natural sand proppant services	140,870			73,092
Contract land and directional drilling services	48,379			36,867
Other services	64,587			36,517
Eliminations	(59,665		)	(6,629		)
Total revenue	1,411,886			322,533

Cost of revenue:
Pressure pumping services (exclusive of depreciation and amortization of $40,474 and $31,734, respectively, for the nine months ended September 30, 2018 and 2017)	232,701			122,714
Infrastructure services (exclusive of depreciation and amortization of $13,071 and $1,379, respectively, for the nine months ended September 30, 2018 and 2017)	535,114			11,829
Natural sand proppant services (exclusive of depreciation, depletion and accretion of $10,376 and $6,599, respectively, for the nine months ended September 30, 2018 and 2017)	103,768			59,119
Contract land and directional drilling services (exclusive of depreciation of $14,028 and $14,966, respectively, for the nine months ended September 30, 2018 and 2017)	44,139			34,629
Other services (exclusive of depreciation and amortization of $11,710 and $9,563, respectively, for the nine months ended September 30, 2018 and 2017)	57,437			28,709
Eliminations	(59,665		)	(6,629		)
Total cost of revenue	913,494			250,371
Selling, general and administrative expenses	58,314			22,459
Depreciation, depletion, amortization and accretion	89,718			64,354
Impairment of long-lived assets	4,769			—
Operating income (loss)	345,591			(14,651		)
Interest expense, net	(2,654		)	(2,929		)
Bargain purchase gain	—			4,012
Other expense, net	(914		)	(707		)
Income (loss) before income taxes	342,023			(14,275		)
Provision (benefit) for income taxes	174,265			(7,323		)
Net income (loss)	$	167,758		$	(6,952	)

Revenue. Revenue for the nine months ended September 30, 2018 increased $1.1 billion, or 338%, to $1.4 billion from $323 million for the nine months ended September 30, 2017. The increase in total revenue is primarily attributable to a $908 million increase in infrastructure services revenue, representing 83% of the overall increase. Additionally, pressure pumping services revenue increased $128 million, representing 12% of the overall increase.

Revenue derived from related parties was $134 million, or 9% of our total revenue, for the nine months ended September 30, 2018 and $174 million, or 54% of our total revenue, for the nine months ended September 30, 2017.

Substantially all of our related party revenue is derived from Gulfport under pressure pumping and sand contracts. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $128 million, or 76%, to $295 million for the nine months ended September 30, 2018 from $167 million for the nine months ended September 30, 2017. Revenue derived from related parties was $88 million, or 30% of total pressure pumping revenue, for the nine months ended September 30, 2018 compared to $120 million, or 71% of total pressure pumping revenue, for the nine months ended September 30, 2017. Substantially all of our related party revenue is derived from Gulfport. Inter-segment revenues, consisting primarily of revenue derived from our sand segment, totaled $6 million and $1 million for the nine months ended September 30, 2018 and 2017, respectively.

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 the Permian Basin, which contributed revenue of $126 million during the nine months ended September 30, 2018 compared to $29 million during the nine months ended September 30, 2017. Additionally, the number of stages completed increased to 5,081 for the nine months ended September 30, 2018 from 3,764 for the nine months ended September 30, 2017.

Infrastructure Services. Infrastructure services division revenue increased $908 million from $15 million for the nine months ended September 30, 2017 to $923 million for the nine months ended September 30, 2018. We generated $885 million, or 96% 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 contracts with PREPA and our infrastructure services, see "Industry Overview - Electrical Infrastructure Industry" above.

Natural Sand Proppant Services. Natural sand proppant services division revenue increased $68 million, or 93%, to $141 million for the nine months ended September 30, 2018, from $73 million for the nine months ended September 30, 2017. Revenue derived from related parties was $25 million, or 18% of total sand revenue, for the nine months ended September 30, 2018 and $39 million, or 54% of total sand revenue, for the nine months ended September 30, 2017. Inter-segment revenue, consisting primarily of revenue derived from our pressure pumping segment, totaled $48 million, or 34% of total sand revenue, for the nine months ended September 30, 2018 and $5 million, or 7% of total sand revenue, for the nine months ended September 30, 2017.

The increase in our natural sand proppant services revenue was primarily attributable to a 94% increase in tons of sand sold from approximately 1,089,851 tons for the nine months ended September 30, 2017 to 2,111,872 tons for the nine months ended September 30, 2018. We completed the expansion of our Taylor and Piranha sand facilities in March and August 2018, respectively. In May 2017, we acquired a wet and dry plant and sand mine located on approximately 600 acres in New Auburn, Wisconsin through our purchase of the assets of Chieftain. These assets contributed revenue of $35 million to our natural sand proppant division for the nine months ended September 30, 2018 compared to $4 million for the nine months ended September 30, 2017.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $11 million, or 31%, from $37 million for the nine months ended September 30, 2017 to $48 million for the nine months ended September 30, 2018. Revenue derived from related parties, consisting primarily of directional drilling revenue from Gulfport and El Toro, was $1 million, or 2% of total drilling revenue, for the nine months ended September 30, 2018 compared to $3 million, or 8% of total drilling revenue, for the nine months ended September 30, 2017.

The increase in contract land and directional drilling revenue was primarily attributable to our directional drilling services, which accounted for $8 million, or 69% of the total increase, as a result of increased utilization from 28% for the nine months ended September 30, 2017 to 45% for the nine months ended September 30, 2018. Our rig moving services accounted for $3 million, or 22%, of the operating division increase, primarily due to increased activity. Our land drilling services accounted for $1 million, or 7%, of the operating division increase, as a result of an increase in average day rates from approximately $14,433 for the nine months ended September 30, 2017 to approximately $16,980 for the nine months ended September 30, 2018, partially offset by a decrease in average active rigs from five for the nine months ended September 30, 2017 to four rigs for the nine months ended September 30, 2018.

Other Services. Other revenue, consisting of revenue derived from our coil tubing, pressure control, flowback, cementing, acidizing, equipment rental, crude oil hauling, water transfer and remote accommodation businesses, increased $28 million, or 77%, to $65 million for the nine months ended September 30, 2018 from $37 million for the nine months ended September 30, 2017. Revenue derived from related parties, consisting primarily of equipment rental and cementing revenue from Gulfport, was $20 million, or 31% of total other revenue, for the nine months ended September 30, 2018 and $12 million, or 32% of total other revenue, for the nine months ended September 30, 2017. Inter-segment revenue, consisting primarily of revenue derived from our infrastructure and pressure pumping segments, totaled $5 million and $0.4 million for the nine months ended September 30, 2018 and 2017, respectively.

Revenue for Stingray Cementing and Stingray Energy, which we acquired in June 2017, increased $16 million for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. During the second quarter of 2018, we acquired RTS, a cementing and acidizing business, and WTL, a crude oil hauling business. These business contributed revenue of $8 million during the nine months ended September 30, 2018. Revenue from our coil tubing, pressure control and flowback services increased $7 million for the nine months ended September 30, 2018 compared to nine months ended September 30, 2017 primarily due to increases in utilization. These increases were partially offset by a decrease in revenue from our remote accommodations business due to a decline in utilization.

Cost of Revenue (exclusive of depreciation, depletion, amortization and accretion expense). Cost of revenue, exclusive of depreciation, depletion, amortization and accretion expense, increased $663 million from $250 million, or 78% of total revenue, for the nine months ended September 30, 2017 to $913 million, or 65% of total revenue, for the nine months ended September 30, 2018. The increase was primarily due to the expansion of our infrastructure services business, which represented a $523 million increase in cost of revenue, as well as an increase in pressure pumping division costs of $110 million, primarily related to the addition of three new fleets during 2017, and an increase in natural sand proppant division costs of $45 million, primarily due to an increase in tons of sand sold during the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017. Cost of revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division cost of revenue, exclusive of depreciation and amortization expense, increased $110 million, or 90%, to $233 million for the nine months ended September 30, 2018 from $123 million for the nine months ended September 30, 2017. The increase was primarily due to the expansion of services into the SCOOP/STACK and the Permian Basin with the addition of three fleets during 2017, which accounted for $85 million, or 77%, of the increase. As a percentage of revenue, our pressure pumping services division cost of revenue, exclusive of depreciation and amortization expense of $40 million and $32 million for the nine months ended September 30, 2018 and 2017, respectively, was 79% and 73% for the nine months ended September 30, 2018 and September 30, 2017, respectively. The increase in costs as a percentage of revenue was primarily due to an increase in cost of goods sold as a result of selling sand with our service package to customers in the mid-continent region.

Infrastructure Services. Infrastructure services division cost of revenue, exclusive of depreciation and amortization expense, was $535 million and $12 million for the nine months ended September 30, 2018 and 2017, respectively. The increase is due to the expansion of our infrastructure business in late 2017 and 2018. The largest components of our cost of revenue include labor-related costs, including contract labor, and travel, meals and lodging expense. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $13 million and $1 million for the nine months ended September 30, 2018 and 2017, respectively, was 58% and 78% for the nine months ended September 30, 2018 and 2017, respectively.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue, exclusive of depreciation, depletion and accretion expense, increased $45 million, or 76%, from $59 million for the nine months ended September 30, 2017 to $104 million for the nine months ended September 30, 2018, primarily due to an increase in cost of goods sold as a result of a 94% increase in tons of sand sold in the 2018 period as compared to the same period in 2017. As a percentage of revenue, cost of revenue, exclusive of depreciation, depletion and accretion expense of $10 million and $7 million for the nine months ended September 30, 2018 and 2017, respectively, was 74% and 81% for the nine months ended September 30, 2018 and September 30, 2017, respectively. The decrease is primarily due to startup costs incurred for our Piranha plant, which we acquired in May 2017.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue, exclusive of depreciation expense, increased $9 million, or 27%, from $35 million for the nine months ended September 30, 2017 to $44 million for the nine months ended September 30, 2018, primarily due to increased

utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue, exclusive of depreciation expense of $14 million and $15 million for the nine months ended September 30, 2018 and 2017, respectively, was 91% and 94% for the nine months ended September 30, 2018 and September 30, 2017, respectively. The decrease was primarily due to higher day rates.

Other Services. Other services division cost of revenue, exclusive of depreciation and amortization expense, increased $28 million, or 100%, from $29 million for the nine months ended September 30, 2017 to $57 million for the nine months ended September 30, 2018, primarily due to the acquisition of Stingray Cementing and Stingray Energy in June 2017 and the acquisitions of RTS and WTL in the second quarter of 2018. As a percentage of revenue, cost of revenue, exclusive of depreciation and amortization expense of $12 million and $10 million for the nine months ended September 30, 2018 and 2017, respectively, was 89% and 79% for the nine months ended September 30, 2018 and 2017, respectively. The increase is primarily the result of start-up costs related to RTS, WTL and the water transfer business in the mid-continent region as well as an increase in equipment rental expense 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 $36 million to $58 million for the nine months ended September 30, 2018, from $22 million for the nine months ended September 30, 2017, primarily related to costs incurred for the expansion of our infrastructure business and the recognition of equity based compensation. The equity based compensation represents compensation expense for awards issued by certain Wexford affiliates and had no cash impact to the Company and no dilutive impact relative to the number of shares outstanding. Following is a breakout of SG&A expenses for the periods indicated (in thousands):



	Nine Months Ended
	September 30, 2018			September 30, 2017
Cash expenses:
Compensation and benefits	$	33,541		$	8,958
Professional services	8,835			5,075
Other^(a)	9,243			5,700
Total cash SG&A expense	51,619			19,733
Non-cash expenses:
Bad debt provision^(b)	(14,543		)	78
Equity based compensation^(c)	17,487			—
Stock based compensation	3,751			2,648
Total non-cash SG&A expense	6,695			2,726
Total SG&A expense	$	58,314		$	22,459


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


b.	During the three months ended September 30, 2018, the Company received payment for amounts previously reserved in 2017. As a result, during the three months ended September 30, 2018, the Company reversed bad debt expense of $16.0 million recognized in 2017.


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

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion increased $26 million, or 39%, to $90 million for the nine months ended September 30, 2018 from $64 million for the nine months ended September 30, 2017. The increase is primarily attributable to an increase in property and equipment purchases in the second half of 2017 and 2018, resulting in increased depreciation expense.

Impairment of Long-Lived Assets. We recorded an impairment of $5 million on various intangible assets during the nine months ended September 30, 2018 related to the movement of certain cementing equipment from the Utica shale to the Permian basin.

Operating Income (Loss). Operating income increased $361 million to $346 million for the nine months ended September 30, 2018 compared to an operating loss of $15 million for the nine months ended September 30, 2017. The increase was primarily the result of an expansion of our infrastructure services business, which accounted for $356 million of the increase in operating income and a $21 million increase in natural sand proppant operating income. These were partially offset

by a $12 million decrease in pressure pumping operating income due to an increase in non-cash equity compensation expense during the nine months ended September 30, 2018.

Interest Expense, Net. Interest expense, net was $3 million for each of the nine months ended September 30, 2018 and 2017. Average outstanding borrowings remained relatively flat for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017.

Other Expense, Net. Non-operating charges, net resulted in expense of $1 million for each of the nine months ended September 30, 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 $174 million on pre-tax income of $342 million for the nine months ended September 30, 2018 compared to an income tax benefit of $7 million on pre-tax loss of $14 million for the nine months ended September 30, 2017. Our effective tax rate was 51% for the nine months ended September 30, 2018 compared to 37% for the nine months ended September 30, 2017. The increase in effective tax rate is primarily due to the equity based compensation expense recognized during the nine months ended September 30, 2018 as well as a higher tax rate in Puerto Rico, where most of our income was generated during the nine months ended September 30, 2018, compared to the United States federal income tax rate. No income was generated in Puerto Rico during the nine months ended September 30, 2017.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before depreciation, depletion, accretion and amortization, impairment of long-lived assets, acquisition related costs, public offering costs, equity based compensation, stock based compensation, bargain purchase gain, interest expense, net, other 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					Nine Months Ended
	September 30,					September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2018		2017			2018		2017
Net income (loss)	$	69,512	$	(801	)	$	167,758	$	(6,952	)
Depreciation, depletion, accretion and amortization expense	32,015		27,224			89,718		64,354
Impairment of long-lived assets	4,582		—			4,769		—
Acquisition related costs	99		264			130		2,455
Public offering costs	260		—			991		—
Equity based compensation	—		—			17,487		—
Stock based compensation	1,415		1,028			4,331		2,648
Bargain purchase gain	—		—			—		(4,012		)
Interest expense, net	458		1,420			2,654		2,929
Other expense, net	400		320			914		707
Provision (benefit) for income taxes	74,835		(1,413		)	174,265		(7,323		)
Adjusted EBITDA	$	183,576	$	28,042		$	463,017	$	54,806

Pressure Pumping Services



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2018		2017		2018			2017
Net income (loss)	$	2,195	$	3,744	$	(7,279	)	$	5,113
Depreciation and amortization expense	12,665		13,039		40,480			31,823
Impairment of long-lived assets	143		—		143			—
Acquisition related costs	6		1		39			1
Public offering costs	61		—		263			—
Equity based compensation	—		—		17,487			—
Stock based compensation	400		428		1,271			1,202
Interest expense	150		592		995			1,023
Other expense, net	2		120		94			127
Adjusted EBITDA	$	15,622	$	17,924	$	53,493		$	39,289

Infrastructure Services



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2018		2017		2018			2017
Net income	$	78,405	$	1,366	$	178,064		$	664
Depreciation and amortization expense	6,591		1,039		13,092			1,379
Acquisition related costs	—		48		(4		)	90
Public offering costs	123		—		483			—
Stock based compensation	555		29		1,618			29
Interest expense	159		68		341			72
Other expense, net	181		10		513			10
Provision for income taxes	77,612		—		178,200			—
Adjusted EBITDA	$	163,626	$	2,560	$	372,307		$	2,244

Natural Sand Proppant Services



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2018		2017		2018			2017
Net income	$	956	$	1,566	$	21,257		$	4,209
Depreciation, depletion, accretion and amortization expense	4,184		3,034		10,381			6,603
Acquisition related costs	—		167		(38		)	2,121
Public offering costs	49		—		144			—
Stock based compensation	211		272		602			524
Bargain purchase gain	—		—		—			(4,012		)
Interest expense	37		87		193			573
Other expense, net	199		98		222			252
Provision for income taxes	—		24		—			33
Adjusted EBITDA	$	5,636	$	5,248	$	32,761		$	10,303

Contract Land and Directional Drilling Services



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017			2018			2017
Net loss	$	(4,060	)	$	(5,018	)	$	(14,964	)	$	(18,332	)
Depreciation and amortization expense	4,327			5,036			14,031			14,978
Impairment of long-lived assets	—			—			187			—
Acquisition related costs	—			(16		)	—			9
Public offering costs	10			—			44			—
Stock based compensation	132			138			540			430
Interest expense, net	53			570			713			1,227
Other expense, net	(5		)	39			67			263
Adjusted EBITDA	$	457		$	749		$	618		$	(1,425	)

Other Services^(a)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Reconciliation of Adjusted EBITDA to net income (loss):	2018			2017			2018			2017
Net (loss) income	$	(7,974	)	$	(2,459	)	$	(9,320	)	$	1,394
Depreciation and amortization expense	4,248			5,076			11,734			9,571
Impairment of long-lived assets	4,439			—			4,439			—
Acquisition related costs	93			65			133			236
Public offering costs	17			—			57			—
Stock based compensation	117			162			300			463
Interest expense, net	59			103			412			34
Other expense, net	23			53			18			55
(Benefit) provision for income taxes	(2,777		)	(1,437		)	(3,935		)	(7,356		)
Adjusted EBITDA	$	(1,755	)	$	1,563		$	3,838		$	4,397

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

Adjusted Net Income and Adjusted Earnings per Share

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



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2018		2017			2018		2017
	(in thousands, except per share amounts)
Net income (loss), as reported	$	69,512	$	(801	)	$	167,758	$	(6,952	)
Equity based compensation	—		—			17,487		—
Adjusted net income (loss)	$	69,512	$	(801	)	$	185,245	$	(6,952	)

Basic earnings (loss) per share, as reported	$	1.55	$	(0.02	)	$	3.75	$	(0.17	)
Equity based compensation	—		—			0.39		—
Adjusted basic earnings (loss) per share	$	1.55	$	(0.02	)	$	4.14	$	(0.17	)

Diluted earnings (loss) per share, as reported	$	1.54	$	(0.02	)	$	3.73	$	(0.17	)
Equity based compensation	—		—			0.39		—
Adjusted diluted earnings (loss) per share	$	1.54	$	(0.02	)	$	4.12	$	(0.17	)

Liquidity and Capital Resources

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet of equipment, organic growth initiatives, investments and acquisitions. Since November 2014, our primary sources of liquidity have been cash on hand, borrowings under our revolving credit facility, cash flows from operations and proceeds from our initial public offering. Our primary uses of capital have been for investing in property and equipment used to provide our services and to acquire complementary businesses. In addition, on July 16, 2018, we initiated a quarterly dividend policy and declared our first quarterly cash dividend, which was paid in August 2018. On October 29, 2018, our Board of Directors declared a quarterly cash dividend of $0.125 per common share payable on November 15, 2018 to stockholders of record on November 8, 2018. Future declaration of cash dividends are subject to approval by our Board of Directors and may be adjusted at its discretion based on market conditions and capital availability.

As of September 30, 2018, we had no borrowings outstanding under our revolving credit facility and $162 million of available borrowing capacity under this facility, after giving effect to $7 million of outstanding letters of credit.

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



	September 30,			December 31,
	2018			2017
Cash and cash equivalents	$	19,692		$	5,637
Revolving credit facility availability	169,233			169,233
Less long-term debt	—			(99,900		)
Less letter of credit facilities (environmental remediation)	(3,877		)	(3,582		)
Less letter of credit facilities (insurance programs)	(2,405		)	(2,486		)
Less letter of credit facilities (rail car commitments)	(455		)	(455		)
Net working capital (less cash)^(a)	91,584			88,798
Total	$	273,772		$	157,245

Net working capital (less cash) is a non-GAAP measure and is calculated by subtracting total current liabilities of $355 million and cash and cash equivalents of $20 million from total current assets of $467 million as of September 30, 2018. As of December 31, 2017, net working capital (less cash) is calculated by subtracting total current liabilities of $220 million and cash and cash equivalents of $6 million from total current assets of $314 million.

At October 30, 2018, we had no borrowings outstanding under our amended and restated revolving credit facility, leaving an aggregate of $177 million of available borrowing capacity under this facility, which is net of letters of credit of $7 million.

Liquidity and Cash Flows

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
Net cash provided by operating activities	$	56,141		$	16,632		$	282,592		$	40,636
Net cash used in investing activities	(41,530		)	(38,135		)	(162,773		)	(140,828		)
Net cash (used in) provided by financing activities	(5,668		)	27,223			(105,713		)	85,149
Effect of foreign exchange rate on cash	47			9			(51		)	82
Net change in cash	$	8,990		$	5,729		$	14,055		$	(14,961	)

Operating Activities

Net cash provided by operating activities was $283 million for the nine months ended September 30, 2018, compared to $41 million for the nine months ended September 30, 2017. Net cash provided by operating activities was $56 million for the

three months ended September 30, 2018 compared to $17 million for the three months ended September 30, 2017. The increase in operating cash flows was primarily attributable to the increase in net income as a result of the expansion of our infrastructure services business and improvements in our pressure pumping and sand businesses.

Investing Activities

Net cash used in investing activities was $163 million for the nine months ended September 30, 2018, compared to $141 million for the nine months ended September 30, 2017. Net cash used in investing activities was $42 million for the three months ended September 30, 2018, compared to $38 million for the three months ended September 30, 2017. Cash used in investing activities was used to purchase property and equipment that is utilized to provide our services and to acquire complementary businesses.

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
Pressure pumping services^(a)	$	5,630	$	19,581	$	21,729	$	72,983
Infrastructure services^(b)	21,737		8,055		78,293		12,013
Natural sand proppant services^(c)	3,145		4,928		15,803		7,898
Contract and directional drilling services^(d)	1,570		2,356		12,271		8,257
Other^(e)	8,663		777		21,434		1,122
Total capital expenditures	$	40,745	$	35,697	$	149,530	$	102,273

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

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

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


d.	Capital expenditures primarily for upgrades to our rig fleet and real estate purchases for the nine months ended September 30, 2018 and upgrades to our rig fleet for the nine months ended September 30, 2017.


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

Financing Activities

Net cash used in financing activities was $106 million for the nine months ended September 30, 2018, compared to net cash provided by financing activities of $85 million for the nine months ended September 30, 2017. Net cash used in financing activities was $6 million for the three months ended September 30, 2018, compared to net cash provided by financing activities of $27 million for the three months ended September 30, 2017. Net cash used in financing activities was primarily attributable to $6 million in dividends paid during the three and nine months ended September 30, 2018 and net repayments under our revolving credit facility of $100 million for the nine months ended September 30, 2018. Net cash provided by financing activities was primarily attributable to net borrowings under our revolving credit facility of $29 million and $94 million for the three and nine months ended September 30, 2017, respectively.

Effect of Foreign Exchange Rate on Cash

The effect of foreign exchange rate on cash was ($0.1) million and $0.1 million for the nine months ended September 30, 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 $111 million and $94 million at September 30, 2018 and December 31, 2017, respectively. Our cash balances were $20 million and $6 million at September 30, 2018 and December 31, 2017, respectively.

Our Revolving Credit Facility

On October 19, 2018, we and certain of our direct and indirect subsidiaries, as borrowers, entered into an amended and restated revolving credit and security agreement with the lenders party thereto and PNC Bank, National Association, as a lender

and as administrative agent for the lenders, which amends and restates our prior revolving credit and security agreement dated as of July 9, 2018, as amended prior to October 19, 2018, to, among other things, (i) extend the maturity date to October 19, 2023, (ii) increase the maximum revolving advance amount to $185 million, with the ability to further increase the maximum revolving advance amount to $350 million under certain circumstances, (iii) increase the letter of credit sublimit to 20% of the maximum revolving advance amount and (iv) decrease the interest rates applicable to loans.

Outstanding borrowings under this amended and restated revolving credit facility bear interest at a per annum rate elected by us that is equal to an alternate base rate or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 1.50% per annum in the case of the alternate base rate, and from 2.00% to 2.50% per annum in the case of LIBOR. The applicable margin depends on the amount of excess availability under this amended and restated revolving credit facility.

At September 30, 2018, we had no outstanding borrowings under our then existing revolving credit facility. At October 30, 2018, we had availability of $177 million under our amended and restated revolving credit facility, after giving effect to $7 million of outstanding letters of credit.

Our amended and restated 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 September 30, 2018 and December 31, 2017, we were in compliance with the financial covenants under our then existing revolving credit facility.

Capital Requirements and Sources of Liquidity

During 2018, we currently estimate that our aggregate capital expenditures will be approximately $205 million. These capital expenditures include $98 million in our infrastructure services segment for assets for additional crews, $25 million in our natural sand proppant services segment primarily related to expansion projects, $21 million in our pressure pumping segment for various pressure pumping equipment, $14 million in our contract land and directional drilling services segment primarily for rig upgrades and real estate, $17 million for expansion of our rental equipment business in Ohio and into Oklahoma, $10 million for the expansion of our water transfer business, $8 million for the expansion of our crude hauling business, $6 million for coil tubing equipment and $6 million for other capital expenditures. During the nine months ended September 30, 2018, our capital expenditures totaled $150 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 both other existing and new industries. 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 September 30, 2018 are as follows (in thousands):



Year ended December 31:	Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments^(a)
Remainder of 2018	$	6,871	$	23,018	$	12,479
2019	19,726		—		29,273
2020	16,402		—		19,391
2021	12,634		—		265
2022	9,299		—		—
Thereafter	7,290		—		—
	$	72,222	$	23,018	$	61,408

Other Commitments

Subsequent to September 30, 2018, a subsidiary in our infrastructure segment entered into an air charter agreement with aggregate commitments of $1.6 million and our pressure pumping subsidiary purchased additional equipment totaling $1.4 million.

Subsequent to September 30, 2018, we ordered additional capital equipment with aggregate commitments of $8.1 million.

New Accounting Pronouncements

In February 2016, the FASB issued ASU No, 2016-02 “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 2016-02 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 in the process of implementing a new lease accounting system in connection with the adoption of this ASU and are continuing to evaluate the impact this new guidance may have on our consolidated financial statements and results of operations.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The demand, pricing and terms for 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 $20 million at September 30, 2018. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure to changes in the fair value of these investments as a result of changes in interest rates. Declines in interest rates, however, will reduce future income.

Interest under our credit facility is payable at a base rate plus an applicable margin. Additionally, at our request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit. At September 30, 2018, we had no outstanding borrowings under our revolving credit facility. As of July 31, 2018, the last day on which we had any material outstanding borrowings under our revolving credit facility, a 1% increase or decrease in the interest rate would have increased or decreased our interest expense by approximately $0.1 million per year, based on $6 million outstanding and a weighted average interest rate of 6.5%. 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 September 30, 2018, we had $2 million of cash, in Canadian dollars, in Canadian accounts. A 10% increase in the strength of the Canadian dollar versus the U.S. dollar would have resulted in an increase in pre-tax income of approximately $0.2 million as of September 30, 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 primarily 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 September 30, 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 September 30, 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 September 30, 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 litigation or subject to disputes or claims related to our business activities, including breaches of contractual obligations, workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us is expected to have a material adverse effect on our financial condition, cash flows or results of operations. See Note 18 "Commitments and Contingencies," of the Notes to Unaudited Condensed Consolidated Financial Statements for additional information.

Item 1A. Risk Factors

Security holders and potential investors in our securities should carefully consider the risk factors in our Annual Report on Form 10-K (Commission File No. 001-37917) filed with the SEC on February 28, 2018 and in our Rule 424(b)(5) prospectus summary and related base prospectus filed with the SEC on June 26, 2018.

Other than set forth below, there have been no material changes to the Risk Factors previously disclosed in our Prospectus Summary dated July 26, 2018.

As of December 31, 2018, we will no longer be an “emerging growth company” and, as a result, we have begun incurring significant additional financial compliance costs by having to comply with increased disclosure and governance requirements.

We have generated over $1.07 billion in revenue throughout the first nine months of 2018. As a result, we will cease to be an emerging growth company as defined in the JOBS Act as of December 31, 2018. We will be an accelerated filer as of December 31, 2018 and will be subject to certain requirements that apply to other public companies, but did not previously apply to us due to our status as an emerging growth company. These requirements include:


•	the provisions of Section 404(b) of the Sarbanes-Oxley Act ("Section 404") requiring that our independent registered public accounting firm provide an attestation report on the effectiveness of our internal control over financial reporting;


•	the requirement to provide detailed compensation discussion and analysis in proxy statements and reports filed under the Exchange Act; and


•	the "say on pay" provisions, which require a non-binding stockholder vote to approve compensation of certain executive officers, and the "say on golden parachute" provisions, which require a non-binding stockholder vote to approve golden parachute arrangements for certain executive officers in connection with mergers and certain other business combinations) of the Dodd-Frank Act.

We have already begun to incur additional compliance costs in connection with our forthcoming loss of emerging growth company status. We expect that our compliance with these additional requirements, including the provisions of Section 404, will continue to increase professional costs and require management to devote substantial time and effort toward ensuring compliance with these requirements.

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

MAMMOTH ENERGY SERVICES, INC.

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

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

8-K

001-37917

7/13/2018

10.1

10.2

Amended and Restated Revolving Credit and Security Agreement, dated as of October 19, 2018, by and among Mammoth Energy Services, Inc. and certain of its direct and indirect subsidiaries, the lenders party to the Revolving Credit and Security Agreement from time to time and PNC Bank, National Association, as a lender and agent for the lenders.

8-K

001-37917

10/25/2018

10.1

10.3#

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

10-Q

001-37917

8/8/2018

10.3

10.4

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

10-Q

001-37917

8/8/2018

10.4

31.1

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

31.2

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

32.1

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

32.2

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

95.1

Mine Safety Disclosure Exhibit

101.1

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

On October 25, 2018, confidential treatment was granted with respect to certain portions of this amendment and extended with respect to certain portions of the original agreement, as subsequently amended, which portions have been omitted and filed separately with 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:	November 1, 2018	By:	/s/ Arty Straehla
			Arty Straehla
			Chief Executive Officer

Date:	November 1, 2018	By:	/s/ Mark Layton
			Mark Layton
			Chief Financial Officer