Exhibit

EXHIBIT 99.1

TABLE OF CONTENTS





		Page
PART II.		2
Item 6.	Selected Financial Data	2
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4
Item 8.	Financial Statements and Supplementary Data	23

PART II. OTHER INFORMATION

Item 6. Selected Financial Data

This section presents our selected historical combined consolidated financial data. The selected historical combined consolidated financial data presented below is not intended to replace our historical consolidated financial statements. You should read the following data along with Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this report.

The historical financial information for periods prior to October 12, 2016, contained in this report relates to Mammoth Energy Partners LP, a Delaware limited partnership, or the Partnership. On October 12, 2016, the Partnership was converted into a Delaware limited liability company named Mammoth Energy Partners LLC, or Mammoth LLC, and then each member of Mammoth LLC contributed all of its membership interests in Mammoth LLC to Mammoth Energy Services, Inc., a Delaware corporation, or Mammoth Inc. Prior to the conversion and the contribution, Mammoth Inc. was a wholly-owned subsidiary of the Partnership. Upon the conversion and the contribution, Mammoth LLC (as the converted successor to the Partnership) became a wholly-owned subsidiary of Mammoth Inc.

On October 13, 2016, Mammoth Inc. priced 7,750,000 shares of its common stock in the IPO at a price to the public of $15.00 per share and, on October 14, 2016, Mammoth Inc.’s common stock began trading on The Nasdaq Global Select Market under the symbol “TUSK.” On October 19, 2016, Mammoth Inc. closed its IPO. Unless the context otherwise requires, references in this report to “we,” “our,” “us” or like terms, when used in a historical context for periods prior to October 12, 2016 refer to the Partnership and its subsidiaries. References in this report to “we,” “our,” “us” or like terms, when used for periods beginning on or after October 12, 2016 refer to Mammoth Inc. and its subsidiaries.

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 this 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.

Presented below is our selected historical financial data for the periods and as of the dates indicated. All of the selected historical financial data has been retrospectively recast for all periods to give effect to the Sturgeon acquisition as if it had occurred on September 13, 2014, the date that Sturgeon commenced operations. As an emerging growth company, in accordance with Item 301 of Regulation S-K, the historical financial data for the years ended December 31, 2013 and 2012 and the balance sheet data as of December 31, 2013 and 2012 are not included in this report.



	Years Ended December 31,
STATEMENT OF OPERATIONS DATA:	2016			2015			2014
Total revenues	$	230,625,597		$	367,936,792		$	275,729,434
Total cost and expenses	$	265,255,544		$	383,710,196		$	253,436,166
Operating (loss) income	$	(34,629,947	)	$	(15,773,404	)	$	22,293,268
Total other expense	$	(3,938,010	)	$	(7,635,113	)	$	(10,301,097	)
(Loss) income before income taxes	$	(38,567,957	)	$	(23,408,517	)	$	11,992,171
Net (loss) income	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Comprehensive (loss) income	$	(89,742,223	)	$	(26,634,250	)	$	4,950,691

Net (loss) earnings per share (basic and diluted)	$	(2.94	)	$	(0.73	)	$	0.21
Weighted average number of shares outstanding	31,500,000			30,000,000			21,056,073

Pro forma information:
Net (loss) income, as reported	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Taxes on income earned as a non-taxable entity	$	15,224,009		$	390,801		$	(7,590,480	)
Taxes due to change to C corporation	$	53,088,861		$	—		$	—
Pro forma net loss	$	(24,139,958	)	$	(21,428,630	)	$	(3,112,503	)
Pro forma loss per common share
Basic and diluted	$	(0.56	)	$	(0.50	)	$	(0.14	)
Weighted average pro forma shares outstanding—basic and diluted	43,107,452			43,107,452			22,730,627

CASH FLOW DATA:
Cash flows provided by operations	$	29,688,435		$	69,638,685		$	15,853,116
Cash flows used in investing activities	$	(7,717,614	)	$	(27,035,233	)	$	(190,411,028	)
Cash flows provided by (used in) provided by financing activities	$	3,074,661		$	(55,556,679	)	$	185,910,751



	December 31,
BALANCE SHEET DATA:	2016		2015		2014
Cash and cash equivalents	$	29,238,618	$	4,038,899	$	17,218,781
Property, plant and equipment, net	$	242,119,663	$	294,882,932	$	355,081,878
Total assets	$	502,362,475	$	536,412,135	$	669,902,358
Total current liabilities	$	29,247,105	$	25,433,269	$	71,022,044
Long-term debt	$	—	$	95,000,000	$	146,041,013
Total liabilities	$	79,582,120	$	122,465,365	$	225,418,628
Total equity	$	422,780,355	$	413,946,770	$	444,483,730

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with (i) Item 6, “Selected Financial Data,” and (ii) the consolidated financial statements and the related notes in Item 8 which have been recast for the periods presented to combine the financial results of Sturgeon Acquisitions, LLC, or Sturgeon, with our financial results as if the acquisition had been effective on September 13, 2014 (the date Sturgeon commenced operations), each of which is included in Exhibit 99.1. 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” and the section entitled “Forward-Looking Statements” appearing elsewhere in our Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 23, 2017.

Overview

We are an integrated, growth-oriented energy service company serving companies engaged in the exploration and development of North American onshore unconventional oil and natural gas reserves. Our primary business objective is to grow our operations and create value for stockholders through organic opportunities and accretive acquisitions. Our suite of services includes pressure pumping services, well services, natural sand proppant services, contract land and directional drilling services and other energy services. Our pressure pumping services division provides hydraulic fracturing services. Our well services division provides pressure control services, flowback services and equipment rentals. Our natural sand proppant services division sells, distributes and, with the inclusion of Sturgeon, produces proppant for hydraulic fracturing. Our contract land and directional drilling services division provides drilling rigs and crews for operators as well as rental equipment, such as mud motors and operational tools, for both vertical and horizontal drilling. Our other energy services division currently provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We believe that the services we offer play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources. Our complementary suite of completion and production and drilling related services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

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

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

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

On June 5, 2017, we acquired Sturgeon and Sturgeon's wholly owned subsidiaries Taylor Frac, LLC, or Taylor Frac, Taylor Real Estate Investments, LLC, or Taylor RE, and South River Road, LLC, or South River. 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 and

recorded Sturgeon's assets and liabilities on a historical cost basis rather than at their fair market value. Therefore, our historical financial information for all periods included in this Current Report on Form 8-K has been recast to combine Sturgeon's financial results with our financial results as if the acquisition had been effective since Sturgeon commenced operations on September 13, 2014.

Each year, we evaluate qualitative and quantitative aspects of our service lines. As a result of that review as of December 31, 2016, we have split our completion and production division into pressure pumping services and well services. In addition, we renamed our remote accommodation services as other energy services. As a result, we now manage our business through five operating divisions: pressure pumping services, well services, natural sand proppant services, contract and directional drilling services and other energy services.

Since the dates presented below, we have conducted our operations through the following entities:

Pressure Pumping Services Division


•	Pressure Pumping—March 2012


•	Logistics—November 2012


•	Barracuda—October 2014


•	Pumpdown—January 2015


•	Mr. Inspections—January 2015


•	Silverback—June 2016


•	Mammoth Equipment Leasing—November 2016

Well Services Division


•	Redback Energy Services—October 2011


•	Redback Coil Tubing—May 2012


•	Mammoth Energy Services—June 2016

Natural Sand Proppant Services Division


•	Muskie Proppant—September 2011


•	Sturgeon—September 2014


•	Taylor Frac—September 2014


•	Taylor RE—September 2014


•	South River—September 2014

Contract Land and Directional Drilling Services Division


•	Bison Drilling—November 2010


•	Panther Drilling—December 2012


•	Bison Trucking—August 2013


•	White Wing—September 2014

Other Energy Services Division


•	Sand Tiger—October 2007

Industry Overview

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

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

The reduction in demand during the first part of 2016, and the resulting oversupply of many of the services and products we provide, substantially reduced the prices we could charge our customers for our products and services, and had a negative impact on the utilization of our services. This overall trend with respect to our customers’ activities and spending continued in 2016. However, oil prices have increased since the 12-year low recorded on February 11, 2016, reaching a high of $54.06 per barrel on December 28, 2016. As commodity prices have begun to recover, we have experienced an increase in activity. If near term commodity prices stabilize at current levels and recover further, we expect to continue to experience an increase in demand for our services and products, particularly in our completion and production, natural sand proppant and contract land and directional drilling businesses. Our other energy services revenue, which are currently only attributable to our remote accommodations business, remained stable through the fourth quarter of 2016. However, we currently project that our other energy services revenues will decrease in the first quarter of 2017 if we are unable to replace one customer that represented approximately 85% of such services during the year ended December 31, 2016, when it completes the construction phase of its project, which is currently estimated to occur in early 2017.

Results of Operations

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015



	Years Ended
	December 31, 2016			December 31, 2015
Revenue:
Pressure pumping services	$	123,855,848		$	169,858,555
Well services	10,024,813			28,851,341
Natural sand proppant services	33,835,698			60,912,433
Contract land and directional drilling services	32,042,509			73,032,089
Other energy services	30,866,729			35,282,374
Total revenue	230,625,597			367,936,792

Cost of Revenue:
Pressure pumping services	82,551,909			129,042,660
Well services	13,540,309			28,144,431
Natural sand proppant services	31,894,499			44,905,053
Contract land and directional drilling services	31,847,969			57,489,608
Other energy services	13,186,060			15,105,497
Total cost of revenue	173,020,746			274,687,249
Selling, general and administrative expenses	18,048,515			22,400,020
Depreciation, depletion, accretion and amortization	72,315,398			74,498,574
Impairment of long-lived assets	1,870,885			12,124,353
Operating loss	(34,629,947		)	(15,773,404		)
Interest expense, net	(4,096,182		)	(5,366,055		)
Other income (expense), net	158,172			(2,269,058		)
Loss before income taxes	(38,567,957		)	(23,408,517		)
Provision (benefit) for income taxes	53,884,871			(1,589,086		)
Net loss	$	(92,452,828	)	$	(21,819,431	)

Revenue. Revenue for 2016 decreased $137.3 million, or 37%, to $230.6 million from $367.9 million for 2015. Revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue decreased $46.0 million, or 27%, to $123.9 million for 2016 from $169.9 million for 2015. The decrease in our pressure pumping services revenue was driven primarily by a decline in fleet utilization from 63%, on three active fleets, for 2015 to 50%, on two active fleets, for 2016. The division decreases also included decreases due to the suspension of our pump down services in the Woodford Shale during the fourth quarter of 2015.

Well Services. Well services division revenue decreased $18.9 million, or 65%, to $10.0 million for 2016 from $28.9 million for 2015. Our coil tubing division revenue declined as a result of a decrease in average day rates from approximately $25,000 for 2015 to approximately $19,000 for 2016. Our flowback services declined as a result of discontinuing our flowback operations in the Appalachian Basin in December 2015 combined with a decline in both pricing and utilization of such services in our other basins.

Natural Sand Proppant Services. Natural sand proppant services division revenue decreased $27.1 million, or 44%, to $33.8 million for 2016, from $60.9 million for 2015. The decrease was primarily attributable to a reduction in the average sales price per ton of sand from $94 in 2015 to $49 in 2016. The decrease was partially offset by an increase in tons of sand sold from approximately 651,077 for 2015 to approximately 683,768 in 2016.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue decreased $41.0 million, or 56%, from $73.0 million for 2015 to $32.0 million for 2016. The decrease was primarily attributable to our land drilling services, which accounted for $35.0 million, or 86%, of the operating division decrease. The decrease in our land drilling services was driven by a decline in average active rigs from ten for 2015 to four for 2016 as well as a decline in average day rates from approximately $17,900 to approximately $12,900 during those same years. Our directional drilling services accounted for $4.3 million, or 10%, of the operating division decrease as a result of utilization declining from 36% for 2015 to 22% for 2016. Our rig moving services accounted for $1.2 million, or 3%, of the operating division decrease primarily driven by the decline in drilling activity. Our drill pipe inspection services accounted for $0.5 million, or 1%, of the operating division decrease as a result of of this business line being discontinued in the second quarter of 2016.

Other Energy Services. Other energy services division revenue, consisting of revenue derived from our remote accommodations business, decreased $4.4 million, or 12%, to $30.9 million for 2016 from $35.3 million for 2015. The decrease was a result of a decrease in revenue per room night, in Canadian dollars, from $180 for 2015 to $177 for 2016. Additionally, total room nights rented decreased from 251,233 for 2015 to 230,530 for 2016.

Cost of Revenue. Cost of revenue decreased $101.7 million from $274.7 million, or 75% of total revenue, for 2015 to $173.0 million, or 75% of total revenue, for 2016. Cost of revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division cost of revenue decreased $46.4 million, or 36%, from $129.0 million for 2015 to $82.6 million for 2016. The decrease was primarily due to decreases in proppant costs, repairs and maintenance expense and labor-related costs. As a percentage of revenue, our pressure pumping services division cost of revenue was 67% and 76% for 2016 and 2015, respectively. The decrease in costs as a percentage of revenue was primarily due to lower repairs and maintenance expense and a decrease in stages completed to 2,442 from 2,963 for 2016 and 2015, respectively.

Well Services. Well services division cost of revenue decreased $14.6 million, or 52%, from $28.1 million for 2015 to $13.5 million for 2016. The decrease was primarily due to declines in labor-related costs and repairs and maintenance expense. As a percentage of revenue, our well services division cost of revenue was 135% and 98% for 2016 and 2015, respectively. The increase in costs as a percentage of revenue was primarily due increased pricing pressure.

Natural Sand Proppant Services. Natural sand proppant services division cost of revenue decreased $13.0 million, or 29%, from $44.9 million for 2015 to $31.9 million for 2016, primarily due to a decrease in product and processing costs. As a percentage of revenue, cost of revenue was 94% and 74% for 2016 and 2015, respectively.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division cost of revenue decreased $25.7 million, or 45%, from $57.5 million for 2015 to $31.8 million for 2016, primarily due to a decrease in labor-related costs and lower utilization. As a percentage of revenue, our contract land and directional drilling services division cost of revenue was 99% and 79% for 2016 and 2015. The increase was primarily due to increased repairs and maintenance and compensation as a percentage of revenue.

Other Energy Services. Other energy services division cost of revenues decreased $1.9 million, or 13%, from $15.1 million for 2015 to $13.2 million for 2016, primarily due to declines in contracted labor-related costs. As a percentage of revenues, cost of revenues was 43% for each of 2016 and 2015. Average revenue per room night, in Canadian dollars, decreased from $180 for 2015 to $177 for 2016. Additionally, total room nights rented decreased from 251,233 for 2015 to 230,530 for 2016.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses decreased $4.4 million, or 19%, to $18.0 million for 2016, from $22.4 million for 2015. The decrease in expenses was primarily attributable to a $2.5 million reduction in bad debt expense, a $0.3 million reduction in compensation and benefits and reductions in travel-related charges and office and computer support expense of $0.5 million and $0.5 million, respectively, for 2016 compared to 2015.

Depreciation, Depletion, Accretion and Amortization. Depreciation, depletion, accretion and amortization decreased $2.2 million, or 3%, to $72.3 million for 2016 from $74.5 million in 2015. The decrease was primarily attributable to $26.2 million of assets that fully depreciated during 2016 in addition to impairments of $10.2 million in fixed assets during 2015 and was partially offset by placing in-service of $6.6 million of capital additions.

Impairment of Long-lived Assets. We recorded an impairment of long-lived assets in 2016 of $1.9 million, which was attributable to various fixed assets. Impairments for 2015 were $12.1 million, of which $10.2 million was attributable to various fixed assets and $1.9 million was attributable to the termination of a long-term contract.

Interest Expense, net. Interest expense decreased $1.3 million, or 24%, to $4.1 million during 2016 compared to $5.4 million during 2015. The decrease in interest expense was attributable to a decrease in average borrowings during 2016 and the repayment of all outstanding borrowings in October 2016 with a portion of the net proceeds from the IPO.

Other (Expense) Income, net. Non-operating charges resulted in other income, net, of $0.2 million for 2016 compared to other expense, net of $2.3 million for 2015. The 2016 amount included $0.7 million of gain recognition on assets disposed during the period compared to a $1.4 million loss for 2015.

Income Taxes. In 2015, we were treated as a pass-through entity for federal income tax and most state income tax purposes. The income tax expense recognized was primarily attributable to our subsidiary, Lodging, which provides our accommodation services in our other energy services division. For 2016, we recognized income tax expense of $53.9 million compared to an income tax benefit of $1.6 million for 2015. In 2016, in connection with the IPO, we became subject to federal income taxes which triggered recognition of federal income tax liabilities associated with historical earnings (See Note 1 to our consolidated financial statements included elsewhere in this report for more information). The 2016 amount included recognition of other items related to the change in classification to a C corporation resulting in total one-time effect of $53.1 million. The 2015 amount included recognition of deferred taxes recorded on income from Lodging in the U.S. related to an entity election that required us to disregard previously recorded deferred tax liabilities. We made an election on entity status in September 2015 that allowed the reversal of the deferred taxes in 2015.

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014



	Years Ended
	December 31, 2015			December 31, 2014
Revenue:
Pressure pumping services	$	169,858,555		$	24,779,686
Well services	28,851,341			45,253,092
Natural sand proppant services	60,912,433			62,553,704
Contract land and directional drilling services	73,032,089			122,164,943
Other energy services	35,282,374			20,978,009
Total revenue	367,936,792			275,729,434

Cost of Revenue:
Pressure pumping services	129,042,660			16,263,083
Well services	28,144,431			31,715,681
Natural sand proppant services	44,905,053			47,308,336
Contract land and directional drilling services	57,489,608			93,571,050
Other energy services	15,105,497			9,673,570
Total cost of revenue	274,687,249			198,531,720
Selling, general and administrative expenses	22,400,020			18,538,848
Depreciation, depletion, accretion and amortization	74,498,574			36,365,598
Impairment of long-lived assets	12,124,353			—
Operating (loss) income	(15,773,404		)	22,293,268
Interest expense, net	(5,366,055		)	(4,573,933		)
Other expense, net	(2,269,058		)	(5,727,164		)
(Loss) income before income taxes	(23,408,517		)	11,992,171
(Benefit) provision for income taxes	(1,589,086		)	7,514,194
Net (loss) income	$	(21,819,431	)	$	4,477,977

Revenue. Revenue for 2015 increased $92.2 million, or 33%, to $367.9 million from $275.7 million for 2014. The net increase in revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division revenue increased $145.1 million, or 585%, to $169.9 million for 2015 from $24.8 million for 2014. The increase was primarily attributable to our pressure pumping services, which were acquired in connection with our acquisition of Pressure Pumping in November 2014 and accounted for substantially all of the division increase in revenue. The increase was partially offset by a decrease in our pump down services primarily driven by a decline in utilization which saw a drop in utilization from 51% for 2014 to 21% for 2015.

Well Services. Well services division revenue decreased $16.4 million, or 36%, to $28.9 million for 2015 from $45.3 million for 2014. The decreases in revenue from both our coil tubing and flowback services, which decreased $9.7 million and $6.7 million, respectively. Our coil tubing division revenue declined as a result of a decline in demand for these services. Our flowback services revenue declined as a result of as a result of discontinuing our flowback operations in the Appalachian Basin in December 2015 combined with a decline in both pricing and utilization of such services in our other basins.

Natural Sand Proppant Services. Natural sand proppant services division revenue declined $1.7 million, or 3%, to $60.9 million for 2015, from $62.6 million for 2014. The decrease was attributable to a decrease in tons of sand sold from approximately 1,067,000 for 2014 to approximately 651,077 in 2015. The decrease was partially offset by an increase in the average sales price per ton of sand from $59 in 2014 to $94 in 2015.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue decreased $49.2 million, or 40%, to $73.0 million for 2015, from $122.2 million for 2014. The decrease was primarily attributable to a decrease in drilling services revenue of $41.4 million, or 84% of the net division decrease in revenue. The decrease in drilling services revenue was primarily attributable to a decline in average active rigs from 12 in 2014 to eight in 2015 as well as a decline in average day rates from $18,900 to $17,900 during those same years. For 2015, our directional drilling services division saw a reduction of $8.1 million, or 17%, of the net division decrease in revenue. Our rig moving and drill pipe inspection service lines saw a combined increase in revenue of $0.3 million, or 1%, of the net decrease in revenue primarily driven by a full year of revenue from our drill pipe inspection service line, which began operations in September 2014.

Other Energy Services. Other energy services division revenue increased $14.3 million, or 68%, to $35.3 million for 2015 from $21.0 million for 2014. The increase was a result of increased occupancy resulting from the expansion of camp capacity from 498 to 884 rooms in the fourth quarter of 2014 as well as an increase in room nights from 115,258 in 2014 to 251,233 in 2015. While the room nights increased, average revenue per room night declined from $206 in 2014 to $180 in 2015.

Cost of Revenue. Cost of revenue increased $76.2 million, or 38%, from $198.5 million, or 72% of total revenue, for 2014 to $274.7 million, or 75% of total revenue, for 2015. Cost of revenue by operating division was as follows:

Pressure Pumping Services. Pressure pumping services division cost of revenue increased $112.7 million, or 682%, from $16.3 million for 2014 to $129.0 million for 2015, primarily due to the acquisition of Pressure Pumping in November 2014. The increase in cost of revenue associated with our pressure pumping services accounted for $111.1 million, or 99%, of the increase. As a percentage of revenue, cost of revenue was 76% and 66% for 2015 and 2014, respectively. The year-over-year increase in cost of revenue as a percentage of revenue was primarily due to a decline in utilization in our pump down services from 51% for 2014 to 21% for 2015.

Well Services. Well services division cost of revenue decreased $3.6 million, or 11%, from $31.7 million for 2014 to $28.1 million for 2015, primarily due a decline in demand for both our coil tubing and flowback services. As a percentage of revenue, cost of revenue was 98% and 70% for 2015 and 2014, respectively. The year-over-year increase in cost of revenue as a percentage of revenue was primarily due to increased pricing pressures from our customers on the costs for these services.

Natural Sand Proppant Services. Natural sand proppant services cost of revenue decreased $2.4 million, or 5%, from $47.3 million for 2014 to $44.9 million for 2015, primarily due to a decrease in product and processing costs. As a percentage of revenue, cost of revenue was 74% and 76% for 2015 and 2014, respectively. The decrease was primarily due to a reduction of labor-related costs.

Contract Land and Directional / Drilling Services. Contract land and directional drilling services division cost of revenue decreased $36.1 million, or 39%, from $93.6 million for 2014 to $57.5 million for 2015, primarily due to a decrease in labor-related costs and a decline in average active rigs from twelve in 2014 to eight in 2015. As a percentage of revenue, drilling cost of revenue was 79% and 77% for 2015 and 2014, respectively. The increase was primarily due to increased competition for our services, which resulted in a decline in average day rates from $18,900 to $17,900 during the same periods.

Other Energy Services. Other energy services division cost of revenue increased $5.4 million, or 56%, from $9.7 million for 2014 to $15.1 million for 2015, primarily due to increases in contracted labor-related costs. As a percentage of revenue, cost of revenue was 43% and 43% for 2015 and 2014, respectively. As a percentage of revenue, the decrease in cost of revenue was primarily due to the increase in division revenue in 2015 associated with an increase in room nights from 115,258 in 2014 to 251,233 in 2015.

Depreciation, Depletion, Accretion and Amortization. Depreciation, depletion, accretion and amortization increased $38.1 million, or 105%, to $74.5 million for 2015 from $36.4 million for 2014. The increase was primarily attributable to the $101.5 million in property, plant and equipment and $40.7 million in amortizing intangible assets that were acquired in connection with our acquisition of Stingray Pressure Pumping LLC and Stingray Logistics LLC on November 24, 2014. The

remainder of the year-over-year increase was attributable to the $111.7 million in property, plant and equipment purchased in 2014 and $26.3 million in property, plant and equipment purchased in 2015.

Impairment of Long-lived Assets. We recorded an impairment of long-lived assets in 2015 of $12.1 million, of which $10.2 million was attributable to various fixed assets and $1.9 million was attributable to the termination of a long-term contract. No impairment of long-lived assets was recorded by us in 2014.

Interest Expense, net. Interest expense increased $0.8 million, or 17%, to $5.4 million for 2015, compared to $4.6 million for 2014. The increase in interest expense was attributable to increased average borrowings during 2015 due primarily to $49.8 million in debt that was assumed in our acquisition of Stingray Pressure Pumping LLC and Stingray Logistics LLC on November 24, 2014. The increase in borrowings was partially offset by the net repayment of $51.0 million in debt during 2015.

Other Expense, net. Non-operating charges resulted in other expense, net of $2.3 million for 2015 compared to other expense, net of $5.7 million for 2014. The 2015 amount consisted primarily of the loss on disposal of long-lived assets, compared to 2014 which included charges associated with a then proposed initial public offering that was postponed due to market conditions existing at that time.

Income Taxes. During 2015 and 2014, we were treated as a pass-through entity for federal income tax and most state income tax purposes. The income tax expense recognized was primarily attributable to our subsidiary, Lodging, which provides our accommodation services. For 2015, we recognized income tax benefit of $1.6 million compared to an income tax expense of $7.5 million for 2014. The change was primarily attributable to deferred taxes recorded on income from Lodging in the U.S. for 2014 related to an entity election that required us to disregard previously recorded deferred tax liability. We made an election on entity status in September 2015 that allowed the reversal of the deferred taxes in 2015.

Non-GAAP Financial Measures

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before depreciation, depletion, accretion and amortization, impairment of long-lived assets, one-time compensation charges associated with the IPO, equity based compensation, interest income, interest expense, other (income) expense, net (which is comprised of the (gain) or loss on disposal of long-lived assets and charges associated with the Partnership's proposed initial public offering in 2014) and provision (benefit) for income taxes. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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

Consolidated



	Years Ended December 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2016			2015			2014
Net (loss) income	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Depreciation, depletion, accretion and amortization	72,315,398			74,498,574			36,365,598
Impairment of long-lived assets	1,870,885			12,124,353			—
One-time IPO compensation charges	1,200,770			—			—
Equity based compensation	501,147			—			3,838,842
Interest income	—			(98,492		)	(214,141		)
Interest expense	4,096,182			5,464,547			4,788,074
Other (income) expense, net	(158,172		)	2,269,058			5,727,164
Provision (benefit) for income taxes	53,884,871			(1,589,086		)	7,514,194
Adjusted EBITDA	$	41,258,253		$	70,849,523		$	62,497,708

Pressure Pumping Services



	Years Ended December 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2016			2015			2014
Net (loss) income	$	(801,039	)	$	(3,026,683	)	$	949,203
Depreciation and amortization	37,012,902			35,728,715			4,015,572
Impairment of long-lived assets	138,587			1,213,885			—
One-time IPO compensation charges	101,760			—			—
Equity based compensation	176,326			—			—
Interest expense	599,147			1,859,195			386,618
Other expense, net	26,743			66,889			1,744,695
Provision for income taxes	—			72,435			10,897
Adjusted EBITDA	$	37,254,426		$	35,914,436		$	7,106,985

Well Services



	Years Ended December 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2016			2015			2014
Net (loss) income	$	(62,197,372	)	$	(8,483,700	)	$	4,803,247
Depreciation and amortization	5,127,879			5,696,547			4,768,024
Impairment of long-lived assets	1,384,751			88,247			—
One-time IPO compensation charges	35,640			—			—
Equity based compensation	43,073			—			53,807
Interest expense	134,007			429,061			831,508
Other (income) expense, net	(565,966		)	686,617			777,382
Provision for income taxes	50,265,203			4,454			18,226
Adjusted EBITDA	$	(5,772,785	)	$	(1,578,774	)	$	11,252,194

Natural Sand Proppant Services



	Years Ended December 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2016			2015			2014
Net (loss) income	$	(8,413,713	)	$	3,383,612		$	5,739,333
Depreciation, depletion, accretion and amortization	6,483,384			6,305,501			4,605,457
Impairment of long-lived assets	—			1,904,981			—
One-time IPO compensation charges	33,150			—			—
Equity based compensation	57,441			—			(24,856		)
Interest income	—			(98,056		)	(208,519		)
Interest expense	434,243			225,202			312,467
Other expense, net	96,388			22,318			1,101,952
Provision for income taxes	3,716			—			4,826
Adjusted EBITDA	$	(1,305,391	)	$	11,743,558		$	11,530,660

Contract Land and Directional Drilling Services



	Years Ended December 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2016			2015			2014
Net loss	$	(30,366,202	)	$	(30,401,338	)	$	(7,300,562	)
Depreciation and amortization	21,512,117			24,626,705			21,319,617
Impairment of long-lived assets	347,547			8,917,240			—
One-time IPO compensation charges	963,660			—			—
Equity based compensation	110,307			—			3,935,902
Interest income	—			—			—
Interest expense	2,828,753			2,890,130			3,194,061
Other expense, net	247,620			1,121,093			1,539,279
(Benefit) provision for income taxes	—			(184,523		)	77,576
Adjusted EBITDA	$	(4,356,198	)	$	6,969,307		$	22,765,873

Other Energy Services



	Years Ended December 31,
Reconciliation of Adjusted EBITDA to net income (loss):	2016		2015			2014
Net income	$	9,325,498	$	16,708,678		$	286,756
Depreciation and amortization	2,179,116		2,141,106			1,656,928
One-time IPO compensation charges	66,560		—			—
Equity based compensation	114,000		—			(126,011		)
Interest income	—		(436		)	(5,622		)
Interest expense	100,032		60,959			63,420
Other expense, net	37,043		372,141			563,856
Provision (benefit) for income taxes	3,615,952		(1,481,452		)	7,402,669
Adjusted EBITDA	$	15,438,201	$	17,800,996		$	9,841,996

Liquidity and Capital Resources

We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Since November 2014, our primary sources of liquidity have been cash on hand, borrowings under our revolving credit facility and cash flows from operations in addition to our proceeds from our initial public offering. Our primary use of capital has been for investing in property and equipment used to provide our services.

As of December 31, 2016, our revolving credit facilities were undrawn, leaving an aggregate of $164.4 million, of available borrowing capacity under this facility.

The following table summarizes our liquidity as of the dates indicated:



	December 31,
	2016			2015
Cash and cash equivalents	$	29,238,618		$	4,038,899
Revolving credit facilities availability	164,354,373			161,556,653
Less long-term debt	—			(95,000,000		)
Less letter of credit facilities (rail car commitments)	(454,560		)	(1,930,560		)
Less letter of credit facilities (insurance programs)	(1,636,000		)	(1,176,000		)
Less letter of credit facilities (environmental remediation)	(1,375,342		)	(1,375,342		)
Net working capital (less cash)	30,453,429			30,788,570
Total	$	220,580,518		$	96,902,220

Liquidity and Cash Flows

The following table sets forth our cash flows for the periods indicated:



	Years Ended December 31,
	2016			2015			2014
Net cash provided by operating activities	$	29,688,435		$	69,638,685		$	15,853,116
Net cash used in investing activities	(7,717,614		)	(27,035,233		)	(190,411,028		)
Net cash (used in) provided by financing activities	3,074,661			(55,556,679		)	185,910,751
Effect of foreign exchange rate on cash	154,237			(226,655		)	(2,418,289		)
Net change in cash	$	25,199,719		$	(13,179,882	)	$	8,934,550

Operating Activities

Net cash provided by operating activities was $29.7 million, $69.6 million and $15.9 million, respectively, for the years ended December 31, 2016, 2015 and 2014. The decrease in operating cash flows from 2015 to 2016 was primarily attributable to the decrease in net income. The increase from 2014 to 2015 was primarily attributable to positive operating income generated by our pressure pumping services as well as cash generated by working capital changes. The cash generated from working capital changes was primarily attributable to the collection of receivables.

Investing Activities

Net cash used in investing activities was $7.7 million, $27.0 million and $190.4 million, respectively, for the years ended December 31, 2016, 2015 and 2014. Substantially all cash used in investing activities was used to purchase property and equipment that is utilized to provide our services. Additionally, in 2014, cash used in for business acquisitions amounted to $80.9 million.

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



	Years Ended December 31,
	2016		2015		2014
Pressure pumping services	$	7,673,187	$	4,169,678	$	180,466
Well services	404,612		6,768,143		11,441,285
Natural sand proppant production	528,049		2,371,526		5,493,441
Contract and directional drilling services	2,709,478		12,650,831		85,801,345
Other energy services	424,380		2,491,821		9,679,496
Net change in cash	$	11,739,706	$	28,451,999	$	112,596,033

Financing Activities

Net cash provided by (used in) financing activities was $3.1 million, $(55.6) million and $185.9 million for the years ended December 31, 2016, 2015 and 2014, respectively. In 2016, net cash provided by financing activities was primarily attributable to net proceeds of $103.1 million from the IPO, offset by net repayments of $95.0 million under our revolving credit facility and $5.0 million in capital distributions. In 2015, net cash used in financing activities was primarily attributable to net repayments of $51.0 million under our revolving credit facility, $3.9 million in capital distributions and $0.6 million in debt issuance costs. In 2014, net cash provided by financing activities was primarily attributable to net repayments of $53.7 million and capital contributions of $134.6 million, offset by $2.3 million in debt issuance costs.

Effect of Foreign Exchange Rate on Cash

The effect of foreign exchange rate on cash was $0.2 million, $(0.2) million and $2.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. The year-over-year effect was driven primarily by a favorable (unfavorable) shift in the weakness (strength) of the Canadian dollar relative to the U.S. dollar for the cash held in Canadian accounts.

Working Capital

Our working capital totaled $59.7 million and $34.8 million at December 31, 2016 and 2015, respectively. Our cash balances totaled $29.2 million and $4.0 million at December 31, 2016 and 2015, respectively.

Mammoth Revolving Credit Facility

On November 25, 2014, we entered into a $170.0 million revolving credit and security agreement with PNC Capital Markets LLC, as lead arranger, PNC Bank, National Association, as the administrative and collateral agent, and the lenders from time-to-time party thereto. Our revolving credit facility, as amended in connection with the IPO, matures on November 25, 2019. Borrowings under our revolving credit facility are secured by our and our subsidiaries’ assets. The maximum availability for future borrowings under our revolving credit facility is subject to a borrowing base calculation prepared monthly. Concurrent with our entry into our revolving credit facility, we repaid all of our then existing subordinate debt with the initial advance under our revolving credit facility.

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

We used a portion of the net proceeds from the IPO to repay all borrowings outstanding under our revolving credit facility and at February 21, 2017 our credit facility remained undrawn with availability of $142.6 million, net of outstanding letters of credit.

Our revolving credit facility contains various customary affirmative and restrictive covenants. Among the covenants are two financial covenants, including a minimum interest coverage ratio (3.0 to 1.0), and a maximum leverage ratio (4.0 to 1.0), and minimum availability ($10.0 million). As of December 31, 2016 and 2015, we were in compliance with these covenants.

Sturgeon Revolving Credit Facility

On June 30, 2015, Sturgeon entered in to a $25.0 million revolving line of credit, or 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, or (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. As of December 31, 2016 and 2015, there were no outstanding borrowings under the Sturgeon revolver, and availability was $18.2 million and $20.0 million, respectively.

The Sturgeon revolver contained various customary affirmative and restrictive covenants. Among the covenants were financial covenants including a minimum fixed charge coverage ratio (3.5 to 1.0) and a minimum availability block ($5.0 million). As of December 31, 2015, Sturgeon was in compliance with its covenants under the facility. Sturgeon was not in compliance with its fixed charge coverage ratio covenant at December 31, 2016, however the Sturgeon revolver was undrawn on that date. Sturgeon was in compliance with all other covenants at December 31, 2016.

Sturgeon's revolver was terminated on June 6, 2017 in connection with the Sturgeon acquisition.

Capital Requirements and Sources of Liquidity

As a result of the decline in drilling and completion activity, we reduced our capital expenditures in 2015 and have further reduced our capital expenditures in 2016. During 2016, our capital expenditures included $7.7 million on our pressure pumping services division primarily for pressure pumping equipment, $2.7 million in our contract land and directional drilling services division primarily for upgrades to our rig fleet, $0.4 million in our other energy services division primarily for an intersection upgrade, $0.4 million in our well services division primarily for upgrades on a coil tubing unit and $0.5 million in our natural sand proppant services division for a conveyor.

With commodity prices beginning to increase in the second half of 2016 and then stabilizing at their current range, we have seen an increase in customer demand, particularly in our pressure pumping and natural sand proppant services divisions. We have increased our capital budget accordingly and, during 2017, we currently estimate that our aggregate capital expenditures will be approximately $120.0 million. These capital expenditures include $66.0 million in our pressure pumping services division for the acquisition of an additional 132,500 horsepower of new high pressure hydraulic pumps and related equipment, $29.0 million in our pressure pumping service division for tractors, pneumatic trailers and transload facilities to enhance our last mile solutions, $9.0 million in our contract land and directional drilling services division for an upgrade to two of our horizontal rigs and $16.0 million in our well services and other energy services divisions, primarily to maintain our coil tubing and flowback services lines and add new service offerings.

We 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, as previously announced, we intend to actively pursue an acquisition strategy to enhance our portfolio of products and services, market positioning and/or geographic presence. We regularly evaluate acquisition opportunities, and the number of opportunities coming to our attention has increased substantially since the IPO. We do not

have a specific acquisition budget for 2017 since the timing and size of acquisitions cannot be accurately forecasted, however, we continue to evaluate opportunities. Our acquisitions may be undertaken with cash, our common stock or a combination of cash, common stock and/or other consideration. In the event we make one or more acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our revolving credit facility, joint venture partnerships, asset sales, offerings of debt or equity securities or other means. We cannot assure you that this additional capital will be available on acceptable terms or at all. If we are unable to obtain funds we need, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to conduct our operations.

Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2016:



	Total		Less than 1 year		1-3 Years		3-5 Years		More than 5 Years
Contractual obligations:
Long-term debt ⁽¹⁾	$	—	$	—	$	—	$	—	$	—
Interest and commitment fees on long-term debt ⁽²⁾	1,727,449		641,929		1,085,520		—		—
Operating lease obligations ⁽³⁾	19,458,702		6,587,913		6,097,454		2,785,606		3,987,729
Purchase commitment to sand suppliers ⁽⁴⁾	2,200,000		2,200,000		—		—		—
Purchase commitments to equipment manufacturers ⁽⁵⁾	18,554,769		18,554,769		—		—		—
	$	41,940,920	$	27,984,611	$	7,182,974	$	2,785,606	$	3,987,729


⁽¹⁾	The long-term debt excludes interest payments on each obligation.


⁽²⁾	Assumption of no long-term debt balance; future charges relate to commitment fees on credit facility.


⁽³⁾	Operating lease obligations relate to real estate, rail cars and other equipment.


⁽⁴⁾	The purchase commitment to a sand supplier represents our annual obligation to purchase a minimum amount of sand.


⁽⁵⁾	Obligations arising from capital improvements/equipment purchases.

Off-Balance Sheet Arrangements

Operating Leases

The Company leases real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2025. Aggregate future minimum lease payments under these non-cancelable operating leases in effect at December 31, 2016 are as follows:



Year ended December 31:	Amount
2017	$	6,587,913
2018	3,785,515
2019	2,311,939
2020	1,392,803
2021	1,392,803
Thereafter	3,987,729
	$	19,458,702

Other Commitments

We entered into a purchase agreement in 2014 with a sand supplier to begin January 1, 2015 and end December 31, 2016. We are subject to an annual commitment of 200,000 tons of sand. During June 2016, we paid a deposit of $0.6 million to the sand supplier to be netted against future purchases of sand under this contract and deferred the commitment until 2017. We have one additional unilateral option to extend for one additional year with a further deposit of $0.6 million. As of December 31, 2016, the future commitment for 2017 under this agreement was $2.2 million.

In the fourth quarter of 2016, we entered into agreements to acquire new high pressure fracturing units and other capital equipment. The future commitments under these agreements was $18.6 million as of December 31, 2016. Subsequently, in February 2017, we ordered additional new high pressure fracturing units with nameplate capacity of 57,500 horsepower and related equipment. The aggregate cost of the February 2017 commitments was $35.2 million. Additionally, subsequent to December 31, 2016, we ordered an aggregate of $84.4 million in other equipment across all operating segments.

Subsequent to December 31, 2016, we entered into an agreement to purchase sand from an unrelated third party seller with aggregate commitments of $30.8 million.

Subsequent to December 31, 2016, we entered into railcar lease agreements with aggregate commitments of $31.3 million.

On October 19, 2017, we entered into a contract to aid in the restoration of utility infrastructure on the island of Puerto Rico. The contract provides for payments of up to $200.0 million, including an initial payment of $15.0 million at the time of signing. As of October 26, 2017, we had entered into $23.8 million of commitments related to this contract and made prepayments and deposits of $5.0 million with respect to these commitments.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 1 of our consolidated financial statements appearing elsewhere in this report for a discussion of additional accounting policies and estimates made by management.

Use of Estimates. In preparing the financial statements, our management makes informed judgments and estimates that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the Company's sand reserves and their impact on calculating the depletion expense, the allowance for doubtful accounts, asset retirement obligation, reserves for self-insurance, depreciation and amortization of property and equipment, business combination valuations, amortization of intangible assets, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets, including goodwill.

Revenue Recognition. We generate revenue from multiple sources within our five operating divisions. In all cases, revenue is recognized when services are performed, collection of the receivables is probable, persuasive evidence of an arrangement exists and the price is fixed and determinable. Services are sold without warranty or the right to return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue. The specific revenue sources are outlined as follows:

Pressure Pumping Services Revenue. Pressure pumping services are typically provided based upon a purchase order, contract or on a spot market basis. Services are provided on a day rate, contracted or hourly basis, and revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and the personnel involved in such services or mobilization. Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. The labor charges and the use of consumable supplies are reflected on completed field tickets.

Well Services Revenue. Well services are typically provided based upon a purchase order, contract, or on a spot market basis. Services are provided on a day rate, contracted, or hourly basis, and revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Our equipment rental services are recognized upon completion of each day's work based on completed field ticket.

Natural Sand Proppant Services Revenue. Revenue from the sale of natural sand proppant is recognized according to the terms of title transfer on the sand. For proppant sold free on board plant, revenue is recognized when the sand is shipped. For proppant sold free on board destination, revenue is recognized when the sand reaches the customer specified transload facility or when the sand is loaded into a truck for last mile delivery depending on the specific terms of each sale.

Contract Land and Directional Drilling Services Revenue. Contract drilling services are provided under daywork or footage contracts, and revenue is recognized as the work progresses based on the days completed or the feet drilled, as applicable. Mobilization revenue and costs for daywork and footage contracts are recognized over the days of actual drilling. Directional drilling services are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Proceeds from customers for the cost of oilfield downhole rental equipment that is involuntarily damaged or lost in-hole are reflected as revenues.

Other Energy Services Revenue. Revenue from our other energy services is recognized when rooms are occupied and services have been rendered. Advance deposits on rooms and special events are deferred until services are provided to the customer.

Revenues arising from claims for amounts billed in excess of the contract price or for amounts not included in the original contract are recognized when billed less any allowance for uncollectibility. Revenue from such claims is only recognized if it is probable that the claim will result in additional revenue, the costs for the additional services have been incurred, management believes there is a legal basis for the claim and the amount can be reliably estimated. Revenues from such claims are recorded only to the extent that contract costs relating to the claims have been incurred. Historically, we have not billed any customer for amounts not included in the original contract.

The timing of revenue recognition may differ from contract billing or payment schedules, resulting in revenues that have been earned but not billed (“unbilled revenue”) or amounts that have been billed, but not earned (“deferred revenue”).

Allowance for Doubtful Accounts. We regularly review receivables and provide for estimated losses through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding our customers’ ability to make required payments, economic events and other factors. As the financial condition of customers change, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event we were to determine that a customer may not be able to make required payments, we would increase the allowance through a charge to income in the period in which that determination is made. Uncollectable accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made of their uncollectibility.

Depreciation and Amortization. In order to depreciate and amortize our property and equipment, we estimate useful lives, attrition factors and salvage values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry.

Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of such assets is evaluated by measuring the carrying amount of the assets against the estimated undiscounted future cash flows associated with the assets. If such evaluations indicate that the future undiscounted cash flow from the assets is not sufficient to recover the carrying value of such assets, the assets are adjusted to their estimated fair values.

Asset retirement obligation. Mine reclamation costs, future remediation costs for inactive mines or other contractual site remediation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred at a site. Such cost estimates include, where applicable, ongoing care, maintenance and monitoring costs. Changes in estimates at inactive mines are reflected in earnings in the period an estimate is revised.

Business Combinations. We account for our business acquisitions under the acquisition method of accounting as indicated in FASB ASC No. 805, “Business Combinations,” which requires the acquiring entity in a business combination to recognize the fair value of all assets acquired, liabilities assumed and any noncontrolling interest in the acquiree and establishes the acquisition date as the fair value measurement point. Accordingly, we recognize assets acquired and liabilities assumed in business combinations, including contingent assets and liabilities and noncontrolling interest in the acquiree, based on fair value estimates as of the date of acquisition. In accordance with FASB ASC No. 805, we recognize and measure goodwill, if any, as of the acquisition date, as the excess of the fair value of the consideration paid over the fair value of the identified net assets acquired.

When we acquire a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated for accounting purposes in a manner similar to the pooling of interest method of accounting. The assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.

Goodwill. Goodwill is tested for impairment annually, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The impairment test is a two-step process. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the implied value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities as if the reporting unit had been acquired in a business combination. The fair value of the reporting unit is determined using the discounted cash flow approach, excluding interest. The impairment for goodwill is measured as the excess of its carrying value over its implied value.

Share-based Compensation. The share-based compensation program consists of restricted stock units granted to employees and restricted stock units granted to non-employee directors under the Mammoth Energy Services, Inc. 2016 Incentive Plan (the "2016 Plan"). The Company recognizes in its financial statements the cost of employee services received in exchange for restricted stock based on the fair value of the equity instruments as of the grant date. In general, this value is amortized over the vesting period; for grants with a non-substantive service condition, this value is recognized immediately. Amounts are recognized in selling, general, and administrative expenses.

Income Taxes. Prior to our IPO, the Partnership and each of its subsidiaries, except Great White Sand Tiger Lodging Ltd., which we refer to as Lodging, was treated as a pass-through entity for federal income tax and most state income tax purposes. Accordingly, income taxes on net earnings were payable by the stockholders, members or partners and are not reflected in the historical financial statements. In connection with our IPO, we became a C corporation subject to federal

income taxes, which triggered the recognition of federal income tax liabilities associated with historical earnings. See Notes 1 and 2 to our consolidated financial statements included elsewhere in this report for more information. Lodging is subject to corporate income taxes and they are provided in the financial statements based upon Financial Accounting Standards Board, Accounting Standard Codification 740 Income Taxes. As such, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities as a result of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

New Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2015-17, "Income Taxes," which simplifies the presentation of deferred income taxes by requiring deferred tax liabilities and assets be classified as noncurrent in the balance sheet. ASU 2015-17 is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. The effect of the adoption is discussed in Note 2 to our consolidated financial statements included elsewhere in this report.

In July 2015, the FASB issued ASU No. 2015-11, “Inventory (Topic 330): Simplifying the Measurement of Inventory,” which changes inventory measured using any method other than last-in, first-out (LIFO) or the retail inventory method (for example, inventory measured using first-in, first-out (FIFO) or average cost) at the lower of cost and net realizable value. ASU 2015-11 is effective for annual and interim reporting periods beginning after December 15, 2016, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 supersedes existing revenue recognition requirements in GAAP and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. Additionally, it requires expanded disclosures regarding the nature, amount, timing, and certainty of revenue and cash flows from contracts with customers. The ASU was effective for annual and interim reporting periods beginning after December 15, 2016, using either a full or a modified retrospective application approach; however, in July 2015 the FASB decided to defer the effective date by one year (until 2018) by issuing ASU No. 2015-14, "Revenue From Contracts with Customers: Deferral of the Effective Date." The Company expects to adopt this new revenue guidance utilizing the retrospective method of adoption in the first quarter of 2018, and because the Company is still evaluating the portion of its revenues that may be subject to the new leasing guidance discussed below, it is unable to quantify the impact that the new revenue standard will have on the Company’s consolidated financial statements upon adoption.

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

Item 8. Financial Statements and Supplementary Data

The information required by this item appears beginning on page F-1 following the signature pages of this report.

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Mammoth Energy Services, Inc.

We have audited the accompanying consolidated balance sheets of Mammoth Energy Services, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of comprehensive (loss) income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Sturgeon Acquisitions LLC, a wholly-owned subsidiary, which statements reflect total assets constituting $84,509,742 and $92,530,726, respectively, of consolidated total assets as of December 31, 2016 and 2015, and total revenues of $27,473,025, $31,643,413 and $18,212,230, respectively, of consolidated total revenues for the years ended December 31, 2016 and 2015 and the period from September 13, 2014 to December 31, 2014. Those statements were audited by other auditors, whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Sturgeon Acquisitions LLC, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company adopted new accounting guidance in 2016 and 2015 related to the presentation of deferred income taxes.

In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Mammoth Energy Services, Inc. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.

/s/GRANT THORNTON LLP

Oklahoma City, Oklahoma

October 26, 2017

F- 1

MAMMOTH ENERGY SERVICES, INC.

CONSOLIDATED BALANCE SHEETS



ASSETS	December 31,
	2016 (a)			2015 (a)
CURRENT ASSETS
Cash and cash equivalents	$	29,238,618		$	4,038,899
Accounts receivable, net	21,169,579			18,365,269
Receivables from related parties	27,589,283			25,121,985
Inventories	6,124,201			7,527,523
Prepaid expenses	4,425,872			4,784,843
Other current assets	391,599			422,219
Total current assets	88,939,152			60,260,738

Property, plant and equipment, net	242,119,663			294,882,932
Sand reserves	55,367,295			56,250,996
Intangible assets, net - customer relationships	15,949,772			24,309,772
Intangible assets, net - trade names	5,617,057			6,328,057
Goodwill	88,726,875			88,726,875
Other non-current assets	5,642,661			5,652,765
Total assets	$	502,362,475		$	536,412,135

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	20,469,542		$	16,940,810
Payables to related parties	203,209			415,563
Accrued expenses and other current liabilities	8,546,198			8,049,984
Income taxes payable	28,156			26,912
Total current liabilities	29,247,105			25,433,269

Long-term debt	—			95,000,000
Deferred income taxes	47,670,789			1,460,959
Asset retirement obligation	259,804			94,904
Other liabilities	2,404,422			476,233
Total liabilities	79,582,120			122,465,365

COMMITMENTS AND CONTINGENCIES (Note 17)

EQUITY
Equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 37,500,000	375,000			—
issued and outstanding at December 31, 2016; zero issued and outstanding at
December 31, 2015
Additional paid in capital	400,205,921			—
Accumulated deficit	(56,322,878		)	—
Common units, 30,000,000 issued and outstanding at December 31, 2015	—			329,090,230
Members' equity	81,738,675			90,783,508
Accumulated other comprehensive loss	(3,216,363		)	(5,926,968		)
Total equity	422,780,355			413,946,770
Total liabilities and equity	$	502,362,475		$	536,412,135

(a) Financial information has been recast to include the financial position and results attributable to Sturgeon Acquisitions LLC ("Sturgeon"). See Note 15.

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

F- 2

MAMMOTH ENERGY SERVICES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME



	Years Ended December 31,
	2016 (a)			2015 (a)			2014 (a)
REVENUE
Services revenue	$	89,642,899		$	172,012,405		$	182,341,309
Services revenue - related parties	107,147,000			132,552,858			30,834,421
Product revenue	8,052,445			25,189,559			53,174,559
Product revenue - related parties	25,783,253			38,181,970			9,379,145
Total revenue	230,625,597			367,936,792			275,729,434

COST AND EXPENSES
Services cost of revenue (1)	140,063,016			225,944,268			150,482,793
Services cost of revenue - related parties	1,063,231			1,378,833			740,591
Product cost of revenue (2)	31,892,044			47,364,148			44,885,817
Product cost of revenue - related parties	2,455			—			2,422,519
Selling, general and administrative	17,290,623			21,449,432			15,783,971
Selling, general and administrative - related parties	757,892			950,588			2,754,877
Depreciation and amortization	72,315,398			74,498,574			36,365,598
Impairment of long-lived assets	1,870,885			12,124,353			—
Total cost and expenses	265,255,544			383,710,196			253,436,166
Operating (loss) income	(34,629,947		)	(15,773,404		)	22,293,268

OTHER (EXPENSE) INCOME
Interest income	$	—		$	98,492		$	214,141
Interest expense	(4,096,182		)	(5,464,547		)	(4,603,595		)
Interest expense - related parties	—			—			(184,479		)
Other, net	158,172			(2,269,058		)	(5,727,164		)
Total other expense	(3,938,010		)	(7,635,113		)	(10,301,097		)
(Loss) income before income taxes	(38,567,957		)	(23,408,517		)	11,992,171
Provision (benefit) for income taxes	53,884,871			(1,589,086		)	7,514,194
Net (loss) income	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977

OTHER COMPREHENSIVE (LOSS) INCOME
Foreign currency translation adjustment (3)	2,710,605			(4,814,819		)	472,714
Comprehensive (loss) income	$	(89,742,223	)	$	(26,634,250	)	$	4,950,691

Net (loss) earnings per share (basic and diluted) (Note 10)	$	(2.94	)	$	(0.73	)	$	0.21
Weighted average number of shares outstanding (Note 10)	31,500,000			30,000,000			21,056,073

Pro Forma C Corporation Data (unaudited):
Net (loss) income, as reported	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Taxes on income earned as a non-taxable entity (Note 10)	15,224,009			390,801			(7,590,480		)
Taxes due to change to C corporation (Note 10)	53,088,861			—			—
Pro forma net loss	$	(24,139,958	)	$	(21,428,630	)	$	(3,112,503	)
Basic and Diluted (Note 10)	$	(0.56	)	$	(0.50	)	$	(0.14	)
Weighted average pro forma shares outstanding—basic and diluted (Note 10)	43,107,452			43,107,452			22,730,627

(1) Exclusive of depreciation and amortization	65,705,373			68,053,581			31,687,048
(2) Exclusive of depreciation and amortization	6,477,214			6,297,798			4,597,583
(3) Net of tax	1,731,887			—			298,170

(a) Financial information has been recast to include the financial position and results attributable to Sturgeon. See Note 15.

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

F- 3

MAMMOTH ENERGY SERVICES, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY





	Common Stock					Members'			Accumulated			Common			Paid-In
	Shares		Amount			Equity			Deficit			Partners			Capital		AOCL			Total
Balance at January 1, 2014	100		$	1		$	116,370,107		$	5,928,873		$	—		$	—	$	(1,584,863	)	$	120,714,118
Capital contributions	—		—			134,553,502			—			—			—		—			134,553,502
Equity based compensation through November 24, 2014	—		—			212,537			—			—			—		—			212,537
Dividends paid	—		—			—			(12,301		)	—			—		—			(12,301		)
Net income through November 24, 2014	—		—			4,177,882			5,210,867			—			—		—			9,388,749
Contribution of predecessor interests for 20MM units (Note 1)	(100	)	(1		)	(172,529,028		)	(11,127,439		)	180,465,348			—		—			(3,191,120		)
Acquisition of Stingray (Note 12)	—		—			—			—			183,630,000			—		—			183,630,000
Equity based compensation from November 25, 2014 to December 31, 2014	—		—			—			—			3,626,304			—		—			3,626,304
Net income	—		—			6,488,525			—			—			—		—			6,488,525
Net loss from November 25, 2014 to December 31, 2014	—		—			—			—			(11,399,297		)	—		—			(11,399,297		)
Other comprehensive gain, net of tax	—		—			—			—			—			—		472,714			472,714
Balance at December 31, 2014 (a)	—		—			89,273,525			—			356,322,355			—		(1,112,149		)	444,483,731
Net income (loss)	—		—			5,411,983			—			(27,231,414		)	—		—			(21,819,431		)
Capital distributions	—		—			(3,902,000		)	—			(711		)	—		—			(3,902,711		)
Other comprehensive income	—		—			—			—			—			—		(4,814,819		)	(4,814,819		)
Balance at December 31, 2015 (a)	—		—			90,783,508			—			329,090,230			—		(5,926,968		)	413,946,770
Net loss prior to LLC conversion	—		—			—			—			(32,085,117		)	—		—			(32,085,117		)
Net loss	—		—			(4,044,833		)	—			—			—		—			(4,044,833		)
Capital distributions	—		—			(5,000,000		)	—			—			—		—			(5,000,000		)
Equity based compensation	—		—			—			—			(18,683		)	—		—			(18,683		)
LLC Conversion (Note 1)	—		—			—			—			(296,986,430		)	296,986,430		—			—
Issuance of common stock at public offering, net of offering costs	37,500,000		375,000			—			—			—			102,699,661		—			103,074,661
Stock-based compensation	—		—			—			—			—			519,830		—			519,830
Net loss subsequent to LLC conversion	—		—			—			(56,322,878		)				—		—			(56,322,878		)
Other comprehensive income	—		—			—			—			—			—		2,710,605			2,710,605
Balance at December 31, 2016 (a)	37,500,000		$	375,000		$	81,738,675		$	(56,322,878	)	$	—		$	400,205,921	$	(3,216,363	)	$	422,780,355

(a) Financial information includes the financial position and results attributable to Sturgeon. See Note 15.

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

F- 4

MAMMOTH ENERGY SERVICES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Years Ended December 31,
	2016 (a)			2015 (a)			2014 (a)
Cash flows from operating activities
Net (loss) income	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Adjustments to reconcile net loss to cash provided by operating activities:
Equity based compensation	501,147			—			3,838,842
Depreciation, depletion, accretion and amortization	72,315,398			74,498,573			36,365,598
Amortization of coil tubing strings	2,027,752			2,075,787			1,508,761
Amortization of debt origination costs	603,124			500,964			1,094,367
Bad debt expense	1,968,001			3,881,397			603,289
(Gain) loss on disposal of property and equipment	(701,903		)	1,429,087			(341,459		)
Impairment of long-lived assets	1,870,885			12,124,353			—
Deferred income taxes	47,898,688			(5,717,451		)	5,814,982
Changes in assets and liabilities:
Accounts receivable, net	(4,640,671		)	32,027,033			(1,922,964		)
Receivables from related parties	(2,462,211		)	9,769,972			(26,741,370		)
Inventories	(624,430		)	(3,998,175		)	(219,321		)
Prepaid expenses and other assets	(198,461		)	4,286,894			(2,220,553		)
Accounts payable	1,411,822			(30,169,363		)	288,195
Payables to related parties	(248,528		)	(756,374		)	(6,514,594		)
Accrued expenses and other liabilities	2,419,880			(8,502,858		)	1,942,159
Income taxes payable	770			8,277			(2,120,793		)
Net cash provided by operating activities	29,688,435			69,638,685			15,853,116

Cash flows from investing activities:
Purchases of property and equipment	(11,739,706		)	(28,451,999		)	(112,498,579		)
Purchases of property and equipment - related parties	—			—			(97,454		)
Business acquisition, net of cash acquired (Note 13 and 15)	—			—			(80,881,068		)
Proceeds from disposal of property and equipment	4,022,092			1,416,766			3,063,803
Other, net	—			—			2,270
Net cash used in investing activities	(7,717,614		)	(27,035,233		)	(190,411,028		)

Cash flows from financing activities:
Borrowings on long-term debt	28,733,679			14,571,158			203,690,193
Repayments of long-term debt	(123,733,679		)	(65,612,171		)	(149,992,040		)
Proceeds from initial public offering	105,838,750			—			—
Initial public offering costs	(2,764,089		)	—			—
Debt issuance costs	—			(612,955		)	(2,328,603		)
Capital distributions	(5,000,000		)	(3,902,711		)	(12,301		)
Capital contributions	—			—			134,553,502
Net cash (used in) provided by financing activities	3,074,661			(55,556,679		)	185,910,751
Effect of foreign exchange rate on cash	154,237			(226,655		)	(2,418,289		)
Net increase (decrease) in cash and cash equivalents	25,199,719			(13,179,882		)	8,934,550
Cash and cash equivalents at beginning of period	4,038,899			17,218,781			8,284,231
Cash and cash equivalents at end of period	$	29,238,618		$	4,038,899		$	17,218,781

Supplemental disclosure of cash flow information:
Cash paid for interest	$	3,707,009		$	5,191,640		$	3,492,763
Cash paid for income taxes	$	3,587,871		$	3,888,470		$	3,709,620
Supplemental disclosure of non-cash transactions:
Acquisition of Stingray Pressure Pumping and Stingray Logistics (Note 13)	$	—		$	—		$	176,570,932
Purchases of property and equipment included in trade accounts payable	$	2,788,602		$	740,555		$	7,047,706

(a) Financial information has been recast to include the financial position and results attributable to Sturgeon. See Note 15.

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

F- 5

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Organization and Basis of Presentation

The accompanying consolidated financial statements were prepared in accordance with the rules and regulations of the Securities and Exchange Commission, and reflect all adjustments, which in the opinion of management are necessary for the fair presentation of the results.

Mammoth Energy Services, Inc. ("Mammoth Inc." or the "Company"), together with its subsidiaries, is an integrated, growth-oriented energy services company serving companies engaged in the exploration and development of North American onshore unconventional oil and natural gas reserves. The Company was incorporated in Delaware in June 2016 as a wholly-owned subsidiary of Mammoth Energy Partners, LP, a Delaware limited liability company (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 Energy Services Inc. and was converted to a Delaware limited partnership in August 2014. On November 24, 2014, Mammoth Energy Holdings, LLC (“Mammoth Holdings,” an entity controlled by Wexford), Gulfport Energy Corporation (“Gulfport”) and Rhino Resource Partners LP (“Rhino”) (collectively known as “Predecessor Interest”) contributed their interest in certain of the entities presented below to the Partnership in exchange for 20 million limited partner units. Mammoth Energy Partners GP, LLC (the “General Partner”) held a non-economic general partner interest in the Partnership.

The following companies (“Operating Entities”) are included in these consolidated financial statements: Bison Drilling and Field Services, LLC (“Bison Drilling”), formed November 15, 2010; Bison Trucking LLC (“Bison Trucking”), formed August 9, 2013; White Wing Tubular Services LLC (“White Wing”), formed July 29, 2014; Barracuda Logistics LLC (“Barracuda”), formed October 24, 2014; Mr. Inspections LLC (“MRI”), formed January 25, 2015; Panther Drilling Systems LLC (“Panther”), formed December 11, 2012; Redback Energy Services, LLC (“Energy Services”), formed October 6, 2011; Redback Coil Tubing, LLC (“Coil Tubing”), formed May 15, 2012; Redback Pump Down Services LLC (“Pump Down”), formed January 16, 2015; Muskie Proppant LLC (“Muskie”), formed September 14, 2011; Stingray Pressure Pumping LLC (“Pressure Pumping”), formed March 20, 2012; Stingray Logistics LLC (“Logistics”), formed November 19, 2012; Great White Sand Tiger Lodging Ltd. (“Lodging”), formed October 1, 2007; Sand Tiger Holdings, Inc. ("ST Holdings"), formed June 27, 2007; Silverback Energy Services LLC ("Silverback"), formed June 8, 2016; and Mammoth Equipment Leasing LLC, formed on November 14, 2016. Prior to the contribution, the Partnership did not conduct any material business operations other than certain activities related to the preparation of the registration statement for a proposed initial public offering.

In addition, on June 5, 2017, Mammoth acquired Sturgeon Acquisitions LLC (“Sturgeon”) and Sturgeon's wholly-owned subsidiaries, Taylor Frac, LLC (“Taylor Frac”), Taylor Real Estate Investments, LLC (“Taylor RE”) and South River Road, LLC (“South River”) (collectively, the "Sturgeon Acquisition"). The accompanying financial statements have been recast to include the financial position and results attributable to the Sturgeon Acquisition. See Note 15 for additional information regarding the Sturgeon Acquisition.

The contribution on November 24, 2014 of all Operating Entities, except Pressure Pumping, Logistics and entities created after contribution, was treated as a combination of entities under common control. On November 24, 2014, the Partnership also acquired Pressure Pumping and Logistics (collectively, the “Stingray Entities”) in exchange for 10 million limited partner units.

On October 12, 2016, the Partnership was converted into a Delaware limited liability company named Mammoth Energy Partners LLC (“Mammoth LLC”), and then Mammoth Holdings, Gulfport and Rhino, as all the members of Mammoth LLC, contributed their member interests in Mammoth LLC to Mammoth Inc. Prior to the conversion and the contribution, Mammoth Inc. was a wholly-owned subsidiary of the Partnership. Following the conversion and the contribution, Mammoth LLC (as the converted successor to the Partnership) was a wholly-owned subsidiary of Mammoth Inc. Mammoth Inc. did not conduct any material business operations until Mammoth LLC was contributed to it. On October 19, 2016, Mammoth Inc. closed its initial public offering of 7,750,000 shares of common stock (the "IPO"), which included an aggregate of 250,000 shares that were offered by Mammoth Holdings, Gulfport and Rhino, at a price to the public of $15.00 per share.

Net proceeds to Mammoth Inc. from its sale of 7,500,000 shares of common stock were approximately $103.1 million. On the closing date of the IPO, Mammoth Inc. repaid all outstanding borrowings under its revolving credit facility and intends to use the remaining net proceeds for general corporate purposes, which may include the acquisition of additional

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equipment and complementary businesses that enhance its existing service offerings, broaden its service offerings or expand its customer relationships.

At December 31, 2015, Mammoth Holdings, Gulfport and Rhino owned 68.7%, 30.5% and 0.8%, respectively, of the limited partner interest in the Predecessor. At December 31, 2016, Mammoth Holdings, Gulfport and Rhino owned the following share of outstanding common stock of Mammoth Inc:



	At December 31, 2016
	Share Count	% Ownership
Mammoth Holdings	20,443,903	54.5	%
Gulfport	9,073,750	24.2	%
Rhino	232,347	0.6	%
Outstanding shares owned by related parties	29,750,000	79.3	%
Total outstanding	37,500,000	100.0	%

Operations

The Company's pressure pumping services include equipment and personnel used in connection with the completion and early production of oil and natural gas wells, well services include coil tubing units used to enhance the flow of oil or natural gas, natural sand proppant services include the distribution and production of natural sand proppant that is used primarily for hydraulic fracturing in the oil and gas industry. The Company's contract land and directional drilling services provides drilling rigs and directional tools for both vertical and horizontal drilling of oil and natural gas wells. The Company also provides other energy services, currently consisting of remote accommodations, for people working in the oil sands located in Northern Alberta, Canada.

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

All of the Company’s operations are in North America. The Company operates in the Permian Basin, the Utica Shale, the Eagle Ford Shale, the Marcellus Shale, the Granite Wash, the Cana-Woodford Shale, the Cleveland Sand and the oil sands located in Northern Alberta, Canada. The Company's business depends in large part on the conditions in the oil and natural gas industry and, specifically, on the amount of capital spending by its customers. Any prolonged increase or decrease in oil and natural gas prices affects the levels of exploration, development and production activity, as well as the entire health of the oil and natural gas industry. Changes in the commodity prices for oil and natural gas could have a material effect on the Company’s results of operations and financial condition.


2.	Summary of Significant Accounting Policies

(a) Principles of Consolidation

The consolidated financial statements are prepared in accordance with Generally Accepted Accounting Principles ("GAAP"). All material intercompany accounts and transactions between the entities within the Company have been eliminated.

(b) Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the Company's sand reserves and their impact on calculating the depletion expense, the allowance for doubtful accounts, asset retirement obligation, reserves for self-insurance, depreciation, depletion, accretion and amortization of property and equipment, business combination valuations, amortization of intangible assets, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets, including goodwill.

All highly liquid investments with an original maturity of three months or less are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance

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Corporation, with the exception of cash held by Lodging in a Canadian financial institution. At December 31, 2016, we had $5.6 million, in Canadian dollars, of cash in Canadian accounts. Cash balances from time to time may exceed the insured amounts; however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks on such accounts.

(d) Accounts Receivable

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

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

Following is a roll forward of the allowance for doubtful accounts for the years ended December 31, 2016, 2015 and 2014:



Balance, January 1, 2014	$	1,621,147
Additions charged to expense	603,289
Deductions for uncollectible receivables written off	(1,634,934		)
Balance, December 31, 2014	589,502
Additions charged to expense	3,881,397
Deductions for uncollectible receivables written off	(458,967		)
Balance, December 31, 2015	4,011,932
Additions charged to expense	1,968,001
Deductions for uncollectible receivables written off	(602,967		)
Balance, December 31, 2016	$	5,376,966

As discussed in Note 1, prolonged declines in pricing can impact the overall health of the oil and natural gas industry. The year ended December 31, 2016 contained such pricing conditions which may lead to enhanced risk of uncollectiblity on certain receivables. As such, the Company has made specific reserves consistent with Company policy which resulted in additions to allowance for doubtful accounts. The Company will continue to pursue collection until such time as final determination is made, consistent with Company policy.

(e) Inventory

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

Inventory processed at the Company’s sand production facility includes direct excavation costs, processing costs, and overhead allocation. Stockpile tonnages are calculated by measuring the number of tons added and removed from the stockpile. Tonnages are verified periodically by an independent surveyor. Costs are calculated on a per ton basis and are applied to the stockpiles based on the number of tons in the stockpile. Inventory transported for sale at the Company’s terminal facility includes the cost of purchased or processed sand, plus transportation related charges.

Inventory also consists of coil tubing strings of various widths, diameters and lengths that are used in providing specialized services to customers who are primarily operators of oil or gas wells. The strings are used at various rates

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based on factors such as well conditions (i.e. pressure and friction), vertical and horizontal length of the well, running speed of the string in the well, and total running feet accumulated to the string. The Company obtains usage information from data acquisition software and other established assessment methods and attempts to amortize the strings over their estimated useful life. In no event will a string be amortized over a period longer than 12 months. Amortization of coil strings is included in services cost of revenue in the Consolidated Statements of Comprehensive Loss and totaled $2,027,752, $2,075,787 and $1,508,761 for the years ended December 31, 2016, 2015 and 2014, respectively.

(f) Prepaid Expenses

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

(g) Property and Equipment

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs that do not increase the capacity, improve the efficiency or safety, or improve or extend the useful life are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is recorded in operations. Depreciation is calculated using the straight-line method over the shorter of the estimated useful life, or the remaining lease term, as applicable. Depreciation does not begin until property and equipment is placed in service. Once placed in service, depreciation on property and equipment continues while being repaired, refurbished, or between periods of deployment.

(h) Sand reserves

Sand reserve costs include engineering, mineralogical studies and other related costs to develop the mine, the removal of overburden to initially expose the mineral and building access ways. Exploration costs are expensed as incurred and classified as product cost of revenue. Capitalization of mine development project costs begins once the deposit is classified as proven and probable reserves. Drilling and related costs are capitalized for deposits where proven and probable reserves exist and the activities are directed at obtaining additional information on the deposit or converting non-reserve minerals to proven and probable reserves and the benefit is to be realized over a period greater than one year. Mining property and development costs are amortized using the units-of-production method on estimated measured tons in in-place reserves. The impact of revisions to reserve estimates is recognized on a prospective basis.

(i) Long-Lived Assets

The Company reviews long-lived assets for recoverability in accordance with the provisions of Financial Accounting Standards Board ("FASB") Accounting Standard Codification (“ASC”) Topic 360, Impairment or Disposal of Long-Lived Assets, which requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Recoverability of assets is measured by comparing the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. These evaluations for impairment are significantly impacted by estimates of revenues, costs and expenses, and other factors. If long-lived assets are considered to be impaired, the impairment to be recognized is measured by the amount in which the carrying amount of the assets exceeds the fair value of the assets. For the years ended December 31, 2016, and 2015, the Company recognized an impairment loss of $1,870,885 and $9,874,458, respectively, on various fixed assets included in property, plant and equipment, net in the Consolidated Balance Sheets. Additionally, during the year ended December 31, 2015, the Company recognized an impairment loss of $1,904,982 on a terminated long term contractual agreement. No impairments occurred during the year ended December 31, 2014.

(j) Goodwill

Goodwill is tested for impairment annually, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The impairment test is a two-step process. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the implied value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities as if the reporting unit had been acquired in a business combination. The fair value of the reporting unit is determined using the discounted cash flow approach, excluding interest. The impairment for goodwill is measured as the excess of its carrying value over its implied value. Goodwill was tested for impairment as of December 31, 2016. For the years ended December 31, 2016 and 2014, no impairment losses were recognized. During year ended December 31, 2015, the Company recognized impairments of $88,247.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(k) Other Non-Current Assets

Other non-current assets primarily consist of deferred financing costs on the credit facility (See Note 8) and sales tax receivables.

(l) Asset Retirement Obligation

Mine reclamation costs, future remediation costs for inactive mines or other contractual site remediation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred at a site. Such cost estimates include, where applicable, ongoing care, maintenance and monitoring costs. Changes in estimates at inactive mines are reflected in earnings in the period an estimate is revised.

(m) Business Combinations

The Company accounts for its business acquisitions under the acquisition method of accounting as indicated in FASB ASC No. 805, Business Combinations, which requires the acquiring entity in a business combination to recognize the fair value of all assets acquired, liabilities assumed and any noncontrolling interest in the acquiree and establishes the acquisition date as the fair value measurement point. Accordingly, the Company recognizes assets acquired and liabilities assumed in business combinations, including contingent assets and liabilities and noncontrolling interest in the acquiree, based on fair value estimates as of the date of acquisition. In accordance with FASB ASC No. 805, the Company recognizes and measures goodwill, if any, as of the acquisition date, as the excess of the fair value of the consideration paid over the fair value of the identified net assets acquired.

When the Company acquires a business from an entity under common control, whereby the companies are ultimately controlled by the same party or parties both before and after the transaction, it is treated for accounting purposes in a manner similar to the pooling of interest method of accounting. The assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.

(n) Amortizable Intangible Assets

Intangible assets subject to amortization include customer relationships and trade names. Customer relationships are amortized based on an estimated attrition factor and trade names are amortized over their estimated useful lives. During the year ended December 31, 2015, the Company terminated one customer relationship and impaired the remaining unamortized value of the intangible and recognized an impairment loss of $256,666. There were no impairment losses recognized for amortizable assets for either the years ended December 31, 2016 or 2014.

(o) 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 and payables from related parties and trade payables approximates fair value because of the short-term nature of the instruments. The fair value of long-term debt approximates its carrying value because the cost of borrowing fluctuates based upon market conditions.

(p) Revenue Recognition

The Company generates revenue from multiple sources within its operating segments. In all cases, revenue is recognized when services are performed, collection of the receivable is probable, persuasive evidence of an arrangement exists, and the price is fixed and determinable. Services are sold without warranty or right of return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue.

Pressure pumping services are typically provided based upon a purchase order, contract, or on a spot market basis. Services are provided on a day rate, contracted, or hourly basis, and revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location, and personnel. Additional revenue is generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. The labor charges and the use of consumable supplies are reflected on the completed field tickets.

Natural sand proppant revenues are recognized when legal title passes to the customer, which may occur at the production facility, rail origin or at the destination terminal. At that point, delivery has occurred, evidence of a contractual arrangement exists, the price is fixed and determinable, and collectability is reasonably assured. Amounts received from customers in advance of sand deliveries are recorded as deferred revenue. Customers have the ability to make up

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

contractual short falls by achieving higher-than-contracted volumes over the shortfall window. Contractual shortfall revenue is deemed not probable until the end of the measurement period.

Well services are typically provided based upon a purchase order, contract, or on a spot market basis. Services are provided on a day rate, contracted, or hourly basis, and revenue is recognized as the work progresses. Jobs for these services are typically short-term in nature and range from a few hours to multiple days. Our equipment rental services are recognized upon completion of each day's work based on a completed field ticket.

Contract drilling services are provided under daywork or footage contracts, and revenue is recognized as the work progresses based on the days completed or the feet drilled, as applicable. Mobilization revenue and costs for daywork and footage contracts are recognized over the days of actual drilling.

Directional drilling services are provided on a day rate or hourly basis, and revenue is recognized as work progresses. Proceeds from customers for the cost of equipment that is damaged or lost down-hole are reflected as service revenues as this is deemed to be perfunctory or inconsequential to the underlying service being performed.

Revenue from remote accommodation services is recognized when rooms are occupied and services have been rendered. Advance deposits on rooms and special events are deferred until services are provided to the customer. During the year ended December 31, 2016, the Company recognized and collected $524,997 in business interruption insurance proceeds which is included in Service revenue in the accompanying Consolidated Statements of Comprehensive Loss. The proceeds resulted from loss of revenue relating to wildfires that forced evacuation of personnel.

The timing of revenue recognition may differ from contract billing or payment schedules, resulting in revenues that have been earned but not billed (“unbilled revenue”). The Company had $2,744,986 and $3,414,853 of unbilled revenue included in accounts receivable, net in the Consolidated Balance Sheets at December 31, 2016 and 2015, respectively. The Company had $10,505,240 and $7,459,988 of unbilled revenue included in receivables from related parties in the Condensed Consolidated Balance Sheets at December 31, 2016 and 2015, respectively.

(q) Earnings per Share

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

(r) Unaudited Pro Forma Earnings (loss) per Share

The Company’s pro forma basic earnings (loss) per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued at the IPO were outstanding for the full year of 2016 and 2015. Diluted earnings per share reflects the potential dilution, using the treasury stock method. During periods in which the Company realizes a net loss, restricted stock awards would be anti-dilutive to net loss per share and conversion into common stock is assumed not to occur.

(s) Equity-based Compensation

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

(t) Stock-based Compensation

The Company's stock-based compensation program consists of restricted stock units granted to employees and restricted stock units granted to non-employee directors under the Mammoth Energy Services, Inc. 2016 Incentive Plan (the "2016 Plan"). The Company recognizes in its financial statements the cost of employee services received in exchange for restricted stock based on the fair value of the equity instruments as of the grant date. In general, this value is amortized over the vesting period; for grants with a non-substantive service condition, this value is recognized immediately. Amounts are recognized in selling, general, and administrative expenses. See Note 12.

In March 2016, the FASB issued Accounting Standard Update ("ASU") No. 2016-09, “Compensation - Stock Compensation,” which modifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. ASU 2016-09 is effective for annual reporting periods beginning after December 15, 2016 with early adoption permitted. With the early adoption of this standard, we are accounting for forfeitures in the period in which they occur. The adoption has no impact on prior period as the year ended December 31, 2016 is the first year under which the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company is treated as as a taxable entity for federal income tax purposes and there have been no historical vestings of either equity or share-based compensation.

(u) Income Taxes

On October 12, 2016, immediately prior to the IPO of Mammoth Inc., the Partnership converted into a limited liability company named Mammoth Energy Partners LLC (“Mammoth LLC”). All equity interests in Mammoth LLC were contributed to Mammoth Inc. and Mammoth LLC became a wholly owned subsidiary of Mammoth Inc. Mammoth Inc. is a C corporation under the Internal Revenue Code and is subject to income tax. Historically, Mammoth LLC and each of the Operating Entities (including the entities acquired in the Sturgeon Acquisition) other than Lodging was treated as a partnership for federal income tax purposes. As a result, essentially all taxable earnings and losses were passed through to its members, and Mammoth LLC did not pay any federal income taxes at the entity level. Mammoth Inc. owns the member interests in several single member limited liability companies. These LLCs are subject to taxation in Texas where the Company does business; therefore, the Company may provide for income taxes attributable to that state on a current basis. The income tax provision for the period before the IPO has been prepared on a separate return basis for Mammoth LLC and all of its subsidiaries that were treated as a partnership for federal income tax purposes.

Subsequent to the IPO, the Company's operations are included in a consolidated federal income tax return (with the exception of the entities acquired in the Sturgeon Acquisition) and other state returns. Accordingly, the Company has recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases for all our subsidiaries as if each entity were a corporation, regardless of its actual characterization for U.S. federal income tax purposes. The Company's effective tax rate was 34.6%, excluding the conversion to a C Corporation (See Note 1), for the year ended December 31, 2016. The Company's effective tax rate can fluctuate as a result of the impact of state income taxes, permanent differences and changes in pre-tax income.

Under FASB ASC 740, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities as a result of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

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

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

The Company evaluates tax positions taken or expected to be taken in preparation of its tax returns and disallows the recognition of tax positions that do not meet a “more likely than not” threshold of being sustained upon examination by the taxing authorities. During the years ended December 31, 2016 and 2015, no material uncertain tax positions existed. Penalties and interest, if any, are recognized in general and administrative expense. The Company's 2016, 2015, 2014 and 2013 income tax returns remain open to examination by the applicable taxing authorities.

In November 2015, the FASB issued ASU No. 2015-17, "Income Taxes," which simplifies the presentation of deferred income taxes by requiring deferred tax liabilities and assets be classified as noncurrent in the balance sheet. ASU 2015-17 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Early adoption was elected for the year ended December 31, 2016 with a retrospective change to the December 31, 2015 consolidated balance sheet as previously presented is required pursuant to ASU 2015-17. There was no impact on the December 31, 2015 consolidated balance sheet.

(v) Foreign Currency Translation

For foreign operations, assets and liabilities are translated at the period-end exchange rate, and income statement items are translated at the average exchange rate for the period. Resulting translation adjustments are recorded within accumulated

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other comprehensive loss. Assets and liabilities denominated in foreign currencies, if any, are re-measured at the balance sheet date. Transaction gains or losses are included as a component of current period earnings.

(w) Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Company’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed as incurred. Liabilities are recorded when environmental costs are probable, and the costs can be reasonably estimated. The Company maintains insurance which may cover in whole or in part certain environmental expenditures. As of December 31, 2016 and 2015, there were no probable environmental matters.

(x) Other Comprehensive (Loss) Income

Comprehensive loss consists of net loss and other comprehensive loss. Other comprehensive loss included certain changes in equity that are excluded from net loss. Specifically, cumulative foreign currency translation adjustments are included in accumulated other comprehensive loss.

(y) Concentrations of Credit Risk and Significant Customers

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents in excess of federally insured limits and trade receivables. The Company's accounts receivable have a concentration in the oil and gas industry and the customer base consists primarily of independent oil and natural gas producers. At December 31, 2016 and 2015, no third-party customer accounted for more than 10% of the Company's trade accounts receivable and receivables from related parties balance combined. At December 31, 2016, and 2015, related party customers accounted for 57% and 58%, respectively, of the Company's trade accounts receivable and receivables from related parties balance combined. At December 31, 2016 and 2015, one related party customer from the pressure pumping segment accounted for 39% and 37%, respectively, of the Company's trade accounts receivable and receivables from related parties balance combined. At December 31, 2016 and 2015, one related party customer from the natural sand proppant segment accounted for 11% and 16%, respectively, of the Company's trade accounts receivable and receivables from related parties balance combined. At December 31, 2016 and 2015, one related party customer accounted for 53% and 56%, respectively, of the Company's trade accounts receivable and receivables from related parties balance combined. During the years ended December 31, 2016 and 2015, one related party customer accounted for 57% and 46%, respectively, of the Company's total revenue. During the years ended December 31, 2016 and 2015 one related party customer from the pressure pumping segment accounted for 44% and 34%, respectively, of the Company's total revenue. During the years ended December 31, 2016 and 2015 one related party customer from the natural sand proppant segment accounted for 11% and 10%, respectively, of the Company's total revenue. One third-party customer accounted for greater than 10% of the Company's total revenue for years ended December 31, 2016, and 2015, at 11% and 12%, respectively. No customers accounted for greater than 10% of the Company's total revenue for the year ended December 31, 2014.

(z) New Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 supersedes existing revenue recognition requirements in GAAP and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services. Additionally, it requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The ASU was effective for annual and interim reporting periods beginning after December 15, 2016, using either a full or a modified retrospective application approach; however, in July 2015 the FASB decided to defer the effective date by one year (until 2018) by issuing ASU No. 2015-14, "Revenue From Contracts with Customers: Deferral of the Effective Date." The Company expects to adopt this new revenue guidance utilizing the retrospective method of adoption in the first quarter of 2018, and because the Company is still evaluating the portion of its revenues that may be subject to the new leasing guidance

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

discussed below, it is unable to quantify the impact that the new revenue standard will have on the Company’s consolidated financial statements upon adoption.

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

3. Inventories

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



	December 31,
	2016		2015
Supplies	$	4,020,670	$	4,421,244
Raw materials	75,971		47,701
Work in process	205,450		233,719
Finished goods	1,822,110		2,824,859
Total inventory	$	6,124,201	$	7,527,523

F- 14

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


4.	Property, Plant and Equipment

Property, plant and equipment include the following:



		December 31,
	Useful Life	2016		2015
Land		$	5,040,482	$	5,040,482
Land improvements	15 years or life of lease	3,640,976		3,734,178
Buildings	15-39 years	54,833,021		53,886,349
Drilling rigs and related equipment	3-15 years	138,526,519		139,619,078
Pressure pumping equipment	3-5 years	96,500,592		93,956,896
Coil tubing equipment	4-10 years	28,019,217		30,190,216
Rail improvements	10-20 years	4,276,928		3,932,750
Vehicles, trucks and trailers	5-10 years	33,140,599		32,654,188
Machinery and equipment	7-20 years	35,548,357		37,829,135
Other property and equipment	3-12 years	11,461,839		11,217,270
		410,988,530		412,060,542
Deposits on equipment and equipment in process of assembly		9,427,307		2,812,083
		420,415,837		414,872,625
Less: accumulated depreciation		178,296,174		119,989,693
Property, plant and equipment, net		$	242,119,663	$	294,882,932

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 years ended December 31, 2016, 2015 and 2014, proceeds from the sale of equipment damaged or lost down-hole were $699,528, $404,383 and $698,860, respectively, and gain on sales of equipment damaged or lost down-hole were $447,477, $76,319 and $47,803, respectively.

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



	Years Ended December 31,
	2016		2015		2014
Depreciation expense	$	62,195,797	$	64,567,989	$	35,087,404
Accretion and depletion expense (see Note 2)	1,048,601		829,210		339,794
Amortization expense (see Note 6)	9,071,000		9,101,375		938,400
Depreciation, depletion, accretion and amortization	$	72,315,398	$	74,498,574	$	36,365,598

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.

F- 15

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


5.	Impairments

A summary of our impairments is as follows:



	December 31,
	2016		2015
Flowback equipment ^(a)	$	1,384,751	$	—
Drilling rigs ^(a)	347,547		8,917,240
Fluid storage equipment ^(a)	—		957,218
Other property, plant and equipment ^(a)	138,587		—
Impairment of long term contractual agreement ^(b)	—		1,904,982
Impairment of goodwill ^(c)	—		88,247
Impairment of intangible ^(d)	—		256,666
	$	1,870,885	$	12,124,353

For the years ended December 31, 2016 and 2015, the Company recognized impairments of $1,870,885 and $9,874,458, respectively, to reduce the carrying value of certain assets which were classified as held for use, to their estimated fair values, based on expected sales prices. No impairments occurred during the year ended December 31, 2014. The Company impaired based on future expected cash flows using significant unobservable inputs (Level 3) based on an income approach.


b.	The Company impaired $1,904,982 of assets in 2015 related to prepaid assets pursuant to a purchase contract from a vendor. The impairment impacted the prepaid expenses and other non-current assets lines of the Consolidated Balance Sheet for $1,080,000 and $824,982, respectively.


c.	The Company determined that there was an indication of impairment present based on the results of the first step of the goodwill impairment test for the goodwill held at Energy Services and fully impaired the $88,247 balance.


d.	The Company terminated one customer relationship related to its amortizable intangible assets and impaired the remaining unamortized value of the intangible of that relationship.

The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management’s judgment. A continued period of low oil and natural gas prices or continued reductions in capital expenditures by our customers would likely have an adverse impact on our utilization and the prices that we receive for our services. This could result in the recognition of future material impairment charges on the same, or additional, property and equipment if future cash flow estimates, based upon information then available to management, indicate that their carrying values are not recoverable.


6.	Goodwill and Intangible Assets

The Company had the following definite lived intangible assets recorded as of the dates presented below:



	December 31,
	2016		2015
Customer relationships	$	33,605,000	$	33,605,000
Trade names	7,110,000		7,110,000
Less: accumulated amortization - customer relationships	17,655,228		9,295,228
Less: accumulated amortization - trade names	1,492,943		781,943
Intangible assets, net	$	21,566,829	$	30,637,829

Amortization expense for intangible assets was $9,071,000, $9,101,375 and $938,400 for the years ended December 31, 2016, 2015, and 2014, respectively. The original life of customer relationships range from 4 to 10 years with a remaining average useful life of 3.35 years. Trade names are amortized over a 10 year useful life and as of December 31, 2016 the remaining useful life was 7.90 years.

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

F- 16

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Year ended December 31:	Amount
2017	$	9,071,004
2018	8,224,005
2019	738,504
2020	738,504
2021	732,752
Thereafter	2,062,060
	$	21,566,829

Goodwill was $88,726,875 at December 31, 2016 and 2015.


7.	Accrued Expenses and Other Current Liabilities

Accrued expense and other current liabilities included the following:



	December 31,
	2016		2015
Accrued compensation, benefits and related taxes	$	2,432,093	$	1,377,270
Financed insurance premiums	3,293,859		3,194,564
State and local taxes payable	319,597		790,302
Insurance reserves	971,351		739,775
Other	1,529,298		1,948,073
Total	$	8,546,198	$	8,049,984

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

F- 17

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


8.	Debt

Mammoth Credit Facility

On November 25, 2014, the Partnership entered into a revolving credit and security agreement with a bank that provides for maximum borrowings of $170.0 million. The facility, as amended in connection with the IPO, matures on November 25, 2019. Borrowings under this facility are secured by substantially all of the assets of Mammoth Inc., 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 operating subsidiaries then outstanding. Interest is payable monthly at a base rate set by the institution’s commercial lending group plus an applicable margin. Additionally, at the Company's request, outstanding balances are permitted to be converted to LIBOR rate plus applicable margin tranches at set increments of $500,000. The LIBOR rate option allows the Company to select interest periods from one, two, three or six months. The applicable margin for either the base rate or the LIBOR rate option can vary from 1.5% to 3.0%, based upon a calculation of the excess availability of the line as a percentage of the maximum credit limit. The deferred loan costs associated with this facility are classified in other non-current assets.

At December 31, 2016, the facility was undrawn and had availability of $146,181,002.

At December 31, 2015, $95,000,000 of the outstanding balance of the facility was in a one month LIBOR rate option tranche with an interest rate of 3.04%, and there was availability of $44,619,551 under the facility.

The facility 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 ($10.0 million). As of December 31, 2016 and 2015, the Company was in compliance with its covenants under the facility.

Sturgeon Credit Facility

On June 30, 2015, Sturgeon entered in to a $25.0 million revolving line of credit secured by substantially all of the assets of Sturgeon (“the Sturgeon revolver”). Advances under the Sturgeon revolver bear 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, or (c) the sum of the Daily LIBOR rate. Additionally, at Sturgeon’s request, advances may be obtained at LIBOR plus 3%. The LIBOR rate option allows Sturgeon to select interest periods from one, two, three, or six month LIBOR futures spot rates. All outstanding principal and interest are due on the June 30, 2018 maturity date. As of December 31, 2016 and 2015, there were no outstanding borrowings under the revolver, and availability was $18.2 million and $20.0 million, respectively.

The facility contains various customary affirmative and restrictive covenants. Among the covenants are financial covenants, including a minimum fixed charge coverage ratio (3.5 to 1.0) and a minimum availability block ($5.0 million). As of December 31, 2015, the Company was in compliance with its covenants under the facility. The Company was not in compliance with its fixed charge coverage ratio covenant at December 31, 2016, however the Sturgeon revolver was undrawn on that date. The Company was in compliance with all other covenants at December 31, 2016. The Sturgeon revolver was terminated on June 6, 2017.


9.	Income Taxes

As discussed in Note 1, the Partnership was converted into a limited liability company on October 12, 2016 and the membership interests in the limited liability company were contributed to the Company. As a result, the Company will file a consolidated return for the period October 12, 2016 through December 31, 2016. Prior to the conversion, the Partnership, other than Lodging, was not subject to corporate income taxes.

The components of income tax expense (benefit) attributable to the Company for the year ended December 31, 2016, 2015 and 2014, respectively, are as follows:

F- 18

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Year Ended December 31,
	2016		2015			2014
U.S. current income tax benefit	$	2,306,512	$	12,861		$	24,805
U.S. deferred income tax expense	47,957,169		(5,625,436		)	5,549,517
Foreign current income tax expense	3,594,014		3,878,855			1,674,407
Foreign deferred income tax expense	27,176		144,634			265,465
Total	$	53,884,871	$	(1,589,086	)	$	7,514,194

Foreign tax credits may be applied for up to five years. Tax credits must be utilized five years subsequent to the distribution of the underlying earnings. As of December 31, 2016, the distributions have not yet occurred.

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



	Year Ended December 31,
	2016			2015			2014
(Loss) income before income taxes	$	(38,567,957	)	$	(23,408,517	)	$	11,992,171
Statutory income tax rate	35		%	35		%	35		%
Expected income tax expense	(13,498,785		)	(8,192,981		)	4,197,260
Income earned as non-taxable entity (See Note 2)	15,166,519			—			—
Effect due to change to C corporation (See Note 2)	53,088,861			—			—
Change in entity status	—			(4,792,243		)	6,379,117
Non taxable entity	—			13,561,578			(1,557,878		)
Other permanent differences	209,546			—			—
State tax expenses	21,181			—			—
Change in tax rate	(24,803		)	—			—
Foreign income tax rate differential	(1,077,648		)	(1,369,575		)	(2,355,816		)
Other	—			(795,865		)	851,511
Total	$	53,884,871		$	(1,589,086	)	$	7,514,194

F- 19

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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



	Year Ended December 31,
	2016			2015
Deferred tax assets:
Allowance for doubtful accounts	$	1,892,761		$	—
Deferred stock compensation	1,686,671			—
Accrued liabilities	746,132			—
Other	1,785,999			86,580
Deferred tax assets	6,111,563			86,580

Deferred tax liabilities:
Property and equipment	$	(42,525,793	)	$	(1,484,350	)
Intangible assets	(7,662,590		)	—
Unrepatriated foreign earnings	(3,451,110		)	—
Other	(142,859		)	(63,189		)
Deferred tax liabilities	(53,782,352		)	(1,547,539		)
Net deferred tax liability	$	(47,670,789	)	$	(1,460,959	)

Reflected in accompanying balance sheet as:
Deferred income taxes	$	(47,670,789	)	$	(1,460,959	)


10.	Stockholders' Equity and Pro Forma Earnings Per Share

Earnings Per Unit

The Partnership's limited partner units were issued November 24, 2014. However, the net income per common unit on the Consolidated Statements of Comprehensive Loss is based on the net income of the Partnership for the full years presented, since the entities were under common control as described in Note 1.

The Partnership's net loss was allocated wholly to the limited partner units as the General Partner did not have an economic interest.

Basic net loss per common unit is calculated by dividing net loss by the weighted-average number of common units outstanding during the period. Although the units were not issued until November 24, 2014, units issued for common control entities have been calculated based on the weighted average units outstanding as if they were outstanding from the beginning of the periods presented, in conjunction with the treatment of common control entities.



	Year Ended December 31,
	2015			2014
Net (loss) income	$	(21,819,431	)	$	4,477,977
Net (loss) earnings per limited partner unit	(0.73		)	0.21
Weighted-average common units outstanding	30,000,000			21,056,073

Common Stock Offering

On October 14, 2016, Mammoth Inc.’s common stock began trading on The Nasdaq Global Select Market under the symbol “TUSK.” On October 19, 2016, the Company closed the IPO of 7,750,000 shares of common stock at $15.00 per share. Net proceeds to Mammoth Inc. from its sale of 7,500,000 shares of common stock were approximately $103.1 million.

F- 20

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The authorized capital stock of the Company consists of 200 million shares of common stock, par value $0.01 per share.

(Loss) Earnings Per Share

The number of common shares outstanding on a fully-converted basis was the same before and after any conversion of our owner units. Each time one common share was issued upon conversion of investor units, the number of common shares went up by one, and the number of common units outstanding that were convertible went down by one. Accordingly, for the year ended December 31, 2015 and 2014, there was no difference between common stock basic and diluted earnings per share because the conversion of common units into common shares did not impact the number of common shares on a fully-converted basis.



Year Ended December 31,	Weighted Average Shares Outstanding	Share Issuance at IPO ^(a)	Conversion		Weighted Average Units Outstanding
2016	31,500,000	1,500,000	(30,000,000	)	30,000,000
2015	30,000,000	—	(30,000,000	)	30,000,000
2014	21,056,073	—	(21,056,073	)	21,056,073


^(a)	Weighted average of 7,500,000 shares issued from the closing date of the IPO on October 19, 2016 to December 31, 2016.



	Year Ended December 31,
	2016			2015			2014
Basic loss per share:
Allocation of earnings:
Net (loss) income	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Weighted average common shares outstanding	31,500,000			30,000,000			21,056,073
Basic (loss) earnings per share	$	(2.94	)	$	(0.73	)	$	0.21

Diluted loss per share:
Allocation of earnings:
Net (loss) income	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Weighted average common shares, including dilutive effect ^(a)	31,500,000			30,000,000			21,056,073
Diluted (loss) earnings per share	$	(2.94	)	$	(0.73	)	$	0.21


^(a)	No incremental shares of potentially dilutive restricted stock awards were included for periods presented as their effect was antidulitive under the treasury stock method.

Unaudited Pro Forma Earnings Per Share

The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the conversion to Mammoth Inc. were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:

F- 21

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Year Ended December 31,
	2016			2015			2014
Pro Forma C Corporation Data (unaudited):
Net (loss) income, as reported	$	(92,452,828	)	$	(21,819,431	)	$	4,477,977
Taxes on income earned as a non-taxable entity	15,224,009			390,801			(7,590,480		)
Taxes due to change to C corporation	53,088,861			—			—
Pro forma net loss	$	(24,139,958	)	$	(21,428,630	)	$	(3,112,503	)

Basic loss per share:
Allocation of earnings:
Net loss	$	(24,139,958	)	$	(21,428,630	)	$	(3,112,503	)
Weighted average common shares outstanding	43,107,452			43,107,452			22,730,627
Basic loss per share	$	(0.56	)	$	(0.50	)	$	(0.14	)

Diluted loss per share:
Allocation of earnings:
Net loss	$	(24,139,958	)	$	(21,428,630	)	$	(3,112,503	)
Weighted average common shares, including dilutive effect ^(a)	43,107,452			43,107,452			22,730,627
Diluted loss per share	$	(0.56	)	$	(0.50	)	$	(0.14	)


^(a)	No incremental shares of potentially dilutive restricted stock awards were included for periods presented as their effect was antidulitive under the treasury stock method.

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


11.	Equity Based Compensation

Upon formation of certain Operating Entities, specified members of management (“Specified Members”) were granted the right to receive distributions from their respective Operating Entity, after the contribution member’s unreturned capital balance was recovered (referred to as “Payout” provision). Additionally, non-employee members were included in the award class (“Non-Employee Members”).

On November 24, 2014, the awards were modified in conjunction with the contribution of the Operating Entities to the Partnership. Awards are not granted in limited or general partner units. Agreements are for interests in the distributable earnings of Mammoth Holdings, Mammoth’s then majority limited partner unit holder.

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

Payout is expected to occur following the sale by Mammoth Holdings of its shares of the Company's common stock, which is considered not probable until the event occurs. Therefore, for the awards that contained the Payout provision, no compensation cost was recognized as the distribution rights do not vest until Payout is reached. For the Specified Member awards, the unrecognized amount, which represents the fair value of the award as of the modification dates or grant date, was $5,618,552. For the Non-Employees Member awards, the unrecognized cost, which represents the fair value of the awards as of December 31, 2016, was $29,054,528.

F- 22

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


12.	Stock-Based Compensation

The 2016 Plan authorizes the Company's Board of Directors or the compensation committee of the Company's Board of Directors to grant incentive restricted stock, restricted stock unit, 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 October 19, 2016	—		$	—
Granted	298,335		14.97
Vested	(11,110	)	(14.69		)
Forfeited	(4,445	)	(15.00		)
Unvested shares as of December 31, 2016	282,780		$	14.98

As of December 31, 2016, there was $3,878,325 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 twenty-one months.

Included in cost of revenue and selling, general and administrative expenses is stock-based compensation expense of $519,830 for the year ended December 31, 2016.


13.	Acquisition of Stingray Entities

Description of the Transaction

On November 24, 2014, the Partnership acquired all ownership interests in Stingray Pressure Pumping LLC (“Pressure Pumping”) and Stingray Logistics LLC (“Logistics”). Pressure Pumping was formed March 20, 2012 and Logistics was formed November 19, 2012, as Delaware limited liability companies. Both were formed by Wexford and Gulfport. The Partnership acquired Pressure Pumping and Logistics in exchange for limited partner interests. The acquisition of the Stingray Entities added to the Company's pressure pumping segment.

At the date of acquisition, the total ownership interest in Pressure Pumping and Logistics were converted to 31.96% (9.6 million common units) and 1.21% (0.4 million common units), respectively, of the Partnership's limited partnership interest. The fair value of the Stingray entities provided as consideration was determined with the assistance of external valuation experts as of acquisition date.

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




Consideration attributable to Stingray Pressure Pumping LLC ⁽¹⁾	$	176,910,000
Consideration attributable to Stingray Logistics LLC ⁽¹⁾	6,720,000
Total consideration transferred	$	183,630,000


⁽¹⁾	See Summary of acquired assets and liabilities below

F- 23

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Pressure Pumping		Logistics		Total
Cash and cash equivalents	$	6,930,597	$	128,471	$	7,059,068
Accounts receivable	25,904,279		2,164,859		28,069,138
Inventories	1,205,059		—		1,205,059
Other current assets	2,800,125		83,892		2,884,017
Property, plant and equipment⁽¹⁾	98,746,182		2,783,700		101,529,882
Identifiable intangible assets - customer relationships⁽²⁾	33,610,000		—		33,610,000
Identifiable intangible assets - trade names⁽²⁾	6,880,000		230,000		7,110,000
Goodwill⁽³⁾	82,867,545		3,175,603		86,043,148
Other Assets	207,057		4,000		211,057
Total assets acquired	$	259,150,844	$	8,570,525	$	267,721,369

Accounts payable and accrued liabilities	$	33,428,913	$	729,181	$	34,158,094
Income taxes payable	115,000		$	5,000	120,000
Long-term debt	48,696,931		$	1,116,344	49,813,275
Total liabilities assumed	$	82,240,844	$	1,850,525	$	84,091,369
Net assets acquired	$	176,910,000	$	6,720,000	$	183,630,000


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


⁽²⁾	Identifiable intangible assets were measured using a combination of income approaches. Trade names were valued using a "Relief-from-Royalty" method. Contractual and non-contractual customer relationships were valued using a "Multi-period excess earnings" method. Identifiable intangible assets will be amortized over 4-10 years.

⁽³⁾

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

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



	2016						2015						2014
	Pressure Pumping			Logistics			Pressure Pumping			Logistics			Pressure Pumping			Logistics
Revenues	$	123,736,030		$	4,393,991		$	166,869,663		$	5,922,131		$	17,731,317		$	635,024
Eliminations⁽¹⁾	(4,350		)	(4,349,075		)	—			(5,922,131		)	—			(635,024		)
Revenues in consolidation	123,731,680			44,916			166,869,663			—			17,731,317			—

Net income (loss)	(2,207,333		)	(367,927		)	(4,870,645		)	630,999			(1,612,370		)	97,525
Eliminations ⁽²⁾	4,802,981			(4,341,053		)	9,013,897			(5,922,131		)	1,051,191			(635,024		)
Net income (loss) in consolidation	2,595,648			(4,708,980		)	4,143,252			(5,291,132		)	(561,179		)	(537,499		)


⁽¹⁾	Eliminations related to work performed on behalf of Stingray Pressure Pumping and Stingray Logistics


⁽²⁾	Eliminations related to work performed on behalf of Stingray Pressure Pumping in addition to services provided by other Mammoth affiliates.

The following table presents unaudited 2014 pro forma information for the Company as if the acquisition had occurred as of January 1, 2014:



	2014
Revenues	$	381,868,708
Net loss	(9,438,437		)

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MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the acquisition. For the year ended December 31, 2014, there were no transaction related costs expensed. The unaudited pro forma consolidated results are not necessarily indicative of what the consolidated results of operations actually would have been had the merger been completed on January 1, 2014. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the Company.


14.	Acquisition of Lantern Rigs

On January 29, 2014, Bison acquired five drilling rigs (“Rigs”) directly from the financial institutions that leased the Rigs to the previous owner, Lantern Drilling Company (“Lantern”). The Company has treated the acquisition of these assets as a business combination because the assets included a workforce and contract arrangements. The acquisition of these Rigs enhanced the Company's contract land and directional drilling segment. At the date of acquisition, the five rigs were valued at $47,225,000. The assets are classified in property, plant and equipment, net in the Consolidated Balance Sheets. After tax the total cash consideration paid for the assets was $50,557,053. The outflow of cash is presented in purchases of property and equipment in the Consolidated Statements of Cash Flow.

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



	2016			2015		2014
Revenues	$	16,069,976		$	24,262,672	$	34,698,597
Net income (loss)	(7,409,865		)	609,069		6,873,499

The following table presents unaudited 2014 pro forma information for the Company as if the acquisition had occurred as of January 1, 2014:



	2014
Revenues	$	262,461,809
Net loss	(966,952		)

F- 25

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

have been had the merger been completed on January 1, 2014. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations of the Company.


15.	Sturgeon Acquisition

On March 20, 2017, and as amended on May 12, 2017, the Company entered into a definitive contribution agreement with MEH Sub LLC, Wexford Offshore Sturgeon Corp., Gulfport, Rhino and Mammoth 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 Sturgeon Acquisition added sand reserves, increased the Company's production capacity and provided access to the Canadian National Railway, which affords access to the Appalachian basin in support of the Company’s pressure pumping services as well as to western Canada.

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

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

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



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

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

Allocation of purchase price
Carrying value of members' equity prior to Sturgeon contribution	$	81,738,675

F- 26

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


16.	Related Party Transactions

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



		REVENUES						ACCOUNTS RECEIVABLE
		Years Ended December 31,						At December 31,
		2016		2015		2014		2016		2015
Pressure Pumping and Gulfport	(a)	$	102,389,505	$	124,311,189	$	12,635,148	$	19,094,509	$	16,218,713
Muskie and Gulfport	(b)	25,783,253		38,181,970		3,133,822		5,373,007		6,801,548
Panther Drilling and Gulfport	(c)	3,011,259		3,703,140		8,302,362		1,434,036		973,873
Energy Services and Gulfport	(d)	—		2,548,418		1,473,094		—		547,570
Lodging and Grizzly	(e)	5,412		941,552		3,809,538		274		906
Bison Drilling and El Toro	(f)	371,873		521,121		—		—		—
Panther Drilling and El Toro	(f)	171,619		192,485		989,484		—		—
Bison Trucking and El Toro	(f)	130,000		144,905		—		—		—
White Wing and El Toro	(f)	20,431		12,719		—		—		—
Energy Services and El Toro	(g)	530,477		168,356		—		108,386		—
White Wing and Diamondback	(h)	1,650		—		—		—		—
Coil Tubing and El Toro	(i)	318,694		—		—		—		—
Panther and DBDHT	(j)	157,940		—		—		100,450		—
The Company and 2017 Stingray Companies	(k)	38,140		8,973		—		1,363,056		464,440
Panther and Diamondback	(l)	—		—		168,673		—		—
Bison Drilling and Diamondback	(l)	—		—		232,299		—		—
Bison Trucking and Diamondback	(l)	—		—		3,176,607		—		—
Energy Services and Pressure Pumping	(m)	—		—		47,216		—		—
Muskie and Pressure Pumping	(n)	—		—		6,245,323		—		—
Other Relationships		—		—		—		115,565		114,935
		$	132,930,253	$	170,734,828	$	40,213,566	$	27,589,283	$	25,121,985


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.	Energy Services performs completion and production services for Gulfport pursuant to a master service agreement.


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


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


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


h.	White Wing provides rental services to Diamondback.


i.	Coil Tubing provides El Toro services in connection with completion activities.


j.	Panther provides services and materials to DBDHT.


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


l.	The contract land and directional drilling segment performed drilling services and sold or leased goods, equipment or facilities to Diamondback to a master service agreement.


m.	Prior to the acquisition of the Stingray Entities, Energy Services rented equipment from Pressure Pumping.


n.	Prior to the acquisition of the Stingray Entities, Muskie sold natural sand proppant to Pressure Pumping.

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MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



		COST OF REVENUE						ACCOUNTS PAYABLE
		Years Ended December 31,						At December 31,
		2016		2015		2014		2016		2015
Panther and DBDHT	(a)	$	48,998	$	101,206	$	250,322	$	—	48,998
Bison Trucking and Diamondback	(b)	169,886		165,951		112,330		—		12,077
Energy Services and Elk City Yard	(c)	106,800		106,800		—		—		—
Lodging and Dunvegan	(d)	8,574		71,980		116,805		3,199		304,746
Bison Drilling and El Toro	(e)	5,000		—		—		—		—
The Company and 2017 Stingray Companies	(f)	723,973		932,896		42,545		174,145		12,208
Muskie and Everest	(g)	—		—		1,969,439		—		—
Bison Drilling and Everest	(g)	—		—		218,589		—		—
Muskie and Hopedale	(h)	2,455		—		453,080		—		—
		$	1,065,686	$	1,378,833	$	3,163,110	$	177,344	$	378,029

		SELLING, GENERAL AND ADMINISTRATIVE COSTS
The Company and Everest	(g)	$	261,535	$	492,657	$	2,297,106	$	12,668	$	28,528
The Company and Wexford	(i)	393,842		383,733		457,771		13,197		9,006
Mammoth and Orange Leaf	(j)	102,515		49,892		—		—		—
Pressure Pumping and Caliber	(k)	—		24,306		—		—		—
		$	757,892	$	950,588	$	2,754,877	$	25,865	$	37,534
								$	203,209	$	415,563


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


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


c.	Energy Services leases property from Elk City Yard.


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


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


f.	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.

Everest has historically provided office space and certain technical, administrative and payroll services to the Company and the Company has reimbursed Everest in amounts determined by Everest based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for the Company. In 2014, Everest provided personnel to support operational functions in addition to significant technical and advisory support.


h.	Muskie utilizes Hopedale's transload facility.


i.	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.


j.	Orange Leaf leases office space to Mammoth Inc.


k.	Caliber leases office space to Pressure Pumping.


17.	Commitments and Contingencies

Lease Obligations

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

Minimum Purchase Commitments

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

Capital Spend Commitments

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

F- 28

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Aggregate future minimum payments under these obligations in effect at December 31, 2016 are as follows:



Year ended December 31:	Operating Leases		Capital Spend Commitments		Minimum Purchase Commitments
2017	$	6,587,913	$	18,554,769	$	2,200,000
2018	3,785,515		—		—
2019	2,311,939		—		—
2020	1,392,803		—		—
2021	1,392,803		—		—
Thereafter	3,987,729		—		—
	$	19,458,702	$	18,554,769	$	2,200,000

For the years ended December 31, 2016, 2015 and 2014, the Company recognized rent expense of $8,166,836, $8,507,802 and $4,274,500, respectively.

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

The Company partially insures some workers’ compensation and auto claims, which includes medical expenses, lost time and temporary or permanent disability benefits. As of December 31, 2016 and 2015, the policy required a deductible per occurrence of $250,000 and $100,000, respectively. The Company establishes liabilities for the unpaid deductible portion of claims incurred relating to workers’ compensation and auto liability based on estimates. As of December 31, 2016 and 2015, the policies contained an aggregate stop loss of $2,000,000 and $1,900,000, respectively. As of December 31, 2016 and 2015, accrued claims were $971,351 and $739,775, respectively. These estimates may change in the near term as actual claims continue to develop. In connection with the insurance programs, letters of credit of $1,636,000 and $1,176,000 as of December 31, 2016 and 2015, respectively, had been issued under the Company's revolving credit agreement supporting the retained risk exposure. As of December 31, 2016 and 2015, in connection with environmental remediation programs, letters of credit of $1,375,342 had been issued under the Sturgeon revolver supporting the retained risk exposure.

The Company is routinely involved in state and local tax audits. During 2015, the State of Ohio assessed taxes on the purchase of equipment the Company believes is exempt under state law. The Company has appealed the assessment and a hearing was scheduled for November 30, 2016. In November 2016, the State of Ohio deferred the hearing until 2017. While the Company is not able to predict the outcome of the appeal, this matter is not expected to have a material adverse effect on the financial position or results of operations of the Company.

On June 3, 2015, a punitive class and collective action lawsuit alleging that Pressure Pumping failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act and Ohio law was filed titled William Crigler, et al v. Stingray Pressure Pumping, LLC in the U.S. District Court Southern District of Ohio Eastern Division. The Company submitted a settlement offer to the plaintiff that was accepted and is expected to be payable in 2017. This settlement will not have a material impact on the Company’s financial position, results of operations or cash flows.

On October 12, 2015, a putative class and collective action lawsuit alleging that Energy Services failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act and Oklahoma law was filed titled William Reynolds, individually and on behalf of all others similarly situated v. Redback Energy Services LLC in the U.S. District Court for the Western District of Oklahoma. The Company is evaluating the background facts and at this time is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On December 2, 2015, a putative class and collective action lawsuit alleging that Bison Drilling failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act and Texas law was filed titled John Talamentez, individually and on behalf of all others similarly situated v. Bison Drilling and Field Services, LLC in the U.S. District Court Western District of Texas Midland/Odessa Division. The Company is evaluating the background facts and at this

F- 29

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

time is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On December 16, 2015, a lawsuit alleging wrongful death was filed titled Cecilia R.G. Uballe and Sabrina Barber, beneficiaries of Eseciel D. Uballe, Deceased v. Bison Trucking LLC in the U.S. District Court of Midland Texas. On December 5, 2016, the Company settled this matter. This resolution did not cause a material impact on the Company’s financial position, results of operations or cash flows.

On February 12, 2016, a putative lawsuit alleging that Energy Services failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Brian Croniser vs. Redback Energy Services LLC in the U.S. District Court Southern District of Ohio. The Company is evaluating the background facts at this time and are not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On June 22, 2016, a putative, Title VII discrimination, and Oklahoma anti-discrimination lawsuit alleging that Redback Energy Services was in violation of the previously mentioned federal and state laws. The lawsuit was filed titled Earl Richardson and Keary Johnson v. Redback Energy Services LLC in the U.S. District Court for the Western District of Oklahoma. The Company is evaluating the background facts at this time and is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On August 1, 2016, a putative class and collective action lawsuit alleging that Energy Services failed to pay a class of workers overtime in compliance with the Fair Labor Standards Act and Texas law was filed titled Michael Caffey, individually and on behalf of all others similarly situated v. Redback Energy Services LLC in the U.S. District Court for the Western District of Texas. The Company is evaluating the background facts and at this time is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

On September 27, 2016, a putative lawsuit alleging that Energy Services failed to pay a class of workers in compliance with the Fair Labor Standards Act was filed titled Michael Drake vs. Redback Coil Tubing LLC, et al in the U.S. District Court Western District of Texas. The Company is evaluating the background facts at this time and is not able to predict the outcome of this lawsuit or whether it will have a material impact on the Company’s financial position, results of operations or cash flows.

The Company is involved in various other legal proceedings in the ordinary course of business. Although we 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 our business, financial condition, results of operations or cash flows.

Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 92% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes discretionary matching contributions of up to 4% of an employee’s compensation and may make additional discretionary contributions for eligible employees. For the years ended December 31, 2016, 2015 and 2014 the Company paid $102,230, $1,514,478 and $1,270,081, respectively, in contributions to the plan.


18.	Operating Segments

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

The Company's Chief Executive Officer and Chief Financial Officer comprise the Company's Chief Operating Decision Maker function ("CODM"). Segment information is prepared on the same basis that our CODM manages the segments,

F- 30

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

evaluates the segment financial statements, and makes key operating and resource utilization decisions. Segment evaluation is determined on a quantitative basis based on a function of revenue and earnings before interest, other expense (income), impairment, taxes and depreciation and amortization as well as a qualitative basis, such as nature of the product and service offerings, types of customers.

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

Additionally, given that the Company is a C Corporation that will file a consolidated income tax returns for periods following the contribution that occurred in October 2016 (See Note 1), the Company deems loss (income) before income taxes to be a more meaningful representation of operational performance. Historical information in this Note to the financial statements has been revised to reflect the presentation methodology.

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



	Completion and Production
Year Ended December 31, 2016	Pressure Pumping Services			Well Services			Sand			Drilling			Other Energy Services		Total
Revenue from external customers	$	21,446,803		$	9,157,042		$	8,052,445		$	28,177,737		$	30,861,317	$	97,695,344
Revenue from related parties	$	102,409,045		$	867,771		$	25,783,253		$	3,864,772		$	5,412	$	132,930,253
Cost of revenue	$	82,551,909		$	13,540,309		$	31,894,499		$	31,847,969		$	13,186,060	$	173,020,746
Selling, general and administrative expenses	$	4,327,599		$	2,336,002		$	3,337,181		$	5,624,705		$	2,423,028	$	18,048,515
Earnings before interest, other expense (income), impairment, taxes and depreciation and amortization	$	36,976,340		$	(5,851,498	)	$	(1,395,982	)	$	(5,430,165	)	$	15,257,641	$	39,556,336
Other expense (income)	$	26,743		$	(565,966	)	$	96,388		$	247,620		$	37,043	$	(158,172	)
Interest expense	$	599,147		$	134,007		$	434,243		$	2,828,753		$	100,032	$	4,096,182
Depreciation, depletion, accretion and amortization	$	37,012,902		$	5,127,879		$	6,483,384		$	21,512,117		$	2,179,116	$	72,315,398
Impairment of long-lived assets	$	138,587		$	1,384,751		$	—		$	347,547		$	—	$	1,870,885
(Loss) income before income taxes	$	(801,039	)	$	(11,932,169	)	$	(8,409,997	)	$	(30,366,202	)	$	12,941,450	$	(38,567,957	)
Provision for income taxes	$	—		$	50,265,203		$	3,716		$	—		$	3,615,952	$	53,884,871
Net (loss) income	$	(801,039	)	$	(62,197,372	)	$	(8,413,713	)	$	(30,366,202	)	$	9,325,498	$	(92,452,828	)
Total expenditures for property, plant and equipment	$	7,673,187		$	404,612		$	528,049		$	2,709,478		$	424,380	$	11,739,706
Goodwill	$	86,043,148		$	—		$	2,683,727		$	—		$	—	$	88,726,875
Intangible assets, net	$	21,435,058		$	131,771		$	—		$	—		$	—	$	21,566,829
Total assets	$	195,121,216		$	66,043,726		$	108,726,424		$	99,867,691		$	32,603,418	$	502,362,475

F- 31

MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Completion and Production
Year Ended December 31, 2015	Pressure Pumping Services			Well Services			Sand		Drilling			Other Energy Services			Total
Revenue from external customers	$	45,538,393		$	26,134,568		$	22,730,463	$	68,457,719		$	34,340,821		$	197,201,964
Revenue from related parties	$	124,320,162		$	2,716,773		$	38,181,970	$	4,574,370		$	941,553		$	170,734,828
Cost of revenue	$	129,042,660		$	28,144,431		$	44,905,053	$	57,489,608		$	15,105,497		$	274,687,249
Selling, general and administrative expenses	$	4,901,459		$	2,285,684		$	4,263,822	$	8,573,174		$	2,375,881		$	22,400,020
Earnings before interest, other expense, impairment, taxes and depreciation and amortization	$	35,914,436		$	(1,578,774	)	$	11,743,558	$	6,969,307		$	17,800,996		$	70,849,523
Other expense	$	66,889		$	686,617		$	22,318	$	1,121,093		$	372,141		$	2,269,058
Interest expense	$	1,859,195		$	429,061		$	225,202	$	2,890,130		$	60,959		$	5,464,547
Interest income	$	—		$	—		$	98,056	$	—		$	436		$	98,492
Depreciation, depletion, accretion and amortization	$	35,728,715		$	5,696,547		$	6,305,501	$	24,626,705		$	2,141,106		$	74,498,574
Impairment of long-lived assets	$	1,213,885		$	88,247		$	1,904,981	$	8,917,240		$	—		$	12,124,353
(Loss) income before income taxes	$	(2,954,248	)	$	(8,479,246	)	$	3,383,612	$	(30,585,861	)	$	15,227,226		$	(23,408,517	)
Provision (benefit) for income taxes	$	72,435		$	4,454		$	—	$	(184,523	)	$	(1,481,452	)	$	(1,589,086	)
Net (loss) income	$	(3,026,683	)	$	(8,483,700	)	$	3,383,612	$	(30,401,338	)	$	16,708,678		$	(21,819,431	)
Total expenditures for property, plant and equipment	$	4,169,678		$	6,768,143		$	2,371,526	$	12,650,831		$	2,491,821		$	28,451,999
Goodwill	$	86,043,148		$	—		$	2,683,727	$	—		$	—		$	88,726,875
Intangible assets, net	$	30,478,558		$	159,271		$	—	$	—		$	—		$	30,637,829
Total assets	$	226,679,023		$	41,072,263		$	118,574,434	$	118,227,357		$	31,859,058		$	536,412,135



	Completion and Production
Year Ended December 31, 2014	Pressure Pumping Services		Well Services		Sand		Drilling			Other Energy Services		Total
Revenue from external customers	$	12,144,538	$	43,732,782	$	53,174,559	$	109,295,518		$	17,168,471	$	235,515,868
Revenue from related parties	$	12,635,148	$	1,520,310	$	9,379,145	$	12,869,425		$	3,809,538	$	40,213,566
Cost of revenue	$	16,263,083	$	31,715,681	$	47,308,336	$	93,571,050		$	9,673,570	$	198,531,720
Selling, general and administrative expenses	$	1,409,618	$	2,339,024	$	3,689,852	$	9,763,922		$	1,336,432	$	18,538,848
Earnings before interest, other expense, impairment, taxes and depreciation and amortization	$	7,106,985	$	11,198,387	$	11,555,516	$	18,829,971		$	9,968,007	$	58,658,866
Other expense	$	1,744,695	$	777,382	$	1,101,952	$	1,539,279		$	563,856	$	5,727,164
Interest expense	$	386,618	$	831,508	$	127,988	$	3,194,061		$	63,420	$	4,603,595
Interest expense from related parties	$	—	$	—	$	184,479	$	—		$	—	$	184,479
Interest income	$	—	$	—	$	208,519	$	—		$	5,622	$	214,141
Depreciation, depletion and amortization	$	4,015,572	$	4,768,024	$	4,605,457	$	21,319,617		$	1,656,928	$	36,365,598
(Loss) income before income taxes	$	960,100	$	4,821,473	$	5,744,159	$	(7,222,986	)	$	7,689,425	$	11,992,171
Provision for income taxes	$	10,897	$	18,226	$	4,826	$	77,576		$	7,402,669	$	7,514,194
Net income (loss)	$	949,203	$	4,803,247	$	5,739,333	$	(7,300,562	)	$	286,756	$	4,477,977
Total expenditures for property, plant and equipment	$	180,466	$	11,441,285	$	5,493,441	$	85,801,345		$	9,679,496	$	112,596,033
Goodwill	$	86,131,395	$	—	$	2,683,727	$	—		$	—	$	88,815,122
Intangible assets, net	$	39,809,101	$	186,770	$	—	$	—		$	—	$	39,995,871
Total assets	$	275,701,590	$	39,977,056	$	130,079,381	$	185,218,626		$	38,925,705	$	669,902,358

The pressure pumping services segment provides hydraulic fracturing. The well services segment provides coil tubing, flowback and equipment rental services. The sand segment sells, distributes and is capable of producing sand for use in hydraulic fracturing. The contract land and directional drilling services segment provides vertical, horizontal and directional drilling services. The other energy services segment provides housing, kitchen and dining, and recreational service facilities for oilfield workers that are located in remote areas away from readily available lodging. The pressure pumping and well service segments primarily services in the Utica Shale of Eastern Ohio, Marcellus Shale in

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MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Pennsylvania, Eagle Ford and Permian basin in Texas and mid-continent region. The natural sand proppant segment primarily services the Utica Shale and Montney Shale in British Columbia and Alberta, Canada. The contract land and directional drilling services segment primarily services the Permian Basin in West Texas. The other energy services segment primarily services Canada.

19. Quarterly Financial Data (unaudited)

The below tables reflect the unaudited quarterly information of the Company that has been retrospectively recast for all periods to give effect to the Sturgeon Acquisition as if it had occurred on September 13, 2014, the date that Sturgeon commenced operations. See Note 15 for additional information regarding the Sturgeon Acquisition.



	Three Months Ended
	March 31,			June 30,			September 30,			December 31,			Total
	2016			2016			2016			2016
Revenue from external customers	$	29,518,227		$	20,345,310		$	20,752,911		$	27,078,896		$	97,695,344
Revenue from related parties	$	3,064,632		$	48,817,324		$	42,573,621		$	38,474,676		$	132,930,253
Cost of revenue	$	32,391,176		$	50,503,643		$	42,854,771		$	47,271,156		$	173,020,746
Selling, general and administrative expenses	$	3,613,874		$	5,206,138		$	3,194,609		$	6,033,894		$	18,048,515
Earnings before other expense (income), interest, depreciation and amortization, impairment and taxes	$	(3,422,191	)	$	13,452,853		$	17,277,152		$	12,248,522		$	39,556,336
Other expense (income)	$	990		$	(626,716	)	$	253,832		$	213,722		$	(158,172	)
Interest expense	$	1,296,356		$	1,012,031		$	1,024,514		$	763,281		$	4,096,182
Depreciation, depletion, accretion and amortization	$	17,751,072		$	18,810,615		$	17,921,471		$	17,832,240		$	72,315,398
Impairment of long-lived assets	$	—		$	1,870,885		$	—		$	—		$	1,870,885
Loss before income taxes	$	(22,470,609	)	$	(7,613,962	)	$	(1,922,665	)	$	(6,560,721	)	$	(38,567,957	)
Provision for income taxes	$	894,360		$	789,375		$	1,055,961		$	51,145,175		$	53,884,871
Net loss	$	(23,364,969	)	$	(8,403,337	)	$	(2,978,626	)	$	(57,705,896	)	$	(92,452,828	)

Net loss per share (basic and diluted) (Note 10)	$	(0.78	)	$	(0.28	)	$	(0.10	)	$	(1.61	)	$	(2.94	)
Weighted average number of shares outstanding (Note 10)	30,000,000			30,000,000			30,000,000			35,951,087			31,500,000

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MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Three Months Ended
	March 31,		June 30,			September 30,			December 31,			Total
	2015		2015			2015			2015
Revenue from external customers	$	76,155,221	$	53,851,354		$	46,626,378		$	20,569,011		$	197,201,964
Revenue from related parties	$	44,030,771	$	50,690,762		$	41,806,945		$	34,206,350		$	170,734,828
Cost of revenue	$	85,007,871	$	78,210,562		$	70,739,930		$	40,728,886		$	274,687,249
Selling, general and administrative expenses	$	5,472,679	$	5,323,083		$	4,605,508		$	6,998,750		$	22,400,020
Earnings before other expense, interest, depreciation and amortization, impairment and taxes	$	29,705,442	$	21,008,471		$	13,087,885		$	7,047,725		$	70,849,523
Other expense	$	911,232	$	1,207,656		$	38,082		$	112,088		$	2,269,058
Interest income	$	46,678	$	51,564		$	250		$	—		$	98,492
Interest expense	$	1,532,394	$	1,276,011		$	1,431,591		$	1,224,551		$	5,464,547
Depreciation, depletion, accretion and amortization	$	18,110,664	$	18,738,887		$	18,670,552		$	18,978,471		$	74,498,574
Impairment of long-lived assets	$	—	$	4,470,781		$	908,456		$	6,745,116		$	12,124,353
Income (loss) before income taxes	$	9,197,830	$	(4,633,300	)	$	(7,960,546	)	$	(20,012,501	)	$	(23,408,517	)
Provision (benefit) for income taxes	$	1,164,943	$	408,193		$	(4,250,643	)	$	1,088,421		$	(1,589,086	)
Net income (loss)	$	8,032,887	$	(5,041,493	)	$	(3,709,903	)	$	(21,100,922	)	$	(21,819,431	)

Net (loss) earnings per share (basic and diluted) (Note 10)	$	0.27	$	(0.17	)	$	(0.12	)	$	(0.70	)	$	(0.73	)
Weighted average number of shares outstanding (Note 10)	30,000,000		30,000,000			30,000,000			30,000,000			30,000,000

As required by Rule 3-02 of Regulation S-K, the Company has presented below the changes, as a result of such recast, in the amounts previously reported by the Company for these periods. The adjustments reflect the changes to the unaudited quarterly financial data as included in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 23, 2017 for the periods indicated.



	Three Months Ended
	March 31,			June 30,			September 30,			December 31,			Total
	2016			2016			2016			2016
Revenue from external customers	$	546,292		$	274,344		$	743,825		$	1,054,843		$	2,619,304
Revenue from related parties	$	(2,466,937	)	$	(53,998	)	$	(183,511	)	$	(287,982	)	$	(2,992,428	)
Cost of revenue	$	(506,044	)	$	(871,735	)	$	120,795		$	727,821		$	(529,163	)
Selling, general and administrative expenses	$	358,810		$	410,409		$	192,800		$	355,521		$	1,317,540
Earnings before other expense (income), interest, depreciation and amortization, impairment and taxes	$	(1,773,411	)	$	681,672		$	246,719		$	(316,481	)	$	(1,161,501	)
Other expense (income)	$	19,182		$	49,780		$	10,939		$	14,166		$	94,067
Interest expense	$	104,461		$	94,721		$	91,765		$	93,778		$	384,725
Depreciation, depletion, accretion and amortization	$	337,481		$	556,823		$	773,041		$	737,195		$	2,404,540
Impairment of long-lived assets	$	—		$	—		$	—		$	—		$	—
Loss before income taxes	$	(2,234,535	)	$	(19,652	)	$	(629,026	)	$	(1,161,620	)	$	(4,044,833	)
Provision for income taxes	$	—		$	—		$	—		$	—		$	—
Net loss	$	(2,234,535	)	$	(19,652	)	$	(629,026	)	$	(1,161,620	)	$	(4,044,833	)

Net loss per share (basic and diluted) (Note 10)	$	(0.07	)	$	—		$	(0.02	)	$	(0.03	)	$	(0.13	)
Weighted average number of shares outstanding (Note 10)	30,000,000			30,000,000			30,000,000			35,951,087			31,500,000

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MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Three Months Ended
	March 31,			June 30,			September 30,			December 31,			Total
	2015			2015			2015			2015
Revenue from external customers	$	7,889,458		$	(2,928,953	)	$	2,475,256		$	1,021,721		$	8,457,482
Revenue from related parties	$	(72,948	)	$	(95,238	)	$	(238,425	)	$	(50,772	)	$	(457,383	)
Cost of revenue	$	4,259,802		$	(6,904,731	)	$	379,702		$	605,159		$	(1,660,068	)
Selling, general and administrative expenses	$	560,105		$	385,075		$	413,591		$	499,701		$	1,858,472
Earnings before other expense, interest, depreciation and amortization, impairment and taxes	$	2,996,603		$	3,495,465		$	1,443,538		$	(133,911	)	$	7,801,695
Other expense	$	14,714		$	11,689		$	(103,947	)	$	188,838		$	111,294
Interest income	$	—		$	—		$	—		$	—		$	—
Interest expense	$	—		$	2,075		$	55,167		$	116,484		$	173,726
Depreciation, depletion, accretion and amortization	$	367,454		$	745,265		$	711,120		$	280,853		$	2,104,692
Impairment of long-lived assets	$	—		$	—		$	—		$	—		$	—
Income (loss) before income taxes	$	2,614,435		$	2,736,436		$	781,198		$	(720,086	)	$	5,411,983
Provision (benefit) for income taxes	$	—		$	—		$	—		$	—		$	—
Net income (loss)	$	2,614,435		$	2,736,436		$	781,198		$	(720,086	)	$	5,411,983

Net (loss) earnings per share (basic and diluted) (Note 10)	$	0.09		$	0.09		$	0.03		$	(0.02	)	$	0.18
Weighted average number of shares outstanding (Note 10)	30,000,000			30,000,000			30,000,000			30,000,000			30,000,000

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MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


20.	Subsequent Events

Subsequent to December 31, 2016, the Company entered into railcar lease agreements with aggregate commitments of $31.3 million.

Subsequent to December 31, 2016, the Company entered into an agreement to purchase sand from an unrelated third party seller with aggregate commitments of $30.8 million.

In February 2017, the Company ordered additional new high pressure fracturing units and related equipment with an aggregate cost of $35.2 million with delivery expected during 2017. Additionally, subsequent to December 31, 2016, the Company ordered an aggregate of $84.4 million in other equipment across all operating segments.

In February 2017, the Company reached a settlement in the case titled William Crigler, et al v. Stingray Pressure Pumping, LLC, which settlement received final approval from the court in August 2017. This settlement will not have a material impact on the Company’s financial position, results of operations or cash flows.

On February 2017, the Company settled the case titled Brian Croniser vs. Redback Energy Services LLC and the lawsuit has been dismissed. This resolution did not have a material impact on the Company’s financial position, results of operations or cash flows.

On February 21, 2017, the Company granted 375,000 restricted stock units ("RSUs"). The RSUs vest in three substantially equal annual installments beginning on the first anniversary of the grant.

On March 27, 2017, the Company entered into a definitive asset purchase agreement, with Chieftain Sand and Proppant, LLC and Chieftain Sand and Proppant Barron, LLC, unrelated third party sellers, following a successful bid in a bankruptcy court auction for substantially all of the assets of the sellers for $36.3 million ("Chieftain Acquisition"). The Chieftain Acquisition closed on May 26, 2017. The Company funded the purchase price for the Chieftain Acquisition with cash on hand and borrowings under the revolving credit facility.

On March 2017, the Company settled the case titled Rusty Hale, individually and on behalf of all others similarly situated v. Redback Energy Services LLC. This resolution did not have a material impact on the Company’s financial position, results of operations or cash flows.

On April 2017, the Company settled the case titled William Reynolds, individually and on behalf of all others similarly situated v. Redback Energy Services LLC. This resolution did not have a material impact on the Company’s financial position, results of operations or cash flows.

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

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

On May 10, 2017, the Company acquired oilfield service equipment and related real property from an unrelated third party seller for $3.8 million.

On June 5, 2017, the Company completed the acquisition of (1) SR Energy, a Delaware limited liability company and (2) Cementing, a Delaware limited liability company (together with SR Energy, the “2017 Stingray Acquisition”) in exchange for the issuance by Mammoth of an aggregate of 1,392,548 shares of its common stock.

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

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

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MAMMOTH ENERGY SERVICES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

On August 24, 2017, the Company settled the case titled Earl Richardson and Keary Johnson v. Redback Energy Services LLC. This resolution did not have a material impact on the Company’s financial position, results of operations or cash flows.

On October 19, 2017, Cobra Acquisitions LLC, a subsidiary of the Company, entered into a contract to aid in the restoration of utility infrastructure on the island of Puerto Rico. The contract provides for payments up to $200.0 million, including an initial payment of $15.0 million at the time of signing. As of October 26, 2017, the Company had entered into $23.8 million of commitments related to this contract and made prepayments and deposits of $5.0 million with respect to these commitments.

F- 37