S-1 1 d753416ds1.htm FORM S-1 Form S-1
Table of Contents

As filed with the Securities and Exchange Commission on September 23, 2014

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Mammoth Energy Partners LP

(formerly known as Stingray Energy Services, Inc.)

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   1389   47-1902732

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

 

 

4727 Gaillardia Parkway, Suite 200

Oklahoma City, OK 73134

(405) 265-4600

(Address, including zip code and telephone number, including area code, of registrant’s principal executive offices)

 

 

Mark Layton

Chief Financial Officer

Mammoth Energy Partners LP

4727 Gaillardia Parkway, Suite 200

Oklahoma City, OK 73134

(405) 265-4600

(Name, address, including zip code and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Seth R. Molay, P.C.

John Goodgame

Patrick J. Hurley

Akin Gump Strauss Hauer & Feld LLP

1700 Pacific Avenue, Suite 4100

Dallas, TX 75201

(214) 969-4780

 

J. Michael Chambers

Brett E. Braden

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, TX 77002

(713) 546-7416

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement is declared effective.

If any securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   x  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

 

Proposed
Maximum
Aggregate

Offering Price(2)

 

Amount of

Registration Fee

Common units representing limited partner interests(1)

  $100,000,000   $12,880

 

 

(1) Includes common units that may be sold to cover the exercise of an over-allotment option granted to the underwriters.
(2) Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(o) under the Securities Act.

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. We and the selling unitholders may not sell the securities described herein until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell such securities and it is not soliciting an offer to buy such securities in any state where such offer or sale is not permitted.

 

Subject to Completion, Dated September 23, 2014.

Mammoth Energy Partners LP

                 Common Units Representing Limited Partner Interests

 

 

This is the initial public offering of our common units representing limited partner interests. Prior to this offering, there has been no public market for our common units. We are offering                  common units in this offering. The selling unitholders identified in this prospectus are offering an additional                  common units in this offering. We will not receive any of the proceeds from the sale of common units by the selling unitholders.

We anticipate that the initial public offering price will be between $             and $             per common unit. We have applied for listing of our common units on The NASDAQ Global Market under the symbol “TUSK.”

The underwriters have an option to purchase an additional                      common units, of which                  common units would be sold by us and                  common units would be sold by the selling unitholders, to cover any over-allotments.

 

 

We are an “emerging growth company” under applicable Securities and Exchange Commission rules and will be subject to reduced public company reporting requirements. Investing in our common units involves risks. See “Risk Factors” beginning on page 22.

These risks include the following:

 

    We may not have sufficient cash available for distribution to pay any quarterly distribution on our common units.

 

    Our partnership agreement does not require us to pay distributions. The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter.

 

    For each of the year ended December 31, 2013 and the twelve months ended June 30, 2014, on a pro forma basis, we would not have generated sufficient cash available for distribution to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015.

 

    Our business is difficult to evaluate because of our limited operating history.

 

    The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

 

    Wexford owns our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates (including Wexford and Gulfport) will have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

 

    Wexford, Gulfport and other affiliates of our general partner may compete with us.

 

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

    Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

 

    We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

 

    Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

 

    Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

 

 

 

     Price to
Public
     Underwriting
Discounts and
Commissions(1)
     Proceeds to
Mammoth Energy
     Proceeds
to Selling
Unitholders
 

Per Common Unit

   $                    $                    $                    $                

Total

   $         $         $         $     

 

(1) See “Underwriting” for additional information regarding underwriter compensation.

Delivery of the common units is expected to be made on or about                     , 2014 through the book-entry facilities of The Depository Trust Company.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved the securities described herein or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse

The date of this prospectus is                     , 2014.


Table of Contents

TABLE OF CONTENTS

 

     Page  

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     22   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     57   

USE OF PROCEEDS

     58   

CAPITALIZATION

     59   

DILUTION

     60   

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     61   

HOW WE WILL MAKE DISTRIBUTIONS

     69   

SELECTED HISTORICAL COMBINED FINANCIAL DATA

     70   

PRO FORMA FINANCIAL INFORMATION

     73   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     78   

BUSINESS

     96   

MANAGEMENT

     120   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     128   

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

     136   

PRINCIPAL AND SELLING UNITHOLDERS

     143   

DESCRIPTION OF OUR COMMON UNITS

     145   

THE PARTNERSHIP AGREEMENT

     147   

UNITS ELIGIBLE FOR FUTURE SALE

     160   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

     162   

INVESTMENT IN MAMMOTH ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

     175   

UNDERWRITING

     177   

LEGAL MATTERS

     182   

EXPERTS

     182   

WHERE YOU CAN FIND MORE INFORMATION

     182   

FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF MAMMOTH ENERGY PARTNERS LP

     A-1   

GLOSSARY OF OIL AND NATURAL GAS TERMS

     B-1   

INDEX TO FINANCIAL STATEMENTS

     F-1   

 

 

 

 

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ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We have not, and the selling unitholders and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We, the selling unitholders and the underwriters are only offering to sell, and only seeking offers to buy, our common units in jurisdictions where offers and sales are permitted.

The information contained in this prospectus is accurate and complete only as of the date of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

This prospectus includes industry data and forecasts that we obtained from internal company surveys, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable.

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

Unless the context otherwise requires, the information in this prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their over-allotment option.

 

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PROSPECTUS SUMMARY

This summary contains basic information about us and the offering. Because it is a summary, it does not contain all the information that you should consider before investing in our common units. You should read and carefully consider this entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our combined financial statements and the accompanying notes included elsewhere in this prospectus.

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the transactions described below other than certain activities related to the preparation of the registration statement for this offering. Except as expressly noted otherwise, the historical financial information of Mammoth Energy Partners LP included in this prospectus is derived from the combined financial statements of the following companies: Redback Energy Services LLC; Redback Coil Tubing LLC; Muskie Proppant LLC; Panther Drilling Systems LLC; Bison Drilling & Field Services LLC; Bison Trucking LLC and Great White Sand Tiger Lodging Ltd., all of which have been controlled and managed by our sponsor, Wexford Capital LP, or Wexford, and which are sometimes referred to in this prospectus as the common control entities. Prior to the closing of this offering, these entities together with White Wing Tubular Services LLC, or White Wing, Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC will be contributed to us by Wexford and Gulfport Energy Corporation (NASDAQ: GPOR), or Gulfport, in return for common units and, as a result, will become our wholly owned subsidiaries. Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC are holding companies for Great White Sand Tiger Lodge Ltd. As such, all of the operations have been in Sand Tiger Lodging Ltd. and the historical results of operations of both Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC are minimal and immaterial, so they are excluded from the financial information presented in this prospectus. White Wing was formed in August 2014 and began operations in September 2014 and, as a result, is not included in the financial information in the prospectus. Also prior to the closing of this offering, two other entities, Stingray Pressure Pumping LLC and Stingray Logistics LLC, which we collectively refer to in this prospectus as the Stingray entities, will be contributed to us by Wexford and Gulfport in return for common units, at which time these entities will also become our wholly owned subsidiaries. Because the Stingray entities are not under common control with the common control entities, the historical financial information of the Stingray entities is not reflected in the historical combined financial statements of Mammoth Energy Partners LP, but instead is presented in this prospectus on a stand alone basis and on a pro forma basis for Mammoth Energy Partners LP. As a result, the historical financial information of Mammoth Energy Partners LP included in this prospectus will not be indicative of the results that would have been achieved on a historical basis or that may be expected for any future periods. For more information, please see “Summary Combined Historical and Pro Forma Financial Data,” “Pro Forma Financial Information” and related notes thereto included elsewhere in this prospectus.

Except as otherwise indicated or required by the context, all references in this prospectus to “Mammoth Energy,” the “Partnership,” “we,” “us” or “our,” and its assets and operations, relate to Mammoth Energy Partners LP and its consolidated subsidiaries after giving effect to the contribution to us of all of the outstanding equity interests in the common control entities and the Stingray entities. References in this prospectus to “our general partner” refer to Mammoth Energy Partners GP LLC, which has sole responsibility for conducting our business and managing our operations as our general partner and is owned by Wexford. For more information regarding our relationships with Wexford and Gulfport, including their right to appoint our board of directors, please see “Management” and “Certain Relationships and Related Party Transactions.” References in this prospectus to “our executive officers,” “our board” and “our directors” refer to the executive officers, board of directors and directors of our general partner, respectively. References in this prospectus to “selling unitholders” refer to those entities identified as selling unitholders in “Principal and Selling Unitholders.” We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” included in this prospectus as Appendix B.

Except as otherwise indicated, all information contained in this prospectus assumes the underwriters do not exercise their over-allotment option and excludes common units reserved for issuance under our equity incentive plan.

 

 

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MAMMOTH ENERGY PARTNERS LP

Overview

We are a growth-oriented Delaware limited partnership serving companies engaged in the exploration and development of North American onshore unconventional oil and natural gas reserves. Our primary business objective is to provide an attractive total return to unitholders by optimizing business results through organic growth opportunities and accretive acquisitions. Our suite of services include completion and production services, contract land and directional drilling services and remote accommodation services. Our completion and production services division provides pressure pumping services, pressure control services, flowback services and equipment rental, and also produces and sells 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 remote accommodation division provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We believe that these services play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources. Our complementary suite of drilling and completion and production related services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

Our Services

Completion and Production Services

Our pressure pumping services consist of hydraulic fracturing services. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. We began providing pressure pumping services in October 2012 with 14 high pressure fracturing units capable of delivering a total of 31,500 horsepower. As of September 1, 2014, we had grown our pressure pumping business to 52 high pressure fracturing units capable of delivering a total of 117,000 horsepower. These units allow us to execute multi-stage hydraulic fracture stimulation on unconventional wells, which enhances production. Currently, we provide pressure pumping services in the Utica Shale of Eastern Ohio.

Our pressure control services consist of coiled tubing, nitrogen and fluid pumping services. Our pressure control services equipment is designed to support drilling activities in unconventional resource plays with the ability to operate under high pressures without having to delay or cease production during completion operations. Ceasing or suppressing production during the completion phase of an unconventional well could result in formation damage impacting the overall recovery of reserves. Our pressure control services help operators minimize the risk of such damage during completion activities. As of September 1, 2014, our pressure control services were provided through our fleet of five coiled tubing units, four nitrogen pumping units, nine fluid pumping units and various well control assets. We provide our pressure control services in the Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma, the Granite Wash and Mississippi Shale in Oklahoma and Texas, the Utica Shale in Ohio and the Permian Basin in West Texas.

Our flowback services consist of production testing, solids control, hydrostatic testing and torque services. Flowback involves the process of allowing fluids to flow from the well following treatment, either in preparation for an impending phase of treatment or to return the well to production. Our flowback equipment consists of manifolds, accumulators, valves, flare stacks and other associated equipment that combine to form up to a total of seven well-testing spreads. We provide flowback services in the Appalachian Basin and mid-continent markets.

Our equipment rental services provide a wide range of rental equipment used in flowback and hydraulic fracturing services. Our equipment rentals consist of light plants and other oilfield related equipment. We provide equipment rental services in the Appalachian Basin, Permian Basin and mid-continent markets.

 

 

 

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As part of our proppant production and sales business, we currently buy raw sand under fixed-price contracts with two suppliers, process it into premium monocrystalline sand (also known as frac sand), a specialized mineral that is used as a proppant at our indoor sand processing plant located in Pierce County, Wisconsin and sell it to our customers for use in their hydraulic fracturing operations to enhance recovery rates from unconventional wells. We produce a range of frac sand sizes for use in all major North American shale basins. Our supply of superior Jordan substrate exhibits the physical properties necessary to withstand the completion and production environments of the wells in these shale basins. Our indoor processing plant is designed for year-round continuous wet and dry plant operation capable of producing a wide variety of frac sand products based on the needs of our customers. We also provide logistics solutions to facilitate delivery of our frac sand products to our customers. Almost all of our frac sand products are shipped by rail to our customers in the Utica Shale, Permian Basin and Bakken Shale. Our access to origin and destination transloading facilities on multiple railways allow us to provide predictable and efficient loading, shipping and delivery of our frac sand products.

Contract Land and Directional Drilling Services

We provide vertical, horizontal and directional drilling services to our customers. We also provided related services such as rig moving and pipe inspection. As of September 1, 2014, we owned and operated 14 land drilling rigs, ranging from 800 to 1,600 horsepower, 11 of which are specifically designed for drilling horizontal wells, which are increasing as a percentage of total wells drilled in North America and are frequently utilized in unconventional resource plays. Our drilling rigs have rated maximum depth capabilities ranging from 12,500 feet to 20,000 feet. Currently, we perform our contract land drilling services in the Permian Basin of West Texas.

Our directional drilling services provide for the efficient drilling and production of oil and natural gas from unconventional resource plays. Our directional drilling equipment includes mud motors used to propel drill bits and kits for measurement while drilling, or MWD, and electromagnetic, or EM, technology. MWD kits are down-hole tools that provide real-time measurements of the location and orientation of the bottom-hole assembly, which is necessary to adjust the drilling process and guide the wellbore to a specific target. This technology, coupled with our services, allows our customers to drill wellbores to specific objectives within narrow location parameters within target horizons.

Our personnel are involved in all aspects of a well from the initial planning of a customer’s drilling program to the management and execution of the horizontal or directional drilling operation. As of September 1, 2014, we owned seven MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 42 mud motors with 14 more expected to be delivered by September 30, 2014 and an inventory of related parts and equipment. As of September 1, 2014, we employed 18 directional drilling personnel with significant industry experience to implement our services. Currently, we perform our directional drilling services in the Appalachian Basin, Anadarko Basin, Arkoma Basin, Permian Basin and the Gulf Coast of Louisiana.

Remote Accommodation Services

Our remote accommodation business provides a turnkey solution for our customers’ accommodation needs. These modular camps, when assembled together, form large dormitories with kitchen and dining facilities and recreation areas. Currently, we provide remote accommodation services in the Canadian oil sands in Alberta, Canada. Recently, we have focused on growing this business by purchasing additional remote accommodation rooms. As of September 1, 2014, we had 700 such rooms and we plan to have a total of 890 such rooms by the end of 2014, 762 of which are expected to be at Sand Tiger Lodge, our camp in northern Alberta, Canada, and 128 of which are expected to be leased as rental equipment to a third party.

Our Industry

We operate principally in the oilfield services industry, but also compete with producers and sellers of natural sand proppant used in hydraulic fracturing operations and remote accommodations providers primarily

 

 

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supporting oil and natural gas operations. We believe that the following trends in our industry should benefit our operations and our ability to achieve our primary business objective:

 

    Increased U.S. Crude Oil Production. According to the U.S. Energy Information Administration, or EIA, U.S. average crude oil production reached approximately 11.9 million barrels per day during July 2014, an increase of approximately 34% over 2012. U.S. average crude oil production has grown at a compound annual growth rate of 6.5% over the period from 2007 through 2013 due to production gains from unconventional reservoirs. We expect that this continued growth will result in increased demand for our services.

 

    Increased use of horizontal drilling to develop unconventional resource plays. According to Baker Hughes, the horizontal rig count on September 12, 2014 was 1,342, or approximately 70% of the total U.S. onshore rig count. This compares to 382 horizontal rigs, or approximately 22% of the total U.S. onshore rig count, at year-end 2006. As a result of improvements in drilling and production-enhancement technologies, oil and natural gas companies are increasingly developing unconventional resources such as tight sands and shales. Successful and economic production of these unconventional resource plays frequently requires horizontal drilling, fracturing and stimulation services. Drilling related activity for unconventional resources is typically done on tighter acre-spacing and thus requires that more wells be drilled relative to conventional resources. We believe that all of these characteristics will drive the demand for our services.

 

    Tight oil production growth is expected to continue to be the primary driver of U.S. oil production growth. According to the EIA, U.S. tight oil production has grown from 380,000 barrels per day in 2007 to almost 3.5 million barrels per day in 2013, representing 35% of total U.S. crude oil production in 2013. A majority of this increase has come from the Eagle Ford play in South Texas, the Bakken Shale in the Williston Basin of North Dakota and Montana, and the Permian Basin in West Texas. We believe the Utica Shale and the Permian Basin, our primary business locations, will be key drivers of US tight oil production as those plays are developed in the coming years due to anticipated increases in horizontal drilling activity.

 

    Horizontal wells are heavily dependent on oil field services. The continued increase in footage drilled per year since 2009 has resulted in increased demand for oil field services. Also, according to Baker Hughes, as of September 12, 2014, oil and liquids focused rigs accounted for approximately 82% of all rigs drilling in the United States, up from 16% at year-end 2005. The scope of services for a horizontal well are greater than for a conventional well. It has been reported in the industry that the average horsepower, length of the lateral and number of fracture stages has continued to increase since 2008. We believe our commitment to provide services in oil and liquids-focused plays, such as the Utica Shale and the Permian Basin, provide us the opportunity to compete in those regional markets where the majority of total footage is drilled each year in the United States.

 

    New and emerging unconventional resource plays. In addition to the growth and development of existing unconventional resource plays such as the Bakken, Eagle Ford, Barnett, Fayetteville, Cotton Valley, Haynesville, Marcellus and Woodford Shales, exploration and production companies continue to find new unconventional resources. These include oil and liquids-based shales in the Permian, Utica, Cana Woodford, Granite Wash, Niobrara and Woodford resource plays. We believe there are a number of exploration and production companies that have acquired vast acreage positions in these plays that will require them to drill and produce hydrocarbons to hold the leased acreage. We believe these emerging resource plays will continue to drive demand for our services as they typically require the use of extended reach horizontal drilling, multiple stage fracture stimulation and high pressure completion capabilities. We also believe we are well-positioned to expand our services in two major developing unconventional plays, the Utica Shale in Ohio and the Permian Basin in West Texas.

 

   

Increased focus on onshore unconventional plays by large independent oil companies, major integrated oil and natural gas companies and national oil companies. Major integrated exploration and

 

 

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production companies have increasingly been allocating capital and other resources to the U.S. onshore unconventional oil and natural gas tight sand and shale resource plays. Over the past two years, exploration and production companies such as ExxonMobil, BP and Chevron have made strategic acquisitions and/or formed joint ventures in these domestic unconventional resource plays. Also, international demand for access to U.S. unconventional development has been increasing as national oil companies look to benefit from the technologies developed in the U.S. shale exploration.

 

    Need for additional drilling activity to maintain production levels. With the increased maturity of the onshore conventional and, in many cases, unconventional resource plays, oil and natural gas production may be characterized as having steeper initial decline curves. As a result, we believe an increasing number of wells will need to be drilled to offset production declines. Given average decline rates and demand forecasts, we believe that the number of wells drilled is likely to continue to increase in coming years. Once a well has been drilled, it requires recurring production and completion services, which we believe will drive demand for our services.

 

    Continued development of the Canadian oil sands. Our remote accommodations business is significantly influenced by the level of development of oil sands deposits in Alberta, Canada and activity levels in support of oil and natural gas development in Canada generally. Despite the general economic downturn in 2009 and early 2010 resulting from the global financial crisis, activity in the Canadian oil sands has grown significantly in the last six years. Demand for oil sands accommodations is influenced to a great extent by the longer-term outlook for crude oil prices rather than current energy prices, given the multi-year time frame to complete oil sands projects and the costs associated with development of such large scale projects. Utilization of our existing Canadian accommodations capacity and our future expansions will largely depend on continued oil sands development spending.

Our Business Strategy

Our primary business objective is to provide an attractive total return to unitholders by optimizing business results through organic growth opportunities and accretive acquisitions. We intend to achieve this by the successful execution of our business plan to strategically deploy our equipment and personnel to provide drilling, completion and production services and remote accommodation services in unconventional resource plays. We believe these services optimize our customers’ ultimate resources recovery and present value of hydrocarbon reserves. We also believe that our services create cost efficiencies for our customers by providing a suite of complementary oilfield services designed to address a wide range of our customers’ needs. Specifically, we intend to:

 

    Capitalize on the increased activity in the unconventional resource plays. Our equipment is designed to provide drilling and completion and production services for unconventional wells, and our operations are strategically located in major unconventional resource plays. We intend to continue capitalizing on the growth in these markets and diversifying our operations across the different unconventional resource basins. Our core operations are focused primarily in the Permian Basin in West Texas and the Utica Shale in Ohio. We intend to continue to strategically deploy assets to these and other unconventional resource basins and will look to capitalize on further growth in emerging unconventional resource plays as they develop. We also plan to continue to grow our accommodations business in the Canadian oil sands as capital projects are announced and contracts awarded to service companies in need of accommodations.

 

   

Expand our services as determined by demand. During the first eight months of 2014, in response to increased customer demand, we expanded our drilling business by acquiring six electric horizontal drilling rigs, expanded our completion and production business to 117,000 horsepower and expanded our remote accommodations business by purchasing additional rooms. We intend to continue to expand our business lines as demand increases in resource plays in which we currently operate, as well as in

 

 

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new resource plays. If we perceive unmet demand in our principal geographic locations for different service lines, we will seek to expand our current service offerings to meet that demand.

 

    Leverage our broad range of services for unconventional wells. We offer a complementary suite of services relating to the drilling of unconventional wells and completion and production services related thereto. Our completion and production division provides pressure pumping services, pressure control services and flowback services for unconventional wells and includes processing and sales of proppant. Our drilling services division adds drilling capabilities to our other well-related services. We intend to leverage our existing customer relationships, operational track record and our industry reputation to cross sell our services and to increase our exposure and product offerings to our existing customers, broaden our customer base and expand opportunistically to other geographic regions in which our customers have operations, as well as to create operational efficiencies for our customers.

 

    Expand through selected, accretive acquisitions. To complement our organic growth, we intend to actively pursue selected, accretive acquisitions of related businesses and assets that can meet our targeted returns on invested capital and enhance our portfolio of products and services, market positioning and/or geographic presence. For instance, we believe demand for horizontal drilling rigs will continue to increase and, in January 2014, we acquired five electric horizontal drilling rigs, and on September 1, 2014 we acquired an additional electric horizontal drilling rig, which increased our fleet of drilling rigs to a total of 14, 11 of which are specifically designed for horizontal drilling. We believe this strategy will facilitate the continued expansion of our customer base, geographic presence and service offerings and permit us to increase cash available for distribution.

 

    Leverage our experienced operational management team and basin-level expertise. We seek to manage our business as closely as possible to the needs of our customer base. Our operational division heads have long-term relationships with our largest customers. We intend to leverage these relationships and our operational management team’s basin-level expertise to deliver innovative, client focused and basin-specific services to our customers.

Our Strengths

We believe that the following strengths will help us achieve our primary business objective:

 

    Quality equipment designed for horizontal drilling. Our service fleet is predominantly comprised of equipment that has been designed to optimize recovery from unconventional wells. As of September 1, 2014, approximately 65% of our pressure pumping equipment had been purpose built within the last twelve months to that end. Most of our pressure control equipment has been designed and built by us and is less than two years old. Our accommodation units have an average age of approximately three years and are built on a customer-by-customer basis to meet their specific needs. We believe that our equipment will allow us to provide a high level of service to our customers and capitalize on future growth in the unconventional resource plays that we serve.

 

    Experienced management and operating team. Our operational division heads have an extensive track record in the oilfield services business with an average of over 26 years of oilfield services experience. In addition, our field managers have expertise in the geological basins in which they operate and understand the regional challenges that our customers face. We believe their knowledge of our industry and business lines enhances our ability to provide innovative, client-focused and basin-specific customer service, which we also believe strengthens our relationships with our customers.

 

   

Strategic geographic positioning. We currently operate facilities and service centers to support our operations in major unconventional resource plays in the United States, including the Utica Shale in Ohio, the Permian Basin in West Texas, the Appalachian Basin in the Northeast, the Arkoma Basin in Arkansas and Oklahoma, the Anadarko Basin in Oklahoma, the Cana Woodford and Woodford Shales

 

 

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in Oklahoma, the Granite Wash and Mississippi Shale in Oklahoma and Texas, the Gulf Coast of Louisiana and the oil sands in Canada. We believe our geographic positioning within growing oil and natural gas liquids resource plays allows us to strategically capitalize on the increased activity in these unconventional resource plays.

 

    Long-term, basin-level relationships with a stable customer base. Our operational division heads and field managers have formed long-term relationships with our customer base. We believe these relationships help provide us a more stable and growth-oriented client base in the unconventional shale markets that we currently serve. Our customers include large independent oil and natural gas exploration and production companies. Our top five customers for the year ended December 31, 2013, representing 58.8% of our revenue on a pro forma basis, were Gulfport, Diamondback Energy, Inc., Grizzly Oil Sands ULC, Apache Corporation and JAMEX, Inc. Our top five customers for the six months ended June 30, 2014, representing 54.3% of our revenue on a pro forma basis, were Gulfport, Breitburn Operating LP, J. Cleo Thompson, RSP Permian LLC and Apache Corporation.

Risk Factors

Investing in our common units involves risks. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 22 for an explanation of these risks before investing in our common units. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy, operating activities or cash available for distribution, which could cause a decrease in the price of our common units and a loss of all or part of your investment.

Risks Related to Our Business

 

 

    We may not have sufficient cash available for distribution to pay any quarterly distribution on our common units.

 

    Our partnership agreement does not require us to pay distributions. The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter.

 

    For each of the year ended December 31, 2013 and the twelve months ended June 30, 2014, on a pro forma basis, we would not have generated sufficient cash available for distribution to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015.

 

    Our business is difficult to evaluate because of our limited operating history.

 

    Difficulties managing the growth of our business may adversely affect our financial condition, results of operations and cash available for distribution.

 

    The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

 

    Competition within our lines of business may adversely affect our ability to market our services.

 

    A decrease in demand for our products or services may have a material adverse effect on our financial condition, results of operations and cash available for distribution.

 

 

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    As part of our proppant production and sales business, we rely on a number of third parties for raw materials and transportation, and the termination of our relationship with one or more of these third parties could adversely affect our operations.

 

    We provide the majority of our remote accommodations services to a limited number of customers and the termination of one or more of these relationships could adversely affect our operations.

 

    Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

 

    Any failure by us to comply with applicable environmental laws and regulations, including those relating to hydraulic fracturing, could result in governmental authorities taking actions that adversely affect our operations, financial condition and cash available for distribution.

 

    Our operations are subject to operational hazards for which we may not be adequately insured.

 

    Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and cash available for distribution and slow our growth.

Risks Inherent in an Investment in Us

 

    Wexford owns our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates (including Wexford and Gulfport) will have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

 

    Wexford, Gulfport and other affiliates of our general partner may compete with us.

 

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

 

    Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

 

    We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

Tax Risks to Unitholders

 

    Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

 

    Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

 

    A portion of our operations are conducted by a corporate subsidiary that is subject to corporate-level income taxes. In the future, we may conduct additional operations in this subsidiary or other subsidiaries that are treated as corporations for U.S. federal income tax purposes.

For a discussion of other considerations that could negatively affect us or your investment in our common units, see “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

 

 

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Our Management

We are managed and operated by the board of directors and executive officers of our general partner, Mammoth Energy Partners GP LLC, which is owned by our founder and sponsor Wexford, a Greenwich, Connecticut based Securities and Exchange Commission, or SEC, registered investment advisor with approximately $4.0 billion under management as of June 30, 2014 and particular experience in the energy and natural resources sector. As a result of owning our general partner, Wexford will have the right to appoint all members of the board of directors of our general partner, including at least three directors meeting the independence standards established by The NASDAQ Stock Market LLC, or NASDAQ, except for those members of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement we expect to enter into with them prior to the closing of this offering. At least one of our independent directors will be appointed by the time our common units are first listed for trading on the NASDAQ Global Market. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operations.

Further, prior to the closing of this offering, we will enter into an advisory services agreement with Wexford under which Wexford will provide us with financial and strategic advisory services related to our business. For further information regarding this agreement, the investor rights agreement with Gulfport and certain other agreements we are also party to with Wexford and its affiliates, please see “Management” and “Certain Relationships and Related Party Transactions.”

Our Relationship with Wexford and Gulfport

In addition to Wexford’s ownership of our general partner and Gulfport’s right to appoint certain directors, upon completion of this offering, assuming Wexford, Gulfport and their respective affiliates make no additional purchases of our common units, Wexford and Gulfport will beneficially own approximately         % and         %, respectively, of our common units (approximately         % and         %, respectively, if the underwriters’ over-allotment option is exercised in full).

Wexford and Gulfport currently own and may in the future acquire businesses and assets that may be attractive for inclusion in our partnership, including but not limited to additional oil field service businesses and sand mines and relating processing facilities. Given our relationship with Wexford and Gulfport and their significant ownership interests in us, we believe they have a strong incentive to support and promote the successful execution of our business plans and objectives, but they have no obligation to do so and will continue to be free to act in a manner that is beneficial to their own interests without regard to ours. As a result, they may elect to dispose of these businesses and assets without offering us the opportunity to acquire them.

Conflicts of Interest and Fiduciary Duties

Although our relationship with our general partner, Wexford and Gulfport may provide significant benefits to us, it may also become a source of potential conflicts. For example, our general partner and its affiliates, including Wexford and Gulfport, are not restricted from competing with us. In addition, certain of the directors of our general partner also serve as officers or directors of, or have ownership in, Wexford or Gulfport.

Our general partner has a contractual duty to manage us in a manner that it believes is not adverse to our interest. However, certain directors of our general partner have fiduciary duties to manage our general partner in a manner beneficial to Wexford or Gulfport. As a result, conflicts of interest may arise in the future between us or our unitholders, on the one hand, and our general partner and its affiliates (including Wexford and Gulfport), on the other hand.

 

 

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Our partnership agreement limits the liability of and replaces the fiduciary duties otherwise owed by our general partner to our unitholders with contractual standards. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of duties by our general partner or its directors or executive officers. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and duties of our general partner and its directors and executive officers, please see “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our general partner and its affiliates, please see “Certain Relationships and Related Party Transactions.”

Our History and the Contribution Transactions

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the transactions described below other than certain activities related to the preparation of the registration statement for this offering. Except as expressly noted otherwise, the historical financial information of Mammoth Energy Partners LP included in this prospectus is derived from the combined financial statements of the following companies: Redback Energy Services LLC, or Redback Energy Services; Redback Coil Tubing LLC, or Redback Coil Tubing; Muskie Proppant LLC, or Muskie Proppant; Panther Drilling Systems LLC, or Panther Drilling; Bison Drilling & Field Services LLC, or Bison Drilling; Bison Trucking LLC, or Bison Trucking; and Great White Sand Tiger Lodging Ltd., or Sand Tiger, all of which have been controlled and managed by our sponsor, Wexford, and which are sometimes referred to in this prospectus as the common control entities. Prior to the closing of this offering, these entities together with White Wing, Great Dunvegan North SARL and Dunvegan North Oilfield Services, ULC will be contributed to us by Wexford and Gulfport in return for common units and, as a result, will become our wholly owned subsidiaries. Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC are holding companies for Sand Tiger. As such, all of the operations have been in Sand Tiger and the historical results of operations of both Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC are minimal and immaterial, so they are excluded from the financial information presented in this prospectus. White Wing was formed in August 2014 and began operations in September 2014 and, as a result, is not included in the financial information in the prospectus.

In addition, Wexford and Gulfport each currently beneficially own a 50% interest in two other entities, Stingray Pressure Pumping LLC, or Stingray Pressure Pumping, and Stingray Logistics LLC, or Stingray Logistics, which two entities we refer to as the Stingray entities. Also prior to the closing of the offering, Wexford and Gulfport will contribute to us all of the outstanding equity interests in the Stingray entities in exchange for          additional common units. We refer to the contribution of the membership interests of the Stingray entities as the “Stingray Contribution,” and together with the contribution of the common control entities, as the “Contribution Transactions.”

Because the Stingray entities will not be under common control with the common control entities at the time they are contributed to us, the historical financial information of the Stingray entities is not reflected in the historical combined financial statements of Mammoth Energy Partners LP, but instead is presented in this prospectus on a stand alone basis and on a pro forma basis for Mammoth Energy Partners LP. As a result, the historical financial information of Mammoth Energy Partners LP as of and for the years ended December 31, 2013 and 2012 and as of

 

 

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and for the six months ended June 30, 2014 and 2013 are not indicative of the results that would have resulted from the Contribution Transactions for any historical period or that may be expected for any future periods. For more information, please see “Summary Combined Historical and Pro Forma Financial Data,” “Pro Forma Financial Information” and related notes thereto included elsewhere in this prospectus.

 

 

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The following organizational charts illustrate (a) our pre-offering organizational structure and (b) our organizational structure after giving effect to the Contribution Transactions and the offering:

 

LOGO

LOGO

 

 

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(a) Our 100% interest in Sand Tiger is held indirectly through two holding companies, Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC. Sand Tiger which through its holding companies will be treated as a corporation for U.S. federal income tax purposes and is subject to Canadian income taxes.
(b) White Wing was formed in August 2014 and did not commence any business operations until September     2014.

Emerging Growth Company

We are an “emerging growth company” within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with certain requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and the reduced disclosure obligations regarding executive compensation in our periodic reports. We intend to take advantage of these reporting exemptions until we are no longer an emerging growth company. For a description of the qualifications and other requirements applicable to emerging growth companies and certain elections that we have made due to our status as an emerging growth company, see “Risk Factors—Risks Inherent in An Investment in Us—For so long as we are an ‘emerging growth company’ we will not be required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investors” on page 50 of this prospectus.

Our Offices

Our principal executive offices are located at 4727 Gaillardia Parkway, Suite 200, Oklahoma City, OK 73134, and our telephone number at that address is (405) 265-4600. Our website address is www.mammothenergypartners.com. Information contained on our website does not constitute part of this prospectus.

 

 

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The Offering

 

Common units offered by us

             common units (             common units if the underwriters’ over-allotment option is exercised in full)

 

Common units offered by the selling unitholders

             common units (             common units if the underwriters’ over-allotment option is exercised in full)

 

Common units to be outstanding immediately after completion of this offering

             common units (             common units if the underwriters’ over-allotment option is exercised in full)

 

Use of proceeds

We intend to use the net proceeds of this offering to repay outstanding borrowings in the amount of $         million under our various debt facilities and for other general partnership purposes, which may include the acquisition of additional equipment and complementary businesses. We will not receive any proceeds from the sale of common units by the selling unitholders. See “Use of Proceeds.”

 

Cash Distributions

Within 60 days after the end of each quarter, beginning with the quarter ending                 , 2014, we expect to make distributions to unitholders of record on the applicable record date. We expect our first distribution will consist of cash available for distribution (as described below) for the period from the closing of this offering through                 , 2014.

 

  In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be in an amount equal to the cash available for distribution we generate in such quarter. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that cash available for distribution for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine are appropriate.

 

  We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or to otherwise reserve cash for distributions, and we do not intend to incur debt to pay quarterly distributions. Further, it is our intent, subject to market conditions, to finance growth capital from external sources, and not to reserve cash for unspecified potential future needs.

 

 

Because our policy will be to distribute an amount equal to all cash available for distribution we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our earnings during each quarter. As a result, our quarterly distributions, if any, will not be

 

 

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stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) our operating performance, (ii) earnings caused by, among other things, fluctuations in demand for our services resulting from changes in the prices of oil and natural gas or other factors, changes in working capital or capital expenditures, including maintenance capital expenditures, and (iii) cash reserves deemed appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant and could result in no distribution for any quarter. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.

 

  For each of the year ended December 31, 2013 and the twelve months ended June 30, 2014, on a pro forma basis, we would not have generated sufficient cash available for distribution to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015. In addition, as of December 31, 2013 and June 30, 2014, on a historical basis, we did not have sufficient cash on hand to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015.

 

  Based on our unaudited pro forma condensed combined financial statements and certain assumptions, if we had been formed and completed the transactions contemplated in this prospectus on January 1, 2013, our unaudited pro forma cash available for distribution for the year ended December 31, 2013 would have been approximately $         million, or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full), and if we had been formed and completed the transactions contemplated in this prospectus on July 1, 2013, our unaudited pro forma cash available for distribution for the twelve months ended June 30, 2014 would have been approximately $         million, or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full). Please see “Cash Distribution Policy and Restrictions on Distributions— Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and for the Twelve Months Ended June 30, 2014.” The amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods and not as presenting our financial results.

 

 

Based upon our forecast for the twelve months ending September 30, 2015, and assuming the board of directors of our general partner

 

 

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declares distributions in accordance with our cash distribution policy, we expect that our aggregate distributions for the twelve months ending September 30, 2015 will be approximately $         million, or $         per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full). Please see “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015.” Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, reserve requirements and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations and financial condition. In addition, the board of directors of our general partner may be required to, or may elect to, eliminate our distributions during periods of reduced prices or demand for oilfield services, among other reasons. Please see “Risk Factors.

 

Subordinated units

None.

 

Incentive distribution rights

None.

 

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please see “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Partnership Interests.

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the unitholders holding at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon the consummation of this offering, assuming Wexford, Gulfport and their respective affiliates make no additional purchases of our common units, Wexford and Gulfport will beneficially own approximately     % and     %, respectively, of our common units (approximately     % and     %, respectively, if the underwriters’ over-allotment option is exercised in full). As a result, Wexford and Gulfport will be able to exercise control over matters requiring unitholder approval and will effectively give them the ability to prevent the removal of our general partner. Please see “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates (including Wexford) beneficially own more than         % of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the

 

 

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common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-common unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. If our general partner and its affiliates (including Wexford) reduce their ownership to below 75% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. See “The Partnership Agreement—Limited Call Right.

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2017, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately         % of the cash expected to be distributed to you with respect to that period. Because of the nature of our business and the expected variability of our quarterly distributions, however, the ratio of our taxable income to distributions may vary significantly from one year to another. Please see “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

 

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to unitholders who are individual citizens or residents of the United States, please see “Material U.S. Federal Income Tax Consequences.

 

Directed Unit Program

At our request, the underwriters have reserved up to         % of the common units being offered by this prospectus for sale to our directors, executive officers, employees, business associates and related persons at the public offering price. The sales will be made by the underwriters through a directed unit program. We do not know if these persons will choose to purchase all or any portion of this reserved common units, but any purchases they do make will reduce the number of common units available to the general public. To the extent the allotted common units are not purchased in the directed unit program, we will offer these common units to the public. These persons must commit to purchase no later than the close of business on the day following the date of this prospectus. Any directors or executive officers purchasing such reserved common units will be prohibited from selling such common units for a period of 180 days after the date of this prospectus.

 

Listing symbol

We have applied for listing of our common units on The NASDAQ Global Market under the symbol “TUSK.”

 

Risk Factors

You should carefully read and consider the information beginning on page 22 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common units.

 

 

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Summary Combined Historical and Pro Forma Financial Data

The following table sets forth our summary combined historical and pro forma financial data as of and for each of the periods indicated. The summary combined historical financial data as of December 31, 2013 and 2012 and for the years ended December 31, 2013 and 2012 are derived from the historical audited combined financial statements of the common control entities included elsewhere in this prospectus. The summary combined historical financial data for the six months ended June 30, 2014 and 2013 are derived from the historical unaudited combined financial statements of the common control entities included elsewhere in this prospectus. The unaudited pro forma financial data give effect to the Stingray Contribution and our acquisition of five electric horizontal drilling rigs in January 2014 in a transaction we refer to as the Drilling Transaction. The unaudited pro forma statement of operations data for the year ended December 31, 2013 and the six months ended June 30, 2014 assume that the Stingray Contributions and the Drilling Transaction occurred on January 1, 2013. The unaudited pro forma balance sheet data assume that the Stingray Contributions occurred on June 30, 2014. Operating results for the years ended December 31, 2013 and 2012 and the six months ended June 30, 2014 and 2013 are not necessarily indicative of results that may be expected for any future periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Selected Historical Combined Financial Data,” “Pro Forma Financial Information” and the historical combined financial statements and related notes of the common control entities included elsewhere in this prospectus.

 

 

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    Pro Forma(1)     Historical(1)  
    Six Months
Ended
June 30,
    Year Ended
December 31,
    Six Months
Ended
June 30,
    Year Ended
December 31,
 
    2014     2013     2014     2013           2013                 2012        
    (in thousands)  

Statement of Operations Data:

           

Revenue:

           

Completion and production services

  $                   $                   $ 44,481      $ 18,455      $ 47,731      $ 16,892   

Contract land and directional drilling services

        51,823        31,936        59,790        26,842   

Remote accommodation services

        9,586        12,895        25,027        14,169   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

        105,890        63,286        132,548        57,903   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenue, excluding depreciation, amortization and impairment:

           

Completion and production services

        36,033        16,987        42,627        13,764   

Contract land and directional drilling services

        42,157        25,209        53,987        20,501   

Remote accommodation services

        4,165        6,115        11,416        7,333   

Selling, general and administrative expenses

        6,082        5,162        13,614        6,443   

Depreciation and amortization

        15,034        8,486        18,995        8,149   

Impairment of long-lived assets

        —          —          938        2,435   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

        103,471        61,959        141,577        58,625   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

        2,419        1,327        (9,029     (722

Interest expense

        (1,864     (801     (2,012     (274

Other income (expense), net

        (43     153        (215     (49
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

        512        679        (11,256     (1,045

Provision for income taxes

        1,059        1,417        2,715        1,013   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

  $        $        $ (547   $ (738   $ (13,971   $ (2,058
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Financial Data:

           

Adjusted EBITDA(2) (unaudited)

  $        $        $ 17,647      $ 9,995      $ 11,422      $ 10,225   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows (used in) provided by operating activities

  $        $        $ (1,062   $ (7,362   $ 4,162      $ 4,791   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Purchases of property and equipment

  $        $        $ (75,128   $ (18,445   $ (63,956   $ (71,584

Other investing activities, net

        575        1,953        634        —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows used in investing activities

  $        $        $ (74,553   $ (16,492   $ (63,322   $ (71,584
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital contributions

  $        $        $ 47,024      $ 17,313      $ 26,979      $ 59,114   

Proceeds from financing arrangements, net of repayments

        27,901        9,002        31,966        13,959   

Other financing activities, net

        (278     (437     (361     (115
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows provided by financing activities:

  $        $        $ 74,647      $ 25,878      $ 58,584      $ 72,958   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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     Pro Forma(1)      Historical(1)  
     As of June 30,      As of December 31,  
     2014      2013      2012  
     (in thousands)  

Balance sheet data:

        

Cash and cash equivalents

   $                    $ 8,284       $ 9,075   

Other current assets

        35,643         18,375   

Property and equipment, net

        155,244         117,656   

Other assets

        3,472         3,396   
  

 

 

    

 

 

    

 

 

 

Total assets

   $                    $ 202,643       $ 148,502   
  

 

 

    

 

 

    

 

 

 

Current liabilities

   $                    $ 57,147       $ 31,067   

Long-term debt, net of current maturities

        22,905         7,213   

Other long-term liabilities

        1,877         1,425   

Unitholders’, shareholders’ and members’ equity

        120,714         108,797   
  

 

 

    

 

 

    

 

 

 

Total liabilities and unitholders’, shareholders’ and members’ equity

   $                    $ 202,643       $ 148,502   
  

 

 

    

 

 

    

 

 

 

 

(1) Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the contribution of the common control entities and the Stingray entities to us prior to the completion of this offering other than certain activities related to the preparation of the registration statement for this offering. The historical combined financial statements and other financial information of Mammoth Energy Partners LP included in this prospectus pertain to assets, liabilities, revenues and expenses of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling, Bison Trucking and Sand Tiger, or the common control entities, which are entities under the common control of our sponsor, Wexford. Except for Sand Tiger, each of the common control entities was treated as a partnership for federal income tax purposes. As a result, essentially all of their taxable earnings and losses were passed through to Wexford, and such entities did not pay federal income taxes at the entity level. Prior to the completion of this offering, all of these entities will become our wholly owned subsidiaries. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date.
(2) 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 earnings before interest expense, provision for income taxes, depreciation and amortization expense, impairment of long-lived assets, equity based compensation and other non-operating income or expense, net. We exclude the items listed above from net income 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.

 

 

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The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net loss.

 

     Pro Forma      Historical  
     Six Months
Ended
June 30,
     Year Ended
December 31,
     Six Months
Ended June 30,
    Year Ended
December 31,
 
     2014      2013      2014     2013         2013             2012      
    

(in thousands)

 

Reconciliation of Adjusted EBITDA to net loss:

              

Net loss

   $         $         $ (547   $ (738   $ (13,971   $ (2,058

Depreciation and amortization expense

           15,034        8,486        18,995        8,149   

Impairment of long-lived assets

           —          —          938        2,435   

Equity based compensation

           194        182        518        363   

Interest expense

           1,864        801        2,012        274   

Other (income) expense, net

           43        (153     215        49   

Provision for income taxes

           1,059        1,417        2,715        1,013   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $         $         $ 17,647      $ 9,995      $ 11,422      $ 10,225   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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RISK FACTORS

An investment in our common units involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common units. Our business, financial condition and results of operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

Risks Related to Our Business

We may not have sufficient cash available for distribution to pay any quarterly distribution on our common units.

We may not have sufficient cash available for distribution each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. Our expected aggregate annual distribution amount for the twelve months ending September 30, 2015 is based on the assumptions set forth in “Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015—Assumptions and Considerations.” If our assumptions prove to be inaccurate, our actual distributions for the twelve months ending September 30, 2015 may be significantly lower than our forecasted distributions, or we may not be able to pay a distribution at all. The amount of cash we have to distribute each quarter principally depends upon the amount of revenues we generate from oilfield services, which are dependent upon the oil and gas industry and particularly on the level of exploration and production activity within the United States and Canada. In addition, the actual amount of cash we will have to distribute each quarter under the cash distribution policy that the board of directors of our general partner will adopt will be reduced by maintenance capital expenditures, payments in respect of debt service and other contractual obligations and fixed charges and increases in reserves for future operating or capital needs that the board of directors may determine is appropriate.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please see “Cash Distribution Policy and Restrictions on Distributions.”

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.

The amount of our quarterly cash distributions, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time and could make no distribution with respect to any particular quarter.

Investors who are looking for an investment that will pay regular and predictable quarterly distributions should not invest in our common units. Our future business performance may be volatile, and our cash flows may be unstable. We will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero.

 

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The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of cash available for distribution we generate. Our partnership agreement does not require us to make any distributions at all.

The board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute all of the cash available for distribution we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters regardless of the amount of cash available for distribution we generate. Our partnership agreement does not require us to make any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.

For each of the year ended December 31, 2013 and the twelve months ended June 30, 2014, on a pro forma basis, we would not have generated sufficient cash available for distribution to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015. In addition, as of December 31, 2013 and June 30, 2014, on a historical basis, we did not have sufficient cash on hand to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015.

During the twelve months ending September 30, 2015, we estimate that we will be able to pay aggregate quarterly distributions of $         per common unit on an annualized basis ($ per common unit if the underwriters’ over-allotment option is exercised in full). In order to pay these estimated distributions, we must generate approximately $         million of cash available for distribution during the twelve months ending September 30, 2015. We have a limited operating history upon which to rely in evaluating whether we will have sufficient cash to allow us to pay quarterly distributions on our common units. In addition, as of December 31, 2013 and June 30, 2014, on a historical basis, we did not have sufficient cash on hand to pay the per common unit quarterly distribution that we estimate we will be able to pay for the twelve months ending September 30, 2015. For a description of the material assumptions underlying our estimate of these per common unit quarterly distributions during the twelve months ending September 30, 2015, please see “Cash Distribution Policy and Restrictions on Distributions— Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015—Assumptions and Considerations.”

The assumptions underlying the forecast of cash available for distribution that we include in “Cash Distribution Policy and Restrictions on Distributions” may prove inaccurate and are subject to significant risks and uncertainties, which could cause actual results to differ materially from our forecasted results.

The forecast of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecast of our results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending September 30, 2015. The assumptions underlying the forecast may prove inaccurate and are subject to significant risks and uncertainties that could cause actual results to differ materially from our forecasted results. If our actual results are significantly below forecasted results, or if our expenses are greater than forecasted, we may not be able to pay the forecasted annual distribution, which may cause the market price of our common units to decline materially.

Our business is difficult to evaluate because we have a limited operating history.

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. All of our historical assets and operations described in this prospectus are currently those of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling and Sand Tiger, which are entities controlled by our sponsor, Wexford, and the Stingray entities, which are entities currently beneficially owned

 

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50% by each of Wexford and Gulfport. Immediately prior to the closing of this offering, we will effect the Contribution Transactions. Although Sand Tiger began operations in 2007, the other operating entities involved in the Contribution Transactions began operations between September 2011 and September 2014. Further, these companies have not previously been operated as one business. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

Our customer base is concentrated and the loss of, or nonperformance by, one or more of our significant customers could cause our revenue to decline substantially.

Our top five customers accounted for approximately 54.3% and 58.8% of our revenue, on a pro forma basis, for the six months ended June 30, 2014 and the year ended December 31, 2013, respectively. Gulfport was our largest customer accounting for approximately 36.8% and 46.1% of our revenue for such periods, respectively, on a pro forma basis, with no other customer accounting for more than 10% of our revenue during those periods. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer decided not to continue to use our services, our revenue would decline and our operating results and financial condition could be harmed. In addition, we are subject to credit risk due to the concentration of our customer base. Any increase in the nonpayment of and nonperformance by our counterparties, either as a result of changes in financial and economic conditions or otherwise, could have an adverse impact on our operating results and cash available for distribution and could adversely affect our liquidity.

Our business depends on the oil and natural gas industry and particularly on the level of exploration and production activity within the United States and Canada, which may be adversely impacted by industry conditions that are beyond our control.

Substantially all of our revenue is derived from sales to companies in the oil and gas industry. We depend largely on our customers’ willingness and ability to make operating and capital expenditures to explore for, develop and produce oil and natural gas in the United States and Canada. If these expenditures decline, our business will suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:

 

    the domestic and foreign supply of and demand for oil and natural gas;

 

    the level of prices, and expectations about future prices, of oil and natural gas;

 

    the level of global oil and natural gas exploration and production;

 

    the cost of exploring for, developing, producing and delivering oil and natural gas;

 

    the expected decline rates of current production;

 

    the price of foreign imports;

 

    political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

 

    the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

    speculative trading in crude oil and natural gas derivative contracts;

 

    the level of consumer product demand;

 

    the discovery rates of new oil and natural gas reserves;

 

    contractions in the credit market;

 

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    available pipeline and other transportation capacity;

 

    weather conditions and other natural disasters;

 

    political instability in oil and natural gas producing countries;

 

    domestic and foreign governmental approvals and regulatory requirements and conditions;

 

    the continued threat of terrorism and the impact of military and other action, including military action in the Middle East;

 

    technical advances affecting energy consumption;

 

    the proximity and capacity of oil and natural gas pipelines and other transportation facilities;

 

    the price and availability of alternative fuels;

 

    the ability of oil and natural gas producers to raise equity capital and debt financing;

 

    merger and divestiture activity among oil and natural gas producers; and

 

    overall domestic and global economic conditions.

Any of the above factors could impact the level of oil and natural gas exploration and production activity and could ultimately have a material adverse effect on our business, financial condition, results of operations and cash flows.

The cyclicality of the oil and natural gas industry may cause our operating results to fluctuate.

We derive our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and natural gas prices. We may experience significant fluctuations in operating results as a result of the reactions of our customers to changes in oil and natural gas prices. For example, in 2009, declines in prices for oil and natural gas, combined with adverse changes in the capital and credit markets, caused many exploration and production companies to reduce their capital budgets and drilling activity. This resulted in a significant decline in demand for oilfield services and adversely impacted the prices oilfield services companies could charge for their services. In addition, a majority of the service revenue we earn is based upon a charge for a relatively short period of time (e.g., an hour, a day, a week) for the actual period of time the service is provided to our customers. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market prices and utilization, with resulting volatility in our revenues.

If oil and natural gas prices remain volatile, or if oil prices decline or natural gas prices remain low or decline further, the demand for our services could be adversely affected.

The demand for our services is primarily determined by current and anticipated oil and natural gas prices and the related general production spending and level of drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and may cause lower rates and lower utilization of our well service equipment. If oil prices decline or natural gas prices continue to remain low or decline further, or if there is a reduction in drilling activities, the demand for our services and our results of operations could be materially and adversely affected.

Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate, or WTI, has ranged from a high of $145.31 per barrel, or Bbl,

 

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in July 2008 to a low of $30.28 per Bbl in December 2008. The Henry Hub spot market price of natural gas has ranged from a high of $13.31 per million British thermal units, or MMBtu, in July 2008 to a low of $1.82 per MMBtu in April 2012. During 2013, West Texas Intermediate prices ranged from $85.61 to $112.24 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.05 to $4.53 per MMBtu. On June 30, 2014, the West Texas Intermediate posted price for crude oil was $106.07 per Bbl and the Henry Hub spot market price of natural gas was $4.39 per MMBtu.

Competition within the oilfield services industry may adversely affect our ability to market our services.

The oilfield services industry is highly competitive and fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. The amount of equipment available may exceed demand, which could result in active price competition. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. In addition, adverse market conditions lower demand for well servicing equipment, which results in excess equipment and lower utilization rates. If market conditions in our oil-oriented operating areas were to deteriorate or if adverse market conditions in our natural gas-oriented operating areas persist, utilization rates may decline.

Shortages, delays in delivery and interruptions in supply of drill pipe, replacement parts, other equipment, supplies and materials may adversely affect our contract land and directional drilling business.

During periods of increased demand for drilling services, the industry has experienced shortages of drill pipe, replacement parts, other equipment, supplies and materials, including, in the case of our pressure pumping operations, proppants, acid, gel and water. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply could result in significant delays in delivery of equipment and materials or prevent operations. Interruptions may be caused by, among other reasons:

 

    weather issues, whether short-term such as a hurricane, or long-term such as a drought, and

 

    shortage in the number of vendors able or willing to provide the necessary equipment, supplies and materials, including as a result of commitments of vendors to other customers or third parties.

These price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating costs. Severe shortages, delays in delivery and interruptions in supply could limit our ability to construct and operate our drilling rigs and could have a material adverse effect on our business, financial condition, cash flows, results of operations and cash available for distribution.

Advancements in drilling and well service technologies could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

As new horizontal and directional drilling, pressure pumping, pressure control and other well service technologies develop, we may be placed at a competitive disadvantage, and competitive pressure may force us to implement new technologies at a substantial cost. We may not be able to successfully acquire or use new technologies.

Further, our customers are increasingly demanding the services of newer, higher specification drilling rigs.

There can be no assurance that we will:

 

    have sufficient capital resources to build new, technologically advanced drilling rigs;

 

    successfully integrate additional drilling rigs;

 

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    effectively manage the growth and increased size of our organization and drilling fleet;

 

    successfully deploy idle, stacked or additional drilling rigs;

 

    maintain crews necessary to operate additional drilling rigs; or

 

    successfully improve our financial condition, results of operations, business or prospects as a result of building new drilling rigs.

If we are not successful in building new rigs and equipment or upgrading our existing rigs and equipment in a timely and cost-effective manner, we could lose market share. New technologies, services or standards could render some of our services, drilling rigs or equipment obsolete, which could have a material adverse impact on our business, financial condition, results of operation and cash available for distribution.

Our business depends upon our ability to obtain specialized equipment and parts from third-party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

We purchase specialized equipment and parts from third party suppliers and affiliates, including companies controlled by Wexford. At times during the business cycle, there is a high demand for hydraulic fracturing, coiled tubing and other oil field services and extended lead times to obtain equipment needed to provide these services. Further, there are a limited number of suppliers that manufacture the equipment we use. Should our current suppliers be unable or unwilling to provide the necessary equipment and parts or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution. In addition, future price increases for this type of equipment and parts could negatively impact our ability to purchase new equipment to update or expand our existing fleet or to timely repair equipment in our existing fleet.

As part of our proppant production and sales business, we rely on third parties for raw materials and transportation, and the termination of our relationship with one or more of these third parties could adversely affect our operations.

As part of our proppant production and sales business, we buy raw sand, process it into premium monocrystalline sand, a specialized mineral that is used as a proppant (also known as frac sand), at our indoor sand processing plant located in Pierce County, Wisconsin and sell it to our customers for use in their hydraulic fracturing operations to enhance the recovery rates of hydrocarbons from oil and natural gas wells. We contract with third party providers to transport raw sand from a sand mine to our sand processing plant. We also provide logistics solutions to deliver our frac sand products to our customers. Because our customers generally find it impractical to store frac sand in large quantities near their job sites, they seek to arrange for product to be delivered where and as needed, which requires predictable and efficient loading and shipping of product. To facilitate our logistics capabilities, we contract with third party providers to transport our frac sand products to railroad facilities for delivery to our customers. We also lease a railcar fleet from various third parties to deliver our frac sand products to our customers and lease or otherwise utilize origin and destination transloading facilities. The termination or nonrenewal of our relationship with any one or more of these third parties involved in the sourcing, transportation and delivery of our frac sand products could result in material operational delays, increase our operating costs, limit our ability to service our customers’ wells or otherwise materially and adversely affect our business, operating results and cash available for distribution.

Future performance of our proppant processing and sales business will depend on our ability to succeed in competitive markets, and on our ability to appropriately react to potential fluctuations in the demand for and supply of frac sand.

In our proppant production and sales business, we operate in a highly competitive market that is characterized by a small number of large, national producers and a larger number of small, regional or local producers.

 

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Competition in the industry is based on price, consistency and quality of product, site location, distribution and logistics capabilities, customer service, reliability of supply and breadth of product offering. The large, national producers with whom we compete include Badger Mining Corporation, Fairmount Minerals, Ltd., Hi-Crush Partners LP, Preferred Proppants LLC, Unimin Corporation and U.S. Silica Holdings Inc. Our larger competitors may have greater financial and other resources than we do, may develop technology superior to ours, may have production facilities that are located closer to sand mines from which raw sand is mined or to their key customers than our processing facility or have a more cost effective access to raw sand and transportation facilities that we do. Should the demand for hydraulic fracturing services decrease, prices in the frac sand market could materially decrease as producers may seek to preserve market share or exit the market and sell frac sand at below market prices. In addition, oil and natural gas exploration and production companies and other providers of hydraulic fracturing services could acquire their own frac sand reserves, develop or expand frac sand production capacity or otherwise fulfill their own proppant requirements and existing or new frac sand producers could add to or expand their frac sand production capacity, which may negatively impact pricing and demand for our frac sand. We may not be able to compete successfully against either our larger or smaller competitors in the future, and competition could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

An increase in the supply of raw frac sand having similar characteristics as the raw frac sand we produce could make it more difficult for us to market our sand on favorable terms or at all.

We have entered into a long-term, take-or-pay contract with our principal frac sand supplier. If significant new reserves of raw frac sand continue to be discovered and developed, and those frac sands have similar characteristics to the frac sand we produce, the market price for our frac sand may decline. If the market price for our frac sand falls below an amount equal to the contracted purchase price in our take-or-pay contract plus our processing and related transportation costs, this could have an adverse effect on our results of operations, cash flows and cash available for distribution over the remaining term of this contract.

Diminished access to water and inability to secure or maintain necessary permits may adversely affect our operations in our proppant production and sales business.

As part of our proppant production and sales business, we own and operate an indoor sand processing plant located in Peirce County, Wisconsin. We also lease and operate two sand transloading facilities, one in Chippewa Falls, Wisconsin and the other in St. Paul, Minnesota. The processing of raw sand and production of natural sand proppant require significant amounts of water. As a result, securing water rights and water access is necessary for the operation of our processing facilities. If the area where our facilities are located experiences water shortages, restrictions or any other constraints due to drought, contamination or otherwise, there may be additional costs associated with securing water access. We have obtained water rights that we currently use to service our activities, and we plan to obtain all required water rights to service any other properties or facilities we may develop or acquire in the future. However, the amount of water that we are entitled to use pursuant to our water rights must be determined by the appropriate regulatory authorities. Such regulatory authorities may amend the regulations regarding such water rights, increase the cost of maintaining such water rights or eliminate our current water rights, and we may be unable to retain all or a portion of such water rights. If implemented, these new regulations could also affect local municipalities and other industrial operations and could have a material adverse effect on costs involved in operating our proppant production and sales business. Such changes in laws, regulations or government policy and related interpretations pertaining to water rights may alter the environment in which we do business, which may have an adverse effect on our financial condition and results of operations. Additionally, a water discharge permit may be required to properly dispose of water at our processing site. Certain of our facilities are also required to obtain storm water permits. The water discharge, storm water or any other permits we may be required to have in order to conduct our operations is subject to regulatory discretion, and any inability to obtain or maintain the necessary permits could have an adverse effect on our financial condition, results of operations and cash available for distribution.

 

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Demand for our frac sand products could be reduced by changes in well stimulation processes and technologies, as well as changes in governmental regulations and other applicable law.

As part of our proppant production and sales business, we sell custom frac sand products to our customers for use in their hydraulic fracturing operations to enhance the recovery rates of hydrocarbons from oil and natural gas wells. A significant shift in demand from frac sand to other proppants, or the development of new processes to replace hydraulic fracturing altogether, could cause a decline in the demand for the frac sand we produce and result in a material adverse effect on our financial condition and results of operations. Further, federal and state governments and agencies have adopted various laws and regulations or are evaluating proposed legislation and regulations that are focused on the extraction of shale gas or oil using hydraulic fracturing, a process which utilizes proppants such as those that we produce. Future hydraulic fracturing-related legislation or regulations could restrict the ability of our customers to utilize, or increase the cost associated with, hydraulic fracturing, which could reduce demand for our proppants and adversely affect our financial condition, results of operations, cash flows and cash available for distribution. For additional information regarding the regulation of hydraulic fracturing, see “Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

We provide the majority of our remote accommodations services to a limited number of customers, and the termination of one or more of these relationships could adversely affect our operations.

We provide turnkey remote accommodations services for oilfield related labor located in remote areas, which services include site identification, permitting and development, facility design, construction, installation and full site maintenance. The majority of our revenue from this business is derived from a limited number of customers pursuant to long-term agreements with these customers. The termination of our relationships or nonrenewal of our agreements with one or more of these customers could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The customized nature, and remote location, of the modular camps that we provide and service present unique challenges that could adversely affect our ability to successfully operate our remote accommodations business.

We rely on a third-party subcontractor to manufacture and install the customized modular units used in our remote accommodations business. These customized units often take a considerable amount of time to manufacture and, once manufactured, often need to be delivered to remote areas that are frequently difficult to access by traditional means of transportation. In the event we are unable to provide these modular units in a timely fashion, we may not be entitled to full, or any, payment therefor under the terms of our contracts with customers. In addition, the remote location of the modular camps often makes it difficult to install and maintain the units, and our failure, on a timely basis, to have such units installed and provide maintenance services could result in our breach of, and non-payment by our customers under, the terms of our customer contracts. Any of these factors could have a material adverse effect on our remote accommodation business and our overall financial condition, results of operations and cash available for distribution.

Health and food safety issues and food-borne illness concerns could adversely affect our remote accommodations business.

We provide food services to our customers as part of our remote accommodations business and, as a result, face health and food safety issues that are common in the food and hospitality industries. Food-borne illnesses, such as E. coli, hepatitis A, trichinosis or salmonella, and food safety issues have occurred in the food industry in the past and could occur in the future. We work to provide a clean, safe environment for our guests and employees and attempt to purchase supplies from reputable suppliers and distributors. Our reliance on third-party food suppliers and distributors increases the risk that food-borne illness incidents could be caused by factors outside of our control. New illnesses resistant to any precautions may develop in the future, or diseases with long incubation periods could

 

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arise. Further, the remote nature of our accommodation facilities and related food services may increase the risk of contamination of our food supply and create additional health and hygiene concerns due to the limited access to modern amenities and conveniences that may not be faced by other food service providers or hospitality businesses operating in urban environment. If our customers become ill from food-borne illness, we could be forced to close some or all of our remote accommodation facilities on a temporary basis or otherwise. Any such incidents and/or any report of publicity linking us to incidents of food-borne illness or other food safety issues, including food tampering or contamination, could adversely affect our remote accommodations business as well as our overall financial condition, results of operations and cash available for distribution.

Development of permanent infrastructure in the Canadian oil sands region or other locations where we locate our remote accommodations could negatively impact our remote accommodations business.

Our remote accommodations business specializes in providing modular housing and related services for work forces in remote areas which lack the infrastructure typically available in towns and cities. If permanent towns, cities and municipal infrastructure develop in the oil sands region of northern Alberta, Canada or other regions where we locate our modular camps, then demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.

Revenue generated and expenses incurred by our remote accommodation business are denominated in the Canadian dollar and could be negatively impacted by currency fluctuations.

Our remote accommodation business generates revenue and incurs expenses that are denominated in the Canadian dollar. These transactions could be materially affected by currency fluctuations. Changes in currency exchange rates could adversely affect our combined results of operations or financial position. We also maintain cash balances denominated in the Canadian dollar. At December 31, 2013, we had $4.0 million of cash in Canadian accounts. A 10% increase in the strength of the Canadian dollar versus the U.S. dollar would have resulted in an increase in pre-tax income of approximately $1.0 million as of December 31, 2013. Conversely, a corresponding decrease in the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

Certain of our completion and production services, particularly our hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations, cash flows and cash available for distribution.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. During the last two years, certain of the areas have experienced extreme drought conditions and competition for water in such shales is growing. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Our inability to obtain water to use in our operations from local sources or to effectively utilize flowback water could have an adverse effect on our financial condition, results of operations, cash flows and cash available for distribution.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team, including our Chief Executive Officer, could disrupt our operations. We do not have an employment agreement with these executives at this time. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

 

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If we are unable to employ a sufficient number of skilled and qualified workers, our capacity and profitability could be diminished and our growth potential could be impaired.

The delivery of our products and services requires skilled and qualified workers with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield services industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited. As a result, competition for experienced oilfield service personnel is intense, and we face significant challenges in competing for crews and management with large and well-established competitors. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Unionization efforts could increase our costs or limit our flexibility.

Presently, none of our employees work under collective bargaining agreements. Unionization efforts have been made from time to time within our industry, to varying degrees of success. Any such unionization could increase our costs or limit our flexibility.

Our operations may be limited or disrupted in certain parts of the continental U.S. and Canada during severe weather conditions, which could have a material adverse effect on our financial condition, results of operations and cash available for distribution.

We provide contract land and directional drilling services completion and production services in the Utica, Permian Basin, Marcellus, Granite Wash, Cana Woodford and Cleveland Sand resource plays located in the continental U.S. We also provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers located in Ohio, Oklahoma, Texas, Wisconsin, Minnesota and Alberta, Canada. For the six months ended June 30, 2014 and the year ended December 31, 2013, we generated approximately 57.1% and 52.4%, respectively, of our pro forma revenue, on a pro forma basis, from our operations in Ohio, Wisconsin, Minnesota and Canada where weather conditions may be severe, particularly during winter and spring months. Repercussions of severe weather conditions may include:

 

    curtailment of services;

 

    weather-related damage to equipment resulting in suspension of operations;

 

    weather-related damage to our facilities;

 

    inability to deliver equipment and materials to jobsites in accordance with contract schedules; and

 

    loss of productivity.

Many municipalities, including those in Ohio and Wisconsin, impose bans or other restrictions on the use of roads and highways, which include weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. This can limit our access to these jobsites and our ability to service wells in these areas. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs in those regions. Weather conditions may also affect the price of crude oil and natural gas, and related demand for our services. Any of these factors could have a material adverse effect on our financial condition, results of operations and cash available for distribution.

 

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Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids can be sold, which could affect the ability of our customers to continue operations and ultimately adversely impact our results of operations, liquidity, financial condition and cash available for distribution.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could limit our ability to grow.

The oilfield services industry is capital intensive. In conducting our business and operations, we have made, and expect to continue to make, substantial capital expenditures. Our total capital expenditures were approximately $64.0 million and $71.6 million for the year ended December 31, 2013 and the year ended December 31, 2012, respectively. Currently, our capital expenditures budget for 2014 is approximately $139.0 million. To date, we have financed capital expenditures primarily with funding from our equity investors, cash generated by operations and borrowings under our revolving credit facilities and term loans from our lenders. Following the completion of this offering and the application of the net proceeds to repay our outstanding indebtedness, we intend to finance our capital expenditures primarily with cash on hand, cash flow from operations and borrowings under our revolving credit facilities. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment or properly maintaining our existing equipment. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures for 2014 or future years could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability and cash available for distribution.

The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable, accretive acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

As a component of our business strategy, we have pursued and intend to continue to pursue selected, accretive acquisitions of complementary assets, businesses and technologies. Acquisitions involve numerous risks, including:

 

    unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including but not limited to environmental liabilities;

 

    difficulties in integrating the operations and assets of the acquired business and the acquired personnel;

 

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    limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business, in order to comply with public reporting requirements;

 

    potential losses of key employees and customers of the acquired businesses;

 

    inability to commercially develop acquired technologies;

 

    risks of entering markets in which we have limited prior experience; and

 

    increases in our expenses and working capital requirements.

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. Furthermore, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have financed capital expenditures primarily with funding from our equity investors, cash generated by operations and borrowings under our revolving credit facilities and term loans. We may incur substantial indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing unitholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.

Our ability to grow through acquisitions and manage growth will require us to continue to invest in operational, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position, results of operations and cash available for distribution may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

We may have difficulty managing growth in our business, which could adversely affect our financial condition, results of operations and cash available for distribution.

As a recently formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand the scope of our activities and our geographic coverage through both organic growth and acquisitions, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, engineers and other professionals in the oilfield services industry, could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution and our ability to successfully or timely execute our business plan.

 

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If our intended expansion of our business is not successful, our financial condition, profitability and results of operations could be adversely affected, and we may not achieve the distributions and increases in revenue and profitability that we hope to realize.

A key element of our business strategy involves the expansion of our services, geographic presence and customer base. These aspects of our strategy are subject to numerous risks and uncertainties, including:

 

    an inability to retain or hire experienced crews and other personnel;

 

    a lack of customer demand for the services we intend to provide;

 

    an inability to secure necessary equipment, raw materials (particularly sand and other proppants) or technology to successfully execute our expansion plans;

 

    shortages of water used in our hydraulic fracturing operations;

 

    unanticipated delays that could limit or defer the provision of services by us and jeopardize our relationships with existing customers and adversely affect our ability to obtain new customers for such services; and

 

    competition from new and existing services providers.

Encountering any of these or any unforeseen problems in implementing our planned expansion could have a material adverse impact on our business, financial condition, results of operations and cash flows, and could prevent us from achieving the distributions and increases in revenues and profitability that we hope to realize.

Our indebtedness and liquidity needs could restrict our operations and make us more vulnerable to adverse economic conditions.

Our existing and future indebtedness, whether incurred in connection with acquisitions, operations or otherwise, may adversely affect our operations and limit our growth, and we may have difficulty making debt service payments on such indebtedness as payments become due. Our level of indebtedness may affect our operations in several ways, including the following:

 

    increasing our vulnerability to general adverse economic and industry conditions;

 

    the covenants that are contained in the agreements governing our indebtedness could limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;

 

    our debt covenants could also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

    any failure to comply with the financial or other covenants of our debt, including covenants that impose requirements to maintain certain financial ratios, could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;

 

    our level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and

 

    our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.

Our new and any future revolving credit facilities will impose restrictions on us that may affect our ability to successfully operate our business.

Our new and any future revolving credit facilities and any future term debt will limit our ability to take various actions, such as:

 

    incurring additional indebtedness;

 

    paying distributions;

 

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    creating certain additional liens on our assets;

 

    entering into sale and leaseback transactions;

 

    making investments;

 

    entering into transactions with affiliates;

 

    making material changes to the type of business we conduct or our business structure;

 

    making guarantees;

 

    disposing of assets in excess of certain permitted amounts;

 

    merging or consolidating with other entities; and

 

    selling all or substantially all of our assets.

In addition, our new and any future revolving credit facilities and any future term debt will require us to maintain certain financial ratios and to satisfy certain financial conditions, which may require us to reduce our debt or take some other action in order to comply with each of them. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under these credit facilities and debt agreements. Further, from time to time certain of our subsidiaries have not been in compliance with one or more of the financial covenants contained in their respective credit agreements. In each instance, the lender waived such noncompliance. If we fail to comply with the covenants in our new or any future credit facilities and such failure is not waived by the lender, a default may be declared by the lenders, which could have a material adverse effect on us.

Our new and any future credit facilities are expected to provide for variable interest rates, which may increase or decrease our interest expense.

On a pro forma basis, we would have had an aggregate of $107.1 million outstanding under various credit facilities at June 30, 2014, which bore interest at variable rates generally based on prime plus various factors. Based on this pro forma debt structure, a 1% increase or decrease in the interest rates would increase or decrease interest expense, respectively, by approximately $1.1 million per year. We do not currently hedge our interest rate exposure.

We may not be able to provide services that meet the specific needs of oil and natural gas exploration and production companies at competitive prices.

The markets in which we operate are generally highly competitive and have relatively few barriers to entry. The principal competitive factors in our markets are price, product and service quality and availability, responsiveness, experience, technology, equipment quality and reputation for safety. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

 

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In addition, some exploration and production companies have begun performing hydraulic fracturing and directional drilling on their wells using their own equipment and personnel. Any increase in the development and utilization of in-house fracturing and directional drilling capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.

Our operations are subject to hazards inherent in the oil and natural gas industry, which could expose us to substantial liability and cause us to lose customers and substantial revenue.

Risks inherent to our industry, such as equipment defects, vehicle accidents, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, pipe or pipeline failures, abnormally pressured formations and various environmental hazards such as oil spills and releases of, and exposure to, hazardous substances. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. The cost of managing such risks may be significant. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues. In addition, these risks may be greater for us than some of our competitors because we sometimes acquire companies that may not have allocated significant resources and management focus to safety and environmental matters and may have a poor environmental and safety record and associated possible exposure.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover all losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations, cash flows and cash available for distribution. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, cash flows and cash available for distribution.

We are subject to extensive environmental, health and safety laws and regulations that may subject us to substantial liability or require us to take actions that will adversely affect our results of operations.

Our business is significantly affected by stringent and complex federal, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection and health and safety matters. As part of our business, we handle, transport and dispose of a variety of fluids and substances, including hydraulic fracturing fluids which can contain hydrochloric acid and certain petrochemicals.

 

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This activity poses some risks of environmental liability, including leakage of hazardous substances from the wells to surface and subsurface soils, surface water or groundwater. We also handle, transport and store these substances. The handling, transportation, storage and disposal of these fluids are regulated by a number of laws, including: the Resource Conservation and Recovery Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; and other federal and state laws and regulations promulgated thereunder. The cost of compliance with these laws can be significant. Failure to properly handle, transport or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to substantial liability for administrative, civil and criminal penalties, cleanup and site restoration costs and liability associated with releases of such materials, damages to natural resources and other damages, as well as potentially impair our ability to conduct our operations. We could be exposed to liability for cleanup costs, natural resource damages and other damages under these and other environmental laws. Such liability is commonly on a strict, joint and several liability basis, without regard to fault. Liability may be imposed as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations have changed in the past, and they are likely to change in the future and become more stringent. If existing environmental requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for oil and natural gas.

In December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other greenhouse gases (collectively, GHGs) present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective in January 2011. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the rule in 2014. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010.

In addition, the EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set New Performance Standards for new coal-fired and natural-gas fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility, which could reduce the demand for our products and services. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

 

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Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry, and it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The Environmental Protection Agency, or EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress.

On August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. For example, on April 12, 2013, the EPA published a proposed

 

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amendment extending compliance dates for certain storage vessels. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty. In addition, the U.S. Department of the Interior published a revised proposed rule on May 24, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected later in 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Several states, including Texas and Ohio, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act, or OSHA, to state regulators and on a public internet website. In January 2012, the Ohio Department of Natural Resources, or ODNR, issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area and the ODNR continues to monitor earthquake activity in proximity to wells undergoing hydraulic fracturing. We use, and intend to continue using, hydraulic fracturing extensively in our operations, and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the demand for these services and materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

 

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Penalties, fines or sanctions that may be imposed by the U.S. Mine Safety and Heath Administration could have a material adverse effect on our proppant production and sales business and our overall financial condition, results of operations and cash flows.

The U.S. Mine Safety and Health Administration, or MSHA, has primary regulatory jurisdiction over commercial silica operations, including quarries, surface mines, underground mines, and industrial mineral process facilities. While we do not directly conduct any mining operations, we are dependent on several regulated mines for the supply of natural sand used in our proppant production. In addition, MSHA representatives perform at least two annual inspections of our production facilities to ensure employee and general site safety. As a result of these and future inspections and alleged violations and potential violations, we and our suppliers could be subject to material fines, penalties or sanctions. Any of our production facilities or our suppliers’ mines could be subject to a temporary or extended shut down as a result of an alleged MSHA violation. Any such penalties, fines or sanctions could have a material adverse effect on our proppant production and sales business and our overall financial condition, results of operations, cash flows and cash available for distribution.

Increasing trucking regulations may increase our costs and negatively impact our results of operations.

In connection with our business operations, including the transportation and relocation of our oilfield service equipment and shipment of frac sand, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials (HAZMAT). Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the United States Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal and state regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations. The rating scale consists of “satisfactory,” “conditional” and “unsatisfactory” ratings. As of September 1, 2014 all of our trucking operations, except for Bison Trucking’s operations that have not yet been rated, have “satisfactory” ratings with the Department of Transportation.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, which may limit our ability to operate in protected areas. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures, which could reduce demand for our services.

 

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Conservation measures and technological advances could reduce demand for oil and natural gas and our services.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We maintain operational insurance coverage of types and amounts that we believe to be customary in the industry, including commercial general liability, workers’ compensation, business auto, excess auto liability, commercial property, motor truck cargo, umbrella liability and excess liability insurance policies. We are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, any insurance obtained by us may not be adequate to cover any losses or liabilities and this insurance may not continue to be available at all or on terms which are acceptable to us. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. See “Business—Operating Risks and Insurance” for additional information on our insurance policies. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our business activities, financial condition, results of operations and cash available for distribution.

We may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, results of operations and cash available for distribution.

We operate with most of our customers under master service agreements, or MSAs. We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. Our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and

 

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in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition, results of operation and cash available for distribution.

We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, common unit price, results of operations, financial condition and cash available for distribution could be materially adversely affected.

We will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as early as December 31, 2015. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming an accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify for an exemption from the requirement to provide auditors’ attestation on internal controls afforded to emerging growth companies under the Jumpstart Our Business Startups Act enacted by the U.S. Congress in April 2012. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations and cash available for distribution could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common units. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

 

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Risks Inherent in an Investment in Us

Our general partner and its affiliates will own a controlling interest in us and will have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our unitholders.

Following the offering, Wexford will own our general partner and will appoint all of the directors of our general partner, except for those members of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement described under “Certain Relationships and Related Party Transactions.” Certain of the directors of our general partner are also officers and/or directors of Wexford or Gulfport. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. Therefore, conflicts of interest may arise between our general partner and its affiliates, including Wexford and Gulfport, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

 

    Our general partner is allowed to take into account the interests of parties other than us, such as Wexford and Gulfport, in exercising certain rights under our partnership agreement.

 

    Neither our partnership agreement nor any other agreement requires Wexford or Gulfport to pursue a business strategy that favors us.

 

    Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

 

    Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

 

    Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders.

 

    Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

 

    Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf.

 

    Our general partner intends to limit its liability regarding our contractual and other obligations.

 

    Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

 

    Our general partner controls the enforcement of obligations that it and its affiliates owe to us.

 

    Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, Wexford and Gulfport and their affiliates may compete with us. Please see “—Wexford, Gulfport and other affiliates of our general partner may compete with us.” and “Conflicts of Interest and Fiduciary Duties.”

 

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The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

In connection with the closing of this offering, the board of directors of our general partner will adopt a cash distribution policy pursuant to which we will distribute an amount equal to the cash available for distribution we generate each quarter to our unitholders. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. Please see “Cash Distribution Policy and Restrictions on Distributions.”

In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of its owners to the detriment of our common unitholders.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the cash available for distribution we generate each quarter, which could limit our ability to grow and make acquisitions.

As a result of our cash distribution policy, we will have limited cash available to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

To the extent we issue additional units in connection with any acquisitions or growth capital expenditures or as in-kind distributions, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per common unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the cash available for distribution that we have to distribute to our unitholders. Please see “Cash Distribution Policy and Restrictions on Distributions.

Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces them with contractual standards of conduct. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

    how to allocate business opportunities among us and its affiliates;

 

    whether to exercise its call right;

 

    how to exercise its voting rights with respect to the units it owns;

 

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    whether to exercise its registration rights; and

 

    whether or not to consent to any merger or consolidation of the Partnership or any amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please see “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

    whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

    our general partner and its executive officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its executive officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

 

    our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction, even a transaction with an affiliate or the resolution of a conflict of interest, is:

(1) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

(2) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please see “Conflicts of Interest and Fiduciary Duties.”

Wexford, Gulfport and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Wexford and Gulfport, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Wexford or Gulfport may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Wexford, Gulfport and their affiliates, may acquire, develop or dispose of other assets or businesses in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets or businesses.

 

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors, Wexford and Gulfport. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please see “Conflicts of Interest and Fiduciary Duties.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Wexford and Gulfport, as a result of Wexford’s ownership of our general partner and the investor rights agreement we expect to enter into with Gulfport prior to the closing of this offering, and not by our unitholders. Please see “Management” and “Certain Relationships and Related Party Transactions.” Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. Unitholders initially will be unable to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon the completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove our general partner. Following the closing of this offering, Wexford and Gulfport will beneficially own     % and     % of our common units, respectively (or     % and     % of our common units, respectively, if the underwriters exercise their option to purchase additional common units in full).

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

 

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Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders. Please see “Cash Distribution Policy and Restrictions on Distributions.”

At the closing of this offering, we and our general partner will also enter into an advisory services agreement with Wexford pursuant to which Wexford will provide general finance and advisory services in exchange for a fee and certain expense reimbursement. This fee will reduce the amount of cash available for distribution to our unitholders. Please see “Certain Relationships and Related Party Transactions—Advisory Services Agreement.”

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the Partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the Partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. Please see “The Partnership Agreement—Limited Liability.”

 

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Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates (including Wexford) beneficially own more than         % of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-common unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. If our general partner and its affiliates (including Wexford) reduce their ownership to below 75% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). Upon consummation of this offering, and assuming no exercise of the underwriters’ over-allotment option, affiliates of our general partner (including Wexford) will collectively own     % of our common units. For additional information about the limited call right, please see “The Partnership Agreement—Limited Call Right.”

We may issue additional common units and other equity interests without unitholder approval, which would dilute existing unitholder ownership interests.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

 

    the proportionate ownership interest of unitholders in us immediately prior to the issuance will decrease;

 

    the amount of cash distributions on each common unit may decrease;

 

    the ratio of our taxable income to distributions may increase;

 

    the relative voting strength of each previously outstanding common unit may be diminished; and

 

    the market price of the common units may decline.

Please see “The Partnership Agreement—Issuance of Additional Partnership Interests.”

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

 

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NASDAQ does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We have applied for listing of our common units on the NASDAQ Global Market. Because we will be a publicly traded partnership, NASDAQ does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of NASDAQ’s corporate governance requirements. Please see “Management.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions and limitations regarding claims, suits, actions or proceedings. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees and limitations regarding claims, suits, actions or proceedings. Please see “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction.” By purchasing a common unit, a limited partner is irrevocably consenting to these provisions and limitations regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.

If you bring a claim, suit, action or proceeding against us and do not obtain a judgment on the merits that substantially achieves the full remedy sought, then you may be obligated to reimburse the litigation costs of us and our affiliates.

If any person brings any claims, suits, actions or proceedings described in “The Partnership Agreement—Applicable Law; Forum, Venue and Jurisdiction” (including, but not limited to, those asserting a claim of breach of a fiduciary duty) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain unitholders.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the U.S. federal income tax status and/or the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates chargeable to our customers, (ii) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (iii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per common unit for the 20 consecutive trading days immediately prior to the date set for redemption. Please see “The Partnership Agreement—Non-Taxpaying Holders; Redemption” and “The Partnership Agreement—Non-Citizen Assignees; Redemption.”

 

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We will incur increased costs as a result of being a publicly traded partnership, which may significantly affect our financial condition.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and NASDAQ, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay our expenses, including the costs of being a publicly traded partnership and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership.

Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these requirements will increase certain of our legal and financial compliance costs and make compliance activities more time-consuming and costly, particularly after we are no longer an “emerging growth company.” For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting.

However, for as long as we remain an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We intend to take advantage of these reporting exemptions until we are no longer an “emerging growth company.”

We could be an “emerging growth company” for up to five years following the completion of our initial public offering, although, if we have more than $1.0 billion in annual revenue, if the market value of our common units that is held by non-affiliates exceeds $700 million as of June 30 of any year, or we issue more than $1.0 billion of non-convertible debt over a three-year period before the end of that five-year period, we would cease to be an “emerging growth company” as of the following December 31.

We estimate that we will incur approximately $         million of incremental costs per year associated with being a publicly traded partnership; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate. After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not “emerging growth companies,” including Section 404 of the Sarbanes-Oxley Act. See “—Risks Related to Our Business—We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, common unit price, results of operations, financial condition and cash available for distribution could be materially adversely affected” on page 42 of this prospectus.

For so long as we are an “emerging growth company” we will not be required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investors.

We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other

 

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public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act and reduced disclosure obligations regarding executive compensation in our periodic reports. We cannot predict if investors will find our common units less attractive because we will rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our common unit price may be more volatile.

Under the Jumpstart Our Business Startups Act of 2012, “emerging growth companies” can delay adopting new or revised accounting standards until such time as those standards apply to private companies. Prior to the completion of this offering, we intend to irrevocably elect not to avail ourselves to this exemption from new or revised accounting standards and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not “emerging growth companies.”

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our common unitholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. As described in “Certain Relationships and Related Party Transactions” these include, among others, agreements to provide our services and frac sand products to our affiliates and agreements pursuant to which our affiliates provide or will provide us with certain services, including administrative and advisory services and office space. Each of these entities is either controlled by or affiliated with Wexford or Gulfport, as the case may be, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our unitholders’ best interests because Wexford and/or Gulfport may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, see “Conflicts of Interest and Fiduciary Duties.”

There has been no public market for our common units and if the price of our common units fluctuates significantly, your investment could lose value.

Prior to this offering, there has been no public market for our common units. Although we have applied for a listing of our common units on The NASDAQ Global Select Market, we cannot assure you that an active public market will develop for our common units or that our common units will trade in the public market subsequent to this offering at or above the initial public offering price. If an active public market for our common units does not develop, the trading price and liquidity of our common units will be materially and adversely affected. If there is a thin trading market or “float” for our common units, the market price for our common units may fluctuate significantly more than the stock market as a whole. Without a large float, our common units are less liquid than the securities of companies with broader public ownership and, as a result, the trading prices of our common units may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The initial offering price, which will be negotiated between us and the underwriters, may not be indicative of the trading price for our common units after this offering. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common units could fluctuate widely in response to several factors, including:

 

    our quarterly or annual operating results;

 

    changes in our earnings estimates;

 

    investment recommendations by securities analysts following our business or our industry;

 

    additions or departures of key personnel;

 

    changes in the business, earnings estimates or market perceptions of our competitors;

 

    our failure to achieve operating results consistent with securities analysts’ projections;

 

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    changes in industry, general market or economic conditions; and

 

    announcements of legislative or regulatory change.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common units could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce the price for our common units.

Upon completion of this offering, Wexford and Gulfport will beneficially own a substantial number of our common units and may sell such common units in the public or private markets. Future sales of these common units or substantial amounts of our common units, or the perception that such sales may occur, could adversely affect the prevailing market price of our common units.

Upon completion of this offering, Wexford and Gulfport will beneficially own              and              common units, respectively, or              and              common units, respectively, if the underwriters’ over-allotment option is exercised in full. Future sales of these common units or substantial amounts of our common units, or the perception that such sales may occur, could adversely affect the prevailing market price of our common units.

We cannot predict the effect, if any, that future sales of common units, or the availability of common units for future sales, will have on the market price of our common units prevailing from time to time. In addition, the sale of common units could impair our ability to raise capital through the sale of additional common units. All of the common units sold in this offering, except for any common units purchased by our affiliates, will be freely tradable. See “Units Eligible for Future Sale.”

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common units or if our operating results do not meet their expectations, our common unit price could decline.

The trading market for our common units will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our common unit price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common units or if our operating results do not meet their expectations, our common unit price could decline.

Purchasers in this offering will experience immediate dilution and will experience further dilution with the future exercise of unit options granted to certain of our executive officers under their respective employment agreements.

The initial public offering price is substantially higher than the pro forma net tangible book value per common unit of our outstanding common units. As a result, you will experience immediate and substantial dilution of approximately $         per common unit, representing the difference between our net tangible book value per common unit as of June 30, 2014 after giving effect to this offering and an assumed initial public offering price of $         (which is the midpoint of the range set forth on the cover of the prospectus). A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover page of this prospectus) would increase (decrease) our net tangible book value per common unit after giving effect to this offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and

 

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estimated offered expenses payable by us. If the options granted to certain of our executive officers under their respective employment agreements are exercised in full, the investors in this offering will experience further dilution. See “Dilution” for a description of dilution.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income purposes, please see “Material U.S. Federal Income Tax Consequences—Partnership Status” for a further discussion.

 

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If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation and depletion recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please see “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file United States federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Please see “Material U.S. Federal Income Tax Consequences—Tax Exempt Organizations and Other Investors.”

 

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We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of our common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please see “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please see “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and could recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following

 

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this offering, Gulfport and affiliates of Wexford will directly and indirectly own approximately     % and     %, respectively, of the total interests in our capital and profits. Therefore, a transfer by Gulfport and affiliates of Wexford of all or a portion of their interests in us could result in a termination of our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please see “Material U.S. Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in Ohio, Oklahoma, Wisconsin, Minnesota, Pennsylvania and Texas. Many of these states impose a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.

We will have a subsidiary that is taxable as a corporation for federal income tax purposes and it will be subject to corporate-level income taxes.

Our subsidiary that will own the remote accommodations services business will be treated as a corporation for federal income tax purposes, which will subject it to corporate-level income taxes and may reduce the cash available for distribution to us and, in turn, to unitholders. In the future, we may conduct additional operations through this subsidiary or other subsidiaries that are subject to corporate-level income taxes.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

    business strategy;

 

    planned acquisitions and future capital expenditures;

 

    ability to obtain permits and governmental approvals;

 

    technology;

 

    financial strategy, including with respect to distributions;

 

    future operating results; and

 

    plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Cash Distribution Policy and Restrictions on Distributions,” “How We Will Make Distributions,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “budget,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective” or “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the many factors including those described in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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USE OF PROCEEDS

Our net proceeds from the sale of                  common units in this offering, assuming a public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus), are estimated to be $         million, after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds we receive are estimated to be $         million if the underwriters’ over-allotment option is exercised in full. We intend to use the net proceeds from this offering to repay our outstanding borrowings in the aggregate amount of $         million under the following credit facilities:

 

Facility

   Amount

April 2013 Redback facility

  

June 2013 Redback facility

  

October 2013 Redback facility

  

July 2014 Redback facility

  

October 2013 Coil Tubing facility

  

January 2013 Muskie facility

  

May 2013 Bison facility

  

July 2013 Stingray Pressure Pumping facility

  

For additional information regarding our outstanding borrowings under each credit facility that will be repaid with the net proceeds from this offering, including the applicable interest rate, the maturity date and the use of proceeds from any borrowings incurred within one year under such facilities, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Existing Credit Facilities.”

Any remaining net proceeds will be used for other general partnership purposes, which may include the acquisition of additional equipment and complementary businesses.

An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds that we will receive in this offering to increase or decrease by approximately $         million.

We will not receive any proceeds from the sale of common units by the selling unitholders, including any sale the selling unitholders may make upon exercise of the underwriters’ over-allotment option.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2014:

 

    on an actual basis;

 

    on a pro forma basis to give effect to the issuance of                 common units to Gulfport and affiliates of Wexford in exchange for the Stingray Contribution; and

 

    on a pro forma basis described above, as adjusted to give effect to the sale of                 common units in this offering at an assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus), our receipt of an estimated $         million of net proceeds from this offering after deducting underwriting discounts and commissions and estimated offering expenses and the use of a portion of those proceeds to repay outstanding borrowings as described under the caption “Use of Proceeds.”

This table does not reflect the issuance of up to                  common units that may be sold to the underwriters upon exercise of their over-allotment option, or the use of the resulting proceeds. You should read the following table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Pro Forma Financial Information” and our combined financial statements and related notes appearing elsewhere in this prospectus.

 

    As of June 30, 2014  
    Actual(1)     Pro Forma     Pro Forma
As Adjusted(2)
 
    (in thousands)  

Cash and cash equivalents

  $ 7,358      $                  $               
 

 

 

   

 

 

   

 

 

 

Long-term debt (including current maturities)(3)

  $ 70,430      $       $    

Members’ equity/Partners’ capital:

     

Member’s equity

    167,522        —          —     

Common unitholders

    —         

Public

    —         

Gulfport and Wexford affiliates

    —         
 

 

 

   

 

 

   

 

 

 

Total members’ equity/unitholders’ capital

    167,522       
 

 

 

   

 

 

   

 

 

 

Total capitalization

  $ 237,952      $       $    
 

 

 

   

 

 

   

 

 

 

 

(1) Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the completion of the offering. The data in the “Actual” column of this table has been derived from the historical combined financial statements and other financial information included in this prospectus that pertain to the assets, liabilities, revenues and expenses of the common control entities.
(2) A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus) would increase (decrease) each of cash and cash equivalents, partners’ capital and total capitalization by $         million, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.
(3) Represents borrowings outstanding under our credit agreements, which borrowings will be repaid in full and which agreements will be terminated at the closing of this offering.

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of our common units sold in this offering will exceed the pro forma net tangible book value per common unit after the offering. Our reported net tangible book value as of June 30, 2014 was $         million, or $         per common unit, based upon common units outstanding as of that date after giving pro forma effect to the Contribution Transactions. Net tangible book value per common unit before the offering is determined by dividing the net tangible book value (total tangible assets less total liabilities) of the capital stock and membership interests received in the Contribution Transactions by the number of common units (                 common units) to be issued to Wexford’s affiliate Mammoth Energy Holdings LLC and to Gulfport in connection with this offering and the Contribution Transactions. Assuming the sale by us of          common units offered in this offering at an estimated initial public offering price of $         per common unit (which is the midpoint of the range set forth on the cover of this prospectus) and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, our net tangible book value as of June 30, 2014 would have been approximately $         million, or $         per common unit, after giving pro forma effect to the Contribution Transactions. This represents an immediate increase in net tangible book value of $         per common unit to our existing unitholders and an immediate dilution of $         per common unit to new investors purchasing common units at the initial public offering price.

The following table illustrates the per common unit dilution:

 

Assumed initial public offering price per common unit

      $                

Net tangible book value per common unit as of June 30, 2014

   $                   

Increase per common unit attributable to new investors

   $        
  

 

 

    

As adjusted net tangible book value per common unit after the offering

      $     
     

 

 

 

Dilution per common unit to new investors

      $     
     

 

 

 

A $1.00 increase (decrease) in the assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth in the cover of this prospectus) would increase (decrease) our net tangible book value after the offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table sets forth, as of June 30, 2014, after giving pro forma effect to the Stingray Contribution, the number of common units to be issued by us in the contribution, the holders of which will be our existing unitholders immediately prior to the closing of this offering, and by the new investors at the assumed initial public offering price of $         per common unit, together with the total consideration paid and average price per common unit paid by each of these groups, before deducting underwriting discounts and commissions and estimated offering expenses.

 

     Common Units
Purchased
    Total Consideration     Average Price  
     Number    Percent     Amount      Percent     Per Common
Unit
 

Existing unitholders

               $                             $                

New investors

                          
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

Total

        100.0   $           100.0   $     
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

If the underwriters’ over-allotment option is exercised in full, the number of common units held by new investors will be increased to             , or approximately     % of the total number of common units.

 

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. Please see “—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015—Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical and pro forma results of operations, you should refer to our historical combined financial statements and pro forma financial data, and the notes thereto, included elsewhere in this prospectus.

General

Cash Distribution Policy

In connection with the closing of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will distribute all of the cash available for distribution we generate each quarter, beginning with the quarter ending                     , 2014. Our first distribution, however, is expected to include cash available for distribution for the period from the closing of this offering through                     , 2014. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that cash available for distribution for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the board of directors may determine is appropriate. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Further, it is our intent, subject to market conditions, to finance growth capital externally. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. Please see “Risk Factors—Risks Inherent in an Investment in Us—The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

Because our policy will be to distribute all cash available for distribution we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low revenue, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in the performance of our operations and earnings caused by, among other things, fluctuations in demands for our services resulting from changes in the prices of oil and natural gas. Such variations in the amount of our quarterly cash distributions may be significant and could result in no distribution for any quarter.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

 

    Our unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis. The board of directors of our general partner will adopt a policy pursuant to which we will distribute to our unitholders each quarter all of the cash available for distribution we generate each quarter, as determined quarterly by the board of directors, but it may change this policy at any time.

 

    We anticipate that the new revolving credit facility we intend to enter into in connection with the consummation of this offering will contain certain financial tests and covenants that we must satisfy. If we are unable to satisfy the restrictions under this new revolving credit facility or any future debt agreements, we could be prohibited from making a distribution to you notwithstanding our stated distribution policy.

 

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    Our business performance may be volatile, and our cash flows may be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions may be volatile and may vary quarterly and annually.

 

    We will not have a minimum quarterly distribution or employ structures intended to maintain or increase quarterly distributions over time. Furthermore, none of our limited partner interests, including those beneficially held by Wexford and Gulfport, will be subordinate in right of distribution payment to the common units sold in this offering.

 

    Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.

 

    Prior to making any distributions on our units, we will reimburse our general partner and certain of its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash to pay distributions to our unitholders.

 

    Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. To fund growth, we will eventually need capital in excess of the amounts we may retain in our business. As a result, our growth will depend on our ability in the future, to raise debt and equity capital from third parties in sufficient amounts and on favorable terms when needed. To the extent efforts to access capital externally are unsuccessful, our ability to grow will be significantly impaired.

We do not have any operating history as an independent company upon which to rely in evaluating whether we will have sufficient cash to allow us to pay distributions on our common units. While we believe, based on our financial forecast and related assumptions, that we should have sufficient cash to enable us to pay the forecasted aggregate distribution on all of our common units for the twelve months ending June 30, 2015, we may be unable to pay the forecasted distribution or any amount on our common units.

We expect to pay our distributions within 60 days of the end of each quarter. Our first distribution is expected to include cash available for distribution for the period from the closing of this offering through                     , 2014.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2013 and for the Twelve Months Ended June 30, 2014

If we had been formed and completed the transactions contemplated in this prospectus on January 1, 2013, our unaudited pro forma cash available for distribution for the year ended December 31, 2013 would have been approximately $             million or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full). If we had been formed and completed the

 

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transactions contemplated in this prospectus July 1, 2013, our unaudited pro forma cash available for distribution for the twelve months ended June 30, 2014 would have been approximately $             million or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full).

The unaudited pro forma condensed combined financial statements upon which the unaudited pro forma cash available for distribution is based do not purport to present the financial results that would have been attained had we been formed and the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our unaudited pro forma condensed combined financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution shown above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed and completed the transactions contemplated in this prospectus in earlier periods and not as presenting our financial results. Please see our unaudited pro forma condensed combined financial statements and the accompanying notes included elsewhere in this prospectus. We have not calculated cash available for distribution on a pro forma quarter-by-quarter basis for the year ended December 31, 2013 or the twelve months ended June 30, 2013 to determine if we would have generated cash available for distribution sufficient to pay with respect to any particular quarter the pro forma average quarterly distribution for such period or any distribution at all.

The following table illustrates, on a pro forma basis, the amount of cash available for distribution for the year ended December 31, 2013 and for the twelve months ended June 30, 2014 that would have been available for distribution to our unitholders. The assumptions and adjustments that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes.

Unaudited Pro Forma Cash Available for Distribution

 

     Year Ended
December 31, 2013
     Twelve Months
Ended

June 30, 2014
 
     (in thousands, except per unit data)  

Revenue

   $         $     

Expenses:

     

Cost of revenue, excluding depreciation, amortization and impairment

   $                    $                

Selling, general and administrative expenses(1)

     

Depreciation and amortization

     

Impairment of long-lived assets

     

Interest expense, net

     

Other (income) expense, net

     

Provision for income taxes

     
  

 

 

    

 

 

 

Net income (loss)

   $         $     
  

 

 

    

 

 

 

Adjustments to reconcile net income (loss) to Adjusted EBITDA(2):

     

Add:

     

Depreciation and amortization

   $         $     

Impairment of long-lived assets

     

Equity based compensation

     

Interest expense, net

     

Other (income) expense, net

     

Provision for income taxes

     
  

 

 

    

 

 

 

Adjusted EBITDA

   $         $     
  

 

 

    

 

 

 

 

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     Year Ended
December 31, 2013
     Twelve Months
Ended

June 30, 2014
 
     (in thousands, except per unit data)  

Less:

     

Cash interest expense

   $                    $                

Provision for income taxes

     

Maintenance capital expenditures(3)

     

Expansion capital expenditures

     

Net working capital

     

Other (income) expense, net

     

Add:

     

Funding for expansion capital expenditures

     
  

 

 

    

 

 

 

Unaudited pro forma cash available for distribution

   $         $     
  

 

 

    

 

 

 

Unaudited pro forma cash distributions per common unit:

     

Assuming no exercise of the underwriters’ over-allotment option

   $         $     

Assuming full exercise of the underwriters’ over-allotment option

   $         $     

Unaudited pro forma aggregate distribution (assuming no exercise of the underwriters’ over-allotment option) to:

     

Common units held by the public

   $         $     

Common units held by Gulfport and Wexford affiliates

     
  

 

 

    

 

 

 

Total Distributions (assuming no exercise of the underwriters’ over-allotment option)

   $         $     
  

 

 

    

 

 

 

Unaudited pro forma aggregate distribution (assuming full exercise of the underwriters’ over-allotment option) to:

     

Common units held by the public

   $         $     

Common units held by Gulfport and Wexford affiliates

     
  

 

 

    

 

 

 

Total Distributions (assuming full exercise of the underwriters’ over-allotment option)

   $         $     
  

 

 

    

 

 

 

 

(1) Includes $             million of estimated incremental annual cash expense associated with being a publicly traded partnership, including $             million of incremental selling, general and administrative expenses and an annual fee of $             pursuant to an advisory services agreement that we expect to enter into with Wexford at the closing of this offering.
(2) For a definition and description of Adjusted EBITDA, please see footnote 2 to the table in “Selected Historical Combined Financial Data.”
(3) Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity.

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015

During the twelve months ending September 30, 2015, we estimate that we will be able to generate $             million of cash available for distribution or $             per common unit on an annualized basis ($             per common unit if the underwriters’ over-allotment option is exercised in full). In “—Assumptions and Considerations” below, we discuss the material assumptions underlying this estimate. The cash available for distribution discussed in this estimate will likely differ from the actual cash available for distribution that we will generate during the twelve months ending September 30, 2015. We can give you no assurance that our assumptions will be realized or that we will generate any cash available for distribution during this period, in which event we will not be able to pay quarterly cash distributions on our common units.

When considering our ability to generate cash available for distribution and how we calculate forecasted cash available for distribution, please keep in mind all the risk factors and other cautionary statements under the

 

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headings “Risk Factors” and “Forward-Looking Statements,” which discuss factors that could cause our results of operations and cash available for distribution to vary significantly from our estimates.

Management has prepared the prospective financial information set forth in the table below to present our expectations regarding our ability to generate $             million of cash available for distribution for the twelve months ending September 30, 2015. The accompanying prospective financial information was not prepared with a view toward public disclosure or complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.

The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by the management team of our general partner as of the date of its preparation, are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to this prospective financial information or to update this prospective financial information to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending September 30, 2015 should not be regarded as a representation by us or the underwriters or any other person that we will be able to, or that we will, make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated cash available for distribution for the twelve months ending September 30, 2015. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”

Neither our independent registered public accounting firm nor any other independent registered public accounting firm has compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor has it expressed any opinion or given any other form of assurance on such information or its achievability, and it assumes no responsibility for such forecasted financial information. Our independent registered public accounting firm’s reports included elsewhere in this prospectus relate to our audited historical financial statements. These reports do not extend to the table and the related forecasted information contained in this section and should not be read to do so.

The following table illustrates the amount of cash available for distribution that we estimate that we will generate for the twelve months ending September 30, 2015 and for each quarter during that twelve-month period that would be available for distribution to our unitholders. All of the amounts for the twelve months ending September 30, 2015 in the table below are estimates and all historical figures in this section are pro forma based on our unaudited pro forma condensed combined financial statements.

 

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Estimated Cash Available for Distribution

 

     Three Months Ending      Twelve Months
Ending
 
     December 31,
2014
     March 31,
2015
     June 30,
2015
     September 30,
2015
     September 30,
2015
 
     (in thousands, except per unit data)  

Revenue

   $         $         $         $         $     

Expenses:

              

Cost of revenue, excluding depreciation, amortization and impairment

   $                    $                    $                    $                    $                

Selling, general and administrative expenses(1)

              

Depreciation and amortization

              

Impairment of long-lived assets

              

Interest expense, net(2)

              

Other (income) expense, net

              

Provision for income taxes

              
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss)

   $         $         $         $         $     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Adjustments to reconcile net income (loss) to Adjusted EBITDA(3):

              

Add:

              

Depreciation and amortization

   $         $         $         $         $     

Impairment of long-lived assets

              

Equity based compensation

              

Interest expense, net

              

Other (income) expense, net

              

Provision for income taxes

              
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Adjusted EBITDA

   $         $         $         $         $     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Less:

              

Cash interest expense

   $         $         $         $         $     

Provision for income taxes

              

Maintenance capital expenditures(4)

              

Expansion capital expenditures

              

Net working capital

              

Other (income) expense, net (5)

              

Add:

              

Funding for expansion capital expenditures

              
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Estimated cash available for distribution

   $         $         $         $         $     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Estimated cash distributions per common unit:

              

Assuming no exercise of the underwriters’ over-allotment option

   $         $         $         $         $     

Assuming full exercise of the underwriters’ over-allotment option

   $         $         $         $         $     

Estimated aggregate distribution (assuming no exercise of the underwriters’ over-allotment option) to:

              

Common units held by the public

   $         $         $         $         $     

Common units held by Gulfport and Wexford affiliates

              
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Distributions (assuming no exercise of the underwriters’ over-allotment option)

   $         $         $         $         $     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Estimated aggregate distribution (assuming full exercise of the underwriters’ over-allotment option) to:

              

Common units held by the public

   $         $         $         $         $     

Common units held by Gulfport and Wexford affiliates

              
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Distributions (assuming full exercise of the underwriters’ over-allotment option)

   $         $         $         $         $     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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(1) Includes $             million of estimated incremental annual cash expense associated with being a publicly traded partnership, including $ million of incremental selling, general and administrative expenses and an annual fee of $             pursuant to an advisory services agreement that we expect to enter into with Wexford at the closing of this offering.
(2) Assumes average borrowings of $             million at an interest rate of                  under a new revolving credit facility we intend to enter into before the closing of this offering. We do not currently have commitments for such a facility and cannot assure you that we will have entered into one before the closing of this offering.
(3) For a definition and description of Adjusted EBITDA, please see footnote 2 to the table in “Selected Historical Combined Financial Data.”
(4) Maintenance capital expenditures are capital expenditures required to maintain, over the long term, our asset base, operating income or operating capacity.
(5) Includes additional contributions from investment and asset sales.

Assumptions and General Considerations

Based upon the specific assumptions outlined below, following completion of this offering, we expect to generate cash available for distribution in an amount sufficient to allow us to pay an aggregate of $             per common unit ($             per common unit if the underwriters’ over-allotment option is exercised in full) on all of our outstanding units for each quarter in respect of the twelve months ending September 30, 2015.

While we believe that our assumptions are reasonable in light of our management’s current expectations concerning future events, such assumptions are not all-inclusive and the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. Such forward-looking statements are based on assumptions and beliefs that our management believes to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances.

Further, we can give no assurance that our forecasted results will be achieved. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the forecasted cash distribution, or any amount, on our outstanding common units in respect of the four calendar quarters ending September 30, 2015 or thereafter, in which event the market price of our common units may decline substantially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” and our accounting policies discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Critical Accounting Policies and Estimates.” Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.

Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending September 30, 2015 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

    There will not be any new federal, state or local regulation of the portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;

 

    There will not be any major adverse change in commodity prices, our business or the energy industry in general;

 

    There will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend;

 

    Although we may undertake projects where opportunities arise, for the purposes of this forecast no acquisitions or other significant growth capital expenditures are reflected (other than as described above);

 

 

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    Market, insurance and overall economic conditions will not change substantially;

 

    Our customers subject to take-or-pay and fixed-volume commitments will fully perform under their contractual arrangements with us; and

 

    We will not undertake any extraordinary transactions that would materially affect our cash flow.

 

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HOW WE WILL MAKE DISTRIBUTIONS

General

Within 60 days after the end of each quarter, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date. Our first distribution is expected to include cash available for distribution for the period from the closing of this offering through                     , 2014. We do not have a legal obligation to pay distributions, and the amount of distributions, if any, declared and paid under our distribution policy is determined by the board of directors of our general partner. See “Cash Distribution Policy and Restrictions on Distributions.”

Method of Distributions

We intend to distribute cash available for distribution to our unitholders, pro rata. Our partnership agreement permits us to borrow to make distributions, but we are not required to, and do not intend to, borrow to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on the units in any quarter.

Common Units

At the closing of this offering, we will have         common units outstanding. Each common unit will be entitled to receive cash distributions to the extent we distribute cash available for distribution. Common units will not accrue arrearages. Our partnership agreement allows us to issue an unlimited number of additional common units or other equity interests of equal or senior rank.

General Partner Interest

Upon the closing of this offering, our general partner will own a non-economic general partner interest and therefore will not be entitled to receive cash distributions. However, it may acquire common units and other equity interests in the future and will be entitled to receive pro rata distributions in respect of those equity interests.

 

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SELECTED HISTORICAL COMBINED FINANCIAL DATA

The following table sets forth our selected historical combined financial data as of and for each of the periods indicated. The selected historical combined financial data as of December 31, 2013 and 2012 and for the years ended December 31, 2013 and 2012 are derived from the historical audited combined financial statements of the common control entities included elsewhere in this prospectus. The selected combined historical financial data as of June 30, 2014 and for the six months ended June 30, 2014 and 2013 are derived from the historical unaudited combined financial statements of the common control entities included elsewhere in this prospectus. The selected combined historical balance sheet data as of June 30, 2013 are derived from the unaudited combined balance sheet of the common control entities as of such date, which is not included in this prospectus. Operating results for the years ended December 31, 2013 and 2012 and the six months ended June 30, 2014 and 2013 do not reflect the Drilling Transaction for periods prior to January 29, 2014 or the Stingray Contribution and are not necessarily indicative of results that may be expected for any future periods or as of any future date. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Pro Forma Financial Information” and the historical combined financial statements and related notes of the common control entities included elsewhere in this prospectus.

 

     Six Months Ended(1)
June 30,
    Year Ended(1)
December 31,
 
     2014     2013     2013     2012  
     (in thousands)  

Statement of Operations Data:

        

Revenue:

        

Completion and production services

   $ 44,481      $ 18,455      $ 47,731      $ 16,892   

Contract land and directional drilling services

     51,823        31,936        59,790        26,842   

Remote accommodation services

     9,586        12,895        25,027        14,169   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     105,890        63,286        132,548        57,903   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenue, excluding depreciation, amortization and impairment:

        

Completion and production services

     36,033        16,987        42,627        13,764   

Contract land and directional drilling services

     42,157        25,209        53,987        20,501   

Remote accommodation services

     4,165        6,115        11,416        7,333   

Selling, general and administrative expenses

     6,082        5,162        13,614        6,443   

Depreciation and amortization

     15,034        8,486        18,995        8,149   

Impairment of long-lived assets

     —          —          938        2,435   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     103,471        61,959        141,577        58,625   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     2,419        1,327        (9,029     (722

Interest expense

     (1,864     (801     (2,012     (274

Other income (expense), net

     (43     153        (215     (49
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     512        679        (11,256     (1,045

Provision for income taxes

     1,059        1,417        2,715        1,013   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (547   $ (738   $ (13,971   $ (2,058
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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     Six Months Ended(1)
June 30,
    Year Ended(1)
December 31,
 
     2014     2013     2013     2012  
     (in thousands)  

Other Financial Data:

        

Adjusted EBITDA(2) (unaudited)

   $ 17,647      $ 9,995      $ 11,422      $ 10,225   
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows (used in) provided by operating activities

   $ (1,741   $ (4,879   $ 4,162      $ 4,791   
  

 

 

   

 

 

   

 

 

   

 

 

 

Purchases of property and equipment

   $ (75,128   $ (18,445   $ (63,956   $ (71,584

Other investing activities, net

     575        1,953        634        —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows used in investing activities

   $ (74,553   $ (16,492   $ (63,322   $ (71,584
  

 

 

   

 

 

   

 

 

   

 

 

 

Capital contributions

   $ 47,024      $ 17,313      $ 26,979      $ 59,114   

Proceeds from financing arrangements, net of repayments

     27,901        9,002        31,966        13,959   

Other financing activities, net

     (278     (437     (361     (115
  

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows provided by financing activities:

   $ 74,647      $ 25,878      $ 58,584      $ 72,958   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

     As of June 30,      As of December 31,  
     2014      2013      2013      2012  
     (in thousands)  

Balance sheet data:

           

Cash and cash equivalents

   $ 7,358       $ 10,946       $ 8,284       $ 9,075   

Other current assets

     53,784         34,222         35,643         18,375   

Property and equipment, net

     214,507         125,390         155,244         117,656   

Other assets

     4,479         3,683         3,472         3,396   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

     280,128       $ 174,241       $ 202,643       $ 148,502   
  

 

 

    

 

 

    

 

 

    

 

 

 

Current liabilities

   $ 71,708       $ 37,528       $ 57,147       $ 31,067   

Long-term debt, net of current maturities

     38,819         9,533         22,905         7,213   

Other long-term liabilities

     2,079         1,932         1,877         1,425   

Shareholders’ and members’ equity

     167,522         125,248         120,714         108,797   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities and shareholders’ and members’ equity

   $ 280,128       $ 174,241       $ 202,643       $ 148,502   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the contribution of the common control entities and the Stingray entities to us prior to the completion of this offering other than certain activities related to the preparation of the registration statement for this offering. The historical combined financial statements and other financial information of Mammoth Energy Partners LP included in this prospectus pertain to assets, liabilities, revenues and expenses of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling, Bison Trucking and Sand Tiger, which are entities under the common control of our sponsor, Wexford. Except for Sand Tiger, each of the common control entities was treated as a partnership for federal income tax purposes. As a result, essentially all of their taxable earnings and losses were passed through to Wexford, and they did not pay federal income taxes at the entity level. Prior to the completion of this offering, each of these entities will become our wholly owned subsidiary.
(2)

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 earnings before interest expense, provision for income taxes, depreciation and amortization expense, impairment of long-lived assets, equity based compensation and other non-operating income or expense, net. We exclude the items listed above from net income in arriving at Adjusted EBITDA

 

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  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 present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net loss.

 

     Six Months
Ended June 30,
    Year Ended
December 31,
 
     2014     2013         2013             2012      
     (in thousands)  

Reconciliation of Adjusted EBITDA to net loss:

        

Net loss

   $ (547   $ (738   $ (13,971   $ (2,058

Depreciation and amortization expense

     15,034        8,486        18,995        8,149   

Impairment of long-lived assets

     —          —          938        2,435   

Equity based compensation

     194        182        518        363   

Interest expense

     1,864        801        2,012        274   

Other (income) expense, net

     43        (153     215        49   

Provision for income taxes

     1,059        1,417        2,715        1,013   
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 17,647      $ 9,995      $ 11,422      $ 10,225   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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PRO FORMA FINANCIAL INFORMATION

The following unaudited pro forma condensed combined financial statements and related notes of the Partnership have been prepared to show the effect of the Stingray Contribution and the Drilling Transaction on the combined historical financial statements of Redback Energy Services (the common control entities) for periods and as of the dates indicated. The unaudited pro forma condensed combined financial statements should be read together with the historical combined financial statements of Redback Energy Services, the historical combined financial statements of Stingray Pressure Pumping LLC and Stingray Logistics LLC (the Stingray entities), and the Statements of Revenues and Direct Operating Expenses of Certain Drilling Rigs of Lantern Drilling Company (relating to the assets acquired in the Drilling Transaction) included elsewhere in this prospectus. The following unaudited pro forma condensed combined financial statements are based on certain assumptions and adjustments as explained in the accompanying notes.

The Stingray Contribution and the Drilling Transaction will be treated as business combinations accounted for under the acquisition method of accounting with the identifiable assets acquired and liabilities assumed recognized at full fair value on the date of the Stingray Contribution and the date of the Drilling Transaction.

The pro forma data presented reflect events directly attributable to the Stingray Contribution and the Drilling Transaction and certain assumptions we believe are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the Stingray Contribution or the Drilling Transaction actually occurred on the dates indicated below.

The Stingray Contribution will be completed immediately prior to the closing of this offering.

The unaudited pro forma condensed combined balance sheet assumes that the Stingray Contribution occurred on June 30, 2014. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2013 and for the six months ended June 30, 2014 assumes the Stingray Contribution and the Drilling Transaction occurred on January 1, 2013.

 

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Mammoth Energy Partners LP

Unaudited Pro Forma Condensed Combined Balance Sheet

June 30, 2014

(dollar amounts in thousands)

 

     Common
Control
Entities
Historical
     Stingray
Entities

Historical
     Pro Forma
Adjustments
     Pro Forma  
Assets            

Cash and cash equivalents

   $ 7,358       $ 12,654       $ —         $                

Other current assets

     50,227         20,219         (4,371 )(a)    
  

 

 

    

 

 

    

 

 

    

 

 

 

Total current assets

     57,585         32,873         (4,371   

Property and equipment, net

     214,507         76,686         —        

Other assets

     8,036         639         —        
  

 

 

    

 

 

    

 

 

    

 

 

 

Total assets

   $ 280,128       $ 110,198       $ (4,371    $     
  

 

 

    

 

 

    

 

 

    

 

 

 
Liabilities and Unitholders’, Shareholders’ and Members’ Equity            

Current liabilities

   $ 71,708       $ 49,935         (4,371 )(a)    

Long-term debt, net of current maturities

     38,819         19,573         —        

Other long-term liabilities

     2,079         —           —        

Unitholders’, shareholders’ and members’ equity

     167,522         40,690         —        
  

 

 

    

 

 

    

 

 

    

 

 

 

Total liabilities and unitholders’, shareholders’ and members’ equity

   $ 280,128       $ 110,198       $ (4,371    $     
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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Mammoth Energy Partners LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Year Ended December 31, 2013

(dollar amounts in thousands)

 

     Common
Control
Entities
Historical
    Stingray
Entities

Historical
    Drilling
Transaction
    Pro Forma
Adjustments
    Pro Forma  

Revenue:

          

Completion and production services

   $ 47,731      $ 82,483      $ —        $ (9,266 )(b)    $                

Contract land and directional drilling services

     59,790        —          33,102       

Remote accommodation services

     25,027        —          —          —       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 132,548      $ 82,483        33,102      $ (9,266   $     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenue, excluding depreciation, amortization and impairment:

          

Completion and production services

     42,627        68,556        —          (9,266 )(b)   

Contract land and directional drilling services

     53,987        —          35,831        (13,602 )(c)   

Remote accommodation services

     11,416        —          —          —       

Selling, general and administrative expenses

     13,614        1,561        497        (497 )(c)   

Depreciation and amortization

     18,995        7,938        —          6,889 (c)   

Impairment of long-lived assets

     938        —           
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 141,577      $ 78,055      $ 36,328      $ (16,476   $     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (9,029     4,428        (3,226     7,210     

Interest expense

     (2,012     (1,090     —          (1,135 )(c)  

Other income (expense), net

     (215     —          —          —       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     (11,256     3,338        (3,226     6,075     

Provision for income taxes

     2,715        —          —          —       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (13,971   $ 3,338      $ (3,226   $ 6,075      $     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma income (loss) before income taxes

           $     

Pro forma provision for income taxes (d)

          
          

 

 

 

Pro forma net loss

           $     
          

 

 

 

Pro forma Adjusted EBITDA

           $     
          

 

 

 

Reconciliation of Adjusted EBITDA to net loss:

          

Net loss

           $     

Depreciation and amortization expense

          

Impairment of long-lived assets

          

Equity based compensation

          

Interest expense

          

Other (income) expense, net

          

Provision for income taxes

          
          

 

 

 

Adjusted EBITDA

           $     
          

 

 

 

 

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Mammoth Energy Partners LP

Unaudited Pro Forma Condensed Combined Statement of Operations

For the Six Months Ended June 30, 2014

(dollar amounts in thousands)

 

     Common
Control
Entities
Historical
    Stingray
Entities

Historical
    Drilling
Transaction
    Pro Forma
Adjustments
    Pro Forma  

Revenue:

          

Completion and production services

   $ 44,481      $ 64,847      $ —        $ (4,916 )(e)    $                

Contract land and directional drilling services

     51,823        —          2,696       

Remote accommodation services

     9,586        —          —         
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 105,890      $ 64,847        2,696        (4,916   $     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cost of revenue, excluding depreciation, amortization and impairment:

          

Completion and production services

     36,033        54,915        2,929        (4,916 )(e)   

Contract land and directional drilling services

     42,157        —          —          —       

Remote accommodation services

     4,165        —          —          —       

Selling, general and administrative expenses

     6,082        1,215        115        —       

Depreciation and amortization

     15,034        8,030        —          —       

Impairment of long-lived assets

     —          —          —          —       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ 103,471      $ 64,160      $ 3,044      $ (4,916   $     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

     2,419        687        (348     —       

Interest expense

     (1,864     (855     —          —       

Other income (expense), net

     (43     44        —          —       
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

     512        (124     (348     —       

Provision for income taxes

     1,059        —          —         
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (547   $ (124   $ (348   $ —        $     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma income (loss) before income taxes

           $     

Pro forma provision for income taxes (d)

          
          

 

 

 

Pro forma net loss

           $     
          

 

 

 

Pro forma Adjusted EBITDA

           $     
          

 

 

 

Reconciliation of Adjusted EBITDA to net loss:

          

Net loss

           $     

Depreciation and amortization expense

          

Impairment of long-lived assets

          

Equity based compensation

          

Interest expense

          

Other (income) expense, net

          

Provision for income taxes

          
          

 

 

 

Adjusted EBITDA

           $     
          

 

 

 

 

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Mammoth Energy Partners LP

Notes to Unaudited Pro Forma Condensed Combined Financial Statements

(dollar amounts in thousands)

 

1. Basis of Presentation

The historical financial information is derived from the combined historical financial statements of Redback Energy Services (the common control entities) and the combined historical financial statements of Stingray Pressure Pumping LLC and its affiliate (the Stingray entities) included elsewhere in this prospectus. The Drilling Transaction statement of operations information was derived from the Statements of Revenue and Direct Operating Expenses for Certain Drilling Rigs of Lantern Drilling Company included elsewhere in this prospectus. The unaudited pro forma condensed combined balance sheet as of June 30, 2014 has been prepared as if the Stingray Contribution occurred on June 30, 2014. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2013 assumes that the Stingray Contribution and the Drilling Transaction occurred on January 1, 2013.

 

2. Pro Forma Assumptions and Adjustments

We made the following adjustments in the preparation of the unaudited pro forma condensed consolidated financial statements.

 

(  ) To record the Stingray Contribution at fair value for approximately $         for              common units value at the assumed initial public offering price of $         per share (the midpoint of the range set forth in the prospectus), which will represent     % of our outstanding common units immediately prior to the closing of this offering. The allocation of the purchase price to the assets acquired and liabilities assumed are preliminary and, therefore, subject to change.

 

(a) To eliminate $4,371 of intercompany receivable and payables primarily related to the purchase of sand used for hydraulic fracturing.

 

(b) To eliminate $9,266 of intercompany sales and purchases of sand used for hydraulic fracturing.

 

(c) To record adjustments in connection with the Drilling Transaction: (i) to reduce cost of revenue by $13,602 for operating lease rental expense under sublease agreements that were not assumed by Bison; (ii) to reduce selling, general and administrative expenses by $497 for operational management fees charged by the former parent company of the acquired drilling rigs that will not be incurred by Bison; (iii) to record $6,889 of depreciation expense in connection with the drilling rigs acquired; and (iv) to record $1,125 of interest expense for the $25,000 of additional long-term debt issued to partially fund the drilling rig acquisition.

 

(d) To record the effect of income taxes to reflect the domestication of Great White Dunvegan North SARL as a Delaware Corporation.

 

(e) To eliminate $4,916 of intercompany receivable and payables primarily related to the purchase of sand for hydraulic fracturing.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Summary Combined Historical and Pro Forma Financial Data,” “Selected Historical Combined Financial Data,” “Pro Forma Financial Information” and the historical combined financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements reflecting our current expectations and 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 the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this prospectus.

Overview

We are a growth-oriented Delaware limited partnership providing completion and production, contract land and directional drilling and remote accommodation services primarily to companies engaged in the exploration and development of North American onshore unconventional sands and shale oil and natural gas reserves. As part of our completion and production services division, we also produce and sell custom natural sand proppant, which is primarily used in hydraulic fracturing operations.

Mammoth Energy Partners LP was originally formed in February 2014 in Delaware as a holding company under the name Redback Inc., and was converted to a Delaware limited partnership in August 2014. Mammoth Energy Partners LP has not and will not conduct any material business operations prior to the transactions described below other than certain activities related to the preparation of the registration statement for this offering. Except as expressly noted otherwise, the historical financial information of Mammoth Energy Partners LP included in this prospectus is derived from the combined financial results for the following companies: Redback Energy Services; Redback Coil Tubing; Muskie Proppant; Panther Drilling; Bison Drilling; Bison Trucking; and Sand Tiger, all of which have been controlled and managed by our equity sponsor, Wexford and which we refer to in this prospectus as the common control entities. Prior to the closing of this offering, these entities together with White Wing, Great Dunvegan North SARL and Dunvegan North Oilfield Services, ULC will be contributed to us by Wexford and Gulfport in return for common units and, as a result, will become our wholly owned subsidiaries. Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC are holding companies for Sand Tiger. As such, all of the operations have been in Sand Tiger and the historical results of operations of both Great White Dunvegan North SARL and Dunvegan North Oilfield Services, ULC are minimal and immaterial, so they are excluded from the financial information presented in this prospectus. White Wing was formed in August 2014 and began operations in September 2014 and, as a result, is not included in the financial information in the prospectus. Also prior to the closing of this offering, two other entities, Stingray Pressure Pumping and Stingray Logistics, which we collectively refer to in this prospectus as the Stingray entities and in which Wexford and its affiliates currently own, in the aggregate, a non-controlling 50% equity interest, will be contributed to us by the holders of all of the equity interests in these entities in return for common units, at which time these entities will also become our wholly owned subsidiaries. The remaining 50% equity interests in the Stingray entities are currently owned, and will be contributed to us, by Gulfport. Because the Stingray entities are not under common control with the common control entities the historical financial information of the Stingray entities is not reflected in the historical combined financial statements of Mammoth Energy Partners LP, but instead is presented in this prospectus on a standalone basis and on a pro forma basis for Mammoth Energy Partners LP. As a result, the historical combined financial information of Mammoth Energy Partners LP as of and for the periods ended December 31, 2013 and 2012 and the six months ended June 30, 2014 and 2013 will not be indicative of the results that would have been achieved on a historical basis or that may be expected for any future periods. For more information, please see “Summary Combined Historical and Pro Forma Financial Data,” “Pro Forma Financial Information” and related notes thereto included elsewhere in this prospectus.

 

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Since the dates presented below, we have conducted our operations through the following entities, which comprise our three operating divisions: completion and production services, contract land and directional drilling services and remote accommodation services. These entities commenced operations on the dates indicated below.

 

    Completion and Production Services Division

 

    Muskie Proppant—September 2011

 

    Redback Energy Services—October 2011

 

    Redback Coil Tubing—May 2012

 

    Contract Land and Directional Drilling Services Division

 

    Bison Drilling—November 2010

 

    Panther Drilling—December 2012

 

    Bison Trucking—August 2013

 

    White Wing—September 2014

 

    Remote Accommodation Services Division

 

    Sand Tiger—October 2007

Our completion and production division provides equipment rental, flowback and pressure control services and also produces custom natural sand proppant that is primarily used in hydraulic fracturing operations. 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 remote accommodations division provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging.

Our customers are predominantly independent oil and natural gas exploration and production companies, and oilfield service companies that use natural sand proppant for hydraulic fracturing. We have facilities and service centers that are strategically located to primarily serve resource plays in the Utica Shale in Eastern Ohio, the Permian Basin in West Texas, the Marcellus Shale in West Virginia and Pennsylvania, the Granite Wash in Okahoma and Texas, the Cana Woodford Shale and the Cleveland Sand in Oklahoma, and the oil sands in Alberta, Canada.

Our primary business objective is to provide an attractive total return to unitholders by optimizing business results through organic growth opportunities and accretive acquisitions. To achieve this objective, we plan to:

 

    continue to capitalize on the increased activity in the high growth unconventional resource plays in the Permian Basin and Utica Shale, using our equipment which is designed to provide services for unconventional wells;

 

    continue to grow our existing customer relationships by cross selling our services and expanding to other geographic regions in which our customers operate;

 

    continue to monitor demand and expand our service offerings by investing in new equipment and facilities to add services and extend our presence in areas that we currently serve and other geographic locations; and

 

    grow our business, relationships and service offerings by acquiring select companies and assets that are accretive and enhance our existing service offerings, broaden our service offerings or expand our customer relationships.

 

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Results of Operations

The following table sets forth selected operating data for the periods indicated. As described more fully above, three of the seven businesses within our operating divisions commenced operations in 2012 or 2013. Therefore, our results of operations for these periods do not include full year results for certain businesses. Consideration should be given to this timing and the related impact on the comparability of our results.

 

     Six Months Ended
June 31,
    Year Ended
December 31,
 
     2014     2013     2013     2012  
     (in thousands)  

Revenue:

        

Completion and production services

   $ 44,481      $ 18,455      $ 47,731      $ 16,892   

Contract land and directional drilling services

     51,823        31,936        59,790        26,842   

Remote accommodation services

     9,586        12,895        25,027        14,169   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

     105,890        63,286        132,548        57,903   
  

 

 

   

 

 

   

 

 

   

 

 

 

Gross Profit(1):

        

Completion and production services

     8,448        1,468        5,104        3,128   

Contract land and directional drilling services

     9,666        6,727        5,803        6,341   

Remote accommodation services

     5,421        6,780        13,611        6,836   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total gross profit(1)

     23,535        14,975        24,518        16,305   

Selling, general and administrative expenses

     6,082        5,162        13,614        6,443   

Depreciation and amortization

     15,034        8,486        18,995        8,149   

Impairment of long-lived assets

     —          —          938        2,435   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating (loss) income

     2,419        1,327        (9,029     (722

Interest expense

     (1,864     (801     (2,012     (274

Other (expense) income, net

     (43     153        (215     (49
  

 

 

   

 

 

   

 

 

   

 

 

 

(Loss) income before income taxes

     512        679        (11,256     (1,045

Provision for income taxes

     1,059        1,417        2,715        1,013   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (547   $ (738   $ (13,971   $ (2,058
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Excludes depreciation and amortization.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Revenue. Revenue for the six months ended June 30, 2014 increased $42.6 million, or 67.3%, to $105.9 million from $63.3 million for the six months ended June 30, 2013. The increase in revenue by operating division was as follows:

Completion and Production Services. Completion and production services division revenue increased $26.1 million, or 141.0%, to $44.5 million for the six months ended June 30, 2014 from $18.4 million for the same period in 2013. The increase was primarily attributable to our sand production operation, which began selling product in February 2013 and accounted for $16.3 million, or 62.5%, of the total division revenue increase for the six month period ended June 30, 2014 compared to the six month period ended June 30, 2013. Our coil tubing services business accounted for $5.4 million, or 20.7%, of the total division revenue increase. Our coiled tubing services revenue growth was primarily attributable to our investment of $7.7 million in additional equipment to complete another coil spread that was placed in service in February 2014. Our pump down services business did not have any revenue during the first six months of 2013 and accounted for $2.9 million, or 11.1%, of the total division revenue increase. Our investment in new equipment to provide pump down services was $6.0 million. Revenue from our remaining completion and

 

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production services business increased $1.5 million, or 5.7%, of the total division revenue increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to a $2.3 million, or 39.0%, increase in revenue at our flow back services business as a result of our investment of $7.7 million in additional flow back equipment since January 1, 2013. This increase was partially offset by a decrease of $0.8 million, or 32.8%, in revenue at our field services business as result of more competition and less rig moves compared to the six month period ended June 30, 2013.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $19.9 million, or 62.3%, to $51.8 million for the six months ended June 30, 2014 from $31.9 million for the same period in 2013. The increase was primarily attributable to our land drilling services, which accounted for $19.6 million, or 99.0%, of the total division revenue increase. In 2013, we invested an additional $14.2 million to increase our rig fleet from seven rigs to eight rigs. The additional rig was placed in service in November 2013. In January 2014, we invested $47.0 million to acquire five additional horizontal drilling rigs. Revenue from our remaining land and directional drilling services business increased $0.3 million, or 1.0% of total division revenue increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to an increase of $2.8 million, or 14.1% of the total division revenue increase, for our rig moving business, which was not operating during the six months ended June 30, 2013. The increase attributable to the rig moving business was substantially offset by a decrease of $2.5 million, or 13.1%, for our directional drilling services business during the six months ended June 30, 2014 compared to the same period in 2013.

Remote Accommodation Services. Remote accommodation services division revenue decreased $3.3 million, or 25.7%, to $9.6 million for the six months ended June 30, 2014 from $12.9 for the same period in 2013. The decrease was a result of a decrease in room nights from 62,426 for the six months ended June 30, 2013 compared to 42,288 for the six months ended June 30, 2014. The decrease in room nights was due to a reduction in room nights for one of our primary customers related to scaling back a project combined with a slow ramp up on another customers’ project.

Gross Profit. Gross profit for the six months ended June 30, 2014 was $23.5 million, or 22.2% of total revenue, compared to $15.0, or 23.7% of total revenue for the six months ended June 30, 2013. Gross profit by operating division was as follows:

Completion and Production Services. Completion and production services gross profit was $8.4 million, or 19.0% of division revenue, for the six months ended June 30, 2014, compared to $1.5 million, or 8.0%, of division revenue for the same period in 2013. The increase was primarily attributable to our sand production operation, which began selling product in 2013 and accounted for $3.1 million, or 44.9%, of the total division gross profit increase for the six month period ended June 30, 2014 compared to the six month period ended June 30, 2013. During the six month period ended June 30, 2013, the market for sand was more competitive, resulting in downward pricing pressure compared to the same period in 2014. Gross profit from our coil tubing services division increased $2.7 million, or 39.1% of the total division gross profit increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase in the coil tubing gross profit was primarily attributable to achieving economies of scale in our operation as a result of the 126.8% revenue growth in the coil tubing services division compared to the six months ending June 30, 2013. Gross profit from our remaining completion and production services business increased $1.1 million, or 15.9% of total division gross profit increase for the six months ended June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to a 39.0% increase in revenue at our flow back services business as well as an increase at our pump down services business, which was not operating during the six months ended June 30, 2013. The increases at our flow back services and pump down services businesses were partially offset by a 32.8% decline in revenues at our field services business.

Contract Land and Directional Drilling Services. Contract land and directional drilling services gross profit was $9.7 million, or 18.7% of division revenue, for the six months ended June 30, 2014 compared to $6.7 million, or 21.1%, of division revenue for the same period in 2013. Gross profit from our

 

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land drilling services business accounted for $3.9 million, or 130.0% of the total division gross profit increase for the six months ending June 30, 2014 compared to the six month period ended June 30, 2013. The increase was primarily attributable to our investment of $61.2 million to increase our rig fleet from seven to thirteen rigs. Gross profit from our rig moving business, which was not operating during the six months ended June 30, 2013 accounted for $1.4 million, or 46.7% of the total division gross profit increase during the six months ended June 30, 2014. The increases in our land drilling and rig moving businesses were partially offset by a $2.3 million decrease at our directional drilling services business for the six month period ended June 30, 2014 compared to the six month period ended June 30, 2013. This specific decrease was primarily due to a customer that changed drilling technology and discontinued use of some of our services.

Remote Accommodation Services. Remote accommodation services division gross profit was $5.4 million, or 56.6% of division revenue, for the six months ended June 30, 2014, compared to $6.8 million, or 52.6% of division revenue, for the same period in 2013. The gross profit was adversely impacted by lower utilization as compared to 2013 due to a reduction in room nights for one of our primary customers related to scaling back a project combined with a slow ramp up on another customers project.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $0.9 million, or 17.8%, to $6.1 million for the six months ended June 30, 2014, from $5.2 million for the six months ended June 30, 2013. The increase in expenses was primarily attributable to increased administrative personnel to support the growth of our operations. As a percentage of revenue, these expenses decreased to 5.7% in 2014, from 8.2% in 2013 due to the increase in our revenues.

Depreciation and Amortization. Depreciation and amortization increased $6.5 million, or 77.2%, to $15.0 million for the six months ended June 30, 2014 from $8.5 million for the six months ended June 30, 2013. The increase was primarily attributable to the acquisition of additional equipment for our contract land drilling operations and our directional drilling business operations.

Interest Expense. Interest expense increased $1.1 million, or 132.7%, to $1.9 million for the six months ended June 30, 2014 from $0.8 million for the six months ended June 30, 2013. The increase in interest expense was attributable to increased borrowings during 2014 and 2013 to support the continued expansion of our operations.

Income Taxes. Each of Redback Energy Services, Redback Coil Tubing, Bison Drilling, Bison Trucking, Panther Drilling and Muskie Proppant is a limited liability company and, as a pass-through entity, does not pay federal income tax and, generally, state income tax. The income tax expense recognized was attributable to Sand Tiger which, through its holding companies will be treated as a corporation for U.S. federal income tax purposes and is subject to Canadian income taxes. For the six months ended June 30, 2014, we recognized $1.1 million of income tax expense compared to $1.4 million for the six months ended June 30, 2013, a decrease of $0.3 million, or 25.3%. The decrease was primarily attributable to Sand Tiger’s decreased profitability.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Revenue. Revenue for the year ended December 31, 2013 increased $74.6 million, or 128.9%, to $132.5 million from $57.9 million for the year ended December 31, 2012. The increase in revenue by operating division was as follows:

Completion and Production Services. Completion and production services division revenue increased $30.8 million, or 182.6%, to $47.7 million for the year ended December 31, 2013 from $16.9 million for the year ended December 31, 2012. The increase was primarily attributable to our sand production operation which did not have any revenue during 2012, and accounted for $17.8 million, or 57.6%, of the total division revenue increase for 2013. Our coiled tubing services business operated for the full year in 2013, compared to four months in 2012, and accounted for $10.5 million, or 34.2%, of the total division revenue increase. Our coiled tubing services revenue growth was attributable to our investment of $3.3 million in

 

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additional equipment that completed another coil spread that was placed in service in February 2013. We also expanded our service offerings during 2013 with an investment of $5.4 million in new equipment to provide pump down services. The first of our four pump down spreads was placed in service in July 2013, and our other three spreads were placed in service in August 2013. Pump down services accounted for $1.7 million, or 5.5%, of the total division revenue increase during 2013. Substantially all of the remaining increase in revenue for this division was attributable to an increase in the workover rig business due to additional drilling activity in the Permian Basin during 2013.

Contract Land and Directional Drilling Services. Contract land and directional drilling services division revenue increased $33.0 million, or 122.7%, to $59.8 million for the year ended December 31, 2013, from $26.8 million for the year ended December 31, 2012. The increase was primarily attributable to our directional drilling services business that commenced operations in late December of 2012, compared to a full year of operations in 2013, and accounted for $19.4 million, or 58.4%, of the total division revenue increase. The land drilling services accounted for $13.1 million, or 39.5%, of the total division revenue increase. In 2012, we invested $28.9 million to increase our rig fleet from four rigs to seven rigs. Of the three new rigs, two were placed in service in August 2012 and one was placed in service in October 2012. In 2013, we invested an additional $14.2 million to increase our rig fleet from seven rigs to eight rigs. The additional rig was placed in service in November 2013.

Remote Accommodation Services. Remote accommodation services division revenue increased $10.8 million, or 76.6%, to $25.0 million for 2013 from $14.2 million for 2012. The increase was a result of our $5.5 million investment in additional housing units to expand our business and increase our capacity to an average of 626 available room nights during 2013 from an average of 422 available room nights during 2012.

Gross Profit. Gross profit for 2013 was $24.5 million, or 18.5% of total revenue, compared to $16.3 million, or 28.2% of total revenue, for 2012. Gross profit by operating division was as follows:

Completion and Production Services. Completion and production services division gross profit was $5.1 million, or 10.7% of division revenue, for 2013, compared to $3.1 million, or 18.5% of revenue, for 2012. The decrease in gross profit as a percentage of revenue was primarily attributable to the direct costs of our sand production business exceeding revenue by $0.8 million during 2013. Our sand operations did not begin selling product until February 2013 at which point the market for sand had become increasingly competitive, resulting in downward pricing pressure. Gross profit for our remaining completion and production services business during 2013 was $5.9 million, or 19.6% of division revenue, compared to $3.1 million, or 18.5% of revenue for 2012. The increase in gross margin as a percentage of revenue was primarily attributable to achieving economies of scale in our coiled tubing business which operated for a full year in 2013 compared to four months in 2012.

Contract Land and Directional Drilling Services. Contract land and directional drilling services gross profit was $5.8 million, or 9.7% of division revenue, in 2013, compared to $6.3 million, or 23.6% of division revenue, in 2012. The decrease in gross profit as a percentage of revenue was primarily attributable to our spudder rigs operating at a loss in 2013 due to increased competition and lower pricing, the trend toward increased horizontal drilling resulting in downward pricing pressure and lower utilization of our vertical drilling rigs and a higher mix of revenue from footage contracts in 2013, which resulted in lower gross margins when compared to gross margins from our daywork contracts. Two of our rigs were also down for a longer than expected period of time for maintenance work during 2013. In December 2013, we discontinued offering spudder rig services and are actively marketing the spudder rigs and related equipment for sale.

Remote Accommodation Services. Remote accommodation services division gross profit was $13.6 million, or 54.4% of division revenue, in 2013, compared to $6.8 million, or 48.2% of division revenue, in 2012. The increase in gross profit as a percentage of revenue was primarily attributable to achieving economies of scale in our operation as a result of the 76.6% growth in revenue.

Selling, General and Administrative Expenses. Selling, general and administrative expenses represent the costs associated with managing and supporting our operations. These expenses increased $7.2 million, or

 

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111.3%, to $13.6 million for 2013, from $6.4 million for 2012. The increase in expenses was primarily attributable to the commencement of our coiled tubing operations in May 2012, our sand production operations in May 2012 and our directional drilling operation in December 2012. As a percentage of revenue, these expenses decreased to 10.3% in 2013, from 11.1% in 2012 due to the increase in our revenues. While construction of our sand production operations and administrative support for these operations began in May 2012, the plant was not complete and our first sales did not occur until February 2013.

Depreciation and Amortization. Depreciation and amortization increased $10.9 million, or 133.1%, to $19.0 million for 2013 from $8.1 million for 2012. The increase was primarily attributable to the expansion of our contract land drilling operations and the timing of the commencement of our coiled tubing, sand production, and directional drilling business operations.

Impairment of Long-lived Assets. Impairment of long-lived assets in 2013 represented a $0.9 million loss to write down the spudder rigs and related equipment to fair value, including estimated costs to sell. Impairment of long-lived assets in 2012 represented a $2.4 million loss on certain properties that resulted from a moratorium on mining for sand.

Interest Expense. Interest expense increased $1.7 million, or 634.7%, during 2013, compared to 2012. The increase in interest expense was attributable to increased borrowings during 2013 to support the continued expansion in our operations. During 2012, substantially all of our operating expansion was funded by our equity holders.

Income Taxes. Each of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling and Bison Trucking is a limited liability company that is 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 Sand Tiger. For 2013, we recognized $2.7 million of income tax expense compared to $1.0 million for 2012, an increase of $1.7 million, or 168.0%. The increase was primarily attributable to Sand Tiger’s increased profitability.

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. Our primary sources of liquidity to date have been capital contributions from our equity holders, borrowings under our credit facilities and cash flows from operations. Following the completion of this offering, we anticipate that our primary sources of liquidity will be cash flows from operations and borrowings under our revolving credit facility. Our primary use of capital has been for investing in property and equipment used to provide our services. Following the completion of this offering, our primary uses of cash will be for paying distributions to our unitholders and for replacement and growth capital expenditures, including acquisitions and investments in property and equipment. We regularly monitor potential capital sources, including equity and debt financings, in an effort to meet our planned capital expenditures and liquidity requirements. Our future success will be highly dependent on our ability to access outside sources of capital.

Our partnership agreement does not require us to distribute any of the cash we generate from operations. We believe, however, that it will be in the best interests of our unitholders if we distribute a substantial portion of the cash we generate from operations. The board of directors of our general partner will adopt a policy to distribute an amount equal to the cash available for distribution we generate each quarter to our unitholders. Our first distribution, however, will include cash available for distribution for the period from the closing of this offering through                     , 2014.

As of June 30, 2014, we had an aggregate of $70.4 million in borrowings outstanding under our credit facilities, leaving an aggregate of $10.1 million of available borrowing capacity under these credit facilities.

 

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Liquidity and cash flow

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

 

     Six Months Ended
June 30,
    Year Ended
December 31,
 
     2014     2013     2013           2012        

Net cash (used in) provided by operating activities

   $ (1,062   $ (7,362   $ 4,162      $ 4,791   

Net cash used in investing activities

     (74,553     (16,492     (63,322     (71,584

Net cash provided by financing activities

     74,647        25,878        58,584        72,958   

Effect of foreign exchange rate on cash

     41        (153     (215     40   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net change in cash

   $ (927   $ 1,871      $ (791   $ 6,205   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating Activities

Net cash used in operating activities was $1.1 million for the six months ended June 30, 2014, compared to $7.4 million for the six months ended June 30, 2013. The decrease in operating cash flows was primarily attributable to timing differences in the collection of trade receivables and payments of related party payables.

Net cash provided by operating activities was $4.2 million for the year ended December 31, 2013, compared to $4.8 million for the year ended December 31, 2012. The decrease in operating cash flows was primarily attributable to timing differences in the collection of trade receivables and payments of trade payables, and an increase in our sand inventories.

Our operating cash flow is sensitive to many variables, the most significant of which are the timing of billing and customer collections and the purchase of sand inventories, and which may affect our cash available for distributions.

Investing Activities

Net cash used in investing activities was $74.6 million for the six months ended June 30, 2014, compared to $16.5 million for the six months ended June 30, 2013. Substantially all cash used in investing activities was used to purchase property and equipment that is utilized to provide our services.

Net cash used in investing activities was $63.3 million for the year ended December 31, 2013, compared to $71.6 million for 2012. Substantially all cash used in investing activities was used to purchase property and equipment that is utilized to provide our services. The following table summarizes our capital expenditures by operating division for the periods indicated:

 

     Six Months Ended
June 30,
     Year Ended
December 31,
 
     2014      2013      2013          2012      

Completion and production

     8,202         8,464         21,920         37,182   

Contract and directional drilling services

     64,313         9,320         36,487         28,954   

Remote accommodations

     2,613         661         5,549         5,448   
  

 

 

    

 

 

    

 

 

    

 

 

 
     75,128         18,445         63,956         71,584   
  

 

 

    

 

 

    

 

 

    

 

 

 

Financing Activities

Net cash provided by financing activities was $74.6 million for the six months ended June 30, 2014, compared to $25.9 million for the six months ended June 30, 2013. We received $47.0 million and $17.3 million from our equity holders during the six months ended June 30, 2014 and 2013, respectively. The remaining financing cash flow was from net borrowings under our credit facilities and issuance of long-term debt.

 

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Net cash provided by financing activities was $58.6 million for the year ended December 31, 2013, compared to $73.0 million for 2012. We received $27.0 million and $59.1 million from our equity holders during the years ended December 31, 2013 and 2012, respectively. The remaining financing cash flow was primarily from net borrowings under our credit facilities.

Working Capital

Our working capital totaled $(10.6) million, $(13.2) million and $(3.6) million at June 30, 2014, December 31, 2013 and December 31, 2012, respectively. Our cash balances totaled $7.4 million, $8.3 million and $9.1 million at June 30, 2014, December 31, 2013 and December 31, 2012, respectively.

Existing Credit Facilities

Redback Energy Services LLC

On April 1, 2013, Redback Energy Services, as borrower, entered into a business loan agreement with Legacy Bank, as lender, providing for a $2.0 million revolving line of credit, subject to a borrowing base limitation, which we sometimes refer to as the April 2013 Redback facility. This facility amended Redback Energy Services’ prior revolving line of credit with Legacy Bank, entered into on April 25, 2012, increasing the amount available for borrowings from $1.5 million to $2.0 million and extending the maturity date from March 31, 2013 to April 1, 2014. On April 1, 2014, the April 2013 facility was once again amended, and the maturity date was extended to April 1, 2015. The borrowing base under the March 2013 facility is currently set as the lesser of $2.0 million and 75% of the aggregate amount of certain eligible accounts of Redback Energy Services specified in the business loan agreement. Interest is payable monthly at the greater of (i) the minimum prime lending rate for large U.S. Money Center Commercial banks as published in the Money Rate Section of The Wall Street Journal (or any substitute index as may be designated by the Legacy Bank), which we refer to as the Legacy Bank prime rate, plus 1.00% and (ii) 5.65% per annum. In the event of default, the interest rate will be increased by adding an additional 5.00% per annum to the applicable interest rate, subject to interest rate limitations under applicable law. As of June 30, 2014, $1.1 million was outstanding under the April 2013 Redback facility with an interest rate of 6.00% per annum.

The April 2013 Redback facility is secured by specified assets of Redback Energy Services and contains certain customary covenants, including covenants that (i) limit the incurrence of additional debt by the borrower in excess of $100,000 without the lender’s prior written approval, (ii) restrict the use of the loan proceeds solely to working capital purposes, (iii) require maintenance of a minimum combined debt service coverage ratio of 1.25 to 1 and a minimum $8.5 million tangible net worth and (iv) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013 and June 30, 2014, Redback Energy Services was in compliance with all of its covenants under this facility. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

On June 21, 2013, in connection with a formation of its pump-down business, Redback Energy Services, as borrower, entered into another business loan agreement with Legacy Bank, as lender, providing for a $1.5 million revolving line of credit, subject to a borrowing base limitation, which we sometimes refer to as the June 2013 Redback facility. The borrowing base under this facility is set as the lesser of $1.5 million and 75% of the aggregate amount of certain eligible accounts of Redback Energy Services specified in the business loan agreement. Interest is payable monthly at the greater of (i) the Legacy Bank prime rate plus 1.00% and (ii) 5.25% per annum. In the event of default, interest rate will be increased by adding an additional 5.00% per annum to the applicable interest rate, subject to interest rate limitations under applicable law. The June 2013 Redback facility matures on May 30, 2015. As of June 30, 2014, $0.3 million was outstanding under this facility, with an interest rate of 5.25% per annum.

The June 2013 Redback facility is secured by specified assets of Redback Energy Services and provides for the cross pledge and cross collateralization of the indebtedness secured under this facility with all other indebtedness of the borrower incurred with the lender. The June 2013 Redback facility contains certain customary covenants,

 

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including covenants that (i) limit the incurrence of additional debt by the borrower in excess of $100,000 without the lender’s prior written approval, (ii) restrict the use of the loan proceeds solely to working capital purposes of Redback Energy Services’ pump down business, (iii) prohibit the borrower’s ability to change its business activities, cease operations, liquidate, merge, acquire or consolidate with any other entity without the lender’s prior written consent, (iv) prohibit the borrower’s ability to transfer collateral not in the ordinary course of business without the lender’s prior written consent, (v) restrict distributions with respect to any capital account, (vi) require maintenance of a minimum combined debt service coverage ratio of 1.25 to 1 and a minimum $8.5 million equity position during the term of the loan plus 50% of net income and (vii) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013 and June 30, 2014, Redback Energy Services was in compliance with all of its covenants under this facility. We intend to repay in full and terminate the June 2013 Redback facility with a portion of the net proceeds from this offering.

On October 7, 2013, Redback Energy Services, as borrower, entered into an additional business loan agreement with Legacy Bank, as lender, providing for an approximately $8.5 million revolving line of credit, subject to a borrowing base limitation, which we sometimes refer to as the October 2013 Redback facility. The borrowing base under this facility is set as the lesser of $8.5 million or 60% of the aggregate amount of certain eligible equipment of Redback Energy Services and 35% of all pump-down equipment specified in the business loan agreement. Interest is payable monthly at the greater of (i) the Legacy Bank prime rate plus 1.00% and (ii) 5.25% per annum. In the event of default, interest rate will be increased by adding an additional 5.00% per annum to the above-referenced interest rate, subject to interest rate limitations under applicable law. The facility matures on October 9, 2014. Redback Energy Services used borrowings under this facility to repay and terminate two prior term loans it had entered into with Legacy Bank (one originally entered into in April 2013 and the other entered into in June 2013 in connection with the formation of its pump down business) in the aggregate principal amount of $8.5 million. As of June 30, 2014, $5.3 million was outstanding under the October 2013 Redback facility, with an interest rate of 5.25% per annum.

The October 2013 Redback facility is secured by specified assets of Redback Energy Services and also provides for the cross pledge and cross collateralization of the indebtedness secured under this facility with all other indebtedness of the borrower incurred with the lender. The October 2013 Redback facility contains certain customary covenants, including covenants that (i) limit the incurrence of additional debt by the borrower in excess of $100,000 without the lender’s prior written approval, (ii) restrict the use of the loan proceeds solely to purchases of equipment, (iii) prohibit the borrower’s ability to change its business activities, cease operations, liquidate, merge, acquire or consolidate with any other entity without the lender’s prior written consent, (iv) prohibit the borrower’s ability to transfer collateral not in the ordinary course of business without the lender’s prior written consent, (v) restrict distributions with respect to any capital account, (vi) require maintenance of a minimum combined debt service coverage ratio of 1.25 to 1 and a loan to value ratio that does not exceed 60% of combined equipment collateral pool and (vii) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013, Redback Energy Services was in compliance with all of its covenants under this facility. As of June 30, 2014, Redback Energy Services was not in compliance with the minimum combined debt service coverage ratio. Redback Energy Services received a waiver on the minimum combined debt service coverage ratio for the first and second quarter of 2014 and expects to be in compliance with the minimum combined debt service coverage ratio in the third quarter of 2014. We intend to repay in full and terminate the October 2013 Redback facility with a portion of the net proceeds from this offering.

On July 22, 2014, Redback Energy Services, as borrower, entered into a promissory note with UMB Bank, n.a., as lender, for $2.0 million which we sometimes refer to as the July 2014 Redback Facility. The loan bears interest at an interest rate of 3.25% per annum and is amortizing in 60 monthly installments of $36,024, with a final maturity date of July 22, 2019. The loan is secured by a security interest in a double fluid pumper trailer and contains certain customary covenants, including covenants that require the borrower to maintain (i) a debt service coverage ratio of no less than 1.25 to 1, (ii) a tangible net worth of no less than $13,236,992, (iii) a debt to tangible net worth ratio of 0.8 to 1 or less and (iv) a current ratio of no less than 0.97 to 1. We intend to repay in full and terminate the July 2014 Redback facility with a portion of the net proceeds from this offering.

 

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Redback Coil Tubing LLC

On October 14, 2013, Redback Coil Tubing, as borrower, entered into a loan and security agreement with Stillwater National Bank and Trust Company, or Stillwater, as lender, which we sometimes refer to as the October 2013 Coil Tubing facility, providing for (i) a term loan in the principal amount of up to $8.0 million and (ii) a $3.0 million revolving credit facility, subject to a borrowing base limitation. The borrowing base under the revolving credit facility is set at an amount equal to 80% of the aggregate amount of certain eligible accounts (specified in the loan and security agreement) as of the date of determination.

Outstanding indebtedness under the term loan and the revolving credit facility bears interest at the prime rate, as published in the “Bonds, Rates & Yields” section of The Wall Street Journal, plus an additional 0.50% if the ratio of funded debt to EBITDA (as defined in the loan and security agreement) is between 3 to 1 and 4 to 1, or 1% if the ratio of funded debt to EBITDA exceeds 4 to 1. Depending on these ratios, the minimum interest rate will range from 4.45% to 5.45%. In the event of default, interest on outstanding indebtedness under the term loan and the revolving credit facility will be payable at the rate of 15% per annum. The term loan matures on October 14, 2017, while the revolving credit facility matures on October 9, 2014. Redback Coil Tubing used $2.4 million in borrowings under the revolving credit facility to repay and terminate its prior term loan and revolving credit facility with Coppermark Bank entered into on October 5, 2012, as subsequently amended. Other borrowings under the revolving credit facility may be used only for general working capital purposes. Borrowings under the term loan may be used only for purchases of equipment. As of June 30, 2014, Redback Coil Tubing had outstanding borrowings of $6.3 million under the term loan and $1.6 million under the revolving credit facility, in each case with an interest rate of 4.45%.

The term loan and the revolving credit facility are secured by specified assets of Redback Coil Tubing. Additionally, the loan and the security agreement contain certain customary covenants, including covenants that (i) restrict the encumbrance of the borrower’s assets, (ii) limit the incurrence of additional debt, (iii) restrict the sale or transfer of the borrower’s assets, (iv) prohibit the borrower’s ability to merge or consolidate with any person or entity, sell all or substantially all assets, materially change its business, amend organizational documents, issue any indebtedness or other rights convertible into any equity interest (or enter into an agreement relating to any of the forgoing), (v) prohibit payment of dividends or making other distributions, (vi) prohibit making loans, except for certain ordinary course advances or extensions of credit, (vii) require maintenance of tangible net worth of at least $15.0 million and a ratio of funded debt to EBITDA that does not exceed 4 to 1 and (viii) require the borrower to provide the lender with certain financial and other information. As of December 31, 2013 and June 30, 2014, Redback Coil Tubing was in compliance with all of its covenants under the October 2013 Coil Tubing facility. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

Muskie Proppant LLC

On January 31, 2013, Muskie Proppant, as borrower, entered into a loan agreement with Citizens State Bank of La Crosse, as lender, providing for a $3.0 million loan. As amended to date, the loan matures on February 1, 2015 and accrues interest at the highest U.S. Prime Rate as published in The Wall Street Journal “Money Table” plus 1.5%, payable monthly. The facility is secured by a real estate mortgage. As of June 30, 2014, $1.9 million was outstanding under this facility, with an interest rate of 4.75%.

In June and July of 2013, Muskie Proppant received an aggregate of approximately $3.5 million in loans from its members to fund the expansion of its processing plant and logistics facilities. Muskie Proppant’s obligations under these loans are secured by substantially all of Muskie Proppant’s assets. These loans mature on July 31, 2014, unless they are accelerated or extended in accordance with their terms. Interest on these loans accrue at a rate equal to the lesser of (i) the prime rate of interest announced from time to time by Citibank, N.A. plus 2.5% per annum and (ii) the maximum rate of interest permitted by applicable law, and is payable monthly. In the event of default, interest will accrue at the lesser of 16% per annum and the maximum amount allowed by law. The notes evidencing these loans contain certain customary covenants, including covenants that prevent

 

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Muskie Proppant, without the prior written consent of the respective noteholder, from (i) incurring or guaranteeing certain debts, (ii) allowing certain liens to encumber its property, (iii) making certain distributions to members, (iv) assigning or transferring certain assets, (v) transacting with affiliates and (vi) acquiring securities in other entities. As of June 30, 2014, Muskie Proppant had outstanding borrowings of $3.7 million under these loans, which bore interest at a weighted average rate of 5.75%, and was in compliance with all of its covenants under these loans. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

Bison Drilling and Field Services LLC

On May 31, 2013, Bison Drilling, as borrower, entered into a loan and security agreement with International Bank of Commerce, as lender, which, as amended, provides for a $5.0 million revolving loan, with a maturity date of June 1, 2015, and a $30.0 million term loan, with a maturity date of April 1, 2017. Effective May 30, 2014, the revolving loan was amended to increase the revolving loan by $2.0 million to $7.0 million. Effective January 31, 2014, the term loan was amended to increase the face amount to $51.9 million and extend the maturity date to April 30, 2017. Initially, the borrowings under the term loan were to be used for purchasing and making improvements to certain business related equipment and business activities, refinancing a current term loan with Amegy Bank and paying certain loan fees. The additional funds were to be used for funding, in part, Bison’s acquisition of five additional electric horizontal drilling rigs. The borrowings under the revolving loan may be used for short-term working capital requirements and refinancing a previous revolving loan with Amegy Bank.

The revolving loan and the term loan each bear interest at the New York Prime Rate, plus an additional percentage of 0.75%, adjusted on the date of change, with a floor of 4.25% per annum for the revolving loan and 4.5% for the term loan. The interest is calculated on the daily outstanding principal balance computed on the basis of a 360 day year for 12 months of 30 days each. As amended, the term loan required Bison Drilling to make only interest payments on a monthly basis through the last day of April 2014. Beginning on May 31, 2014, the term loan requires Bison Drilling to pay monthly payments of principal and interest based upon a 36 month amortization of the remaining principal balance. For the revolving loan, Bison Drilling pays interest-only monthly payments through the maturity date of May 31, 2015, at which time all accrued interest and unpaid principal will be due and payable in full. As of June 30, 2014, Bison Drilling had outstanding borrowings of $49.2 million under the term loan, with an interest rate of 4.5% and $4.8 million under the revolving loan, with an interest rate of 4.25%.

Both loans are secured by Bison Drilling’s personal property, now owned or hereafter acquired, and the loans contain customary covenants, including covenants that (i) require quarterly financial statements and annual audited financial statements, (ii) require annual projection reports, (iii) require a monthly borrowing base certificate, (iv) restrict distributions to its members, (v) restrict the incurrence of additional debt, (vi) require a leverage ratio not greater than 3 to 1 and a fixed charge ratio not less than 1.35 to 1, (vii) restrict the issuance of loans and guarantees, (viii) restrict transactions with affiliates and (ix) require a minimum tangible net worth of (a) at least $30.0 million as of December 31, 2013 and (b) at least $50.0 million as of January 31, 2014. As of December 31, 2013, Bison Drilling’s actual tangible net worth was $28.9 million and Bison Drilling received a waiver from the lender for such non-compliance. At June 30, 2014, Bison Drilling was in violation of the minimum fixed coverage ratio with a ratio of 1.20 to 1 and received a waiver from the lender. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

Stingray Pressure Pumping LLC

On July 3, 2013, Stingray Pressure Pumping entered into a loan and security agreement with International Bank of Commerce providing for a term credit loan in the amount of $50.0 million for the purpose of purchasing additional equipment. Outstanding borrowings bear interest at the prime rate as quoted by JP Morgan Bank & Co., New York, New York, plus 0.75%, with a floor of 4.50% per annum. Interest is calculated on the daily outstanding principal balance computed on the basis of a 365 day year for 12 months of 30 days each.

 

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The loan is secured by, among other things, all of Stingray Pressure Pumping’s accounts, goods, equipment, fixtures, inventory, now owned or hereafter acquired, and the loan contains certain customary covenants, including covenants that (i) require quarterly financial statements and annual audited financial statements, (ii) require annual projection reports, (iii) require an annual receivable report in conjunction with the quarterly statements, (iv) restrict distributions to members, (v) restrict the incurrence of additional debt, (vi) require a debt to tangible net worth ratio that does not exceed 1.75 to 1; (vii) restrict the issuance of loans and guarantees, (viii) restrict transactions with affiliates and (ix) require, initially, a minimum tangible net worth of $30.0 million, which increases each year by one-third of the prior year’s net income (but may not be reduced as a result of the prior year’s net income loss, if any).

As of June 30, 2014, Stingray Pressure Pumping had an outstanding balance of $35.4 million, with an interest of 4.50%, and was in compliance with the covenants of the loan, including the debt to tangible net worth ratio. We intend to repay in full and terminate this loan with a portion of the net proceeds from this offering.

Stingray Logistics LLC

On November 26, 2012, Stingray Logistics, as borrower, entered into a master loan and security agreement with Mack Financial Services, a division of VFS US LLC, as lender, for the purpose of acquiring construction, motor vehicles, trailers and other personal property or related equipment. Pursuant to the agreement, Stingray Logistics LLC granted a purchase money security interest in any of the equipment acquired with the proceeds of the loan. Each acquisition is made pursuant to a separate schedule, which is deemed a separate loan agreement with respect to the acquired equipment, and incorporates the terms of the master loan agreement.

The master loan and security agreement contains customary covenants, including covenants that (i) require the purchased equipment to be free from all claims and liens, (ii) require the equipment to remain in good operating condition and in conformity with all governmental regulations, (iii) restrict the transfer of the equipment, (iv) require borrower to maintain certain types of insurance coverage and (v) require borrower to provide lender with financial information upon request by lender.

On November 26, 2012, Stingray Logistics entered into a schedule under this master loan and security agreement pursuant to which Stingray Logistics borrowed approximately $0.9 million at an interest rate of 5.99% to purchase thirteen vehicles. The term for the loan is 48 months, with monthly interest and principal payments of approximately $21,635.

On September 25, 2013, Stingray Logistics entered into a credit sales contract for the purchase of six vehicles. Pursuant to this agreement, Stingray Logistics granted a purchase money security interest in the purchased equipment and is required to make 48 monthly payments which started on October 25, 2013, for a total of $0.5 million. The credit sales contract contains customary covenants, including covenants that (i) require the equipment to remain free from all liens and security interests, (ii) require the equipment to remain in good operating condition and in conformity with all governmental regulations, (iii) require quarterly and annual financial statements and (iv) require borrower to maintain certain types of insurance coverage. The aggregate balance as of June 30, 2014 of these arrangements was $1.3 million.

New Revolving Credit Facility

In connection with the consummation of this offering, we intend to enter into a new revolving credit facility to replace our existing credit facilities that will be repaid and terminated. However, we do not currently have commitments for such facility and cannot assure you that we will have entered into such agreement before the closing of this offering.

Capital Requirements and Sources of Liquidity

During the year ended December 31, 2013, our capital expenditures for the common control entities, excluding acquisitions, were approximately $21.9 million, $36.5 million and $5.6 million in our completion and

 

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production services division, contract land and directional drilling services division and remote accommodation services division, respectively, for aggregate capital expenditures of approximately $64.0 million. During the six months ended June 30, 2014, our capital expenditures for the common control entities, excluding acquisitions, were approximately $8.2 million, $16.6 million and $2.6 million in our completion and production services division, contract land and directional drilling services division and remote accommodation services division, respectively, for aggregate capital expenditures of approximately $27.4 million. During 2014, we currently estimate that our aggregate capital expenditures will be approximately $139.0 million, of which approximately $77.1 million has been allocated to our contract land and directional drilling division primarily for the recent Drilling Transaction and maintenance capital expenditures, approximately $9.8 million has been allocated to our remote accommodations service division primarily for expansion of facilities and approximately $13.6 million has been allocated to our completion and production services division primarily for additional pumping and coil tubing units.

We believe that the proceeds of this offering, our operating cash flow and available borrowings under our revolving credit facilities will be sufficient to fund our operations and make expected distributions for at least the next twelve months. However, future cash flows are subject to a number of variables, and significant additional capital expenditures will 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 and make expected distributions. Further, we do not have a specific acquisition budget for 2014 since the timing and size of acquisitions cannot be accurately forecasted. 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 or distributions and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our new revolving credit facility, joint venture partnerships, asset sales, offerings of debt and 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, finance the capital expenditures necessary to conduct our operations or make expected distributions.

Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2013 (in thousands):

 

     Total      Less than
1 Year
     1-3 Years      3-5 Years      More than
5 Years
 

Contractual obligations:

              

Long-term debt, including current portion(1)

   $ 31,616       $ 8,712       $ 19,927       $ 2,977       $ —     

Operating lease obligations(2)

     11,225         2,539         4,152         2,022         2,512   

Purchase commitment to sand supplier(3)

     3,329         1,000         2,329         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
   $ 46,170       $ 12,251       $ 26,408       $ 4,999       $ 2,512   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 
(1) The long-term debt excludes interest payments on each obligation.
(2) Operating lease obligations relate to real estate, rail cars and other equipment.
(3) The purchase commitment to a sand supplier represents our monthly obligation to purchase a minimum amount of sand. If the minimum purchase requirement is not met, the shortfall is settled each month in cash.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our combined 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 2 of our combined financial statements appearing elsewhere in this prospectus for a discussion of additional accounting policies and estimates made by management.

 

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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 allowance for doubtful accounts, depreciation and amortization of property and equipment, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets.

Revenue Recognition. We generate revenue from multiple sources within our three 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. The specific revenue sources are outlined as follows:

Completion and Production Services Revenue. Completion and production 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.

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.

Remote Accommodation Services. Revenue from remote accommodation services is recognized when rooms are occupied and services have been rendered. Advanced deposits on rooms and special events are deferred until services are provided to the customer.

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

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

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

 

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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 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.

Income Taxes. The Partnership and each of our subsidiaries, except Sand Tiger, is treated as a pass-through entity for federal income tax and most state income tax purposes. Accordingly, income taxes on net earnings are payable by the stockholders, members or partners and are not reflected in the historical financial statements. Sand Tiger is subject to corporate income taxes and they are provided in the financial statements based upon Financial Accounting Standards Board, or FASB, Accounting Standard Codification, or ASC, 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.

Emerging Growth Company

The Jumpstart Our Business Startups Act of 2012 permits an “emerging growth company” like us to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We are choosing to “opt out” of this provision and, as a result, we will comply with new or revised accounting standards as required when they are adopted. This decision to opt out of the extended transition period is irrevocable.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm is not yet required to formally attest to the effectiveness of our internal controls over financial reporting, and will not be required to do so for as long as we are an “emerging growth company” pursuant to the provisions of the Jumpstart Our Business Startups Act of 2012 or as long as we are a non-accelerated filer. See “Summary—Emerging Growth Company.” Please also see “Risk Factors—Risks Inherent in an Investment in Us—For so long as we are an ‘emerging growth company’ we will not be required to comply with certain disclosure requirements that are applicable to other public companies and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investors.”

 

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Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended 2013 and 2012 or the six month period ended June 30, 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

Quantitative and Qualitative Disclosure about Market Risks

The demand, pricing and terms for oil and gas services provided by us are largely dependent upon the level of activity for the U.S. oil and natural gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and natural gas; the level of prices, and expectations about future prices of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and natural gas; the expected rates of declining current production; the discovery rates of new oil and natural gas reserves; available pipeline and other transportation capacity; weather conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; environmental regulations; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and natural gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and natural gas producers.

The level of activity in the U.S. oil and natural gas exploration and production industry is volatile. Expected trends in oil and natural gas production activities may not continue and demand for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and therefore affect demand for our services. A material decline in oil and natural gas prices or U.S. activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. Recently, demand for our services has been strong and we are continuing our past practice of committing our equipment on a short-term or day-to-day basis.

Interest Rate Risk

We had a cash and cash equivalents balance of $7.4 million at June 30, 2014. We do not enter into investments for trading or speculative purposes. We do not believe that we have any material exposure to changes in the fair value of these investments as a result of changes in interest rates. Declines in interest rates, however, will reduce future income.

We had $70.4 million outstanding under various credit facilities at June 30, 2014, which bore interest at variable rates generally based on prime plus various factors. Based on the current debt structure, a 1% increase or decrease in the interest rates would increase or decrease interest expense by approximately $0.7 million per year. We do not currently hedge our interest rate exposure.

Foreign Currency Risk

Our remote accommodation businesses generate revenue and incur expenses that are denominated in the Canadian dollar. These transactions could be materially affected by currency fluctuations. Changes in currency exchange rates could adversely affect our consolidated results of operations or financial position. We also maintain cash balances denominated in the Canadian dollar. At June 30, 2014, we had $3.5 million of cash in Canadian accounts. A 10% increase in the strength of the Canadian dollar versus the U.S. dollar would have resulted in an increase in pre-tax income of approximately $0.3 million as of June 30, 2014. Conversely, a corresponding decrease in the strength of the Canadian dollar would have resulted in a comparable decrease in pre-tax income. We have not hedged our exposure to changes in foreign currency exchange rates and, as a result, could incur unanticipated translation gains and losses.

 

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Seasonality

We provide completion and production services primarily in the Utica, Permian Basin, Eagle Ford, Marcellus, Granite Wash, Cana Woodford and Cleveland sand resource plays located in the continental U.S. We also provide remote accommodation services in the oil sands in Alberta, Canada. We serve these markets through our facilities and service centers that are strategically located to serve resource plays in Ohio, Oklahoma, Wisconsin, Minnesota and Alberta, Canada. For the year ended December 31, 2013 and the six months ended June 30, 2014, we generated approximately 52.4% and 57.1%, respectively, of our pro forma revenue from our operations in Ohio, Wisconsin, Minnesota and Canada where weather conditions may be severe. As a result, our operations may be limited or disrupted, particularly during winter and spring months, in these geographic regions, which would have a material adverse effect on our financial condition and results of operations. Our operations in Oklahoma and Texas are generally not affected by seasonal weather conditions.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements.

 

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BUSINESS

General

Overview

We are a growth-oriented Delaware limited partnership providing completion and production services, contract and directional drilling services and remote accommodation services primarily to companies engaged in the exploration and development of North American onshore unconventional sands and shale oil and natural gas reserves, commonly referred to as “unconventional resources.” Our primary business objective is to provide an attractive total return to unitholders by optimizing business results and maximizing distributions through organic growth opportunities and accretive acquisitions.

“Unconventional resources” references the different manner by which they are exploited as compared to the extraction of conventional resources. In unconventional drilling, the wellbore is generally drilled to specific objectives within narrow parameters, often across long, lateral intervals within narrow horizontal formations offering greater contact area with the producing formation. Typically, the well is then hydraulically fractured at multiple stages to optimize production. Our completion and production services division provides pressure pumping services, pressure control services, flowback services and equipment rental, and also produces and sells 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 remote accommodation division provides housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We believe that these services play a critical role in increasing the ultimate recovery and present value of production streams from unconventional resources. Our complementary suite of drilling and completion and production related services provides us with the opportunity to cross-sell our services and expand our customer base and geographic positioning.

Our facilities and service centers are strategically located in Ohio, Oklahoma, Wisconsin, Minnesota, Pennsylvania, Texas and Alberta, Canada primarily to serve the following resource plays:

 

    The Utica Shale in Eastern Ohio;

 

    The Permian Basin in West Texas;

 

    The Appalachian Basin in the Northeast;

 

    The Arkoma Basin in Arkansas and Oklahoma;

 

    The Anadarko Basin in Oklahoma;

 

    The Marcellus Shale in West Virginia and Pennsylvania;

 

    The Granite Wash and Mississippi Shale in Oklahoma and Texas;

 

    The Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma;

 

    The Gulf Coast of Louisiana; and

 

    The oil sands in Alberta, Canada.

Our operational division heads have an average of over 26 years of oilfield service experience and bring valuable basin-level expertise and long-term customer relationships to our business. We provide our completion and production and contract and directional drilling services to a diversified range of both public and private independent producers. Our top five customers for the year ended December 31, 2013, representing 58.8% of our revenue, on a pro forma basis, were Gulfport, Diamondback Energy, Inc., Grizzly Oil Sands ULC, Apache Corporation and JAMEX, Inc. Our top five customers for the six months ended June 30, 2014, representing 54.3% of our revenue on a pro forma basis, were Gulfport, Breitburn Operating LP, J. Cleo Thompson, RSP Permian LLC and Apache Corporation.

 

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We commenced our operations in October 2007 with the acquisition of the assets of Sand Tiger. We have since grown organically and through acquisitions by focusing on the increasing needs of producers in unconventional resource plays. Further information regarding our growth is provided below under “—Our Services.” After giving pro forma effect to the Stingray Contribution and Drilling Transaction, we had $238.9 million of revenue, a $7.8 million net loss and $34.7 million of Adjusted EBITDA for the year ended December 31, 2013 and $168.5 million of revenue, a $1.0 million net loss and $25.8 million of Adjusted EBITDA for the six months ended June 30, 2014. For a definition of Adjusted EBITDA, a reconciliation of Adjusted EBITDA to net income (loss), the most closely comparable financial measure calculated in accordance with GAAP, and a discussion of Adjusted EBITDA as a performance measure, please see “Selected Historical Combined Financial Data” and “Pro Forma Financial Information.”

Our Services

We manage our business through three operating divisions: completion and production services, contract and directional drilling services and remote accommodation services.

Completion and Production Services

Our completion and production business provides pressure pumping, pressure control services, flowback services and equipment rental, as well as production and sales of proppant for hydraulic fracturing.

Pressure Pumping. Our pressure pumping services consist of hydraulic fracturing and well cementing services. These services are intended to optimize hydrocarbon flow paths during the completion phase of horizontal shale wellbores. Currently, we provide pressure pumping services in the Appalachian Basin in the Northeast. Our pressure pumping services include the following:

 

    Hydraulic Fracturing. We provide high-pressure hydraulic fracturing services. Fracturing services are performed to enhance the production of oil and natural gas from formations having low permeability such that the flow of hydrocarbons is restricted. We have significant expertise in multi-stage fracturing of horizontal oil- and natural gas-producing wells in shale and other unconventional geological formations.

The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, in our case primarily sand or ceramic beads, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or loosen viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures created, thereby increasing the mobility of the hydrocarbons. As a result of the fracturing process, production rates are usually enhanced substantially, thus increasing the rate of return for the operator.

We own and operate fleets of mobile hydraulic fracturing units and other auxiliary heavy equipment to perform fracturing services. Our hydraulic fracturing units consist primarily of a high pressure hydraulic pump, a diesel engine, a transmission and various hoses, valves, tanks and other supporting equipment that are typically mounted to a flat-bed trailer. As of September 1, 2014, we owned a total of 52 high-pressure fracturing units capable of delivering a total of 117,000 horsepower. We refer to the group of fracturing units, other equipment and vehicles necessary to perform a typical fracturing job as a “fleet” and the personnel assigned to each fleet as a “crew.” In areas in which we operate on a 24-hour-per-day basis, we typically staff three crews per fleet. All of our fracturing units and high pressure pumps are manufactured to our specifications to enhance the performance and durability of our equipment and meet our customers’ needs.

Each hydraulic fracturing fleet includes a mobile, on-site control center that monitors pressures, rates and volumes, as applicable. From there, our field-level managers supervise the job-site by radio. Each control center is equipped with high bandwidth satellite hardware that provides continuous upload and download of job telemetry data. The data is delivered on a real-time basis to on-site job personnel, the operator and an assigned coordinator at our headquarters for display in both digital and graphical form.

 

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An important element of fracturing services is determining the proper fracturing fluid, proppants and injection program to maximize results. In virtually all of our hydraulic fracturing jobs, our customers specify the composition of the fracturing fluid to be used. The fracturing fluid may contain hazardous substances, such as hydrochloric acid and certain petrochemicals. Our customers are responsible for the disposal of the fracturing fluid that flows back out of the well as waste water. The customers remove the water from the well using a controlled flow-back process, and we are not involved in that process or in the disposal of the fluid.

Pressure Control. Our pressure control services consist of coiled tubing, nitrogen and fluid pumping services. Our pressure control services equipment is designed to support drilling activities in unconventional resource plays with the ability to operate under high pressures without having to delay or cease production during completion operations. Ceasing or suppressing production during the completion phase of an unconventional well could result in formation damage impacting the overall recovery of reserves. Our pressure control services help operators minimize the risk of such damage during completion activities. Currently, we provide pressure control services in Cana Woodford and Woodford Shales and the Cleveland Sand in Oklahoma, the Granite Wash and Mississippi Shale in Oklahoma and Texas, the Utica Shale in Ohio and the Permian Basin in West Texas. Our pressure control services include the following:

 

    Coiled Tubing Services. Coiled tubing services involve injecting coiled tubing into wells to perform various well-servicing and workover operations. Coiled tubing is a flexible steel pipe with a diameter of typically less than three inches and manufactured in continuous lengths of thousands of feet. It is wound or coiled on a truck-mounted reel for onshore applications. Due to its small diameter, coiled tubing can be inserted into existing production tubing and used to perform a variety of services to enhance the flow of oil or natural gas without using a larger, more costly workover rig. The principal advantages of using coiled tubing in a workover include the ability to (i) continue production from the well without interruption, thus reducing the risk of formation damage, (ii) move continuous coiled tubing in and out of a well significantly faster than conventional pipe in the case of a workover rig, which must be jointed and unjointed, (iii) direct fluids into a wellbore with more precision, allowing for improved stimulation fluid placement, (iv) provide a source of energy to power a downhole mud motor or manipulate down-hole tools and (v) enhance access to remote fields due to the smaller size and mobility of a coiled tubing unit. As of September 1, 2014, we had five coiled tubing units capable of running over 21,000 feet of two inch coil rated at 10,000 pounds per square inch, or psi, service, which we believe is well suited for performance requirements of the unconventional resource markets we serve. The average age of these units was less than three years at September 1, 2014 with the deep service unit being a 2009 model.

 

    Nitrogen Services. Nitrogen services involve the use of nitrogen, an inert gas, in various pressure pumping operations. When provided as a stand-alone service, nitrogen is used in displacing fluids in various oilfield applications. As of September 1, 2014, we had a total of four nitrogen pumping units capable of pumping at a rate of up to 3,000 standard cubic feet per minute with pressures up to 15,000 psi. Pumping at these rates and pressures is typically required for the unconventional oil and natural gas resource plays we serve. The average age of these units was less than three years at September 1, 2014.

 

    Fluid Pumping Services. Fluid pumping services consist of maintaining well pressure, pumping down wireline tools, assisting coiled tubing units and the removal of fluids and solids from the wellbore for clean-out operations. As of September 1, 2014, we had nine fluid pumping units with an average age of less than two years. Of these, four were coiled tubing double pump units capable of output of up to 13 barrels per minute, and are rated to a maximum of 15,000 psi service and four were quintuplex wireline pump down units capable of output of up to 20 barrels per minute, and are rated to a maximum of 15,000 psi service.

Flowback. Our flowback services consist of production testing, solids control, hydrostatic testing and torque services. Flowback involves the process of allowing fluids to flow from the well following a treatment, either in

 

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preparation for an impending phase of treatment or to return the well to production. Our flowback equipment consists of manifolds, accumulators, valves, flare stacks and other associated equipment that combine to form up to a total of seven well-testing spreads. We provide flowback services in the Appalachian Basin, the Permian Basin and mid-continent markets.

 

    Production Testing. Production testing focuses on testing production potential. Key measurements are recorded to determine activity both above and below ground. Production testing and the knowledge it provides help our customers determine where they can more efficiently deploy capital. As of September 1, 2014, we had five production testing packages.

 

    Solids Control. Solids control services provide prepared drilling fluids for drilling rigs with equipment such as sand separators and plug catchers. These services reduce costs throughout the entire drilling process. As of September 1, 2014, we had 12 solids control packages.

 

    Hydrostatic Testing. Hydrostatic testing is a procedure in which pressure vessels, such as pipelines, are tested for damage or leaks. This method of testing helps maintain safety standards and increases the durability of the pipeline. We employ hydrostatic testing at industry standards and to a customer’s desired specifications and configuration. As of September 1, 2014, we had two hydrostatic testing packages.

 

    Torque Services. Torque refers to the force applied to a rotary device to make it rotate. We offer a comprehensive range of torque services, offering a customer the dual benefit of reducing costs on the rig as well as reducing hazards for both personnel and equipment. We had five torque service packages as of September 1, 2014.

Equipment Rentals. Our equipment rental services provide a wide range of rental equipment used in flowback and hydraulic fracturing services. Our equipment rentals consist of light plants and other oilfield related equipment. We provide equipment rental services in the Appalachian Basin, Permian Basin and mid-continent markets.

Proppant Production and Sales. In our proppant production and sales business, we process raw sand into premium monocrystalline natural sand proppant, also known as frac sand, which is the most widely used type of proppant due to its broad applicability in unconventional oil and natural gas wells and its cost advantage relative to other proppants. Natural frac sand may be used as proppant in all but the highest pressure and temperature drilling environments and is being employed in nearly all major U.S. unconventional oil and natural gas producing basins, including those in which we operate. Industry estimates that the total domestic proppant market is projected to grow 11% annually through 2017. We buy raw sand from third party suppliers under fixed-price contracts, process it into premium monocrystalline sand at our indoor sand processing plant located in Pierce County, Wisconsin. We collaborate with our customers to develop products to help them optimize production from unconventional wells. We start by producing a majority of the standard proppant sizes as defined by the ISO/API 13503-2 specifications. These grain sizes can be customized to meet the demands of a specific well. Our supply of superior Jordan substrate exhibits the physical properties necessary to withstand the environments of completion and production of the wells in North American shale basins. Our indoor processing plant (which we own and operate) is designed for year-round continuous wet and dry plant operation capable of producing a wide variety of frac sand products based on the needs of our customers.

We also provide logistics solutions to facilitate delivery of our frac sand products to our customers. Our logistics capabilities in this regard are important to our customers, who focus on both the reliability and flexibility of product delivery. Because our customers generally find it impractical to store frac sand in large quantities near their job sites, they typically prefer product to be delivered where and as needed, which requires predictable and efficient loading and shipping capabilities. We contract with third party providers to transport our frac sand products to railroad facilities for delivery to our customers. We currently lease or have access to origin transloading facilities on the Canadian National Railway Company (CN), Union Pacific (UP), Burlington Northern Santa Fe (BNSF) and the Canadian Pacific (CP) rail systems and use an in-house railcar fleet that we lease from various third parties to deliver our frac sand products to our customers. Origin transloading facilities

 

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on multiple railways allow us to provide predictable and efficient loading and shipping of our frac sand products. We also utilize a destination transloading facility in Cadiz, Ohio, which is operated by one of our affiliates, to serve the Utica Shale, and utilize destination transloading facilities located in some of North America’s other prolific resource plays, including the Permian Basin and Bakken Shale, to meet our customers’ delivery needs.

Master Services Agreements. We contract with most of our completion and production customers under master service agreements, or MSAs. Generally, under our MSAs, including those relating to our hydraulic fracturing services, we assume responsibility for, including control and removal of, pollution or contamination which originates above surface and originates from our equipment or services. However, our customer assumes responsibility for, including control and removal of, all other pollution or contamination which may occur during operations, including that which may result from seepage or any other uncontrolled flow of drilling fluids. We may have liability in such cases if we are negligent or commit willful acts which cause such events. Generally, our customers also agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that, in the case of our hydraulic fracturing operations, their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation of risk, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

Contract and Directional Drilling Services

Our contract and directional drilling business provides contract drilling and directional drilling services.

Contract Drilling. As part of our contract drilling services, we provide both vertical and horizontal drilling services to our customers. Currently, we perform our contract drilling services in the Permian Basin of West Texas. Our top five customers for the contract drilling services for the year ended December 31, 2013 were Diamondback Energy E&P, LLC, JAMEX, Inc., EXL Petroleum, LP, Red Willow Production, LLC and Cambrian Management, LTD. For the six months ended June 30, 2014, the top five customers for the contract drilling services were Breitburn Operating LP, J. Cleo Thompson, RSP Permian LLC, Capitan Energy and Hibernia Resources LLC.

A majority of the wells we drill for our customers are drilled in unconventional basins or resource plays. These plays are generally characterized by complex geologic formations that often require higher horsepower, premium rigs and experienced crews to reach targeted depths. As of September 1, 2014, we owned and operated 14 land drilling rigs, ranging from 800 to 1,600 horsepower, 11 of which are specifically designed for drilling horizontal and directional wells, which are increasing as a percentage of total wells drilled in North America and are frequently utilized in unconventional resource plays. As of September 1, 2014, 13 of our 14 drilling rigs were operating under term contracts with a term of more than one well or a stated period of time. To facilitate the provision of our contract drilling services, as of September 1, 2014, we also owned 32 trucks specifically tailored to move rigs and two cranes to assist us in moving rigs in the Permian Basin. As part of our contract drilling services we also provide pipe inspection services.

A land drilling rig generally consists of engines, a hoisting system, a rotating system, a drawworks, a mast, pumps and related equipment to circulate the drilling fluid under various pressures, blowout preventers, drill string and related equipment. The engines power the different pieces of equipment, including a rotary table or top drive that turns the drill pipe, or drill string, causing the drill bit to bore through the subsurface rock layers.

 

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Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a drilling line, a traveling block and hook assembly and ancillary equipment that attaches to the rotating system, a mechanism known as the drawworks. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydromatic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.

The rotating equipment from top to bottom consists of a swivel, the kelly bushing, the kelly, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the swivel and the drill bit as the drill stem. The swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drill bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.

Drilling fluid, often called drilling mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.

There are numerous factors that differentiate drilling rigs, including their power generation systems, horsepower, maximum drilling depth and horizontal drilling capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well.

Our drilling rigs, including the five electric horizontal drilling rigs acquired in January 2014, have rated maximum depth capabilities ranging from 12,500 feet to 20,000 feet. Of these drilling rigs, six are electric rigs and seven are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the

 

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power from its generators (which in the case of mechanical rigs, power the rig directly) into electricity to power the rig. Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job. Power requirements for drilling jobs may vary considerably, but most of our mechanical drilling rigs employ six engines to generate between 400 and 1,700 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations drill to measured depths greater than 10,000 to 18,000 feet. Generally, land rigs operate with four crews of five people and two tool pushers, or rig managers, rotating on a weekly or bi-weekly schedule.

We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs.

We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. We typically enter into drilling contracts that provide for compensation on a daywork basis. Occasionally, we enter into drilling contracts that provide for compensation on a footage basis, however, a majority of such footage drilling contracts also provide for daywork rates for work outside core drilling activities contemplated by such footage contracts and under certain other circumstances. We have not historically entered into turnkey contracts; however, we may decide to enter into such contracts in the future. It is also possible that we may acquire such contracts in connection with future acquisitions of drilling assets. Contract terms we offer generally depend on the complexity and risk of operations, t