Mammoth Energy Services Inc.
MAMMOTH ENERGY SERVICES, INC. (Form: 8-K, Received: 10/27/2017 06:10:24)



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 8-K

CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): February 23, 2017
 
Mammoth Energy Services, Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
32-0498321
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
001-37917
 
 
(Commission File Number)
 
14201 Caliber Drive Suite 300
Oklahoma City, Oklahoma
 
73134
(Address of principal executive offices)
 
(Zip Code)
 
  (405) 608-6007
 
 
  (Registrant’s telephone number, including area code)
 
 
 
 
 
(Former name or former address, if changed since last report)
 

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company  ý

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ý  
Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:


¨  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
¨  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
¨  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
¨  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act(17 CFR 240.13e-4(c))









Item 2.02. Results of Operations and Financial Condition.

The information required by this item is included in Item 8.01 and incorporated by reference herein.

Item 8.01. Results of Operations and Financial Condition

As previously reported by Mammoth Energy Services, Inc. (“Mammoth” or the "Company") in its Current Report on Form 8-K filed on June 9, 2017, Mammoth acquired certain oilfield service companies (the “Acquisitions”) from Gulfport Energy Corporation, Rhino Exploration LLC, and certain affiliates of Wexford Capital LP. In the Acquisitions, which closed on June 5, 2017, Mammoth acquired: (1) Sturgeon Acquisitions LLC (“Sturgeon”) and Sturgeon’s wholly owned subsidiaries Taylor Frac LLC, Taylor Real Estate Investments LLC and South River Road LLC; (2) Stingray Energy Services LLC; and (3) Stingray Cementing LLC in exchange for the issuance by Mammoth of an aggregate of 7,000,000 shares of its common stock. On August 2, 2017, Mammoth amended its initial report on Form 8-K to provide the audited financial statements, the unaudited interim financial statements and the pro forma financial information, which are required by Item 9.01(a) and (b) of Form 8-K in connection with the Acquisitions.

Prior to the completion of the Acquisitions, Mammoth and Sturgeon were entities under common control and in accordance with generally accepted accounting principles in the United States ("GAAP"), Mammoth has accounted for its acquisition of Sturgeon in a manner similar to the pooling of interest method of accounting. As such, Mammoth's historical financial information for all periods included in this report has been recast to combine Sturgeon's financial results with Mammoth's financial results as if the acquisition of Sturgeon had been effective since Sturgeon commenced operations on September 13, 2014.
 
The Company's Annual Report on Form 10-K for the year ended December 31, 2016 filed with the SEC on February 23, 2017 (the "2016 Form 10-K") is hereby recast by this Current Report on Form 8-K as follows:

2016 Form 10-K (Exhibit 99.1)
The Selected Financial Data included herein Exhibit 99.1 supersedes Part II, Item 6 of the 2016 Form 10-K
The Management's Discussion and Analysis of Financial Condition and Results of Operations included herein Exhibit 99.1 supersedes Part II, Item 7 of the 2016 Form 10-K
The Financial Statements and Supplementary Data included herein supersedes Part II, Item 8 and 15 of the 2016 Form 10-K

There have been no revisions or updates to any other sections of the 2016 Form 10-K, other than the revisions noted above. This Current Report on Form 8-K should be read in conjunction with the 2016 Form 10-K and any references herein to Items 6, 7 and 8 under Part II of the 2016 Form 10-K refer to Exhibit 99.1. As of the date of this Current Report on Form 8-K, future references to the Company's historical financial statements should be made to this Current Report as well as future quarterly and annual reports on Form 10-Q and Form 10-K, respectively.

Item 9.01. Financial Statements and Exhibits

(d)    Exhibits.

Number
Exhibit
 
 
 
21.1
List of significant subsidiaries
23.1
Consent of Grant Thornton LLP
23.2
Consent of PricewaterhouseCoopers LLP
99.1
Audited consolidated financial statements of Mammoth Energy Services, Inc. as of December 31, 2016 and 2015 and for each of the years ended December 31, 2016, 2015, and 2014, including notes thereto, and the report of the independent registered accounting firm thereon.
99.2
Audited consolidated financial statements of Sturgeon Acquisitions LLC as of December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended and the period September 13, 2014 to December 31, 2014, including notes thereto, and the report of the independent registered public accounting firm thereon.
101.1
Interactive data files pursuant to Rule 405 of Regulation S-T.






Signatures

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

 
 
 
 
 
MAMMOTH ENERGY SERVICES, INC.
Date:
October 26, 2017
 
By:
 
/s/ Mark Layton
 
 
 
 
 
Mark Layton
 
 
 
 
 
Chief Financial Officer and Secretary
 
 
 
 
 
 
 
 
 
 
 
 






Number
Exhibit
 
 
 
Consent of PricewaterhouseCoopers LLP
Audited consolidated financial statements of Sturgeon Acquisitions LLC as of December 31, 2016 and 2015, and the results of its operations and its cash flows for the years then ended and the period September 13, 2014 to December 31, 2014, including notes thereto, and the report of the independent registered public accounting firm thereon.
101.1
Interactive data files pursuant to Rule 405 of Regulation S-T.





EXHIBIT 21.1

Mammoth Energy Services, Inc.
List of Significant Subsidiaries

Name of Subsidiary
Mammoth Energy Partners LLC
Bison Drilling and Field Services LLC
Bison Trucking LLC
White Wing Tubular Services LLC
Barracuda Logistics LLC
Panther Drilling Systems LLC
Redback Energy Services LLC
Redback Coil Tubing LLC
Muskie Proppant LLC
Stingray Pressure Pumping LLC
Stingray Logistics LLC
Great White Sand Tiger Lodging Ltd.
Sand Tiger Holdings, Inc.
Redback Pumpdown Services LLC
Mr. Inspections LLC
Silverback Energy Services LLC
Mammoth Equipment Leasing LLC
Cobra T&D LLC
Cobra Acquisitions LLC
Sturgeon Acquisitions LLC
Taylor Frac, LLC
Taylor Real Estate Investments, LLC
South River Road, LLC





EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated October 26, 2017 , with respect to the consolidated financial statements of Mammoth Energy Services, Inc. included in the Current Report on Form 8-K of Mammoth Energy Services, Inc. dated October 26, 2017 . We consent to the incorporation by reference of the said report in the Registration Statement of Mammoth Energy Services, Inc. on Form S-8 (File No. 333-217361).

/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
October 26, 2017




EXHIBIT 23.2
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-217361) of Mammoth Energy Services, Inc. of our report dated August 14, 2017, relating to the financial statements of Sturgeon Acquisitions LLC, which appears in this current report on Form 8‑K of Mammoth Energy Services, Inc.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma
October 26, 2017



EXHIBIT 99.1
TABLE OF CONTENTS
 
 
 
 
 
 
 
Page
Item 6.
Item 7.
Item 8.




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.

2


 
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



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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

4


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.

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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.


6


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 .


7


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.


8


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.

9



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 .


10


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 .

Selling, General and Administrative Expenses . Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $3.9 million, or 21%, to $22.4 million for 2015 , from $18.5 million for 2014 . The increase in expenses was primarily attributable to a $3.1 million increase in bad debt expense.

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

11


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 .


12


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





13


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










14


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




15


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.


16


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

17


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.


18


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.


19


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.

20


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

21


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.


22


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.

23



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
)