As filed with the Securities and Exchange Commission on October 14, 2014

Registration No. 333-198894

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

AMENDMENT NO. 1

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Mammoth Energy Partners LP

(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 73142

(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 73142

(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):

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 and previously paid.

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.

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 October 14, 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:

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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.

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

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

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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.

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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.

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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.

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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


	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		72

SELECTED HISTORICAL COMBINED FINANCIAL DATA		73

PRO FORMA FINANCIAL INFORMATION		76

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		81

BUSINESS		100

MANAGEMENT		124

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		132

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		140

PRINCIPAL AND SELLING UNITHOLDERS		147

DESCRIPTION OF OUR COMMON UNITS		149

THE PARTNERSHIP AGREEMENT		151

UNITS ELIGIBLE FOR FUTURE SALE		164

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES		166

INVESTMENT IN MAMMOTH ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS		179

UNDERWRITING		181

LEGAL MATTERS		186

EXPERTS		186

WHERE YOU CAN FIND MORE INFORMATION		186

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

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.

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 and 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, Sand Tiger Holdings Inc. and Dunvegan North Oilfield Services, ULC will be contributed to us by Mammoth Energy Holdings LLC, or Mammoth Holdings, an entity controlled by Wexford, Gulfport Energy Corporation (NASDAQ: GPOR), or Gulfport, and Rhino Resource Partners LP (NYSE: RNO), or Rhino, in return for common units and, as a result, will become our wholly owned subsidiaries. Sand Tiger Holdings Inc. (which when referred to in this prospectus includes its predecessor 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 Sand Tiger Holdings Inc. 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 Mammoth Holdings 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, together with White Wing, Sand Tiger Holdings Inc. and Dunvegan North Oilfield Services, ULC. 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.

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. We have contracted to purchase eight additional high-pressure fracturing units, which are expected to be delivered by October 31, 2014 and will increase the total number of high-pressure fracturing units we own to 60. 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 and Marcellus Shale in West Virginia.

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.

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 and an inventory of related parts and equipment. Subsequent to September 1, 2014, we acquired 14 additional mud motors. 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 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:

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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.

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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.

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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.

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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.

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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.

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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 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.

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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.

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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:

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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.

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our business lines as demand increases in resource plays in which we currently operate, as well as in 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.

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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.

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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.

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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:

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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.

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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.

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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 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.

•

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 beneficially 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.”

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 Mammoth Holdings, an entity controlled 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, Mammoth Holdings 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 the one member of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement we expect to enter into with Gulfport 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 beneficial ownership of our general partner and Gulfport’s right to appoint one director, 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.

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

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, Mammoth Energy 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

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.

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

(a)

Our 100% interest in Sand Tiger is held indirectly through two holding companies, Sand Tiger Holdings Inc. and Dunvegan North Oilfield Services, ULC. Through its holding companies, Sand Tiger will be treated as a corporation for U.S. federal income tax purposes and is subject to Canadian income taxes.

(b)

The remaining approximately 6.0% interest in Muskie Proppant is owned by Rhino. Immediately prior to the closing of this offering. Rhino will contribute its interest in Muskie Proppant to us in return for common units representing less than 1% of our common units outstanding prior to this offering. Rhino is a New York Stock Exchange - listed limited partnership. Rhino’s general partner is an affiliate of Wexford.

(c)	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 73142, 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.

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 expansion capital expenditures 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

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 $27.4 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 $41.8 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

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 $87.8 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

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.

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.


	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


	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)

(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.

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

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.

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.

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

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:

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

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

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

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

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the expected decline rates of current production;

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the price of foreign imports;

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

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

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speculative trading in crude oil and natural gas derivative contracts;

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the level of consumer product demand;

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the discovery rates of new oil and natural gas reserves;

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contractions in the credit market;

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available pipeline and other transportation capacity;

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weather conditions and other natural disasters;

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political instability in oil and natural gas producing countries;

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domestic and foreign governmental approvals and regulatory requirements and conditions;

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

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technical advances affecting energy consumption;

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

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the price and availability of alternative fuels;

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

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

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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,

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:

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

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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:

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

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successfully integrate additional drilling rigs;

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

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successfully deploy idle, stacked or additional drilling rigs;

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maintain crews necessary to operate additional drilling rigs; or

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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.

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 Pierce 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. 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.

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. 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 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 Chairman, President and Chief Financial 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.

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:

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curtailment of services;

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

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weather-related damage to our facilities;

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

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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.

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 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:

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

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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;

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

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inability to commercially develop acquired technologies;

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

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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.

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:

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

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

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

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shortages of water used in our hydraulic fracturing operations;

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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

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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:

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increasing our vulnerability to general adverse economic and industry conditions;

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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;

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

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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;

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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

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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:

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incurring additional indebtedness;

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paying distributions;

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creating certain additional liens on our assets;

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entering into sale and leaseback transactions;

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making investments;

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entering into transactions with affiliates;

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

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making guarantees;

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disposing of assets in excess of certain permitted amounts;

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merging or consolidating with other entities; and

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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.

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.

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.

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.

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.

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.

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.

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.

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.

The operational insurance coverage we maintain for our business may not fully insure us 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 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.

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:

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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.

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

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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.

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

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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.

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

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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.

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

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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.

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

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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.”

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 expansion 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:

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how to allocate business opportunities among us and its affiliates;

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whether to exercise its call right;

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

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whether to exercise its registration rights; and

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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:

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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;

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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

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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.

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.

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.”

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:

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

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

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the ratio of our taxable income to distributions may increase;

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

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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.

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.”

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 $3.5 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

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:

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our quarterly or annual operating results;

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changes in our earnings estimates;

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

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additions or departures of key personnel;

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

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

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changes in industry, general market or economic conditions; and

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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

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.

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.

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.”

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

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.

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.

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
September 2014 Panther Drilling 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.

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)

(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.

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 Holdings, Rhino 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.

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 expansion capital expenditures 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.

•

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 $27.4 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 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 $41.8 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, 2014 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 had we been formed and completed the transactions contemplated by this prospectus on January 1, 2013 and July 1, 2013, respectively. 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	$	238,867		$	299,692
Expenses:
Cost of revenue, excluding depreciation, amortization and impairment	$	189,549		$	243,834
Selling, general and administrative expenses⁽¹⁾		18,675			20,145
Depreciation and amortization		33,822			42,538
Impairment of long-lived assets		938			938
Interest expense, net		4,238			5,320
Other (income) expense, net		215			676
Provision for income taxes		2,715			2,357

Net income (loss)	$	(11,285	)	$	(16,116	)

Adjustments to reconcile net income (loss) to Adjusted EBITDA⁽²⁾:
Add:
Depreciation and amortization	$	33,822		$	42,538
Impairment of long-lived assets		938			938
Equity based compensation		518			531
Interest expense, net		4,238			5,320
Other (income) expense, net		215			676
Provision for income taxes		2,715			2,357

Adjusted EBITDA	$	31,161		$	36,244


	Year Ended December 31, 2013			Twelve Months Ended June 30, 2014
	(in thousands, except per unit data)
Less:
Cash interest expense	$	4,238		$	5,320
Provision for income taxes		2,715			2,357
Expansion and maintenance capital expenditures⁽³⁾		112,571			175,176
Net working capital⁽⁴⁾		(3,472	)		(13,735	)
Other (income) expense, net		295			486
Add:
Funding for expansion and maintenance capital expenditures⁽⁵⁾		112,571			175,176

Unaudited pro forma cash available for distribution	$	27,385		$	41,816

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)	$	27,385		$	41,816


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)	$	27,385		$	41,816

(1)

Includes $3.5 million of estimated incremental annual cash expense associated with being a publicly traded partnership, including $3.0 million of incremental selling, general and administrative expenses and an annual fee of $500,000 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. We did not differentiate between expansion capital expenditures and maintenance capital expenditures during the periods presented.

(4)	Net working capital reflects the period-over-period change in operating cash flow.

(5)	Funding for expansion and maintenance capital expenditures came primarily from borrowings under our revolving credit facilities and term loans, capital contributions and cash generated by operations.

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 approximately $87.8 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 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 approximately $87.8 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.

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	$	114,240		$	128,459		$	145,619		$	155,471		$	543,789
Expenses:
Cost of revenue, excluding depreciation, amortization and impairment	$	82,421		$	93,096		$	106,319		$	112,468		$	394,305
Selling, general and administrative expenses⁽¹⁾		5,188			5,011			5,093			5,158			20,450
Depreciation and amortization		14,513			16,138			17,635			17,908			66,194
Impairment of long-lived assets		—			—			—			—			—
Interest expense, net⁽²⁾		906			371			688			826			2,791
Other (income) expense, net		—			—			—			—			—
Provision for income taxes		594			1,097			810			751			3,252

Net income (loss)	$	10,618		$	12,746		$	15,074		$	18,360		$	56,798

Adjustments to reconcile net income (loss) to Adjusted EBITDA⁽³⁾:
Add:
Depreciation and amortization	$	14,513		$	16,138		$	17,635		$	17,908		$	66,194
Impairment of long-lived assets		—			—			—			—			—
Equity based compensation		—			—			—			—			—
Interest expense, net		906			371			688			826			2,791
Other (income) expense, net		—			—			—			—			—
Provision for income taxes		594			1,097			810			751			3,252

Adjusted EBITDA	$	26,631		$	30,352		$	34,207		$	37,845		$	129,035

Less:
Cash interest expense	$	906		$	371		$	688		$	826		$	2,791
Provision for income taxes		594			1,097			810			751			3,252
Maintenance capital expenditures⁽⁴⁾		7,035			7,998			8,445			8,535			32,013
Expansion capital expenditures		34,167			47,315			23,465			2,275			107,222
Net working capital⁽⁵⁾		5,647			(3,348	)		1,251			668			4,218
Other (income) expense, net ⁽⁶⁾		(252	)		(247	)		(249	)		(252	)		(1,000	)
Add:
Funding for expansion capital expenditures⁽⁷⁾		34,167			47,315			23,465			2,275			107,222

Estimated cash available for distribution	$	12,701		$	24,481		$	23,262		$	27,317		$	87,761

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)	$	12,701		$	24,481		$	23,262		$	27,317		$	87,761

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)	$	12,701		$	24,481		$	23,262		$	27,317		$	87,761

(1)

(2)	Assumes average borrowings of $59.5 million at an interest rate of LIBOR plus 2.75% under a new revolving credit facility we intend to enter into 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)	Net working capital reflects the period-over-period change in operating cash flow.

(6)	Includes additional assumed contributions from investment and asset sales.

(7)	We expect to fund these expansion capital expenditures primarily with funds generated from our operations and borrowings under our new revolving credit facility.

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 twelve months 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.

Operations and Revenues. We estimate that our total revenues for the twelve months ending September 30, 2015 will be approximately $543.8 million as compared to our pro forma total revenues of approximately $299.7 million for the twelve months ended June 30, 2014 and $238.9 million for the year ended December 31, 2013. Our forecast of total revenues is based on the following assumptions by operating division:

Completion and Production Services. Our completion and production services division includes our pressure control and well services, pressure pumping services, flow back services and our proppant production and sales business. We estimate that our total completion and production services division revenue for the twelve months ending September 30, 2015 will be approximately $362.0 million as compared to approximately $179.5 million for the twelve months ended June 30, 2014 and approximately $120.9 million for the year ended December 31, 2013, on a pro forma basis. In general, we believe that this

increase will be attributable to increased utilization of equipment purchased in 2013 and 2014, contributions from additional equipment intended to be purchased in 2014 and 2015 and our contracted income associated with our pressure pumping and sand contracts with Gulfport that were effective October 1, 2014.

Pressure Control and Well Services. In our pressure control services business, we anticipate generating revenue of approximately $48.6 million for the twelve months ending September 30, 2015 as compared to revenue of approximately $25.8 million for the twelve months ended June 30, 2014 and approximately $18.3 million for the year ended December 31, 2013, on a pro forma basis. We experienced lower utilization rates in 2013 and the first half of 2014 while additional coil tubing units and other equipment purchased during those periods were being placed into service. As of September 1, 2014, we had five coiled tubing units, with an average age of less than three years, capable of running over 21,000 feet of two inch coil rated at 10,000 psi in service, which we believe are well suited for the performance requirements of the unconventional resource markets we serve in the Permian Basin and Midcontinent region. Since this additional equipment was placed into service, the utilization rates of our pressure control equipment have steadily increased and are expected to remain at the current more elevated levels given the increasing demand for coil tubing services. We intend to acquire and place into service three additional coil tubing units and other coil tubing equipment during the twelve months ending September 30, 2015 at a cost of approximately $15.7 million supporting our expansion into West Texas. We expect rising utilization as new equipment suited to the Permian Basin is delivered given the strong drilling demand in that market.

We made significant investments during 2013 and the first half of 2014 in our fluid pumping equipment, adding nine additional pump down spreads in total. As of September 1, 2014, we had nine fluid pumping units with an average age of less than two years. We intend to acquire and place into service seven additional pump down spreads during the twelve months ending September 30, 2015 at an estimated cost of approximately $10.6 million, which are expected to be placed into service in the first and second quarters of 2015.

Pressure Pumping Services. In our pressure pumping services business, we anticipate generating revenue of approximately $224.1 million for the twelve months ending September 30, 2015 as compared to approximately $117.0 million for the twelve months ended June 30, 2014 and approximately $82.5 million for the year ended December 31, 2013, on a pro forma basis. As of September 1, 2014, we owned a total of 52 high-pressure fracturing (pumping) units, grouped into three fleets or “spreads,” capable of delivering a total of 117,000 horsepower. We have contracted to purchase eight additional high-pressure fracturing units with expected delivery by October 31, 2014, which will bring our fleet to 20 units per spread. For our existing three fracturing fleets, we anticipate higher utilization levels and day rates supported by a multi-year take or pay contract for two of the three fracturing spreads as well as increased utilization from our third spread, which was brought online in early 2014. Our multi-year take or pay contract includes a monthly service fee paid for each of the two spreads. Additionally, we intend to add an additional fracturing spread fleet comprised of 20 high-pressure fracturing units in 2015 with expected delivery in April 2015 at a cost of approximately $33.0 million.

Flowback Services. In our flowback services business, we anticipate generating revenue of approximately $27.2 million for the twelve months ending September 30, 2015 as compared to approximately $13.9 million for the twelve months ended June 30, 2014 and approximately $11.6 million for the year ended December 31, 2013, on a pro forma basis. As of September 1, 2014, we had five production testing packages, 12 solids control packages, two hydrostatic testing packages and five torque services packages as well as other flowback equipment to form up to a total of seven well-testing spreads. In anticipation of increased activity in the basins we serve, we intend to add additional production testing, solids control and rental equipment during the second and third quarters of 2015 at a cost of approximately $8.2 million.

Proppant Production and Sales. In our proppant production and sales business, we anticipate generating revenue of approximately $62.1 million for the twelve months ending September 30, 2015 as compared to approximately $22.8 million for the twelve months ended June 30, 2014 and approximately $8.5 million for the year ended December 31, 2013, on a pro forma basis. In our proppant production and

sales business, we anticipate selling approximately 535,000 tons of proppant at an average price per ton of approximately $116 as compared to approximately 337,000 tons at an average price per ton of $102 for the twelve months ended June 30, 2014 and approximately 166,000 tons at an average price per ton of $119 for the year ended December 31, 2013. We currently have three long-term sales contracts (one-year and multi-year in nature) that that we expect will account for approximately 67% of our forecasted proppant sales revenue for the twelve months ending September 30, 2015. Additionally, the upward pricing trends in the spot market and our intention to sell excess non-contracted sand in the spot market contribute to our revenue forecast. Underpinning our higher forecasted revenues are certain equipment upgrades and additions that we made in September 2014, enabling us to increase our production of sand in excess of 600,000 tons per year on an annualized basis.

Contract Land and Directional Drilling Services. We estimate that our total contract land and directional drilling services division revenue for the twelve months ending September 30, 2015 will be approximately $150.3 million as compared to approximately $98.5 million for the twelve months ended June 30, 2014 and approximately $92.9 million for the year ended December 31, 2013, on a pro forma basis. To provide our land drilling services, we expanded our land drilling rig fleet from eight to 14 rigs in 2014 and currently anticipate adding one additional rig to our fleet in mid-2015 at a cost of approximate $17.5 million. Of the six new land drilling rigs in 2014, five were placed in service in February 2014 after having been acquired in January 2014 from Lantern Drilling. The sixth rig was acquired in June 2014 and is now contracted and to be placed in service in October 2014. As of September 1, 2014, we had 13 drilling rigs operating under term contracts with a term of more than one well and an average duration of approximately seven months. To provide our directional drilling services, we own seven MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 56 mud motors and an inventory of related parts and equipment. Overall, in our contract land and directional drilling services division, we expect utilization levels to continue to rise due to strong demand in the Permian Basin. Based on the current rig market in the Permian Basin, we believe current day rates are in excess of our current contracts, supporting an increase pricing as contracts are renewed. As a result, in our land drilling services, we anticipate extending the terms of our existing contracts at the then current market prices.

Remote Accommodation Services. We estimate that our remote accommodation services division revenue for the twelve months ending September 30, 2015 will be approximately $31.5 million as compared to approximately $21.7 million for the twelve months ended June 30, 2014 and approximately $25.0 million for the year ended December 31, 2013, on a pro forma basis. We believe that this increase will be attributable to increased utilization of available room nights and additional available rooms, approximately 68% of which are contracted during the twelve months ending September 30, 2015. As of September 1, 2014, we had 700 rooms and we plan to have a total of 890 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. The new rooms have been ordered and are expected to be in service in December 2014.

Cost of Revenues (Excluding Depreciation, Amortization and Impairment). We estimate that our total cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $394.3 million as compared to approximately $243.8 million for the twelve months ended June 30, 2014 and approximately $189.5 million for the year ended December 31, 2013, on a pro forma basis. Our forecast of cost of revenues (excluding depreciation, amortization and impairment) is based on the following assumptions by operating division:

Completion and Production Services. We estimate that our completion and production services division cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $276.1 million as compared to approximately $149.1 million for the twelve months ended June 30, 2014 and approximately $101.9 million for the year ended December 31, 2013, on a pro forma basis. Our completion and production services cost of revenues consists of labor expenses, utility and fuel costs, repairs and maintenance expenses, and health, safety and environmental related costs, among others. The majority of the increase is attributable to the increase in

forecasted revenue as our variable costs scale in line with forecasted revenue. A small portion of the cost increase is expected to result from contractual price increases in our vendor contracts and our assumption that non-contracted costs will rise in line with historical inflation averages.

Contract Land and Directional Drilling Services. We estimate that our contract land and directional drilling services division cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $104.3 million as compared to approximately $85.2 million for the twelve months ended June 30, 2014 and approximately $76.2 million for the year ended December 31, 2013, on a pro forma basis. Our contract land and directional drilling services cost of revenues consists of labor expenses, utility and fuel costs, repairs and maintenance expenses, and health, safety and environmental related costs, among others. The majority of the increase is attributable to the increase in forecasted revenue as our variable costs scale in line with forecasted revenue with some of the costs being passed through to customers. A small portion of the cost increase is expected to result from contractual price increases in our vendor contracts and our assumption that non-contracted costs will rise in line with historical inflation averages.

Remote Accommodation Services. We estimate that our remote accommodation services division cost of revenues (excluding depreciation, amortization and impairment) for the twelve months ending September 30, 2015 will be approximately $13.9 million as compared to approximately $9.5 million for the twelve months ended June 30, 2014 and approximately $11.4 million for the year ended December 31, 2013, on a pro forma basis. Our remote accommodation services cost of revenues consists of labor expenses, utility and fuel costs, repairs and maintenance expenses, and health, safety and environmental related costs, among others. The majority of the increase is attributable to the increase in forecasted revenue as our variable costs scale in line with forecasted revenue. A small portion of the cost increase is expected to result from contractual price increases in our vendor contracts and our assumption that non-contracted costs will rise in line with historical inflation averages.

Selling, General and Administrative Expenses. We estimate that our total selling, general and administrative expenses for the twelve months ending September 30, 2015 will be approximately $20.5 million as compared to approximately $20.1 million for the twelve months ended June 30, 2014 and approximately $18.7 million for the year ended December 31, 2013, on a pro forma basis. Each period includes $3.0 million of incremental selling, general and administrative expenses that we expect to incur annually as the result of being a publicly traded partnership and an annual fee of $500,000 pursuant to an advisory services agreement that we expect to enter into with Wexford at the closing of this offering. Please see “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.” In connection with this offering, we have added, and expect to continue to add, additional personnel to bolster our corporate functions to support our growing operations and public company obligations. Our estimate of selling, general and administrative expenses for the forecast period does not include any compensation expense that may be incurred in connection with the grant of awards pursuant to the equity incentive plan in connection with this offering. Any charge associated with the grant of such awards will be a non-cash expense. Please see “Management—Executive Compensation.”

Depreciation and Amortization. We estimate that our total depreciation and amortization for the twelve months ending September 30, 2015 will be approximately $66.2 million as compared to approximately $42.5 million for the twelve months ended June 30, 2014 and approximately $33.8 million for the year ended December 31, 2013, on a pro forma basis. We estimate the increase will be primarily attributable to higher depreciation expenses related to additional equipment and fixed assets to be placed into service in each of our operating divisions as described above under “—Operations and Revenues.”

Interest Expense. We estimate that our total interest expense for the twelve months ending September 30, 2015 will be approximately $2.9 million as compared to approximately $5.3 million for the twelve months ended June 30, 2014 and approximately $4.2 million for the year ended December 31, 2013, on a pro forma basis. We plan to fully repay all borrowings outstanding under our existing credit facilities with net proceeds from this offering and put in place a new credit facility that will be used for various purposes, including to fund our

equipment purchases and other organic growth projects. Accordingly, future changes in interest expense will be attributable to changes in borrowings during the forecast period to support our operations. Our new credit facility to be entered into in connection with this offering is expected to offer more competitive terms than our prior combination of divisional loans which are all being repaid and terminated upon the closing of this offering. We have assumed average borrowings of $59.5 million at an interest rate of LIBOR plus 2.75% under this new credit facility. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—New Revolving Credit Facility.”

Capital Expenditures. We estimate that our total capital expenditures will be $139.2 million for the twelve months ending September 30, 2015 as compared to approximately $175.2 million for the twelve months ended June 30, 2014 and approximately $112.6 million for the year ended December 31, 2013, on a pro forma basis. We estimate that our expansion capital expenditures and maintenance capital expenditures will be approximately $107.2 million and $32.0 million, respectively, for the twelve months ending September 30, 2015, compared to an aggregate expansion and maintenance capital expenditures of approximately $175.2 million for the twelve months ended June 30, 2014 and approximately $112.6 million for the year ended December 31, 2013, on a pro forma basis. We did not differentiate between expansion capital expenditures and maintenance capital expenditures during the twelve months ended June 30, 2014 or the year ended December 31, 2013. Substantially all of our growth capital expenditures during the forecast period are expected to be attributable to the additional equipment anticipated to be purchased as described above under “—Operations and Revenues.” We anticipate that approximately 79.0% of our total expansion capital expenditures during the forecast period will be attributable to our completion and production services division and that approximately 21% and 0% will be attributable to our contract land and directional drilling services division and our remote accommodations services division, respectively. After the closing of this offering, we expect to fund expansion capital expenditures with funds generated from our operations, borrowings under our anticipated new revolving credit facility and term loans and issuances of additional equity and debt securities. For purposes of this forecast, we have assumed that we will fund all of the forecasted expansion capital expenditures with borrowings under our anticipated new revolving credit facility. We anticipate that the majority of our maintenance capital expenditures will be spent on the replacement and refurbishment of equipment that becomes damaged due to the nature of operating in challenging environments and will be funded with cash from operations or borrowings under our new revolving credit facility. We anticipate that approximately 62% of our total maintenance capital expenditures during the forecast period will be attributable to our completion and production services division and that approximately 35% and 3% will be attributable to our contract land and directional drilling services division and our remote accommodations services division, respectively.

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 expansion capital expenditures are reflected (other than as described above);

•

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.

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.

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	)


	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)

(2)

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

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.

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			(b)
Other assets		8,036		639			(b)

Total assets	$	280,128	$	110,198	$			$

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			(c)

Total liabilities and unitholders’, shareholders’ and members’ equity	$	280,128	$	110,198	$			$

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	)(d)	$
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	)(d)
Contract land and directional drilling services		53,987			—			35,831			(13,602	)(e)
Remote accommodation services		11,416			—			—			—
Selling, general and administrative expenses		13,614			1,561			497			(497	)(e)
Depreciation and amortization		18,995			7,938			—			6,889	(e)
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	)(e)
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													$

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	)(f)	$
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			—			(4,916	)(f)
Contract land and directional drilling services		42,157			—			2,929			(244	)(g)
Remote accommodation services		4,165			—			—			—
Selling, general and administrative expenses		6,082			1,215			115			(115	)(g)
Depreciation and amortization		15,034			8,030			—			574	(g)
Impairment of long-lived assets		—			—			—			—

Total	$	103,471		$	64,160		$	3,044		$	(4,701	)	$

Operating income (loss)		2,419			687			(348	)		215
Interest expense		(1,864	)		(855	)		—			(94	)(g)
Other income (expense), net		(43	)		44			—			—

Income (loss) before income taxes		512			(124	)		(348	)		121
Provision for income taxes		1,059			—			—				(c)

Net income (loss)	$	(547	)	$	(124	)	$	(348	)	$	121		$

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													$

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.

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

(b)

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.

(c)	To record the effect of income taxes to reflect the domestication of Sand Tiger Holdings Inc. as a Delaware Corporation.

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

(e)

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.

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

(g)

To record adjustments in connection with the Drilling Transaction to: (i) reduce cost of revenue by $244 for operating lease rental expense under sublease agreements that were not assumed by Bison Drilling; (ii) reduce selling, general and administrative expenses by $115 for operational management fees charged by the former parent company of the acquired drilling rigs that will not be incurred by Bison Drilling; (iii) record $574 of depreciation expense in connection with the drilling rigs acquired; and (iv) record $94 of interest expense for the $25,000 of additional long-term debt issued to partially fund the Drilling Transaction.

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, Sand Tiger Holdings Inc. and Dunvegan North Oilfield Services, ULC will be contributed to us by Mammoth Holdings, Gulfport and Rhino in return for common units and, as a result, will become our wholly owned subsidiaries. Sand Tiger Holdings Inc. 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 Sand Tiger Holdings Inc. 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.

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.

•

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.

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

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 million, 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

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

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

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 expansion 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.

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.

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,

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 had an original maturity of October 9, 2014. In September 2014, the facility was extended and now has a maturity date of April 1, 2015. 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.

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. In September 2014, the term loan was amended to include another $2.5 million of principal. 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 September 25, 2015. 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 2.0%, 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 5.25%.

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, 2015, 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 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, provided 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 which, as amended, provides 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.

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.

In September 2014, Stingray Pressure Pumping amended the term loan agreement to receive funds for the purchase of additional equipment and bring the balance up to the original agreement capacity of $50.0 million.

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.

Panther Drilling Systems LLC

In September 2014, Panther Drilling, as borrower, entered into a loan and security agreements with Bank7, as lender, providing for a term loan in the principal amount of $4.0 million. The loan requires three months of interest only payments beginning October 2014. Principal and interest payments will then begin January 2015 for 35 months until the maturity date of December 8, 2017. The loan has an interest rate of 5.75%. The loan is secured by specified assets and contains customary covenants. Among these are (i) restrictions on the encumbrance of the borrower’s assets, (ii) requirements to provide certain financial statements to the lender on a regular basis, (iii) the requirement of a minimum quarterly EBITDA of $730,000 starting with the first quarter of 2015 and (iv) a minimum net worth requirement of $7.5 million.

New Revolving Credit Facility

In connection with this offering, we and our subsidiaries intend to enter into a $150.0 million senior secured revolving credit facility, which we refer to as the new credit facility, with PNC Capital Markets LLC, as lead arranger, PNC Bank, National Association, as the administrative and collateral agent, and the lenders from time-to-time party thereto, to, among other things, provide for ongoing working capital needs, including capital expenditures and fund general capital needs. Borrowings under the new credit facility will be secured by a first priority perfected security interest in all of our assets, and our direct and indirect domestic subsidiaries will guarantee our obligations under the facility.

The new credit facility will be available on a revolving basis during a five-year period commencing on the new credit facility’s closing date. Outstanding borrowings will bear interest, at our option, at a rate based on LIBOR plus 250, 275 or 300 basis points (depending on the percentage of maximum available credit then-available) or the base rate plus 150, 175 or 200 (depending on the percentage of maximum available credit then-available).

The new credit facility will contain customary negative covenants including, but not limited to, restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make certain investments, divest assets, effect fundamental changes (including mergers, consolidations and certain joint ventures), change the nature of our business, make restricted payments (including dividends), enter into swap contracts and forward sales contracts and enter into affiliate transactions. The negative covenants will be subject to certain exceptions, conditions and limitations as specified in the new credit facility.

The new credit facility also will contain certain affirmative covenants, including, but not limited to, affirmative covenants regarding periodic reports, payment of fees, conduct of business, maintenance of existence, payment of indebtedness, standards of financial statements, tax shelter regulations and federal securities laws. In addition, under the new credit facility, we will be subject to certain financial covenants, including, but not limited to, (i) a minimum interest coverage ratio, requiring us to maintain an interest coverage ratio of not less than 3.00:1.00 and (ii) a maximum leverage covenant prohibiting us (other than in certain limited circumstances) from having a ratio of funded debt to EBITDA of greater than 4.00:1.00 (increasing to 4.25:1.00 during a specified permitted acquisition period). The affirmative covenants and financial covenants will be subject to certain exceptions, conditions and limitations as specified in the new credit facility. The new credit facility also will contain customary indemnification obligations.

The lenders will be able to accelerate all of the indebtedness under the new credit facility upon the occurrence (and during the continuance of) any event of default. The new credit facility will contain customary events of default, including bankruptcy, non-payment, breach of covenants, change of control, materially incorrect representations and cross-default to other indebtedness. Generally, with the consent of lenders holding a majority of the outstanding loans or commitments to lend, we will be able to amend the terms and provisions of the new credit facility.

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 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 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.

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.

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.”

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.

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.

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:

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The Utica Shale in Eastern Ohio;

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The Permian Basin in West Texas;

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The Appalachian Basin in the Northeast;

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The Arkoma Basin in Arkansas and Oklahoma;

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The Anadarko Basin in Oklahoma;

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The Marcellus Shale in West Virginia and Pennsylvania;

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The Granite Wash and Mississippi Shale in Oklahoma and Texas;

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

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The Gulf Coast of Louisiana; and

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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:

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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 have contracted to purchase eight additional high-pressure fracturing units, which are expected to be delivered by October 31, 2014 and will increase the total number of high-pressure fracturing units we own to 60. 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:

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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, in service, which we believe are well suited for the 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.

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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.

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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.

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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.

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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.

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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.

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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, seven 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, the on-site drilling conditions, the type of equipment used, the anticipated duration of the work to be performed and market conditions. As of September 1, 2014, ten of our 14 drilling rigs were operating under term contracts that provide for a take-or-pay model where customers cannot terminate contracts without paying the full amount remaining, three were operating under contracts that allow the customer to terminate on 30 days’ notice, upon payment of an agreed upon fee, and the rig we acquired on September 1, 2014 was not yet in service.

Daywork Contracts. Under daywork drilling contracts, we provide equipment and labor and perform services under the direction, supervision and control of our customers. We are paid a specified operating daywork rate from the time the drilling unit is rigged up at the drilling location and is ready to commence operations. Additionally, the daywork drilling contracts typically provide for fees and/or a daywork rates for mobilization, demobilization, moving, standby time and for any continuous period that normal operations are suspended or cannot be carried on because of force majeure conditions. The daywork drilling contracts also generally provide that the customer has the right to designate the points at which casing will be set and the manner of setting, cementing and testing. Such specifications include hole size, casing size, weight, grade and approximate setting depth. Furthermore, the daywork drilling contracts specify the equipment, materials and services to be separately furnished by us and our customer. Under these contracts, liability is typically allocated so that our customer is solely responsible for the following: (i) damage to our surface equipment as a result of certain corrosive elements; (ii) damage to customer’s equipment; (iii) damage to our in-hole equipment; (iv) damage or loss to the hole; (v) damage to the underground; and (vi) costs and damages associated with a wild well. We remain responsible for any damage to our surface equipment (except for damage resulting from the presence of certain corrosive elements) and for pollution or contamination from spills of materials that originate above the surface, are wholly in our control and are directly associated with our equipment. Daywork drilling contracts generally allow the customer to terminate the contract prior to drilling to a specified depth. This right, however, is generally subject to early termination compensation, the amount of which depends on when the termination occurs.

Footage Contracts. Under footage contracts, the contractor is typically paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. A majority of these types of drilling contracts, however, contain both footage and daywork basis provisions, the applicability of which typically depends on the depth of drilling and/or the type of services being performed. For instance, when drilling occurs below a specified drilling depth or when work is considered outside the scope of the footage basis, which we refer to as core drilling, then daywork contract terms apply similar to those described above. Otherwise, the footage contract terms apply. These include a footage rate price that is a specific dollar amount per linear foot of

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hole drilled within the contract footage depth. Also, under the footage contract terms, we assume more responsibility for base drilling activities compared to daywork drilling. For instance, in addition to assuming responsibility for damage to our surface equipment and damage caused by certain pollution and contamination, we are responsible for the following: (i) damage to our in-hole equipment; (ii) damage to the hole that is attributable to our performance; and (iii) any costs or expenditures associated with drilling a new hole after such damage. Our customers remain responsible for any loss to their equipment, for any damage to a hole caused by them and for any underground damage. As with contracts for daywork drilling, footage drilling contracts generally allow the customer to terminate the contract before drilling to a specified depth. This right, however, is generally subject to early termination compensation, the amount of which depends on when the termination occurs.

Because we assume higher risk in a footage drilling contract, we typically pay more of the out-of-pocket costs associated with such contracts as compared to daywork contracts. We endeavor to manage these additional risks through the use of our engineering expertise and bid the footage contracts accordingly. We typically maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a negative impact on our profitability. While we have historically entered into few footage contracts, we may enter into more such arrangements in the future to the extent warranted by market conditions.

Turnkey Contracts. Turnkey contracts typically provide for a drilling company to drill a well for a customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. The drilling company would provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. The drilling company may subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, a drilling company would not receive progress payments and would be paid by its customer only after it had performed the terms of the drilling contract in full.

The risks to the drilling company under a turnkey contract are substantially greater than those under a daywork basis. This is primarily because under a turnkey contract, the drilling company assumes most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel.

Directional Drilling. 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. The evolution of unconventional resource reserve recovery has increased the need for the precise placement of a wellbore. Wellbores often travel across long-lateral intervals within narrow formations as thin as ten feet. 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. Currently, we perform our directional drilling services in the Appalachian Basin, Anadarko Basin, Arkoma Basin, Permian Basin and the Gulf Coast of Louisiana. For the year ended December 31, 2013, our top five customers for the directional drilling services were Gulfport, Fairway Resources, LLC, Le Norman Operating LLC, Charter Oak Production Co., LLC and Spring Operating Co. For the six months ended June 30, 2014, our top five customers for the directional drilling services were Gulfport, Le Norman Operating LLC, Fairway Resources, LLC, El Toro Resources LLC, and Ranken Energy Corporation.

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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 and an inventory of related parts and equipment. Subsequent to September 1, 2014, we acquired 14 additional mud motors. As of September 1, 2014, we employed 18 directional drillers with significant industry experience to implement our services.

Remote Accommodations Services

Our remote accommodations services provide housing, kitchen and dining, and recreational service facilities for oilfield workers located in remote areas away from readily available lodging. We provide a turnkey solution for our customers’ accommodation needs. These modular camps, when assembled together, form large dormitories, with kitchen/dining facilities and recreation areas. These camps are operated as “all inclusive,” where meals are prepared and provided for the guests. The primary revenue source for these camps is lodging fees. In 2013, we expanded our remote accommodation services business after being awarded a long-term contract by an unrelated third party. We also have an agreement with an affiliate pursuant to which we provide remote accommodation services on an on-going basis. See “Certain Relationships and Related Party Transactions.” As of September 1, 2014, we had 700 remote accommodation rooms and by the end of 2014, we expect to own facilities supporting oil sands activities in northern Alberta, Canada with an aggregate of 890 rooms, 762 of which are expected to be at Sand Tiger Lodge, our camp in northern Alberta, and 128 of which are expected to be leased as rental equipment to a third party.

Our Industry

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Increased U.S. Crude Oil Production. According to the 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.

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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.

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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 0.38 million 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 target business locations, will be key drivers of U.S. tight oil production as these plays are developed in the coming years due to anticipated increases in horizontal drilling activity.

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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

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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.

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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. In certain cases, exploration and production companies have acquired vast acreage positions in these plays that 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.

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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 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 Corporation, BP p.l.c. and Chevron Corporation 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. The following table represents some of the largest publicly announced joint ventures and acquisitions completed in domestic onshore unconventional oil and natural gas shale plays since the beginning of 2008.


Acquirer	Seller	Play	Date	Deal Value ($mm)
Devon Energy Corporation	GeoSouthern	Eagle Ford	11/20/2013	$6,000.0
Whiting Petroleum Corp.	Kodiak Oil and Gas Corp.	Bakken	7/13/2014	6,000.0
Royal Dutch Shell Plc	East Resources Inc.; KKR	Marcellus	5/28/2010	4,700.0
Apache Corporation	Mariner Energy Inc.	Permian	4/15/2010	3,900.0
Denbury Resources Inc.	Encore Acquisition Company	Permian	11/1/2009	4,464.9
Statoil ASA	Brigham Exploration Company	Bakken	10/17/2011	4,400.0
Chevron Corporation	Atlas Energy Inc.	Marcellus	11/9/2010	4,307.6
Marathon Oil Corporation	Hilcorp Resources	Eagle Ford	6/1/2011	3,500.0
CONSOL Energy Inc.	Dominion Resources Inc.	Marcellus	3/15/2010	3,475.0
Statoil Hydro	Chesapeake Energy Corporation	Marcellus	11/11/2008	3,375.0
Chevron Corporation; EnerVest Ltd., Royal Dutch Shell Plc	Chesapeake Energy Corporation	Permian	9/12/2012	3,300.0
Plains Exploration & Production Co	Chesapeake Energy Corporation	Haynesville	7/1/2008	3,300.0
Noble Energy Inc.	CONSOL Energy Inc.	Marcellus	8/18/2011	3,200.0
Encana Corporation	Freeport-McMoRan Inc. Assets	Eagle Ford	5/7/2014	3,100.0
Apache Corporation	BP Plc	Permian	7/20/2010	3,100.0
Baytex Energy Corp.	Aurora Oil and Gas	Eagle Ford	2/6/2014	2,588.0
American Energy Partners	Enduring Resources	Permian	6/9/2014	2,500.0
Total SA	Chesapeake Energy Corporation; EnerVest Ltd.	Utica	12/30/2011	2,320.0
CNOOC Limited	Chesapeake Energy Corporation	Eagle Ford	10/10/2010	2,160.0
Exxon Mobile Corp.	Denbury Resources, Inc.	Bakken	9/20/2012	2,000.0

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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 that 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.

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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 and maximizing distributions 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 resource 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:

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Capitalize on the increased activity in the unconventional resource plays. Our equipment is designed to provide horizontal 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 Utica Shale in Ohio and the Permian Basin in West Texas. 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.

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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 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.

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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 drilling and completion and production services 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

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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.

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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 drillings 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.

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Leverage our experienced operational management team and basin-level expertise. We seek to manage our business as close as possible to the needs of our customer base. Our operational division heads have longstanding 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 business goals:

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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 June 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.

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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 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 resource plays allows us to strategically capitalize on the increased activity in these unconventional resource plays.

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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 three

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months ended March 31, 2014, representing 55.7% of our revenue on a pro forma basis, were Gulfport, Breitburn Operating LP, J. Cleo Thompson, Apache Corporation and Hibernia Resources LLC.

Our Relationship with Wexford and Gulfport

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 Mammoth Energy, an entity controlled by our founder and sponsor Wexford. As a result of owning our general partner, Mammoth Energy will have the right to appoint all members of the board of directors of our general partner, except for the member of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement.

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 objections, but they will continue to be free to act in a manner that is beneficial to their own interests without regard to ours.

For further information regarding our relationship with Wexford and Gulfport, including the investor rights agreement, please see “Management” and “Certain Relationships and Related Party Transactions.”

Properties

Our corporate headquarters are located at 4727 Gaillardia Parkway, Suite 200, Oklahoma City, Oklahoma 73142. We currently own ten properties, six located in Ohio, one located in Wisconsin, one located in Texas and two located in Canada, which are used for field offices, yards, production plants or housing. In addition to our headquarters, we also lease thirteen properties that are used for field offices, yards or transloading facilities for frac sand. We lease all of these properties from third parties.

We believe that our facilities are adequate for our current operations.

Marketing and Customers

Our customers consist primarily of independent oil and natural gas producers and land-based drilling contractors in North America. For the six months ended June 30, 2014 and the year ended December 31, 2013, on a pro forma basis, we had approximately 112 and 146 customers, respectively, including Gulfport, Diamondback Energy, Inc., Grizzly Oil Sands ULC, Apache Corporation, JAMEX, Inc., Chesapeake Energy Corporation and Marathon Oil. 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. For the six months ended June 30, 2014 and the year ended December 31, 2013, Gulfport was our largest customer accounting for approximately 36.8% and 46.1% of our revenue, respectively, on a pro forma basis, with no other customer accounting for more than 10% of our revenue during those periods. For the year ended December 31, 2012, Gulfport, Grizzly Oil Sands ULC and Marathon Oil were our largest customers accounting for approximately 26%, 20% and 14%, respectively, of our revenue, on a pro forma basis, with no other customer accounting for more than 10% of our revenue for that year. Although we believe we have a broad customer base and wide geographic coverage of operations, 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, revenue could decline and our operating results and financial condition could be harmed.

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Operating Risks and Insurance

Our operations are subject to hazards inherent in the oilfield services industry, such as accidents, blowouts, explosions, fires and spills and releases that can cause:

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personal injury or loss of life;

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damage or destruction of property, equipment, natural resources and the environment; and

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suspension of operations.

In addition, claims for loss of oil and natural gas production and damage to formations can occur in the oilfield services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in us being named as a defendant in lawsuits asserting large claims.

Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.

Despite our efforts to maintain safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property damage, personal injury and other losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees, regulatory agencies and other parties. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.

We maintain commercial general liability, workers’ compensation, business auto, commercial property, motor truck cargo, umbrella liability, in certain instances, excess liability, and directors and officers insurance policies providing coverages of risks and amounts that we believe to be customary in our industry. The limits for our general liability policies for our business entities fall within the following ranges (as may be applicable):

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Commercial General Liability Limit (primary policy): $1,000,000 to $2,000,000 per occurrence and $2,000,000 per project aggregate.

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Commercial Umbrella Limit: $1,000,000 to $10,000,000.

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Excess Liability Limit (in excess of Commercial Umbrella): $10,000,000 to $25,000,000.

In some cases, the above policies require a deductible, ranging from $5,000 to $25,000 per occurrence. We also maintain workers’ compensation insurance policies with limits of $1,000,000, with deductibles ranging from $1,000 to $2,500. Further, we have pollution legal liability coverage for our business entities with limits ranging from $1,000,000 to $5,000,000, which coverage is subject, in certain cases, to 30-day discovery and 90-day reporting requirements and deductibles ranging from $10,000 to $25,000. Our pollution liability policy would cover, among other things, third party liability and costs of clean-up relating to environmental contamination on our premises while our equipment and chemicals are in transit and while on our customers’ job site. With respect to our hydraulic fracturing operations, coverage would be available under our pollution legal liability policy for any surface or subsurface environmental clean-up and liability to third parties arising from any surface or subsurface contamination.

We also have certain specific coverages for some of our businesses. For our remote accommodation services business, we maintain an insurance policy to cover our back-up generator, water treatment plant and other property, which has a limit of $22,256,500 and an insurance policy of up to $7,500,000 to cover business interruptions and loss of profits (subject to waiting periods ranging from 48 hours and 96 hours). For our pressure pumping services business, we maintain an equipment floater that covers losses up to $20,000,000 per occurrence and $20,000,000 per well site. The deductible is $10,000 for equipment valued at least $100,000 and $5,000 for equipment valued under $100,000.

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For our proppant production and sales business, we maintain insurance to cover the loss of certain equipment, buildings and other property, including loss of income for certain specified events. We maintain a main property policy, providing coverage for up to $10,000,000 for certain major equipment breakdowns and catastrophic events, provided, however, that damages from flooding and earthquakes are limited to up to $5,000,000, with a $50,000 deductible per occurrence. The deductibles for other types of coverages under the main property policy range from $2,500 to $25,000. We also maintain three excess property insurance policies for the proppant production and sales business to insure various buildings, business and personal property, equipment and expenses related to business interruption, providing coverage ranging from $15,000,000 to approximately $39,200,000 per occurrence, once damages exceed certain specified thresholds and subject to deductibles ranging from $10,000 per occurrence to $50,000 per occurrence in the case of earthquake and flood damage.

For our contract land and directional drilling business, we maintain inland marine insurance to cover physical loss or damage to our drilling rigs and other mobile equipment. For Bison, this insurance provides coverage up to a limit of $55,997,542, in the case of our drilling rigs, and $14,316,690, in the case of our mobile equipment. The deductible for Bison’s operating rigs is $150,000 per occurrence while the deductible for its stacked rigs is $100,000 per occurrence. In the case of mobile equipment, the deductible for each occurrence is 5% of the scheduled value of the equipment, subject to a $5,000 minimum. In the event of a total loss or constructive total loss, no deductible will apply. For Panther, the inland marine insurance provides coverage for mobile equipment up to a limit of $4,978,694. For equipment that Panther leases from others, the insurance provides coverage of up to $500,000 per item and up to $3,000,000 for all equipment items combined. For equipment that Panther may lease to others, the insurance provides coverage of up to $250,000 per item and up to $1,000,000 for all equipment items combined. The deductible Panther is required to pay is $5,000 for items up to $150,000 and $10,000 for items greater than $150,000. Panther’s inland marine insurance excludes coverage equipment damage that occurs while the equipment is located underground.

Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, 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, 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. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. See “Risk Factors” on page 22 of this prospectus for a description of certain risks associated with our insurance policies.

Safety and Remediation Program

In the oilfield services industry, an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced and skilled workforce. Recently, many of our large customers have placed an emphasis not only on pricing, but also on safety records and quality management systems of contractors. We believe these factors will gain further importance in the future. We have committed resources toward employee safety and quality management training programs. Our field employees are required to complete both technical and safety training programs. Further, as part of our safety program and remediation procedures, we check fluid lines for any defects on a periodic basis to avoid line failure during hydraulic fracturing operations, marking such fluid lines to reflect the most recent testing date. We also regularly monitor pressure levels in the fluid lines used for fracturing and the surface casing to verify that the pressure and flow rates are consistent with the job specific model in an effort to avoid failure. As part of our safety procedures, we also have the capability to shut down our pressure pumping and fracturing operations both at the lines and in our data van. In addition, we maintain spill kits on location for containment of pollutants that may be spilled in the process of providing our hydraulic fracturing services. The spill kits are generally comprised of pads and booms for absorption and containment of spills, as well as soda ash for neutralizing acid. Fire extinguishers are also in place on job sites at each pump.

Historically, we have used a third-party contractor to provide remediation and spill response services when necessary to address spills that were beyond our containment capabilities. None of these prior spills were significant,

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and we have not experienced any incidents, citations or legal proceeding relating to our hydraulic fracturing services for environmental concerns. To the extent our hydraulic fracturing or other oilfield services operations result in a future spill, leak or other environmental impact that is beyond our ability to contain, we intend to engage the services of such remediation company or an alternative company to assist us with clean-up and remediation.

Competition

The markets in which we operate are highly competitive. To be successful, a company must provide services and products that meet the specific needs of oil and natural gas exploration and production companies and drilling services contractors at competitive prices.

We provide our services and products across the United States and in Alberta, Canada and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies.

Our major competitors for our pressure control services include Schlumberger Limited, Halliburton Company, Baker Hughes Incorporated, Weatherford International Ltd., Key Energy Services Inc., Nabors Industries Ltd., Complete Energy Services, Inc. and RPC Incorporated and a significant number of locally oriented businesses. Our major competitors in pressure pumping services include Halliburton Company, Baker Hughes Incorporated, Schlumberger Limited, Weatherford International Ltd, Nabors Industries Ltd., RPC Incorporated, Complete Energy Services, Inc. and FracTech Services, Inc. In our contract and directional drilling services segment, our primary competitors include Helmerich & Payne, Inc., Precision Drilling Corporation, Patterson-UTI Energy, Inc., Cactus Drilling, Sidewinder Drilling, Inc., Baker Hughes Incorporated, Weatherford International Ltd. and various regional and local service providers. Our major competitors in our proppant production and sales business are Badger Mining Corporation, Fairmount Minerals, Ltd., Hi-Crush Partners LP, Preferred Proppants LLC, Unimin Corporation and U.S. Silica Holdings Inc. Our major competitors for our remote accommodation business include Oil States International, Inc., Black Diamond Limited and a significant number of local businesses.

We believe that the principal competitive factors in the market areas that we serve are quality of service and products, reputation for safety and technical proficiency, availability and price. While we must be competitive in our pricing, we believe our customers select our services and products based on the local leadership and basin-expertise that our field management and operating personnel use to deliver quality services and products.

Regulation

We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the handling of hazardous materials, the transportation of explosives, the protection of human health and the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance which is incorporated into our daily operating procedures. The oil and natural gas industry is subject to environmental regulation pursuant to local, state and federal legislation.

Transportation Matters

In connection with our 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 and 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.

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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 which 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 have “satisfactory” ratings with the Department of Transportation. We have undertaken comprehensive efforts that we believe are adequate to comply with the regulations. Further information regarding our safety performance is available at the Department of Transportation Federal Motor Carrier Safety Administration website at www.fmcsa.dot.gov.

Environmental Matters and Regulation

Our operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. We handle, transport, store and dispose of wastes that are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, which affect our activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although certain petroleum production wastes are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

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Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

NORM. In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials associated with oil and gas deposits and, accordingly may result in the generation of wastes and other materials containing naturally occurring radioactive materials, or NORM. NORM exhibiting levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because certain of the properties presently or previously owned, operated or occupied by us may have been used for oil and gas production operations, it is possible that we may incur costs or liabilities associated with NORM.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. Noncompliance with these requirements may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, our sand proppant production operations are subject to air permits issued by the Wisconsin Department

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of Natural Resources regulating our emission of fugitive dust and other constituents. In addition, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail below in “—Regulation of Hydraulic Fracturing.” These and other laws and regulations may increase the costs of compliance for some facilities where we operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. 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 U.S., 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 Source 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 that correspond to 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 such allowances is expected to escalate significantly. 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, tornadoes 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.

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Regulation of Hydraulic Fracturing

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 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.

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 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 for 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

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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 the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. 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. Many other states have adopted similar legislation, including several where we provide services.

Regulation of Sand Proppant Production

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are

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authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although changes to the regulatory burden on the oil and natural gas industry could affect the demand for our services, we would not expect to be affected any differently or to any greater or lesser extent than other companies in the industry with similar operations.

Drilling. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

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the location of wells;

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the method of drilling and casing wells;

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the timing of construction or drilling activities, including seasonal wildlife closures;

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the surface use and restoration of properties upon which wells are drilled;

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the plugging and abandoning of wells; and

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notice to, and consultation with, surface owners and other third parties.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

State Regulation. States regulate the drilling for oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

OSHA Matters

We are also subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Employees

As of September 1, 2014, we had approximately 914 full time employees, including 262 salaried administrative or supervisory employees. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full time employees.

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Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

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MANAGEMENT

Management of Mammoth Energy Partners LP

We are managed and operated by the board of directors and executive officers of our general partner.

Mammoth Holdings owns all the membership interests in our general partner. As a result of owning our general partner, Mammoth Holdings, an entity controlled by Wexford, will have the right to appoint all members of the board of directors of our general partner, including the independent directors, except for those members of the board of directors of our general partner appointed by Gulfport pursuant to an investor rights agreement. Pursuant to the investor rights agreement we will enter into with Gulfport prior to the closing of this offering, as long as Gulfport and its affiliates own 10% or more of our common units, Gulfport shall be entitled to appoint one director.

Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our unitholders as well as a fiduciary duty to its owner.

Upon the closing of this offering, we expect that our general partner will have five directors, one of whom will be independent as defined under the independence standards established by NASDAQ and the Exchange Act. Spencer D. Armour, III will serve as the initial independent member of the board of directors of our general partner. In accordance with the rules of NASDAQ, Mammoth Holdings will appoint one additional independent member within 90 days of the effective date of the registration statement of which this prospectus forms a part and one additional independent member within one year of such effective date, bringing the total number of directors on the board of directors of our general partner to seven. NASDAQ does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by NASDAQ and the Exchange Act, subject to the transitional relief during the one-year period following completion of this offering.

The executive officers of our general partner will manage the day-to-day affairs of our business and intend to devote as much time as is necessary for the proper conduct of our business.

Our partnership agreement requires us to reimburse our general partner and certain of its affiliates, including Wexford, for all expenses they incur and payments they make on our behalf in connection with operating our business. 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. In addition, in connection with the closing of this offering, we and our general partner will 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. Please see “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

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Executive Officers and Directors of Our General Partner

The following table shows information for the executive officers and directors of our general partner upon the consummation of this offering. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board. There are no family relationships among any of our directors or executive officers. Ages are as of June 30, 2014.


Name	Age		Position
Marc McCarthy		43	Executive Chairman and Director
Phil Lancaster		56	President
Mark Layton		39	Chief Financial Officer
Spencer D. Armour, III		60	Director Nominee
Aaron Gaydosik		38	Director Nominee
Joseph M. Jacobs		61	Director Nominee
Kenneth A. Rubin		59	Director Nominee

Marc McCarthy has served as Executive Chairman of the Board of Directors of our general partner since September 17, 2014. Mr. McCarthy is currently a Senior Managing Director at Wexford, having joined Wexford in June 2008. Upon completion of this offering, Mr. McCarthy will become a consultant to Wexford. Mr. McCarthy also serves as a director of Coronado Midstream LLC, a private gas gathering and processing operation in Midland, TX. From September 2009 until June 2013, Mr. McCarthy served as Chairman of the Board and a director of EPL Oil & Gas, Inc., an independent oil and natural gas exploration and production company. He also served on the Nominating and Governance Committee of EPL Oil & Gas, Inc. Before joining Wexford, Mr. McCarthy was a Senior Managing Director at Bear Stearns & Co., Inc. within its Global Equity Research Department having been responsible for coverage of the international oil and gas sector. Mr. McCarthy joined Bear Stearns & Co. in 1997 and held various positions of increasing responsibility until his departure in June 2008. Prior to 1997, he worked in equity research at Prudential Securities, also following the oil and gas sector. Mr. McCarthy is a Chartered Financial Analyst and received a B.A. in Economics from Tufts University. We believe Mr. McCarthy’s experience as a director of both publicly-traded and private oil and gas companies, as well as his experience in evaluating financial, strategic and operational aspects of companies in our industry at Wexford, qualifies him for service as a Director of our general partner.

Phil Lancaster became President of our general partner in August 2014 and served as its initial director from August 2014 to September 2014. Mr. Lancaster has served as Chief Executive Officer of Redback Energy Services LLC since September 2011. From June 2006 to November 2010, Mr. Lancaster served as Chief Executive Officer of Great White Energy Services, and from November 2010 to September 2011, Mr. Lancaster was a consultant to Wexford in connection with energy-related investments. Mr. Lancaster served on the board of directors of Bronco Drilling Company, Inc., a Nasdaq-listed drilling company, from August 2005 until July 2006 and Gulfport, a Nasdaq Global Select listed exploration and production company, from February 2006 until August 2006. Mr. Lancaster received a Bachelor of Science degree from the David Lipscomb College.

Mark Layton became Chief Financial Officer of our general partner in August 2014. Mr. Layton served as Chief Financial Officer of Stingray Pressure Pumping LLC from January 2014 to August 2014. Mr. Layton was employed from August 2011 through January 2014 by Archer Well Company Inc. where his last position was Director of Finance for North America. From September 2009 through August 2011, Mr. Layton was employed by Great White Energy Services, Inc. where his last position was Corporate Controller and Director of Financial Reporting. Mr. Layton served as Vice President of Finance of Crossroads Wireless, Inc., a wireless telecommunications service company, from May 2007 through September 2009. In February 2009, an involuntary petition petition under Chapter 7 of the United States Bankruptcy Code was filed against Crossroads Wireless, Inc. in the Western District of Oklahoma. From April 2004 through May 2007, Mr. Layton served as the Director of Financial Reporting for Chickasaw Holding Company, a telecommunications service company.

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He began his career in public accounting with Finley & Cook PLLC. Mr. Layton has a Bachelor of Science degree in Accounting from the University of Central Oklahoma. Mr. Layton is a Certified Public Accountant.

Spencer D. Armour, III has agreed to serve as a director of our general partner and is expected to join the Board of Directors of our general partner prior to the closing of this offering. Mr. Armour has served as chairman of ProPetro Services, Inc. since January 2013 and has been a partner at PT Petroleum, LLC since March 2013. He has also served as Managing Partner of Armada Gas & Oil Company in Midland, Texas, a company that invests in oil and gas production, minerals and the oilfield service sector, since 2009. Mr. Armour has over thirty years of experience in the oilfield service business. From April 2007 to December 2008, Mr. Armour served as Vice President of Corporate Development at Basic Energy Services, Inc. From March 2006 until March 2007, Mr. Armour served as Chief Executive Officer of Sledge Drilling Corp. From January 2002 until February 2006, he served as Executive Vice President of Contracts/Drilling Fluids for Patterson-UTI Energy, Inc. Mr. Armour served as a director of Patterson-UTI Energy, Inc. from July 1999 to May 2002. He founded Lone Star Mud, Inc. in 1986 and served as its President until January 1998. He was appointed for a six year term to the University of Houston System Board of Regents in September 2011 and currently serves as Chairman of the Finance Committee. Mr. Armour received a Bachelor of Science in Economics from the University of Houston in 1977. We believe Mr. Armour’s knowledge of the oilfield services industry and his experience as a director of a public company qualifies him for service as a Director of our general partner.

Aaron Gaydosik has agreed to serve as a Director of our general partner and is expected to join the board of directors of our general partner prior to the closing of this offering. Mr. Gaydosik has served as Chief Financial Officer of Gulfport since August 2014. From July 2013 until joining Gulfport, Mr. Gaydosik served as Vice President of Finance at Kodiak Oil & Gas Corp., an independent energy company with operations focused primarily in the Williston Basin of North Dakota. From May 2007 through July 2013, Mr. Gaydosik held various positions of increasing levels of responsibility at Credit Suisse, most recently as a Director in its Oil and Gas Group, focused on capital markets and advisory transactions primarily for exploration and production companies. His prior investment banking experience also includes two years in the energy group at Wachovia Securities. Mr. Gaydosik holds a Bachelor of Business Administration in Finance from Southern Methodist University and a Masters of Business Administration from the University of Chicago Booth School of Business. We believe Mr. Gaydosik’s experience with financial matters in the oil and gas industry qualifies him for service as a Director of our general partner.

Joseph M. Jacobs has agreed to serve as a Director of our general partner and is expected to join the board of directors of our general partner prior to the closing of this offering. Mr. Jacobs is the President of Wexford, which he co-founded in 1994. From 1982 to 1994, Mr. Jacobs was employed by Bear Stearns & Co., Inc., where he attained the position of Senior Managing Director. From 1979 to 1982, he was employed as a commercial lending officer at Citibank, N.A. Mr. Jacobs served as a director for ICx Technologies, Inc. from December 2002 to August 2010, Republic Airways Holding Inc. from March 1998 to June 2008 and Azul S.A. from March 2008 to January 2010, and has served on the boards and creditors’ committees of a number of public and private companies in which Wexford has held investments. Mr. Jacobs has served as a director of the general partner of Rhino Resources LP since July 2010. Mr. Jacobs holds an M.B.A. from Harvard Business School and a B.S. in Economics from the Wharton School of the University of Pennsylvania. Mr. Jacobs was selected to serve as a director due to his significant service on the boards of other public and private companies, which provides a thorough understanding of board roles and responsibilities and widespread knowledge of various industries, businesses, operations, opportunities and risks. We believe Mr. Jacobs’ current position as President of Wexford also provides a comprehensive knowledge of management strategy and policy that qualifies him for service as a Director of our general partner.

Kenneth A. Rubin has agreed to serve as a Director of our general partner and is expected to join the board of directors of our general partner prior to the closing of this offering. Mr. Rubin joined Wexford in 1996 and became a partner in 2001. Mr. Rubin focuses on investment grade and government fixed income investments. Mr. Rubin has served on the board of directors of the general partner of Rhino Resources LP since January 2014

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and has served on the boards of private companies. Mr. Rubin holds a Juris Doctor degree from Stanford Law School, Order of the Coif, and a Bachelor of Arts degree in economics and mathematics from Yale University. We believe Mr. Rubin’s long-term experience in the capital and investment markets. Mr. Rubin and his understanding of our business, history and organization qualifies him for service as a Director of our general partner.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee. We do not expect that we will have a compensation committee, but rather that the board of directors of our general partner will have authority over compensation matters.

Audit Committee

We are required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by NASDAQ and Rule 10A-3 promulgated under the Exchange Act, subject to certain transitional relief during the one-year period following consummation of this offering as described above. Spencer D. Armour, III will serve as the initial member of the audit committee. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

Conflicts Committee

We expect that at least one independent member of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee will determine if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Wexford and Gulfport, and must meet the independence standards established by NASDAQ and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Director Compensation

To date, none of the directors have received compensation for services rendered as a board member. Members of the board of directors of our general partner who are also officers or employees of our general partner will not receive compensation for their services as directors. It is anticipated that after the completion of this offering, non-employee directors will be paid a monthly retainer of $ and a per meeting attendance fee of $ and reimbursed for all ordinary and necessary expenses incurred in the conduct of our business.

In connection with this offering, we intend to implement an equity incentive plan. Under the plan, certain non-employee directors will be granted restricted units, which will vest in three equal annual installments beginning on the date of grant.

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Compensation Committee Interlocks and Insider Participation

The board of directors of our general partner does not currently have a compensation committee and although it is not required and does not currently intend to establish a compensation committee, it may do so in the future. None of our executive officers serve, or have served during the past year, as a member of the board of directors or compensation committee of any other company that has one or more executive officers serving as a member of the board of directors of our general partner.

Executive Compensation

Summary of Compensation for Our Named Executive Officers

The following table shows the compensation of all individuals serving as our principal executive officer during 2013 and of our two other most highly compensated executive officers serving as of December 31, 2013, whose total compensation exceeded $100,000 for the fiscal year ended December 31, 2013.


	Year		Salary		Bonus⁽¹⁾		All Other Compensation⁽²⁾		Total
Marc McCarthy, Chairman⁽³⁾		2013	$	—	$	—	$	—	$	—
Phil Lancaster, President⁽⁴⁾		2013	$	298,148	$	100,000	$	36,948	$	435,096
Mark Layton, Chief Financial Officer⁽⁵⁾		2013	$	—	$	—	$	—	$	—

(1)	Consists of a discretionary bonus.

(2)

Consists of $7,393 attributable to our matching contributions to Mr. Lancaster’s 401(k) account, $20,223 attributable to reimbursement of medical premiums and expenses, $332 attributable to life insurance premiums paid by us on behalf of Mr. Lancaster and $9,000 attributable to an automobile allowance provided by us to Mr. Lancaster.

(3)	Mr. McCarthy became our Executive Chairman on September 17, 2014, and did not receive any compensation from us in 2013.

(4)	Represents compensation Mr. Lancaster received during 2013 as the Chief Executive Officer of Redback Energy Services LLC.

(5)	Mr. Layton joined us in January 2014 and did not receive any compensation from us in 2013.

Employment Agreements

In September 2014, we entered into an oral employment agreement with Mark Layton, our Chief Financial Officer. Mr. Layton’s annual base salary is $225,000, which can be increased from time to time by the board of directors or compensation committee of our general partner. Subject to Mr. Layton’s achievement of certain performance goals to be determined by the board of directors or the compensation committee, Mr. Layton will be eligible to receive a target annual bonus of 75% of his annual base salary. Upon the completion of this offering, Mr. Layton will receive a one-time cash bonus of $300,000 and will be entitled to receive annual equity incentive awards equal to 100% of his annual base salary, which will vest equally over a four year period. Mr. Layton is entitled to participate in any life and medical insurance plans and other similar plans that we establish from time to time for our executive employees. Mr. Layton’s employment with us is terminable by either party.

2014 Equity Incentive Plan

Prior to the completion of this offering, we did not have any option or other equity incentive plan and there are no options, restricted units or other equity awards outstanding for any of our named executive officers. Prior to this offering, we intend to implement our equity incentive plan as described below. The equity incentive plan is intended to provide an additional incentive to our management and directors following the completion of this offering to continue to grow our business and enhance the value for our unitholders.

Eligible award recipients are employees, consultants and directors of our company and its affiliates. The equity interests that may be issued pursuant to awards consist of our authorized but unissued common units, and

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the maximum aggregate amount of such common units which may be issued upon exercise of all awards under the plan may not exceed common units, subject to adjustment to reflect certain transactions or changes in our capital structure.

We anticipate granting unit options and restricted phantom units to employees and certain non-employee directors under the plan upon completion of this offering in an amount to be determined by the plan administrator.

Securities to be Offered. The aggregate number of common units initially authorized for issuance of awards under the plan is common units. However, (i) common units covered by an award that expires or otherwise terminates without having been exercised in full and (ii) common units that are forfeited to, or repurchased by, us pursuant to a forfeiture or repurchase provision under the plan may return to the plan and be available for issuance in connection with a future award.

Administration. The board of directors of our general partner (or the compensation committee or any other committee of the board of directors as may be appointed by the board of directors of our general partner from time to time) will administer the plan. Among other responsibilities, the plan administrator selects participants from among the eligible individuals, determines the number of common units that will be subject to each award and determines the terms and conditions of each award, including methods of payment, vesting schedules and limitations and restrictions on awards. The plan administrator may amend, suspend or terminate the plan at any time. Amendments will not be effective without unitholder approval if unitholder approval is required by applicable law or stock exchange requirements. Unless terminated earlier, our equity incentive plan will terminate in August 2024.

Unit Options. Unit options will be treated as nonstatutory options and may be granted pursuant to option agreements to employees, directors and consultants. The plan administrator will determine the exercise price of a unit option, provided that the exercise price of a unit option cannot be less than 100% of the fair market value of a common unit on the date of grant, except when assuming or substituting options in limited situations such as an acquisition. Unit options granted under the plan will vest over a period of time specified by the plan administrator in the individual option agreements, and will generally have a term of ten years, unless specified otherwise by the plan administrator in the option agreement.

Acceptable consideration for the purchase of common units issued upon the exercise of a unit option will be determined by the plan administrator and may include (i) cash or check, (ii) a broker-assisted cashless exercise, (iii) the tender of common units previously owned by the option holder, (iv) unit withholding and (v) other legal consideration approved by the plan administrator, such as exercise with a full recourse promissory note (not applicable for directors and executive officers).

Unless the plan administrator provides otherwise (solely with respect to intervivos transfers to certain family members and estate planning vehicles), unit options generally are not transferable except by will or the laws of descent and distribution. An optionee may designate a beneficiary, however, who may exercise the unit option following the option holder’s death.

Restricted Awards. Restricted awards are awards of either actual common units (e.g., restricted unit awards), or of hypothetical units (restricted phantom units) having a value equal to the fair market value of an identical number of common units, that will be settled in the form of common units or cash upon vesting or other specified payment date, and which may provide that such restricted awards may not be sold, transferred or otherwise disposed of for such period as the plan administrator determines. The purchase price and vesting schedule, if applicable, of restricted awards are determined by the plan administrator. A restricted phantom unit is similar to a restricted unit award except that participants holding restricted phantom units do not have any unitholder rights until the restricted phantom unit is settled with common units. Restricted phantom units

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represent an unfunded and unsecured obligation and prior to settlement in the form of common units a holder of a restricted phantom unit has no rights other than those of a general unsecured creditor.

To the extent provided by the plan administrator, in its discretion, distributions made by the Partnership with respect to restricted units will be subject to the same forfeiture and other restrictions as the restricted unit in which case such distributions will be held without interest until the restricted unit vests or is forfeited. In addition, the plan administrator may provide that such distributions be used to acquire additional restricted units for the Participant, which may be subject to such vesting and other terms as the plan administrator may prescribe. Absent such restrictions, distributions will be paid to the holder of restricted unit without restriction at the same time as cash distributions are paid by the Partnership to its unitholders.

Performance Awards. Performance awards entitle the recipient to vest in or acquire common units, or restricted phantom units that will be settled in the form of common units or cash upon the attainment of specified performance goals. The plan administrator may condition the right to exercise or receive an award under the equity incentive plan, or may increase or decrease the amount payable with respect to an award, based on the attainment of one or more specified performance goals. Performance awards may be granted independent of or in connection with the granting of any other award under the plan. Performance goals will be established by the plan administrator based on one or more business criteria that apply to the plan participant, a business unit or our company and our affiliates. Performance goals will be objective and generally will be determined prior to the time that 25% of the service period has elapsed but not later than 90 days after the beginning of the service period. No payout will be made on a performance award granted to a named executive officer unless all applicable performance goals and service requirements are achieved. Performance awards may not be sold, assigned, transferred, pledged or otherwise encumbered and terminate upon the termination of the participant’s service to us or our affiliates.

Unit Appreciation Rights. Unit appreciation rights may be granted independent of or in tandem with the granting of any unit option under the plan. Unit appreciation rights are granted pursuant to unit appreciation rights agreements. The exercise price of a unit appreciation right granted independent of an option is determined by the plan administrator, but as a general rule will be no less than 100% of the fair market value of a common unit on the date of grant. The exercise price of a unit appreciation right granted in tandem with a unit option is the same as the exercise price of the related unit option. Upon the exercise of a unit appreciation right, we will pay the participant an amount equal to the product of (i) the excess of the per unit fair market value of a common unit on the date of exercise over the strike price, multiplied by (ii) the number of common units with respect to which the unit appreciation right is exercised. Payment will be made in cash, delivery of units, or a combination of cash and units as deemed appropriate by the plan administrator.

Anti-Dilution Adjustments. In the event that there is an equity restructuring change in our common units without the receipt of consideration by us, such as pursuant to a merger, consolidation, reorganization, recapitalization, reincorporation, distribution in property other than cash, unit split, liquidating distribution, combination of units, exchange of units, change in entity structure or other transaction, appropriate adjustments will be made to the various limits under, and the unit terms of, the plan including (i) the number and class of units reserved under the plan, (ii) the maximum number of unit options and unit appreciation rights that can be granted to any one person in a calendar year and (iii) the number and class of units and exercise price, strike price, or purchase price, if applicable, of all outstanding unit awards.

Transactions. In the event of a change in control transaction (other than a transaction resulting in Wexford, Gulfport or an entity controlled by, or under common control with Wexford or Gulfport maintaining direct or indirect control over the Partnership), or a transaction such as a dissolution or liquidation of our company, or any separation or division, including, but not limited to, a split-up, a split-off or a spin-off, or a sale in one or a series of related transactions, of all or substantially all of the assets of our company or a merger, consolidation, or reverse merger in which we are not the surviving entity, then all outstanding unit awards under the plan may be assumed, continued or substituted for by any surviving or acquiring entity (or its parent company), or may be

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cancelled either with or without consideration for the vested portion of the awards, all as determined by the plan administrator. In the event an award would be cancelled without consideration paid to the extent vested, the award recipient may exercise the award in full or in part for a period specified by the plan administrator, which also may accelerate the vesting of such awards in its discretion.

Tax Withholding. At our discretion, and subject to conditions that the plan administrator may impose, a participant’s minimum statutory tax withholding with respect to an award may be satisfied by withholding from any payment related to an award or by the withholding of common units issuable pursuant to the award based on the fair market value of the common units.

Termination of Employment or Service. The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

401(k) Plan

Each of our entities has a 401(k) Plan. Under these plans, our employees may elect to defer a portion of their compensation up to the statutorily prescribed limit, and each pay period our entities make matching contributions to participating employees’ deferrals, with various matching percentages and vesting. These 401(k) Plans are intended to qualify under Section 401(a) of the Internal Revenue Code. As such, contributions to the 401(k) Plans and earnings on those contributions generally are not taxable to the employee until distributed from the 401(k) Plans, and all contributions are deductible by our entities when made.

Limitations on Liability and Indemnification of Officers and Directors

Limited Partnership Agreement

Our limited partnership agreement provides that we will, to the fullest extent permitted by Delaware law, indemnify our directors and officers against losses that they may incur in investigations and legal proceedings resulting from their service. See “Conflicts of Interest and Fiduciary Duties” and “The Partnership Agreement— Indemnification” for further discussion.

Indemnification Agreements

We will enter into indemnification agreements with each of our current directors and executive officers effective upon the closing of this offering. These agreements require us to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and executive officers.

Liability Insurance

We intend to provide liability insurance for our directors and officers, including coverage for public securities matters. There is no pending litigation or proceeding involving any of our directors, officers or employees for which indemnification from us is sought. We are not aware of any threatened litigation that may result in claims for indemnification from us.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

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) and Wexford will own a non-economic general partner interest in us that does not entitle it to receive distributions.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliates (including Wexford and Gulfport) in connection with the formation, ongoing operation and any liquidation of the Partnership.

Formation Stage

The consideration received by our general partner and its affiliates prior to or in connection with this offering

•

With respect to Wexford, common units and $ million of the net proceeds of this offering as a selling unitholder of common units ($ million for common units if the underwriters exercise their over-allotment option in full);

•

With respect to Gulfport, common units and $ million of the net proceeds of this offering as a selling unitholder of common units ($ million for common units if the underwriters exercise their over-allotment option in full); and

•

With respect to our general partner, a non-economic general partner interest.

Operational Stage

Payments to our general partner and its affiliates

We will reimburse our general partner and certain of its affiliates (including Wexford) for all expenses incurred on our behalf. At the closing of this offering, we and our general partner will 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.

Cash distributions to our general partner and its affiliates

We will generally make cash distributions 100% to our unitholders, including affiliates of our general partner, pro rata.

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its non-economic general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of the interest. Please see “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

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Liquidation Stage

Liquidation

Upon our liquidation, our unitholders will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements and Transactions with Affiliates in Connection with this Offering

In connection with this offering, we will enter into certain agreements and transactions with our general partner, Wexford, Gulfport and Rhino as described in more detail below.

Contribution Agreements

In connection with the closing of this offering, we will enter into contribution agreements with Gulfport, Rhino and Mammoth Holdings that will effect the Contribution Transactions. For more information regarding the Contribution Transactions see “Prospectus Summary - Our History and Contribution Transactions.”

Registration Rights and Investor Rights Agreements

Under our partnership agreement and the registration rights agreement that we will enter into with Mammoth Holdings prior to the closing of this offering, our general partner and its affiliates (including Wexford and Mammoth Holdings) will have certain demand and “piggyback” registration rights. Further, prior to the closing of this offering, we will enter into an investor rights agreement with Gulfport in which Gulfport will be granted (i) certain demand and “piggyback” registration rights, (ii) the right to designate one director of our general partner for so long as Gulfport owns 10% or more of our outstanding common units and (iii) certain information rights. Our registration rights agreement with Rhino will provide for “piggyback” registration rights. For more information regarding these rights, see “Management” and “Units Eligible for Future Sale—Registration Rights.”

Advisory Services Agreement

Prior to the closing of this offering we will enter into an advisory services agreement with Wexford under which Wexford will provide us with general financial and strategic advisory services related to our business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. This agreement has a term of two years commencing on the completion of this offering. The agreement will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. The agreement may be terminated at any time by either party upon 30 days’ prior written notice. In the event we terminate the agreement, we are obligated to pay all amounts due through the remaining term of the agreement. In addition, in this agreement we have agreed to pay Wexford to-be-negotiated market-based fees approved by our independent directors for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the advisory services agreement will not extend to our day-to-day business or operations. In this agreement, we have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. In the event we are dissatisfied with the services provided by Wexford, our only remedy against Wexford is to terminate the agreement.

Other Agreements with Affiliates

Effective September 9, 2013, Panther Drilling entered into a master service agreement with Diamondback E&P, whereby Panther provides directional drilling and other services to Diamondback E&P. This master service agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from work performed prior to the termination of the master service agreement.

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Furthermore, the master service agreement does not obligate Diamondback E&P to issue any order or accept any offers from Panther Drilling for its directional drilling or other services. In the third quarter 2013, Diamondback E&P began using Panther Drilling’s directional drilling services. For the six months ended June 30, 2014, Panther Drilling recognized $0.2 million from Diamondback E&P. Diamondback E&P owed Panther Drilling $0.01 million at June 30, 2014. For the year ended December 31, 2013, Diamondback E&P incurred $0.4 million for services performed by Panther Drilling. Diamondback E&P owed Panther Drilling $0.3 million as of December 31, 2013. Diamondback E&P is a wholly-owned subsidiary of Diamondback Energy, Inc., or Diamondback, in which Gulfport and affiliates of Wexford beneficially owned approximately 1.7% and 12.0%, respectively, of its outstanding common stock as of September 22, 2014.

On October 17, 2013, Bison Trucking entered into a master service contract with Diamondback E&P, pursuant to which Bison Trucking may, from time to time, provide services or sell or lease goods, equipment or facilities to Diamondback E&P in connection with its business activities. This agreement, which may be terminated at the option of either party on 30 days’ notice, does not obligate Diamondback E&P to issue any order or accept any offers from Bison Trucking for its services. Bison Trucking recognized $0.3 million from Diamondback E&P for services during the six months ended June 30, 2014. As of June 30, 2014, Diamondback E&P owed Bison Trucking $0.1 million. For the year ended December 31, 2013, Diamondback E&P incurred $0.05 million for services performed by Bison Trucking and, as of December 31, 2013, owed Bison Trucking $0.05 million for work performed under the master service contract.

On January 1, 2013, Bison Drilling entered into a master field services agreement with Diamondback E&P, pursuant to which Bison Drilling may, from time to time, provide services or sell or lease specified goods to Diamondback E&P in connection with its business activities. This agreement, which may be terminated at the option of either party upon 30 days’ notice, does not obligate Diamondback E&P to issue any order or accept any offers from Bison Drilling for its services. On February 21, 2013, this master field services agreement was amended to provide a revised rate schedule for services. Diamondback E&P incurred $0.6 million for services for the six months ended June 30, 2014 and as of June 30, 2014 owed Bison Drilling $0.1 million. For the year ended December 31, 2013 and 2012, Diamondback E&P incurred $4.1 million and $3.8 million, respectively, for services performed by Bison Drilling and, as of December 31, 2013 and 2012, owed Bison Drilling $0.2 million and $0.3 million, respectively, for work performed under the master field services contract.

On January 1, 2013, Bison Drilling entered into a master drilling agreement with Diamondback E&P, pursuant to which Bison Drilling may provide rigs to Diamondback E&P to be used in connection with Diamondback E&P’s exploration and development of its oil and natural gas properties. The master drilling agreement may be terminated at the option of either party on 30 days’ notice. If Diamondback E&P requires drilling services within the Permian Basin, then Diamondback E&P must order such services from Bison Drilling and Bison Drilling must provide such services. However, the master drilling agreement does not obligate Diamondback E&P to issue any order to Bison Drilling for drilling services and it does not obligate Bison Drilling to accept an order from Diamondback E&P for a rig if two of its rigs are then obligated to perform other drilling services and such drilling services have not been completed. For the six months ended June 30, 2014, Diamondback E&P incurred $2.3 million for services and, as of June 30, 2014, owed Bison Drilling $0.8 million. For the year ended December 31, 2013 and 2012, Diamondback E&P incurred $9.9 million and $13.1 million, respectively, for services performed by Bison Drilling and, as of December 31, 2013 and 2012, owed Bison Drilling $0.5 million and $2.0 million, respectively, for work performed under the master drilling agreement.

Pursuant to two separate limited loan guaranty agreements, each effective January 31, 2014, certain affiliates of Wexford agreed to guarantee up to $25.0 million of principal and interest under Bison Drilling’s loan and security agreement with International Bank of Commerce, dated May 31, 2013, as subsequently amended. Each of these guaranty agreements will automatically terminate and the obligations of each guarantor will be released at such time as the principal amount outstanding under Bison Drilling’s term loan, as amended, is $30.0 million or less.

We have provided remote accommodation and food services to Grizzly Oil Sands ULC, or Grizzly, an entity owned approximately 75% by affiliates of Wexford and approximately 25% by Gulfport, since 2008. Since

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June 25, 2012, these services have been provided to Grizzly pursuant to a written agreement with an initial term of one year. The agreement automatically renews for successive one-year terms unless terminated by either party by giving written notice of such termination to the other party at least 30 days prior to the expiration of the then-current term. We recognized $2.1 million for the six months ended June 30, 2014. As of June 30, 2014, Grizzly owed us approximately $1.2 million. For the years ended December 31, 2013 and 2012, we recognized revenue from Grizzly of approximately $12.8 million and $6.5 million, respectively, and as of December 31, 2013 and December 31, 2012, Grizzly owed us additional amounts of approximately $3.6 million and $1.0 million, respectively, for such services. Prior to June 2012, we provided these services to Grizzly without a written agreement.

On May 16, 2013, Muskie entered into a master services agreement with Diamondback E&P LLC, or Diamondback E&P, whereby Muskie Proppant sells custom natural sand proppant to Diamondback E&P. This agreement, which may be terminated at the option of either party on 30 days’ notice, does not obligate Diamondback E&P to issue any order or accept any offers from Muskie Proppant for sand proppant. Muskie Proppant did not recognize any revenue from Diamondback E&P for the six months ended June 30, 2014. Muskie Proppant recognized $0.7 million of revenue from sales of sand proppant to Diamondback E&P in 2013, and did not recognize any revenue from Diamondback E&P in 2012. Diamondback E&P did not owe Muskie Proppant any amounts as of December 31, 2013 or 2012.

In September 2014, effective October 1, 2014, Gulfport entered into a sand supply agreement with Muskie Proppant. Pursuant to this agreement, Muskie Proppant has agreed to sell and deliver, and Gulfport has agreed to purchase, specified annual and monthly amounts of proppant sand, subject to certain exceptions specified in the agreement, at a fixed price per ton, subject to certain adjustments, plus agreed costs and expenses. Failure by either Muskie Proppant or Gulfport to deliver or accept the minimum monthly amount results in damages calculated per ton based on the difference between the monthly obligation amount and the amount actually delivered or accepted, as applicable. In addition, failure to pick up the sand on a timely basis from the designated facility will lead to demurrage charges payable by Gulfport. If Gulfport fails to make payments when due, or Muskie Proppant fails to deliver the required amounts of sand over three consecutive months, the other party can terminate the sand supply agreement. The sand supply agreement has a term ending on September 30, 2018 and includes, among others, confidentiality and non-solicitation provisions.

Panther Drilling performs directional drilling services for Gulfport pursuant to a master service agreement, dated February 22, 2013. The master service agreement may be terminated by Panther Drilling at any time prior to the receipt of notification by Gulfport to perform work pursuant to the agreement. Gulfport, however, may terminate the master service agreement at any time by giving written notice to Panther Drilling. The master service agreement does not obligate Gulfport to call upon Panther Drilling to perform any work under the master service agreement, and Panther Drilling is not obligated to accept any work requests from Gulfport. Furthermore, the designation of any work to be performed by Panther Drilling and the cessation of such work shall be at the sole discretion of Gulfport. For the six months ended June 30, 2014, Gulfport incurred $3.5 million for services performed by Panther Drilling and, as of June 30, 2014, owed Panther Drilling $1.6 million. For the year ended December 31, 2013 and 2012, Gulfport incurred $12.9 million and $0.1 million, respectively, for services performed by Panther Drilling and, as of December 31, 2013 and 2012, owed Panther Drilling $1.8 million and $0.1 million, respectively, for work performed under the master service contract.

Panther Drilling provides directional drilling services to an entity under common ownership. For the six months ended June 30, 2014, the Panther Drilling recognized $0.7 million of revenue from this entity. Receivables from related parties included $0.7 million at June 30, 2014. No revenue was earned from this entity in the prior year and there was no amount owed as of December 31, 2013.

Redback Energy Services performs completion and production services for Gulfport pursuant to a master service agreement dated June 11, 2012. The master service agreement may be terminated by Redback Energy Services at any time prior to the receipt of notification by Gulfport to perform work pursuant to the agreement.

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Gulfport, however, may terminate the master service agreement at any time by giving written notice to Redback Energy Services. The master service agreement does not obligate Gulfport to call upon Redback Energy Services to perform any work under the master service agreement, and Redback Energy Services is not obligated to accept any work requests from Gulfport. For the six months ended June 30, 2014 and the year ended December 31, 2013, Gulfport incurred $0.4 million and $0 million, respectively, for services performed by Redback Energy Services and, as of June 30, 2014 and December 31, 2013, owed Redback Energy Services $0.4 million and $0 million, respectively, for work performed under the master service agreement.

From time to time, we provide goods and services and pay for goods and services on behalf of certain affiliates of Wexford. As of June 30, 2014 these affiliates owed us $0.04 million. During the years ended December 31, 2013 and 2012, these affiliates incurred $0.02 million and $0.02 million, respective, for services performed. At December 31, 2013 and 2012, these Wexford affiliates owed us an aggregate of $0.07 million and $0.06 million, respectively.

On May 7, 2013, Muskie Proppant entered into a transloading agreement with Hopedale Mining LLC, or Hopedale, pursuant to which Hopedale will operate and maintain our Nelms No. 1 rail transloading facility located in Cadiz, Ohio and transload sand on a requirement basis. The agreement provides for a term of two years, subject to the option to terminate as described below. Under the agreement, Muskie Proppant is obligated to pay Hopedale a transloading fee in the amount of $4.00 per ton of sand. If Muskie Proppant fails to transload at least 7,500 tons of sand per month on average for a three-month period or pay an average of $30,000 for each month during such period (or such lesser amount as may be due in accordance with the agreement), Hopedale has the right to terminate the agreement. Muskie Proppant incurred $0.2 million in costs for the six months ended June 30, 2014 and, as of June 30, 2014, owed Hopedale $0.03 million. For the year ended December 31, 2013, Muskie Proppant incurred $0.3 million in costs to Hopedale and, as of December 31, 2013, owed Hopedale $0.03 million under this agreement. Hopedale is a wholly-owned subsidiary of Rhino Resource Partners LP, which is an affiliate of Wexford.

Redback Coil Tubing purchases coil tubing equipment from Serva Group, Ltd. and Serva Group LLC, which prior to their sale to an unrelated third party in May 2014 were affiliates of Wexford and are collectively referred to as Serva Group. Redback Coil Tubing also contracts for repairs and maintenance services from Serva Group. For the six months ended June 30, 2014, Redback Coil Tubing purchased $0.09 million of equipment from and incurred $0.2 million of repairs and maintenance cost payable to Serva Group. As of May 2014, this entity was sold and is no longer a related party to Serva Group. During the year ended December 31, 2013, Redback Coil Tubing purchased $1.7 million of equipment and incurred $0.2 million of repairs and maintenance cost from the Serva Group. During the year ended December 31, 2012, Redback Coil Tubing purchased $8.0 million of equipment. At December 31, 2013 and December 31, 2012, Redback Coil Tubing owed $1.3 million and $1.4 million, respectively to the Serva Group.

Panther Drilling rents rotary steerable equipment in connection with its directional drilling services from Double Barrel Downhole Technologies, an affiliate of Wexford. Costs incurred for the six months ended June 30, 2014 were $0.2 million. Costs incurred for the year ended December 31, 2013 were $1.4 million.

In July 2013, Muskie Proppant received loans in the aggregate principal amount of approximately $3.5 million from its members, which consisted of Gulfport and entities controlled by Wexford. Muskie Proppant makes monthly interest payments on these loans at the prime rate plus 2.5% (5.75% at December 31, 2013). The loans mature on July 31, 2015. The aggregate balances of these loans and accrued interest as of June 30, 2014 and December 31, 2013 were $3.7 million and $3.6 million, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Existing Credit Facilities” for additional information regarding these loans.

Pursuant to a limited loan guaranty agreement, dated July 3, 2013, certain affiliates of Wexford guaranteed the full and prompt payment of up to $15.0 million borrowed by Stingray Pressure Pumping under the Loan and

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Security Agreement, dated July 3, 2013, by and between Stingray Pressure Pumping and International Bank of Commerce. In September 2014, the amount guaranteed was reduced to $9.5 million as a result of Stingray Pressure Pumping reaching certain financial milestones.

Everest Operations Management LLC, or Everest, an affiliate of Wexford, has historically provided office space and certain technical, administrative and payroll services to us, and we have reimbursed Everest in amounts determined by it based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for us. The reimbursement amounts were determined based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by Everest, or specifically identified invoices processed, depending on the nature of the cost. For the six months ended June 30, 2014, we incurred $2.5 million in expenses and, as of June 30, 2014, owed $0.5 million under these arrangements. For the years ended December 31, 2013 and 2012, we incurred total costs under these arrangements of $25.3 million and $15.6 million, respectively, and, as of December 31, 2013 and December 31, 2012, owed $0.7 million and $0.7 million, respectively, under these arrangements. To the extent these services continue after the completion of this offering, we intend to enter into written services agreements on substantially the same terms as those described above.

SG Holdings I, LLC, or SG Holding, an affiliate of Wexford, has historically provided office space and certain technical, administrative and payroll services to us, and we have reimbursed SG Holding in amounts determined by it based on estimates of the amount of office space provided and the amount of employees’ time spent performing services for us. The reimbursement amounts were determined based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by SG Holding, or specifically identified invoices processed depending on the nature of the cost. For the six months ended June 30, 2014, we incurred $0.3 million in expenses and, as of June 30, 2014, we owed $0.4 million under these arrangements. For the years ended December 31, 2013 and 2012, we incurred total costs under these arrangements of $0.7 million and $0.4 million, respectively, and, as of December 31, 2013 and December 31, 2012, owed $0.3 million and $0.3 million, respectively, under these arrangements. To the extent these services continue after the completion of this offering, we intend to enter into written services agreements on substantially the same terms as described above.

From time to time, we pay for goods and services on behalf of certain affiliates of Wexford, and certain of these affiliates pay for goods and services on our behalf. For the six months ended June 30, 2014, we incurred $0.03 million in costs related to these transactions. For years ended December 31, 2013 and 2012, we incurred $0.6 million and $0.4 million, respectively. As of June 30, 2014, these affiliates did not owe us any amounts and we owed them an aggregate of $0.5 million. At December 31, 2013 and 2012, these Wexford affiliates owed us an aggregate of $0.0 and $0.2 million, respectively, and we owed them an aggregate of $1.2 million and $1.1 million, respectively, under these arrangements.

Wexford provides certain administrative and analytical services to companies under common control. For the years ended December 31, 2013 and 2012, we incurred $0.3 million and $0.07 million, respectively. As of December 31, 2013 and 2012, we owed Wexford $0.03 million and $0.2 million, respectively.

The Stingray entities were formed in March 2012 and November 2012, respectively. Since their formation, the Stingray entities have provided Gulfport with hydraulic fracturing services and equipment rentals in the Utica Shale in Ohio. In December 2013, the Stingray entities entered into a master services agreement with Gulfport. Gulfport agreed to use Stingray Pressure Pumping’s services (or pay liquidated damages if it fails to do so), and Stingray was obligated to provide such services, for a specified number of well fracing stages each year in certain Ohio counties if Gulfport drills and/or completes wells in these counties. The agreement provided for a primary term expiring on November 15, 2015 in the case of hydraulic fracturing services and January 1, 2016 in the case of each service other than our hydraulic fracturing. The master services agreement could be terminated by Gulfport at any time by giving the applicable Stingray entity written notice. Additionally, Gulfport could, without liability, countermand any work order given to the applicable Stingray entity at any time before it begin such

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work. If the work had already begun such work, then Gulfport could still cancel the service at any time, being liable only for the value of the work performed prior to the cancellation. The applicable Stingray entity could terminate the master service agreement by giving Gulfport written notice prior to receiving a notification from Gulfport to perform a specific service. For the six months ended June 30, 2014, the Stingray entities recognized revenue of approximately $60.8 million and had receivables of $13.6 million as of June 30, 2014. For the year ended December 31, 2013 and the period from March 20, 2012 through December 31, 2012, all of the Stingray entities revenue recognized was provided to Gulfport. As of December 31, 2013 and December 31, 2012, Gulfport owed the Stingray entities $8.2 million and $5.3 million, respectively, for these services.

In September 2014, effective October 1, 2014, Gulfport entered into an amended and restated master services agreement for pressure pumping services with Stingray Pressure Pumping. Pursuant to this agreement, Stingray Pressure Pumping has agreed to provide hydraulic fracturing, stimulation and related completion and rework services to Gulfport, dedicating two frac spreads and related equipment for the performance of these services. Gulfport has agreed to pay Stingray Pressure Pumping a monthly service fee plus the associated costs of the services provided. Gulfport and Stingray Pressure Pumping have each agreed to maintain insurance at certain minimum thresholds. This agreement has a term ending on September 30, 2018 and includes, among others, confidentiality and non-solicitation provisions. This agreement may be terminated in the event of a covenant breach by either party on 45 days written notice and a failure to cure. Stingray Pressure Pumping may also terminate in the event of payment default by Gulfport.

Since the formation of the Stingray entities, Gulfport has provided the Stingray entities with certain office space and IT, accounting, administrative and payroll services and employees and the Stingray entities have reimbursed Gulfport in an amount determined by Gulfport based on estimates of the amount of office space provided and the amount of its employees’ time spent performing services for the Stingray entities. The reimbursement amounts were determined based upon underlying salary costs of Gulfport employees performing Stingray entities related functions, payroll, revenue or headcount, or specific invoices processed, depending on the nature of the cost. For the six months ended June 30, 2014, the Stingray entities incurred total costs of approximately $0.0 million, and did not have a payable amount. For the year ended December 31, 2013 and the period from March 20, 2012 through December 31, 2012, the Stingray entities incurred total costs of $0.4 million and $1.8 million, respectively, under this arrangement. As of December 31, 2013 and December 31, 2012, the Stingray entities owed Gulfport $0.0 and $0.9 million, respectively, for these services.

The Company also rented certain equipment used in its hydraulic fracturing operations from Stingray Energy Services LLC. These amounts totaled $0.05 million for the six months ended June 30, 2014. As of June 30, 2014 and December 31, 2013, related party accounts payable included $0.1 million to this affiliate. The Company also pays certain other costs on behalf of the affiliate. At June 30, 2014 and December 31, 2013, related party accounts receivable included $2.4 million and $1.8 million, respectively.

The Company also provides certain management, administrative, and treasury functions to Stingray Cementing, LLC. The Company also pays certain other costs on behalf of the affiliate which are passed through to the affiliate. At June 30, 2014 and December 31, 2013, accounts receivable due from the affiliate were $0.8 million and $1.0 million, respectively. In November of 2012, certain equipment was purchased for the Company and paid for by this affiliate resulting in a $0.09 million payable to the affiliate at June 30, 2014 and December 31, 2013.

The Stingray entities also are parties to an agreement to purchase equipment from an affiliate of Wexford. For the year ended December 31, 2013 and the year ended December 31, 2012, the Stingray entities purchased equipment and/or made deposits for equipment not yet delivered in the aggregate amounts of $10.3 million and $0.0 million, respectively. The Stingray entities also contracted for repairs and maintenance services with an affiliate of Wexford and, for the year ended December 31, 2013 and for the period from March 20, 2012 (inception) through December 31, 2012, the cost of such services were $1.7 million and $0.2 million, respectively. As December 31, 2013 and 2012, the Stingray entities owed this affiliate $2.0 million and $0.2 million, respectively. For the six months ended June 30, 2014, purchases totaled $2.1 million and costs incurred for repairs and maintenance were $0.3 million.

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Procedures for Review, Approval and Ratification of Transactions with Related Persons

We expect that the board of directors of our general partner will adopt policies for the review, approval and ratification of transactions with related persons. We anticipate the board will adopt a written code of business conduct and ethics, under which a director would be expected to bring to the attention of the chief executive officer or the board any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Historically, the review and approval of related party transactions have been the responsibility of our management, and all of the transactions and agreements disclosed in this section have been approved by our management, subject to a conflicts of interest policy set forth in our employee handbook, pursuant to which all of our employees must avoid any situations where their personal outside interest could conflict, or even appear to conflict, with the interests of the Partnership. Although our management believes that the terms of the related party transactions described above are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties.

Please see “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest” for additional information regarding the relevant provisions of our partnership agreement.

The code of business conduct and ethics described above will be adopted in connection with the closing of this offering, and as a result, the transactions described above were not reviewed according to such procedures.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership. 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 replace them with contractual standards. Our partnership agreement also specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law.

When our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning it must not act in a manner that it believes is adverse to our interests. This duty to act in good faith is the default standard set forth under our partnership agreement and our general partner will not be subject to any higher standard.

Our partnership agreement specifies decisions that our general partner may make in its individual capacity, and permits our general partner to make these decisions free of any contractual or other duty to us or our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment of the partnership agreement.

When the directors and officers of our general partner cause our general partner to manage and operate our business, the directors and officers must cause our general partner to act in a manner consistent with our general partner’s applicable duties. However, the directors and officers of our general partner have fiduciary duties to manage our general partner, including when it is acting in its capacity as our general partner, in a manner beneficial to Wexford or Gulfport.

Conflicts may arise as a result of the duties of our general partner and its directors and officers to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. Where the directors and officers of our general partner are causing our general partner to act in its capacity as our general partner, the directors and officers must cause the general partner to act in good faith, meaning they cannot cause the general partner to take an action that they believe is adverse to our interests. However, where a decision by our general partner in its capacity as our general partner is not clearly not adverse to our interest, the directors of our general partner may determine to submit the determination to the conflicts committee for review or to seek approval by the unitholders, as described below.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its directors, executive officers and owners (including Wexford) and other affiliates (including Gulfport), on the one hand, and us and our limited partners, on the other hand.

Whenever a conflict arises between our general partner or its owners, on the one hand, and us or our limited partners, on the other hand, the resolution, course of action or transaction in respect of such conflict of interest shall be conclusively deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action or transaction in respect of such conflict of interest is:

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approved by the conflicts committee of our general partner; or

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approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

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Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, all determinations, other actions or failures to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be presumed to be “in good faith,” and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Please see “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

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amount and timing of asset purchases and sales;

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cash expenditures;

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borrowings;

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entry into and repayment of current and future indebtedness;

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issuance of additional units; and

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the creation, reduction or increase of reserves.

Our partnership agreement permits us to borrow funds to make a distribution, and further provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.

The directors of our general partner who are also officers or directors of Wexford or Gulfport have a fiduciary duty to make decisions in the best interests of the owners of Wexford or Gulfport, which may be contrary to our interests.

Certain directors of our general partner are also officers or directors of Wexford or Gulfport. These officers and directors have fiduciary duties to Wexford or Gulfport that may cause them to pursue business strategies that disproportionately benefit Wexford or Gulfport or which otherwise are not in our best interests.

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.

Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general

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partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the Partnership or amendment of the partnership agreement.

Our partnership agreement restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that have the effect of restricting the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

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our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it did not believe that the decision was adverse to our interests;

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our general partner and its officers and directors will not be liable for monetary damages or otherwise to us or our limited partners for any losses sustained or liabilities incurred as a result of the general partner’s, officer’s or director’s determinations, acts or omissions in their capacities as general partner, officers or directors, 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 the conduct of our general partner or such officer or director engaged by it in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and

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in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith.

Furthermore, 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. By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please see “—Fiduciary Duties” and “The Partnership Agreement.”

Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

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

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

•

expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

•

preparing and transmitting tax, regulatory and other filings, periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

•

acquiring, disposing, mortgaging, pledging, encumbering, hypothecating, or exchanging our assets or merging or otherwise combining us with or into another person;

•

negotiating, executing and performing contracts, conveyance or other instruments;

•

distributing cash;

•

selecting or dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

•

maintaining insurance for our benefit;

•

forming, acquiring an interest in, and contributing property and loaning money to, any further limited partnerships, joint ventures, corporations, limited liability companies or other entities;

•

controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

•

indemnifying any person against liabilities and contingencies to the extent permitted by law;

•

purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing additional options, rights, warrants, appreciation rights, phantom or tracking interests relating to our partnership interests; and

•

entering into agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please see “The Partnership Agreement” for information regarding the voting rights of unitholders.

Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.

We will reimburse our general partner and certain of its affiliates (including Wexford) for the costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine such other expenses that are allocable to us, and neither the partnership agreement nor the advisory services agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. Please see “Certain Relationships and Related Party Transactions—Agreements and Transactions with Affiliates in Connection with this Offering.”

Common units are subject to our general partner’s call right.

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market price calculated in accordance with the terms of our partnership agreement. 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your 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 call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please see “The Partnership Agreement—Limited Call Right.”

We may choose to not retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is 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 and Gulfport may compete with us for investment opportunities and may own an interest in entities that compete with us. 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 and 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.

Duties of the General Partner

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions that eliminate the fiduciary duties that might otherwise be owed by our general partner and replaces them with various contractual standards governing the duties of our general partner and any contractual methods of resolving conflicts of interest. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in

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addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these provisions, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The provisions enable our general partner to take into consideration all parties involved in the proposed action. These provisions also strengthen the ability of our general partner to attract and retain experienced and capable directors. These provisions disadvantage our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests. The following is a summary of:

•

the default fiduciary duties imposed on general partners of limited partnerships by the Delaware Act in the absence of partnership agreement provisions to the contrary;

•

the contractual standards contained in our partnership agreement that replace the default fiduciary duties; and

•

certain rights and remedies of limited partners with respect to these contractual duties.

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it believed its actions or omissions were not adverse to our interests, and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards replace the obligations to which our general partner would otherwise be held.

If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general partner or its affiliates, and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, its board, which may include board members affected by the conflict of interest, 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

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overcoming such presumption and proving that such decision was not in good faith. These standards replace the obligations to which our general partner would otherwise be held.

Rights and remedies of limited partners

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its reliance on the provisions of our partnership agreement.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct of our general partner or such officer or director engaged by it in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please see “The Partnership Agreement—Indemnification.”

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PRINCIPAL AND SELLING UNITHOLDERS

The following table sets forth certain information with respect to the beneficial ownership of our common units by:

•

the selling unitholders;

•

each unitholder known by us to be the beneficial owner of more than five percent of the outstanding common units;

•

each of our directors;

•

each of our named executive officers; and

•

all of our directors and executive officers as a group.

Except as otherwise indicated, we believe that each of the unitholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned.

Common Units
Beneficially Owned
Prior to Offering⁽¹⁾

Common Units
Beneficially Owned
After Offering⁽¹⁾

Common Units
Beneficially Owned
After Offering if the
Underwriters’ Over-
allotment Option Is
Exercised in Full⁽¹⁾

Name of Beneficial Owner

Number

Percentage

Number

Percentage

Number

Percentage

Selling Unitholders and other 5% Unitholders:

Mammoth Energy Holdings LLC⁽²⁾

Gulfport Energy Corporation

Rhino Resource Partners LP

Executive Officers and Directors:

Marc McCarthy

Phil Lancaster

Mark Layton

Spencer D. Armour, III*

Aaron Gaydosik*

Joseph M. Jacobs*

Kenneth A. Robin*

All executive officers and directors as a group ( persons)

*	Director nominee.

(1)

Percentage of beneficial ownership is based upon common units outstanding as of , 2014, and common units outstanding after the offering. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any common units which such person has the right to acquire within 60 days. For purposes of computing the percentage of outstanding common units held by each person or group of persons named above, any security that such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our unitholders may differ.

(2)

Wexford is the manager of Mammoth Energy Holdings LLC, which is one of the selling unitholders in this offering. The number of common units to be sold in the offering by Mammoth Energy Holdings LLC includes up to common units that will be sold if the underwriters exercise their over-allotment option in full. As manager of Mammoth Energy Holdings LLC, Wexford has the exclusive authority to, among other things, purchase, hold and dispose of its assets, including the common units that will be owned by Mammoth Energy Holdings LLC. Wexford may, by reason of its status as manager of Mammoth Energy Holdings LLC, be deemed to beneficially own the interest in the common units owned by Mammoth Energy Holdings LLC. Each of Charles E. Davidson and Joseph M. Jacobs may, by reason of his status as a controlling person of Wexford, be deemed to beneficially own the interests in the common units owned by

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Mammoth Energy Holdings LLC. Each of Charles E. Davidson, Joseph M. Jacobs and Wexford share the power to vote and to dispose of the interests in the common units owned by Mammoth Energy Holdings LLC. Each of Messrs. Davidson and Jacobs disclaims beneficial ownership of the common units owned by Mammoth Energy Holdings LLC and Wexford. Wexford’s address is Wexford Plaza, 411 West Putnam Avenue, Greenwich, Connecticut 06830.

Each of the selling unitholders in this offering is deemed to be an underwriter within the meaning of Section 2(a)(11) of the Securities Act.

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DESCRIPTION OF OUR COMMON UNITS

Our Common Units

The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the relative rights and privileges of holders of our common units to partnership distributions, please see “How We Will Make Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please see “The Partnership Agreement.”

Transfer Agent and Registrar

will serve as registrar and transfer agent for our common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

•

special charges for services requested by a holder of a common unit; and

•

other similar fees or charges.

There is no charge to our unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

•

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

•

gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

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Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Listing

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

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide investors and prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•

with regard to the duties of our general partner, please see “Conflicts of Interest and Fiduciary Duties”;

•

with regard to the transfer of common units, please see “Description of Our Common Units—Transfer of Common Units”; and

•

with regard to allocations of taxable income and taxable loss, please see “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

We were originally formed in February 2014 in Delaware as a corporation and converted to a Delaware limited partnership in August 2014. We will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of providing oil field services, our general partner may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Adjustments to Capital Accounts Upon Issuance of Additional Common Units

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will generally allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders prior to such issuance on a pro rata basis, so that after such issuance, the capital account balances attributable to all common units are equal.

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that call for the approval of a “unit majority” require the approval of a majority of the common units.

At the closing of this offering, Wexford and Gulfport will have the ability to ensure passage of, as well as the ability to ensure the defeat of, any amendment which requires a unit majority by virtue of their combined % beneficial ownership of our common units.

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In voting their common units, our general partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners. The holders of a majority of the common units (including common units deemed owned by our general partner) represented in person or by proxy shall constitute a quorum at a meeting of such common unitholders, unless any such action requires approval by holders of a greater percentage of such units in which case the quorum shall be such greater percentage.

The following is a summary of the vote requirements specified for certain matters under our partnership agreement.

Issuance of additional units

No approval right.

Amendment of the partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please see “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. Please see “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

Dissolution of our partnership

Unit majority. Please see “—Dissolution.”

Continuation of our business upon dissolution

Unit majority. Please see “—Dissolution.”

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2024 in a manner that would cause a dissolution of our partnership. Please see “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner

Not less than 66 2/3 % of the outstanding common units, including common units held by our general partner and its affiliates. Please see “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest

No approval right. Please see “—Transfer of General Partner Interest.”

Transfer of ownership interests in our general partner

No approval right. Please see “—Transfer of Ownership Interests in the General Partner.”

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

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Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

•

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

•

brought in a derivative manner on our behalf;

•

asserting a claim of breach of a duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

•

asserting a claim arising pursuant to any provision of the Delaware Act; or

•

asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims and irrevocably waives the right to trial by jury.

If any person brings any of the aforementioned claims, suits, actions or proceedings 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.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

•

to remove or replace our general partner;

•

to approve some amendments to our partnership agreement; or

•

to take other action under our partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could 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. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

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Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distrib

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