Confidential Draft Registration Statement (Submission No. 2)

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BY EMERGING GROWTH COMPANY PURSUANT TO SECTION 6(e) OF THE SECURITIES ACT OF 1933

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

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

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):

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 stockholders 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.

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

We anticipate that the initial public offering price of our common stock will be between $ and $ per share. We intend to apply for listing of our common stock on The NASDAQ Global Market under the symbol “SRAY.”

The underwriters have an option to purchase an additional shares of our common stock, of which shares would be sold by us and shares would be sold by the selling stockholders, to cover any overallotments.

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 stock involves risks. See “Risk Factors” beginning on page 15.

Delivery of the shares of common stock is expected to be made on or about , 2014 through the book-entry facilities of The Depositary 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.

You should rely only on the information contained in this prospectus. We have not, and the selling stockholders 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 stockholders and the underwriters are only offering to sell, and only seeking offers to buy, our common stock 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 stock. 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. 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.” Stingray Energy Services, Inc. (formerly known as Redback Inc.) was incorporated in February 2014 in Delaware as a holding company and will not conduct any material business operations prior to the transactions described below. Except as expressly noted otherwise, the historical financial information included in this prospectus is that of Redback Energy Services LLC, Redback Coil Tubing LLC, Muskie Proppant LLC, Panther Drilling Systems LLC, Bison Drilling & Field Services LLC, Bison Trucking LLC and Great White Sand Tiger Lodging Ltd., all of which have been controlled and managed by our equity sponsor, Wexford Capital LP, or Wexford, and which are sometimes referred to in this prospectus as the common control entities. Prior to the effectiveness of the registration statement of which this prospectus is a part, these entities will be contributed to us in return for shares of our common stock and, as a result, will become our wholly-owned subsidiaries. At the same time, four other entities, Stingray Pressure Pumping LLC, Stingray Cementing LLC, Stingray Logistics LLC and Stingray Energy Services LLC, which we collectively refer to in this prospectus as the Stingray entities, will be contributed to us in return for shares of our common stock, 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 our historical combined financial statements, but instead is presented in this prospectus on a pro forma basis. As a result, our historical financial information included in this prospectus will not be indicative of the results 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 “Stingray Energy,” the “Company,” “we,” “us” or “our,” and its assets and operations, relate to Stingray Energy Services, Inc. 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.

STINGRAY ENERGY SERVICES, INC.

Overview

We are a diversified oilfield service company providing services to companies engaged in the exploration and development of North American onshore unconventional oil and natural resources. Our suite of services include completion and production services, contract land and directional drilling services and remote accommodation services. To extract unconventional resources, 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. We use our equipment to drill and complete those horizontal wells. We believe that services such as ours are critical in increasing the ultimate recovery and present value of production streams for 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 completion and production services division provides pressure pumping services, pressure control services, flowback services and equipment rental, as well as production and sales of proppant for hydraulic fracturing.

Our pressure pumping services consist of hydraulic fracturing and well cementing services. These services are primarily used in optimizing 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 April 30, 2014, we had grown our pressure pumping business to 52 high pressure fracturing units capable of delivering a total of 117,000 horsepower. These units allow us to execute multi-stage hydraulic fracture stimulation on unconventional wells, which enhances production. Currently, we provide pressure pumping services in the Utica Shale of Eastern Ohio.

Our pressure control services consist of coiled tubing, nitrogen and fluid pumping services. Our pressure control services equipment is tailored to servicing unconventional resources 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. As of January 31, 2014, our pressure control services were provided through our fleet of four coiled tubing units, four nitrogen pumping units, eight 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 and the Utica Shale in Ohio. We provide flowback services in the mid-continent markets.

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 six well-testing spreads. We provide flowback services in the Appalachian Basin and mid-continent markets.

Our equipment rental services provide a wide range of premium rental equipment used in pressure control, flowback and hydraulic fracturing services. In addition, we provide heavy-lift crane services and services associated with the transfer of fresh water to the well site. Our equipment rentals consist of two heavy-lift cranes, 17.5-miles of water transfer equipment, forklifts, manlifts, generators, light plants, rig mats 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, 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 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

Our contract land and directional drilling services division provides operating drilling rigs and crews for operators as well as rental equipment, such as motors and operational tools, for both vertical and horizontal drilling.

As part of our contract land drilling services, we provide both vertical and horizontal drilling for our customers. As of December 31, 2013, we owned and operated eight land drilling rigs, ranging from 800 to 1,500 horsepower, five 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. In January 2014, we acquired five additional horizontal drilling rigs to complement our existing fleet and, as of April 30, 2014, had a total of 13 drilling rigs. Our marketable drilling rigs, including these newly acquired 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 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 and our services allow 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 to the management and execution of the horizontal or directional drilling operation. As of April 30, 2014, we owned six MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 29 motors and an inventory of parts and other equipment. At that date, we employed 12 directional drillers 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 Louisiana Gulf.

Remote Accommodation Services

Our remote accommodation business consists of oilfield related remote accommodation services. Our remote accommodations services provide housing for oilfield related labor 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 and dining facilities and recreation areas. Currently, we provide remote accommodation services in the Canadian Oil Sands in Alberta, Canada.

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:

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Increased U.S. Crude Oil Production. According to the EIA, U.S. crude oil production reached approximately 10.0 million barrels per day at the end of 2013, an increase of approximately 12% over 2012. U.S. 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 March 31, 2014 was 1,211, or more than 66% of the total U.S. onshore rig count. This compares to 337 horizontal rigs, or less than 20% 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 0.38 million barrels per day in 2007 to almost 3.5 million barrels per day in 2013, and now represents 35% of total U.S. crude oil production. 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 the 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 April 30, 2014, oil and liquids focused rigs accounted for over 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. 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 are also 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 business strategy is to leverage our equipment and personnel to provide drilling, completion and production services and remote accommodation services in unconventional resource plays. These services optimize the ultimate recovery and present value of hydrocarbon reserves in the unconventional resource plays that we serve. We believe that our services provide cost efficiencies for our customers. Specifically, we intend to:

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Capitalize on the increased activity in the unconventional resource plays. Our equipment is tailored 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 capturing the anticipated 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 this and other unconventional resource basins and will look to capture 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 completion and production and remote accommodations business as determined by demand. In 2013 and early 2014, we expanded our drilling business with the acquisition of five electric horizontal drilling rigs in a transaction we refer to as the Drilling Transaction, expanded our completion and production business by 72,000 horsepower and purchased additional remote accommodation rooms in response to increased customer demand, and expect to have a total of 700 remote accommodation rooms by mid-2014. We intend to continue to expand our business lines as demand increases in resource plays in which we currently operate, as well as new resource plays. If there is demand for another service line in one of our principal geographic locations, we will seek to expand our current service offerings to meet that demand. For instance, if the price for unconventional completions increases in the Permian Basin in West Texas, we will look to add units and increase horsepower in that region to complement our existing completion and production services in the region.

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Leverage our broad range of services for unconventional wells. We offer a complementary suite of services relating to the drilling and completion and production of unconventional wells. Our completion and production division provides pressure pumping services, pressure control services and flowback services for unconventional wells and includes production and sales of proppant. Our drilling services division adds drilling capabilities to our other well-related services. These complementary business lines provide us with the opportunity to cross sell our services and expand our service offerings to existing customers, obtain new customers and expand our geographic presence. We intend to continue to expand our services in an effort to increase cross selling opportunities and create operational efficiencies for our customers.

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Capitalize on organic growth opportunities. We intend to use our existing customer relationships, cross selling of services and operational track record to expand opportunistically to other geographic regions in which our customers have operations. In addition, we believe our reputation will allow us to successfully expand our customer base and geographic presence.

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Expand through selected acquisitions. To complement our organic growth, we intend to actively pursue selected acquisitions of complementary businesses 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, in January 2014, we acquired five electric horizontal drilling rigs which increased our fleet of drilling rigs to a total of 13, ten 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.

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Leverage our experienced operational management team and basin-level expertise. We seek to manage our business as close to our customer base as possible. Our operational division heads have an average of over 26 years of experience in the oilfield service business. These members of our management team have long-term customer relationships with our largest customers. We intend to leverage our operational management team’s basin-level expertise to deliver innovative, 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. Our service fleet is predominantly comprised of equipment that has been tailored to provide services for unconventional wells. As of April 30, 2014, approximately 65% of our pressure pumping equipment had been built within the last twelve months. Most of our pressure control equipment has been designed and built by us and is less than two years old. We have built eight of our 13 drilling rigs to meet the specific needs of operators in the Permian Basin. Our accommodations units have an average age of approximately three years and are built on a customer-by-customer basis as new build contracts are awarded. We believe that our equipment will allow us to provide a high level of service to our customers and capture 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. We believe their knowledge of our industry and business lines enhances our ability to provide a high level of customer service. In addition, our field managers have expertise in the geological basins in which they operate and understand the regional challenges that our customers face, which we believe strengthens our relationships with our customers.

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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 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. Our operations are primarily focused in the growing oil and natural gas liquids resource plays. We believe our geographic positioning provides us with both a more stable revenue stream and access to higher growth 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 will 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.

Risk Factors

Investing in our common stock involves risks. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 15 for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

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

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Difficulties managing the growth of our business may adversely affect our financial condition and results of operations.

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

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

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

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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.

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

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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 and financial condition.

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

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

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Our two largest stockholders control a significant percentage of our common stock and their interests may conflict with yours.

For a discussion of other considerations that could negatively affect us, see “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Our Equity Sponsor

We were formed by our equity sponsor, Wexford Capital LP, or Wexford, which is a Greenwich, Connecticut-based Securities and Exchange Commission, or SEC, registered investment advisor with approximately $3.9 billion under management as of December 31, 2013. Wexford has made public and private equity investments in many different sectors and has particular expertise in the energy and natural resources sector. 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. We are also party to certain other agreements

with Wexford and its affiliates. For a description of the advisory services agreement and other agreements with Wexford and its affiliates, see “Related Party Transactions” beginning on page 94 of this prospectus. Although our management believes that the terms of these related party agreements are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties. The existence of these related party agreements may give Wexford the ability to further influence and maintain control over many matters affecting us.

Our History and the Contribution Transactions

Stingray Energy Services, Inc. was incorporated in February 2014 in Delaware as a holding company and will not conduct any material business operations prior to the transactions described below. Except as expressly noted otherwise, the historical financial information included in this prospectus is that of Redback Energy Services LLC, or Redback Energy Services, Redback Coil Tubing LLC, or Redback Coil Tubing, Muskie Proppant LLC, or Muskie Proppant, Panther Drilling Systems LLC, or Panther Drilling, Bison Drilling & Field Services LLC, or Bison Drilling, Bison Trucking LLC, or Bison Trucking, and Great White Sand Tiger Lodging Ltd., or Sand Tiger, all of which have been controlled and managed by our equity sponsor, Wexford, and which are sometimes referred to in this prospectus as the common control entities. Prior to the completion of this offering, Wexford will cause all of the outstanding equity interests in these seven entities controlled by Wexford to be contributed to us in exchange for shares of our common stock. Wexford and Gulfport Energy Corporation, or Gulfport, each currently beneficially own a 50% interest in four other entities, Stingray Pressure Pumping LLC, or Stingray Pressure Pumping, Stingray Cementing LLC, or Stingray Cementing, Stingray Logistics LLC, or Stingray Logistics, and Stingray Energy Services LLC, or Stingray Energy Services. Wexford and Gulfport will also contribute all of the outstanding equity interest in these four entities in return for additional shares of our common stock. Upon completion of this offering, assuming Wexford, Gulfport and their respective affiliates make no additional purchases of our common stock, Wexford and Gulfport will beneficially own approximately % and %, respectively, of our common stock (approximately % and %, respectively, if the underwriters’ option to purchase additional shares is exercised in full). As a result, Wexford and Gulfport will be able to exercise control over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and corporate transactions. We refer to the contribution of the capital stock 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 are not under common control with the other seven entities to be contributed to us in connection with this offering, the historical financial information of the Stingray entities is not reflected in our historical combined financial statements, but instead is presented in this prospectus on a pro forma basis. As a result, our historical financial information for the years ended December 31, 2013 and 2012 will not be indicative of the results 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.

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, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. 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 Related to this Offering and our Common Stock—We are an ‘emerging growth company’ and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors” on page 35 of this prospectus.

Our Offices

Our principal executive offices are located at 14301 Caliber Drive, Suite 300, Oklahoma City, OK 73134, and our telephone number at that address is (405) 265-4600. Our website address is www.stingrayenergyservices.com. Information contained on our website does not constitute part of this prospectus.

The Offering

Common stock offered by us

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

Common stock offered by the selling stockholders

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

Common stock to be outstanding immediately after completion of this offering

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 corporate purposes, which may include the acquisition of additional equipment and complementary businesses. We will not receive any proceeds from the sale of shares by the selling stockholders. See “Use of Proceeds.”

Dividend policy

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future.

Directed Share Program

At our request, the underwriters have reserved up to % of the common stock 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 share program. We do not know if these persons will choose to purchase all or any portion of this reserved common stock, but any purchases they do make will reduce the number of shares available to the general public. To the extent the allotted shares are not purchased in the directed share program, we will offer these shares 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 stock will be prohibited from selling such stock for a period of 180 days after the date of this prospectus.

Listing symbol

We intend to apply to list our shares of common stock on The NASDAQ Global Market under the symbol “SRAY.”

Risk Factors

You should carefully read and consider the information beginning on page 15 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 stock.

Except as otherwise indicated, all information contained in this prospectus:

•

assumes the underwriters do not exercise their over-allotment option; and

•

excludes shares of common stock reserved for issuance under our equity incentive plan.


	Pro Forma	Historical
	Year Ended December 31,	Year Ended December 31,
	2013	2013			2012
	(in thousands, except per share data)
Statement of Operations Data:
Revenue:
Completion and production services	$	$	47,731		$	16,892
Contract land and directional drilling services			59,790			26,842
Remote accommodation services			25,027			14,169

Total			132,548			57,903

Cost of revenue, excluding depreciation, amortization and impairment:
Completion and production services			42,627			13,764
Contract land and directional drilling services			53,987			20,501
Remote accommodation services			11,416			7,333
Selling, general and administrative expenses			13,614			6,443
Depreciation and amortization			18,995			8,149
Impairment of long-lived assets			938			2,435

Total			141,577			58,625

Operating loss			(9,029	)		(722	)
Interest expense			(2,013	)		(274	)
Other income (expense), net			(215	)		(49	)

Loss before income taxes			(11,257	)		(1,045	)
Provision for income taxes			2,715			1,013

Net loss	$	$	(13,972	)	$	(2,058	)

Pro Forma C Corporation Data⁽¹⁾(unaudited):
Historical loss before income taxes	$	$	(11,257	)	$	(1,045	)
Pro forma provision benefit for income taxes			401			676

Pro forma net loss	$	$	(11,658	)	$	(1,721	)

Pro forma income (loss) per common share—basic and diluted	$	$

Weighted average pro forma shares outstanding—basic and diluted⁽²⁾

Other Financial Data:
Adjusted EBITDA⁽³⁾ (unaudited)	$	$	10,904		$	9,862

Cash flows provided by operating activities	$	$	4,162		$	4,791

Purchases of property and equipment	$	$	(63,956	)	$	(71,584	)
Other investing activities, net			634			—

Cash flows used in investing activities	$	$	(63,322	)	$	(71,584	)

Capital contributions	$	$	26,979		$	59,114
Proceeds from financing arrangements, net of repayments			31,966			13,959
Other financing activities, net			(361	)		(115	)

Cash flows provided by financing activities:	$	$	58,584		$	72,958


	Pro Forma	Historical
	As of December 31, 2013	As of December 31,
	As of December 31, 2013	2013		2012
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
Shareholders’ and members’ equity			120,714		108,797

Total liabilities and shareholders’ and members’ equity	$	$	202,643	$	148,502

(1)

Stingray Energy Services, Inc. was incorporated on February 2014 in Delaware as a holding company and will not conduct any material business operations prior to the contribution of the common control entities and the Stingray entities to us prior to the completion of this offering. The historical combined financial statements and other financial information included in this prospectus pertain to assets, liabilities, revenues and expenses of Redback Energy Services, Redback Coil Tubing, Muskie Proppant, Panther Drilling, Bison Drilling, Bison Trucking and Sand Tiger, or the common control entities, which are entities under the common control of our equity sponsor, Wexford. Except for Sand Tiger, each of the common control entities was treated as a partnership for federal income tax purposes. As a result, essentially all of their taxable earnings and losses were passed through to Wexford, and such entities did not pay federal income taxes at the entity level. Prior to the completion of this offering, all of these entities will become our wholly-owned subsidiaries and, because we are a subchapter C corporation under the Internal Revenue Code, their earnings will become subject to federal income tax. For comparative purposes, we have included a pro forma financial data for the historical periods to give effect to income taxes assuming the earnings of these entities had been subject to federal income tax as a subchapter C corporation since inception. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date.

(2)

Unaudited pro forma basic and diluted income (loss) per share will be presented for the latest fiscal year and interim period on the basis of the aggregate number of shares to be issued in connection with the contribution to us of all of the outstanding equity interests in the common control entities, upon determination of the number of those shares.

(3)	Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss), see “Selected Historical Combined Financial Data” on page 44 of this prospectus.

An investment in our common stock 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 stock. 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.

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

Stingray Energy Services, Inc. was incorporated in Delaware in February 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 equity sponsor, Wexford, and the Stingray entities, which are entities currently beneficially owned 50% by each of Wexford and Gulfport. Immediately prior to the effectiveness of the registration statement of which this prospectus is a part, each of these entities will be contributed to us and will become our wholly-owned subsidiaries. Although Sand Tiger began operations in 2007, the ten other entities began operations between September 2011 and August 2013. 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.

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

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 oil and natural gas services industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to 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 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:

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 increases in revenues and profitability that we hope to realize.

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.

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:

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 low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per million British thermal units, or MMBtu, in April 2012 to a high of $13.31 per MMBtu in July 2008. 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 April 1, 2014, the West Texas Intermediate posted price for crude oil was $99.74 per Bbl and the Henry Hub spot market price of natural gas was $4.28 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:

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 and results of operations.

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

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.

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 and results of operation.

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 and cash flows. 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 buy raw sand under contracts with two suppliers, 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 and operating results.

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 and cash flows.

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. Until the past few years, the supply of raw frac sand had not kept pace with the increasing demand for raw frac sand, which contributed to steadily increasing prices for raw frac sand over the last decade. 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 further. 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 would likely have a material adverse effect on our results of operations and cash flows over the remaining term of this contract.

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

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

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 and cash flows. 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 and results of operations.

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, bovine spongiform encephalopathy or “mad cow disease,” hepatitis A, trichinosis or salmonella, and food safety issues have occurred in the food industry in the past and could occur in the future. We work to provide a clean, safe environment for our guests and employees and attempt to purchase supplies from reputable suppliers and distributors. Our reliance on third-party food suppliers and distributors increases the risk that food-borne illness incidents could be caused by factors outside of our control. New illnesses resistant to any precautions may develop in the future, or diseases with long incubation periods could 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 and results of operations.

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 and cash flows.

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 and cash flows.

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

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

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.

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.

A significant reduction by Wexford or Gulfport of their ownership interests in us could adversely affect us.

Immediately prior to the completion of this offering, Wexford and Gulfport will beneficially own % and %, respectively, of the Company’s equity interests. Upon completion of this offering, assuming neither of these stockholders nor their respective affiliates make any additional purchases of our common stock, Wexford and Gulfport will beneficially own approximately % and %, respectively, of our common stock, or % and %, respectively, if the underwriters exercise in full their option to purchase additional shares. See “Principal and Selling Stockholders” beginning on page 98 of this prospectus. Further, we anticipate that several individuals who will serve as our directors upon completion of this offering will be affiliates of Wexford and Gulfport. We believe that Wexford’s and Gulfport’s substantial ownership interests in us provides them with an economic incentive to assist us to be successful. Upon the expiration of the lock-up restrictions on transfers or sales of our

securities following the completion of this offering, neither Wexford nor Gulfport will be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Wexford or Gulfport sells all or a substantial portion of its ownership interest in us, it may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations.

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 and financial condition.

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. Our capital expenditures for 2014 are estimated to be approximately $106.5 million. To date, we have financed capital expenditures primarily with funding from our equity investors, cash generated by operations and borrowings under our revolving credit facilities and term loans from our lenders. Following the completion of this offering and the application of the net proceeds to repay our outstanding indebtedness, we intend to finance our capital expenditures primarily with cash on hand, cash flow from operations and borrowings under our revolving credit facilities. We may be unable to generate sufficient cash from operations and other capital resources to maintain planned or future levels of capital expenditures which, among other things, may prevent us from acquiring new equipment or properly maintaining our existing equipment. This could put us at a competitive disadvantage or interfere with our growth plans. Further, our actual capital expenditures for 2014 or future years could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount we have available, we could be required to seek additional sources of capital, which may include debt financing, joint venture partnerships, sales of assets, offerings of debt or equity securities or other means. We may not be able to obtain any such alternative source of capital. We may be required to curtail or eliminate contemplated activities. If we can obtain alternative sources of capital, the terms of such alternative may not be favorable to us. In particular, the terms of any debt financing may include covenants that significantly restrict our operations. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.

The growth of our business through acquisitions may expose us to various risks, including those relating to difficulties in identifying suitable 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 acquisitions of complementary assets, businesses and technologies. Acquisitions involve numerous risks, including:

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 stockholders. 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 and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

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 58.8% of our revenue, on a pro forma basis, for the year ended December 31, 2013. 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 could adversely affect our liquidity.

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:

Our revolving credit facilities impose restrictions on us that may affect our ability to successfully operate our business.

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

In addition, our revolving credit facilities and term debt 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 our revolving credit facility.

Our credit facilities 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 $95.7 million outstanding under various credit facilities at December 31, 2013, 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 by approximately $1.0 million per year. We do not currently hedge our interest rate exposure.

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 and results of operations.

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 year ended December 31, 2013, we generated approximately 56.1% of our 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:

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 and results of operations.

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 and cash flows.

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

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

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

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

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 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 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.

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 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 and cash flows.

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

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

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

Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria which could result in a suspension of operations. The rating scale consists of “satisfactory,” “conditional,” and “unsatisfactory” ratings. As of December 31, 2013, all of our trucking operations, except for Bison Trucking’s operations that have not yet been rated, have “satisfactory” ratings with the Department of Transportation.

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

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

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 and cash flows.

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

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

We maintain operational insurance coverage of types and amounts that we believe to be customary in the industry, including commercial general liability, workers’ compensation, business auto, excess auto liability, commercial property, motor truck cargo, umbrella liability and excess liability insurance policies. We are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risk. Further, any insurance obtained by us may not be adequate to cover any losses or liabilities and this insurance may not continue to be available at all or on terms which are acceptable to us. Insurance rates have in the past been subject to wide fluctuation and changes in coverage could result in less coverage, increases in cost or higher deductibles and retentions. See “Business—Operating Risks and Insurance” on page 78 of this prospectus 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 and results of operations.

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

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 and results of operation.

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, stock price and results of operations and financial condition 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 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 stock. 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.

Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

Upon completion of this offering, Wexford, through its affiliate Stingray Holdings LLC, and Gulfport will beneficially own approximately % and %, respectively, of our common stock, or % and %, respectively, if the underwriters exercise their over-allotment option in full. See “Principal and Selling

Stockholders” on page 98 of this prospectus. As a result, Wexford and Gulfport together, will be able to control, and Wexford alone, will continue to be able to exercise significant influence, over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Wexford and Gulfport with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. This continued concentrated ownership will make it impossible for another company to acquire us and for you to receive any related takeover premium for your shares unless these stockholders approve the acquisition.

We will incur increased costs as a result of being a public company, which may significantly affect our financial condition.

As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. We will incur costs associated with our public company reporting requirements. We also anticipate that we will incur costs associated with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, particularly after we are no longer an “emerging growth company.” We also expect these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

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, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. 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 stock 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.

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, stock price and results of operations and financial condition could be materially adversely affected” on page 33 of this prospectus.

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock 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, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

Under the Jumpstart Our Business Startups Act, “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.”

Since we are a “controlled company” for purposes of The NASDAQ Global Select Market’s corporate governance requirements, our stockholders will not have, and may never have, the protections that these corporate governance requirements are intended to provide.

Since we are a “controlled company” for purposes of The NASDAQ Global Select Market’s corporate governance requirements, we are not required to comply with the provisions requiring that a majority of our directors be independent, the compensation of our executives be determined by independent directors or nominees for election to our board of directors be selected by independent directors. If we choose to take advantage of any or all of these exemptions, our stockholders may not have the protections that these rules are intended to provide.

The corporate opportunity provisions in our certificate of incorporation could enable Wexford, our equity sponsor, or other affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.

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 stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. As described under the caption “Related Party Transactions” beginning on page 94 of this prospectus, 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 stockholders’ 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 “—Risks Related to this Offering and our Common Stock—Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders” on page 33 of this prospectus.

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

Prior to this offering, there has been no public market for our common stock. Although we intend to apply for a listing of our common stock on The NASDAQ Global Select Market, we cannot assure you that an active public market will develop for our common stock or that our common stock 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 stock does not develop, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock is less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock 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 stock after this offering. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

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 stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market after this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline. See “Shares Eligible for Future Sale” on page 102 of this prospectus. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock. After this offering, we will have shares of common stock outstanding, excluding stock options. All of the shares sold in this offering, except for any shares purchased by our affiliates, will be freely tradable.

Stingray Holdings LLC, Gulfport and our directors and executive officers will be subject to agreements that limit their ability to sell our common stock held by them. These holders cannot sell or otherwise dispose of any shares of our common stock for a period of at least 180 days after the date of this prospectus, which period may be extended under limited circumstances, without the prior written approval of the representative of the underwriters. However, these lock-up agreements are subject to certain specific exceptions. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

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

The trading market for our common stock 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 stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

Purchasers in this offering will experience immediate dilution and will experience further dilution with the future exercise of stock 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 share of our outstanding common stock. As a result, you will experience immediate and substantial dilution of approximately $ per share, representing the difference between our net tangible book value per share as of December 31, 2013 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 share (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 share after giving effect to this offering by $ , and increase (decrease) the dilution to new investors by $ , assuming the number of shares 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” beginning on page 43 of this prospectus for a description of dilution.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors

may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our stockholders.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our revolving credit facility prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

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:

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,” “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,” “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.

Our net proceeds from the sale of shares of common stock in this offering, assuming a public offering price of $ per share (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’ option to purchase additional shares 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:

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 corporate 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 share would cause the net proceeds that we will receive in this offering to increase or decrease by approximately $ million. If our net proceeds are reduced, we will have less proceeds and may not have sufficient funds to repay all outstanding borrowings, which would increase our interest expense and decrease our net income.

We will not receive any proceeds from the sale of shares by the selling stockholders, including any sale the selling stockholders may make upon exercise of the underwriters’ option to purchase additional shares.

Stingray Energy Services, Inc. has never declared or paid any cash dividends on its capital stock. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business and do not anticipate declaring or paying any cash dividends in the foreseeable future. Any future determination as to the declaration and payment of dividends will be at the discretion of our board of directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant. In addition, the terms of our existing outstanding borrowings restrict the payment of dividends to the holders of our common stock and any other equity holders.

The following table sets forth our cash and cash equivalents and capitalization as of December 31, 2013:

This table does not reflect the issuance of up to shares of our common stock that may be sold to the underwriters upon exercise of their option to purchase additional shares from us, 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” and our combined financial statements and related notes appearing elsewhere in this prospectus.

Dilution is the amount by which the offering price paid by the purchasers of our common stock sold in this offering will exceed the pro forma net tangible book value per share after the offering. Our reported net tangible book value as of December 31, 2013 was $ million, or $ per share, based upon shares outstanding as of that date after giving pro forma effect to the Contribution Transactions. Net tangible book value per share before the offering is determined by dividing the net tangible book value (total tangible assets less total liabilities) of the capital stock received in the Contribution Transactions by the number of shares of our common stock ( shares) to be issued to Wexford’s affiliate Stingray Holdings LLC and to Gulfport in connection with this offering and the Contribution Transactions. Assuming the sale by us of shares of common stock offered in this offering at an estimated initial public offering price of $ per share (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 December 31, 2013 would have been approximately $ million, or $ per share, after giving pro forma effect to the Contribution Transactions. This represents an immediate increase in net tangible book value of $ per share to our existing stockholders and an immediate dilution of $ per share to new investors purchasing shares at the initial public offering price.

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share (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 shares 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 December 31, 2013, after giving pro forma effect to the contribution to us of all of the outstanding equity interests in the Stingray entities, the number of shares of common stock to be issued by us in the contribution, the holders of which will be our existing stockholders immediately prior to the closing of this offering, and by the new investors at the assumed initial public offering price of $ per share, together with the total consideration paid and average price per share paid by each of these groups, before deducting underwriting discounts and commissions and estimated offering expenses.

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

The data in the table excludes shares of common stock reserved for issuance under our equity incentive plan.

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 our historical audited combined financial statements included elsewhere in this prospectus. The unaudited pro forma C Corporation financial data presented give effect to income taxes assuming we operated as a taxable corporation since inception. Operating results for the years ended December 31, 2013 and 2012 are not necessarily indicative of results that may be expected for the entire year 2013 or any future periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Pro Forma Financial Information” and our historical combined financial statements and related notes included elsewhere in this prospectus.

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

The following unaudited pro forma condensed combined financial statements and related notes of the Company have been prepared to show the effect of the Stingray Contribution and the Drilling Transaction. The unaudited pro forma condensed combined financial statements should be read together with the historical financial statements of Redback Energy Services, the historical financial statements of Stingray, and the Statements of Revenues and Direct Operating Expenses of Certain Drilling Rigs of Lantern Drilling Company included elsewhere in this prospectus. The accompanying unaudited pro forma condensed combined financial statements are based on assumptions and include 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 acquisition 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 contribution of the Stingray entities or the Drilling Transaction occurred on the dates indicated below.

The Stingray Contribution will be completed immediately prior to the effectiveness of the registration statement of which this prospectus is a part.

The unaudited pro forma condensed combined balance sheet assumes that the contribution of the Stingray entities and the Drilling Transaction occurred on December 31, 2013. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2013 assumes the contribution of the Stingray entities and the Drilling Transaction occurred on January 1, 2013.

The historical financial information is derived from the historical financial statements of Redback Energy Services and the historical financial statements of Stingray. The Drilling Transaction balance sheet information was prepared on the basis of the allocation of Bison’s purchase price of the assets acquired. The Drilling Transaction statement of operation information was derived from the Statements of Revenue and Direct Operating Expenses for Certain Drilling Rigs of Lantern Drilling Company. The unaudited pro forma condensed combined balance sheet as of December 31, 2013 has been prepared as if the contribution of the Stingray entities and the Drilling Transaction occurred on December 31, 2013. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2013 assumes that the contribution of the Stingray entities and the Drilling Transaction had occurred on January 1, 2013.

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

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.

We are a diversified oilfield service company providing completion and production, contract land and directional drilling and remote accommodation services, primarily in the North American onshore unconventional sands and shale oil and natural gas markets. 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.

Stingray Energy Services, Inc. (formerly known as Redback Inc.) was incorporated in February 2014 in Delaware as a holding company and will not conduct any material business operations prior to the transactions described below. Except as expressly noted otherwise, the historical financial information included in this prospectus is that of 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. Prior to the effectiveness of the registration statement of which this prospectus is a part, these entities will be contributed to us in return for shares of our common stock and, as a result, will become our wholly-owned subsidiaries. In addition, at the same time, four other entities, Stingray Pressure Pumping, Stingray Cementing, Stingray Logistics and Stingray Energy Services, 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 shares of our common stock, at which time these entities will also become our wholly-owned subsidiaries. The remaining 50% equity interests in the Stingray entities are currently owned by Gulfport. Because the Stingray entities are not under common control with the other four entities to be contributed to us in connection with this offering, the historical financial information of the Stingray entities is not reflected in our historical combined financial statements, but instead is presented in this prospectus on a pro forma basis. As a result, our historical financial information for the periods ended December 31, 2013 and 2012, will not be indicative of the results 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.

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

Our completion and production division provides equipment rental, flowback and pressure control services. We also produce custom natural sand proppant that is primarily used in hydraulic fracturing operations. Our contract land and directional drilling services division provides operating drilling rigs and crews for operators as well as rental equipment, such as 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 predominately independent oil and natural gas exploration and production companies, and oilfield service companies that use natural sand proppant for hydraulic fracturing. We have facilities and service centers that are strategically located to primarily serve resource plays in the Utica Shale in Eastern Ohio, the Permian Basin in West Texas, the Marcellus Shale in West Virginia and Pennsylvania, the Granite Wash in Okahoma and Texas, the Cana Woodford Shale and the Cleveland Sand in Oklahoma, and the oil sands in Alberta, Canada.

Our objective is to grow our business organically and through the acquisition of complementary companies. To achieve this objective, we plan to:

The following table sets forth selected operating data for the periods indicated. As described more fully above, five of the seven businesses within our operating divisions commenced operations in 2011, 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.

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 same period in 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 also 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 were 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 comparable period in 2012. The increase was primarily attributable to our directional drilling services business which 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 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 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 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 revenue, in 2013, compared to $6.3 million, or 23.6% of 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, 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 revenue, in 2013, compared to $6.8 million, or 48.2% of 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 10.2% in 2013, from 11.1% in 2012 due to the increase in our revenues.

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.

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. Our primary use of capital has been for investing in property and equipment used to provide our services. 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.

As of December 31, 2013, we had an aggregate of $46.0 million in borrowings outstanding under our credit facilities, leaving an aggregate of $7.7 million of available borrowing capacity under these credit facilities.

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.

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:

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.

On March 18, 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, or the March 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 March 17, 2014. The borrowing base under the March 2013 facility is 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) 6.00% per annum. In the event of default, the interest rate will be increased by adding an additional 5% per annum to the applicable interest rate, subject to interest rate limitations under applicable law. As of December 31, 2013, $0.8 million was outstanding under this facility, with an interest rate of 6% per annum.

The March 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 $25,000 without the lender’s prior written approval, (ii) restrict the use of the loan proceeds solely to working capital purposes, (iii) require maintenance of all operating accounts with the lender, (iv) require maintenance of a minimum combined debt service coverage ratio of 1.25 to 1 and a minimum $4.0 million tangible net worth and (v) 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. 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, or 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% per annum to the applicable interest rate, subject to interest rate limitations under applicable law. The facility matures on June 20, 2014. As of December 31, 2013, $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, 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 September 23, 2013, Redback Energy Services, as borrower, entered into an additional business loan agreement with Legacy Bank, as lender, providing for an $8.5 million revolving line of credit, subject to a borrowing base limitation, or the September 2013 facility. The borrowing base under this facility is set as the lesser of $8.5 million and 60% of the aggregate amount of certain eligible equipment 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% per annum to the above-referenced interest rate, subject to interest rate limitations under applicable law. The facility matures on September 22, 2014. In October 2013, 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 2012 and refinanced in March 2012 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 December 31, 2013, $2.8 million was outstanding under this facility, with an interest rate of 5.25% per annum.

The September 2013 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 September 2013 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. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

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, or the October 2013 Coil Tubing facility, providing for (i) a term loan in the principal amount of up to $8.0 million and (ii) a $3.0 million revolving credit facility, subject to a borrowing base limitation. The borrowing base under the revolving credit facility is set at an amount equal to 80% of the aggregate amount of certain eligible accounts (specified in the loan and security agreement) as of the date of determination.

Outstanding indebtedness under the term loan and the revolving credit facility bears interest at the prime rate, as published in the “Bonds, Rates & Yields” section of The Wall Street Journal, plus an additional 0.50% if the ratio of funded debt to EBITDA (as defined in the loan and security agreement) is between 3 to 1 and 4 to 1, or 1% if the ratio of funded debt to EBITDA exceeds 4 to 1. Depending on these ratios, the minimum interest rate will range from 4.45% to 5.45%. In the event of default, interest on outstanding indebtedness under the term loan and the revolving credit facility will be payable at the rate of 15% per annum. The term loan matures on October 14, 2017, while the revolving credit facility matures on October 9, 2014. Redback Coil Tubing used $2.4 million in borrowings under the revolving credit facility to repay and terminate its prior term loan and revolving credit facility with Coppermark Bank entered into on October 5, 2012, as subsequently amended. Other borrowings under the revolving credit facility may be used only for general working capital purposes. Borrowings under the term loan may be used only for purchases of equipment. As of December 31, 2013, Redback Coil Tubing had outstanding borrowings of $4.1 million under the term loan and $1.6 million under the revolving credit facility, in each case with an interest rate of 4.5%.

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, Redback Coil Tubing was in compliance with all of its covenants under the loan and security agreement. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

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 December 31, 2013, $2.1 million was outstanding under this facility, with an interest rate of 4.75%.

In June and July of 2013, Muskie Proppant received an aggregate of approximately $3.5 million in loans from its members to fund the expansion of its processing plant and logistics facilities. Muskie Proppant’s obligations under these loans are secured by substantially all of Muskie Proppant’s assets. These loans mature on

July 31, 2014, unless they are accelerated or extended in accordance with their terms. Interest on these loans accrue at a rate equal to the lesser of (i) the prime rate of interest announced from time to time by Citibank, N.A. plus 2.5% per annum and (ii) the maximum rate of interest permitted by applicable law, and is payable monthly. In the event of default, interest will accrue at the lesser of 16% per annum and the maximum amount allowed by law. The notes evidencing these loans contain certain customary covenants, including covenants that prevent 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 December 31, 2013, Muskie Proppant had outstanding borrowings of $3.5 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.

On May 31, 2013, Bison Drilling and Field Services LLC, as borrower, entered into a loan and security agreement with International Bank of Commerce, as lender, providing for a $5.0 million revolving loan, with a maturity date of June 1, 2014, and a $30.0 million term loan, with a maturity date of April 1, 2017. Effective January 31, 2014, the term loan was amended to increase the face amount to $51,863,284.12 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, paying off a previous term loan and paying certain loan fees. The additional funds were to be used for funding, in part, Bison’s acquisition of five additional 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 of Texas.

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. The interest is calculated on the daily outstanding principal balance computed on the basis of a 360 day year for twelve (12) months of thirty (30) days each. As amended, the term loan required Bison to make only interest payments on a monthly basis through April 2014. Beginning on May 31, 2014, the term loan requires Bison to pay monthly payments of principal and interest based upon a thirty-six (36) month amortization of the remaining principal balance. For the revolving loan, Bison pays interest only monthly payments through the maturity date of June 1, 2014, at which time all accrued interest and unpaid principal will be due and payable in full. As of December 31, 2013, Bison had outstanding borrowings of $27.5 million under the term loan, with an interest rate of 4.5% and $3.4 million under the revolving loan, with an interest rate of 4.25%.

Both loans are secured by Bison’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 million as of January 31, 2014. As of December 31, 2013, Bison’s actual tangible net worth was $28.9 million and Bison received a one-time waiver from the lender for such non-compliance. Bison expects to be fully compliant with this covenant in future periods. We intend to repay in full and terminate this facility with a portion of the net proceeds from this offering.

In connection with the consummation of this offering, we intend to enter into a new revolving credit facility to replace our existing credit facilities that will be repaid and terminated.

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 2014, we currently estimate that our aggregate capital expenditures will be approximately $106.5 million, of which approximately $57.1 million has been allocated to our contract land and directional drilling division primarily for the recent Drilling Transaction and maintenance capital expenditures, approximately $20.2 million has been allocated to our remote accommodations service division primarily for expansion of facilities and approximately $29.2 million has been allocated to our completion and production services division primarily for additional pumping and coil tubing units.

We believe that the proceeds of this offering, our operating cash flow and available borrowings under our revolving credit facilities will be sufficient to fund our operations 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. 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 and/or seek additional capital. If we seek additional capital for that or other reasons, we may do so through borrowings under our revolving credit facilities, 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, or we may not be able to complete acquisitions that may be favorable to us, or finance the capital expenditures necessary to conduct our operations.

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

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, the Company has not billed any customer for amounts not included in the original contract.

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. Each of our entities, except Sand Tiger, is a limited liability company that 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. Upon completion of this offering, we will be taxed as a C corporation.

The JOBS Act 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.

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.

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. 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.

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.

We had a cash and cash equivalents balance of $8.3 million at December 31, 2013. 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 $46.0 million outstanding under various credit facilities at December 31, 2013, 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 $0.5 million per year. We do not currently hedge our interest rate exposure.

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 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.

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, we generated

approximately 56.1% of our revenue, on a pro forma basis, 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.

We are a diversified oilfield service company providing completion and production services, contract and directional drilling and remote accommodation services primarily in the North American onshore unconventional sands and shale oil and natural gas markets, commonly referred to as “unconventional resources.” These resources are called unconventional due to the different manner by which they are extracted as compared to the extraction of conventional resources. To extract unconventional resources, 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. We use our equipment to drill and complete these horizontal wells. We believe that services such as ours are critical in increasing the ultimate recovery and present value of production streams for 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 and Alberta, Canada primarily to serve the following resource plays:

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.

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 contribution of the Stingray entities, we had $ million in revenue, net income of $ million and $ million in Adjusted EBITDA for the year ended December 31, 2013. 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” on page 44 of this prospectus.

We manage our business through three operating divisions: completion and production services, contract and directional drilling services and remote accommodation 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 primarily used in optimizing 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:

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 oil and gas molecules. At the completion 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 April 30, 2014, we owned a total of 52 high-pressure fracturing units capable of delivering a total of 117,000 horsepower. The group of fracturing units, other equipment and vehicles necessary to perform a typical fracturing job is referred to as a “fleet” and the personnel assigned to each fleet are commonly referred to 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, of each critical piece of equipment used on the job site. Management and supervision of each job is controlled from the control center via radio to the personnel that are operating the equipment. Each control center is also equipped with high band-width satellite hardware that provides continuous upload and download of job telemetry data. The data is delivered on a real-time basis to designated personnel of the Company and the operator for display in both digital and graphical form. In addition to our field supervision, the assigned coordinator at our main office can simultaneously monitor the same digital and graphical data that is being viewed by the on-site job personnel.

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 that we are to use for a specific fracturing job. 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 tailored to the unconventional resources market 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. Currently, we provide pressure control services in the mid-continent markets. Our pressure control services include the following:

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 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 six well-testing spreads. We provide flowback services in the Appalachian Basin and mid-content markets.

Equipment Rentals. Our equipment rental services provide a wide range of premium rental equipment used in pressure control, flowback and hydraulic fracturing services. In addition, we provide heavy-lift crane services and services associated with the transfer of fresh water to the well site. Our equipment rentals consist of two heavy-lift cranes, 17.5-miles of water transfer equipment, forklifts, manlifts, generators, light plants, rig mats 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. oil and natural gas producing basins, including the Bakken, Barnett, Eagle Ford, Fayetteville, Granite Wash, Marcellus, Niobrara, Permian, Piceance, Utica and Woodford basins. 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 then 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 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 environments of completion and production of the wells in these 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. The processes and technologies applied in our plant result in reduced down-time and low staff turnover, providing for more consistent and higher quality products. We collaborate with our customers to develop products to help them leverage the highest long-term production of an oil or gas well. We start by producing a majority of the standard proppant sizes as defined by the ISO/API 13503-2 specifications. These grain distributions can be customized to meet the demands of a specific well.

We contract with third party providers to transport raw sand from our sand mine suppliers to our sand processing plant. 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 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 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 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 most prolific resource plays, including the Permian Basin and Bakken Shale, to meet our customers’ delivery needs.

Master Services Agreements. We operate with most of our completion and production 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 and results of operation.

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 for our customers. Currently, we perform our contract drilling services in the Permian Basin of West Texas. Our top seven 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, Cambrian Management, LTD, J Cleo Thompson and RSP Permian, L.L.C.

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 December 31, 2013, we owned and operated eight land drilling rigs, ranging from 800 to 1,500 horsepower, five 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. In January 2014, we acquired five additional electric

horizontal drilling rigs to complement our existing fleet and, as of April 30, 2014, had a total of 13 drilling rigs, all of which were operating on term contracts with a term of more than one well or a stated period of time.

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. 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 marketable drilling rigs, including the new rigs acquired in January 2014, have rated maximum depth capabilities ranging from 12,500 feet to 20,000 feet. Of these drilling rigs, six are electric rigs and seven are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the 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 operating 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. 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 April 30, 2014, 11 of our 13 drilling rigs were operating under term contracts which provide for a take-or-pay model where customers cannot terminate contracts without paying the full amount remaining. An additional contract had one well remaining under contract, with the remaining contract allowing the customer to terminate on 30 days’ notice, upon payment of an agreed upon fee.

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 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.

Although we have not historically entered into any turnkey contracts, we may decide to enter into such arrangements in the future to the extent warranted by market conditions. It is also possible that we may acquire such contracts in connection with future acquisitions. 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.

For the years ended December 31, 2013, and 2012, our contract drilling services represented approximately 82% and 100%, respectively, of our total revenue, on a pro forma basis, in our contract land and directional drilling services business.

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 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 and our services allow 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 are often drilled sideways 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 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 Louisiana Gulf. 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.

As of April 30, 2014, we owned six MWD kits and one EM kit used in vertical, horizontal and directional drilling applications, 29 motors and an inventory of parts and other equipment. As of April 30, 2014, we employed 12 directional drillers with significant industry experience to implement our services.

For the year ended December 31, 2013, our directional drilling services represented approximately 18% of our total revenue, on a pro forma basis, in our contract land and directional drilling services business. We did not provide these services in 2012.

Our remote accommodations services provide housing for oilfield related labor 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,” in that 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 it with remote accommodation services on an on-going basis. See “Related Party Transactions.” By mid-2014, we expect to own and operate facilities supporting oil sands activities in northern Alberta, Canada with an aggregate of 700 rooms.

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

Our corporate headquarters are located at 14301 Caliber Drive, Suite 300, Oklahoma City, Oklahoma 73134 in an office building leased from Caliber Investment Group LLC, an affiliate of ours. 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 eight properties that are used for field offices, yards or transloading facilities for frac sand. We lease all of these properties from third parties.

Our customers consist primarily of independent oil and natural gas producers and land-based drilling contractors in North America. For the year ended December 31, 2013, on a pro forma basis, we had over 180 customers, 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 58.8% and 36.8% of our revenue, on a pro forma basis, for the years ended December 31, 2013 and 2012, respectively. For the year ended December 31, 2013, Gulfport was our largest customer accounting for approximately 46.1% of our revenue, on a pro forma basis, with no other customer accounting for more than 10% of our revenue for that period. 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.

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:

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):

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 $25,000,000 per occurrence and $10,000,000 per well site. The deductible is equal to 2% of the value of covered property (with the minimum being $2,500 and the maximum being $50,000). Additionally, the pressure pumping services business is insured against loss of business income for certain interruptions up to $1,000,000, which is subject to a 7-day waiting period.

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 15 of this prospectus for a description of certain risks associated with our insurance policies.

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 capabilities 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, 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.

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.

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.

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.

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 December 31, 2013, 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.

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 which 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.

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 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.

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.

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 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.

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.

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 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:

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.

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.

As of April 30, 2014, we had approximately 628 full time employees, including 169 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.

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, the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition or results of operations.

Set forth below is the name, age, position and a brief account of the business experience of each of our executive officers and directors as of April 1, 2014.

Phil Lancaster has served as our Chief Executive Officer 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 has served as our Chief Financial Officer since January 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 Crossroads Wireless, Inc., a wireless telecommunications service company, as Vice President of Finance 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. 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.

Upon completion of this offering, our board of directors will consist of directors, at least three of whom will satisfy the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. Our certificate of incorporation provides that the terms of office of the directors are one year from the time of their election until the next annual meeting of stockholders or until their successors are duly elected and qualified.

Our certificate of incorporation provides that the authorized number of directors will generally be not less than five nor more than thirteen, and the exact number of directors will be fixed from time to time exclusively by the board of directors pursuant to a resolution adopted by a majority of the whole board. In addition, our certificate of incorporation and our bylaws provide that, in general, vacancies on the board may be filled by a majority of directors in office, although less than a quorum.

Our board of directors will establish an audit committee in connection with this offering whose functions include the following:

The specific functions and responsibilities of the audit committee will be set forth in the audit committee charter. Upon completion of this offering, our audit committee will include at least one director who satisfies the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. Within one year after completion of the offering, we expect that our audit committee will be composed of three members that will satisfy the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. We also expect that one of the members of the audit committee will qualify as an audit committee financial expert as defined under these rules and listing standards, and the other members of our audit committee will satisfy the financial literacy standards for audit committee members under these rules and listing standards.

Pursuant to our bylaws, our board of directors may, from time to time, establish other committees to facilitate the management of our business and operations. Because we are considered to be controlled by Wexford under The NASDAQ Global Market rules, we are eligible for exemptions from provisions of these rules requiring a majority of independent directors, nominating and corporate governance and compensation committees composed entirely of independent directors and written charters addressing specified matters. We may elect to take advantage of these exemptions. In the event that we cease to be a controlled company within the meaning of these rules, we will be required to comply with these provisions after the specified transition periods.

Although we will be eligible for an exemption from the compensation committee requirements under The NASDAQ Global Market rules, we intend to establish a compensation committee composed of at least two independent directors in connection with this offering.

To date, none of our directors has received compensation for services rendered as a board member. Members of our board of directors who are also officers or employees of our company will not receive compensation for their services as directors. It is anticipated that after the completion of this offering, we will pay our non-employee directors a monthly retainer of $ and a per meeting attendance fee of $ and reimburse 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 stock units, which will vest in three equal annual installments beginning on the date of grant.

We do not currently have a compensation committee. None of our executive officers serves, or has 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 our board of directors or compensation committee.

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.

We do not currently have an employment agreement with our Chief Executive Officer or Chief Financial Officer.

Prior to the completion of this offering, we did not have any stock option or other equity incentive plan except for the equity awards granted in the employment agreements with our named executive officers and, except for such awards, there are no stock options, restricted stock 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.

Eligible award recipients are employees, consultants and directors of our company and its affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock which may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed shares, subject to adjustment to reflect certain corporate transactions or changes in our capital structure. At any time after the Company is subject to the deduction limitations under Section 162(m) of the Internal Revenue Code, the maximum number of shares of common stock issuable under our equity incentive plan to any one participant during a calendar year shall not exceed shares.

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

Share Reserve. The aggregate number of shares of common stock initially authorized for issuance under the plan is shares. However, (i) shares covered by an award that expires or otherwise terminates without having been exercised in full and (ii) shares 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. Our board of directors (or our compensation committee or any other committee of the board of directors as may be appointed by our board of directors from time to time) administers the plan. Among other responsibilities, the plan administrator selects participants from among the eligible individuals, determines

the number of shares 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 stockholder approval if stockholder approval is required by applicable law or stock exchange requirements. Unless terminated earlier, our equity incentive plan will terminate in August 2024.

Stock Options. Incentive and nonstatutory stock options are granted pursuant to incentive and nonstatutory stock option agreements. Employees, directors and consultants may be granted nonstatutory stock options, but only employees may be granted incentive stock options. The plan administrator determines the exercise price of a stock option, provided that the exercise price of a stock option generally cannot be less than 100% (and in the case of an incentive stock option granted to a more than 10% stockholder, 110%) of the fair market value of our common stock on the date of grant, except when assuming or substituting options in limited situations such as an acquisition. Generally, options granted under the plan vest ratably over a five-year period and have a term of ten years (five years in the case of an incentive stock option granted to a more than 10% stockholder), unless specified otherwise by the plan administrator in the option agreement.

Acceptable consideration for the purchase of common stock issued upon the exercise of a stock 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 stock previously owned by the optionee, (iv) stock 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), nonstatutory 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 option following the optionee’s death. Incentive stock options are not transferable except by will or the laws of descent and distribution.

Restricted Awards. Restricted awards are awards of either actual shares of common stock (e.g., restricted stock awards), or of hypothetical share units (e.g., restricted stock units) having a value equal to the fair market value of an identical number of shares of common stock, that will be settled in the form of shares of common stock 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 stock unit is similar to a restricted stock award except that participants holding restricted stock units do not have any stockholder rights until the stock unit is settled with shares. Stock units represent an unfunded and unsecured obligation for us and a holder of a stock unit has no rights other than those of a general creditor.

Performance Awards. Performance awards entitle the recipient to vest in or acquire shares of common stock, or hypothetical share units having a value equal to the fair market value of an identical number of shares of common stock that will be settled in the form of shares of common stock upon the attainment of 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 will be intended to meet the requirements of Section 162(m) of the Code. Performance goals must be determined prior to the time 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.

Stock Appreciation Rights. Stock appreciation rights may be granted independent of or in tandem with the granting of any option under the plan. Stock appreciation rights are granted pursuant to stock appreciation rights

agreements. The exercise price of a stock 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 our common stock on the date of grant. The exercise price of a stock appreciation right granted in tandem with an option is the same as the exercise price of the related option. Upon the exercise of a stock appreciation right, we will pay the participant an amount equal to the product of (i) the excess of the per share fair market value of our common stock on the date of exercise over the strike price, multiplied by (ii) the number of shares of common stock with respect to which the stock appreciation right is exercised. Payment will be made in cash, delivery of stock, or a combination of cash and stock as deemed appropriate by the plan administrator.

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

Corporate 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 Company), or a corporate transaction such as a dissolution or liquidation of our company, or any corporate 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 stock awards under the plan may be assumed, continued or substituted for by any surviving or acquiring entity (or its parent company), or may be 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 of ten days.

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 are not taxable to the employee until distributed from the 401(k) Plans, and all contributions are deductible by our entities when made.

Our certificate of incorporation provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the Delaware General Corporation Law, or DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by the DGCL:

This provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

Our certificate of incorporation also 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.

Our bylaws include provisions relating to advancement of expenses and indemnification rights consistent with those provided in our certificate of incorporation. In addition, our bylaws provide:

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.

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.

We do not currently have a written policy regarding the review and approval of related party transactions, but intend to implement such a policy in connection with, and prior to the completion of, this offering. In connection with this offering, we will establish an audit committee consisting solely of independent directors whose functions will be set forth in the audit committee charter. We anticipate that one of the audit committee’s functions will be to review and approve all relationships and transactions in which we and our directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their immediate family members, have a direct or indirect material interest. We anticipate that such policy will be a written policy included as part the audit committee charter that will be implemented by the audit committee and in the Code of Business Conduct and Ethics that our board of directors will adopt prior to the completion of this offering.

Historically, the review and approval of related party transactions have been the responsibility of our management, and all of the transactions discussed under “Related Party Transactions” below 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 Company. Although our management believes that the terms of the related party transactions described below are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties.

Our management will continue to review and approve related party transactions, subject to the above-referenced conflicts of interest policy, until the adoption of the policy regarding the review and approval of such transactions by the audit committee, which we intend to adopt in connection with, and prior to the completion of, this offering.

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 $ , 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.

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 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. 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, we entered into a master services agreement with Diamondback E&P LLC, or Diamondback E&P, pursuant to which we sell 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 us for sand proppant. We 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 us any amounts as of December 31, 2013 or 2012. Diamondback E&P is a wholly-owned subsidiary of Diamondback Energy, Inc., or Diamondback, in which Gulfport and affiliates of Wexford beneficially owned approximately 7.2% and 22.6%, respectively, of its outstanding common stock as of December 31, 2013.

Effective September 9, 2013, Panther 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. Furthermore, the master service agreement does not obligate Diamondback E&P to issue any order or accept any offers from Panther for its directional drilling or other services. In the third quarter 2013, Diamondback E&P began using Panther’s directional drilling services. For the year ended December 31, 2013, Diamondback E&P incurred $0.4 million for services performed by Panther. Diamondback E&P owed Panther $0.3 million as of December 31, 2013.

Panther 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 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. The master service agreement does not obligate Gulfport to call upon Panther to perform any work under the master service agreement, and Panther is not obligated to accept any work requests from Gulfport. Furthermore, the designation of any work to be performed by Panther and the cessation of such work shall be at the sole discretion of Gulfport. For the year ended December 31, 2013 and 2012, Gulfport incurred $12.9 million and $0.1 million, respectively, for services performed by Panther and, as of December 31, 2013 and 2012 owed Panther $1.8 million and $0.1 million, respectively, for work performed under the master service contract.

On October 17, 2013, Bison Trucking LLC, or 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. 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 and Field Services LLC, or 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. 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 Diamondbac 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 year ended December 31, 2013 and 2012, Diamondback E&P incurred $9.4 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.

On May 7, 2013, we 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, we are obligated to pay Hopedale a transloading fee in the amount of $4.00 per ton of sand. If we fail 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. For the year ended December 31, 2013, we incurred $0.3 million in costs to Hopedale and, as of December 31, 2013, owed Hopedale $0.2 million under this agreement. Hopedale is a wholly-owned subsidiary of Rhino Resource Partners LP, which is an affiliate of Wexford.

Three of the four Stingray entities were formed between March 2012 and November 2012, and the fourth Stingray entity was formed in February 2013. Since their formation, the Stingray entities have provided Gulfport with water transfer, hydraulic fracturing and well cementing services and equipment rentals in the Utica Shale in Ohio. In December 2013, the Stingray entities entered into a master services agreement with Gulfport. Under the agreement, Gulfport is obligated to offer us the opportunity to provide it with water transfer, rental and cementing services before contacting any other service provider, provided that, with respect to well cementing services, this obligation terminates after Gulfport has given us the right to provide such services in connection with four drilling rigs. We have the right to refuse any request by Gulfport for water transfer, well cementing and equipment rental services if we are unable to provide such services to Gulfport due to concurrent operations. With respect to hydraulic fracturing services, Gulfport agreed to use our services (or pay liquidated damages if it fails to do so), and we are 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 provides for a primary term expiring on January 1, 2016 in the case of each service other than our hydraulic fracturing service, with respect to which the primary term expires November 15, 2015. After the expiration of the primary term, the agreement for the provision of each service will continue on a year-to-year basis until terminated. The master services agreement may be terminated by Gulfport at any time by giving us written notice. Additionally, Gulfport can, without liability, countermand any work order given to us at any time before we begin such work. If we have already begun such work, then Gulfport can still cancel the service at any time, being liable to us only for the value of the work performed prior to the cancellation. We may terminate the master service agreement by giving Gulfport written notice prior to receiving a notification from Gulfport to perform a specific service. For the year ended December 31, 2013 and the period from March 20, 2012 through December 31, 2012, the Stingray entities recognized revenue of approximately $95.1 million and $8.5 million, respectively, for the services provided to Gulfport. As of December 31, 2013 and December 31, 2012, Gulfport owed the Stingray entities $8.6 million and $5.3 million respectively, for these services.

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 we reimburse 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 year ended December 31, 2013 and the period from March 20, 2012 through December 31, 2012, the Stingray entities incurred total costs of $0.6 million and $2.4 million, respectively, under this arrangement. As of December 31, 2013 and December 31, 2012, the Stingray entities owed Gulfport $0 and $0.9 million, respectively, for these services.

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 $10.4 million and $21.0 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 $3.1 million and $0.2 million, respectively.

In July 2013, Muskie 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 makes monthly interest payments one these loans at the prime rate plus 2.5% (5.75% at September 30, 2013). The loans mature on July 31, 2014. 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.

Everest Operations Management LLC and SG Holdings I, each an affiliate of Wexford, have historically provided office space and certain technical, administrative and payroll services to us and we reimbursed these Wexford affiliates in amounts determined by them 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 these Wexford affiliates, or specifically identified invoices processed, depending on the nature of the cost. For the years ended December 31, 2013 and 2012, we incurred total costs under these arrangements of $25.1 million and $15.2 million, respectively, and, as of December 31, 2013 and December 31, 2012, owed $1.4 million and $1.3 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 with these affiliates on substantially the same terms as those 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. At December 31, 2013 and 2012, these Wexford affiliates owed us an aggregate of $0 and $0.2 million, respectively, and we owed an aggregate of $1.5 million and $2.8 million, respectively, to the Wexford affiliates under these arrangements.

We purchase coil tubing equipment from Serva Group, Ltd. and Serva Group LLC, which are affiliates of Wexford and are collectively referred to as Serva Group. We also contract for repairs and maintenance services. During the year ended December 31, 2013, we 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, we purchased $8.0 million of equipment. At December 31, 2013 and December 31, 2012, we owed $1.3 million and $1.4 million, respectively to the Serva Group.

Prior to the closing of this offering, we will enter a registration rights agreement with each of Redback Holdings LLC and Gulfport under which we will grant them certain demand and “piggyback” registration rights. For more information regarding this agreement, see “Shares Eligible for Future Sale—Registration Rights” on page 103 of this prospectus.

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

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

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

We will amend and restate our certificate of incorporation and bylaws in connection with this offering. The following description of our common stock, certificate of incorporation and our bylaws are summaries thereof and are qualified by reference to our certificate of incorporation and our bylaws as so amended and restated, copies of which will be filed with the SEC as exhibits to the registration statement of which this prospectus is a part.

Our authorized capital stock consists of 200,000,000 shares of common stock, par value $0.01 per share, and shares of preferred stock, par value $0.01 per share. We intend to apply for listing of our shares of common stock on The NASDAQ Global Market under the symbol “SRAY.”

Holders of shares of common stock are entitled to one vote per share on all matters submitted to a vote of stockholders. Shares of common stock do not have cumulative voting rights, which means that the holders of more than 50% of the shares voting for the election of the board of directors can elect all the directors to be elected at that time, and, in such event, the holders of the remaining shares will be unable to elect any directors to be elected at that time. Our certificate of incorporation denies stockholders any preemptive rights to acquire or subscribe for any stock, obligation, warrant or other securities of ours. Holders of shares of our common stock have no redemption or conversion rights nor are they entitled to the benefits of any sinking fund provisions.

In the event of our liquidation, dissolution or winding up, holders of shares of common stock shall be entitled to receive, pro rata, all the remaining assets of our company available for distribution to our stockholders after payment of our debts and after there shall have been paid to or set aside for the holders of capital stock ranking senior to common stock in respect of rights upon liquidation, dissolution or winding up the full preferential amounts to which they are respectively entitled.

Holders of record of shares of common stock are entitled to receive dividends when and if declared by the board of directors out of any assets legally available for such dividends, subject to both the rights of all outstanding shares of capital stock ranking senior to the common stock in respect of dividends and to any dividend restrictions contained in debt agreements. All outstanding shares of common stock and any shares sold and issued in this offering will be fully paid and nonassessable by us.

Our board of directors is authorized to issue up to shares of preferred stock in one or more series. The board of directors may fix for each series:

We do not need stockholder approval to issue or fix the terms of the preferred stock. The actual effect of the authorization of the preferred stock upon your rights as holders of common stock is unknown until our board of directors determines the specific rights of owners of any series of preferred stock. Depending upon the rights granted to any series of preferred stock, your voting power, liquidation preference or other rights could be adversely affected. Preferred stock may be issued in acquisitions or for other corporate purposes. Issuance in connection with a stockholder rights plan or other takeover defense could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, control of our company. We have no present plans to issue any shares of preferred stock.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws

Some provisions of our certificate of incorporation and our bylaws contain provisions that could make it more difficult to acquire us by means of a merger, tender offer, proxy contest or otherwise, or to remove our incumbent officers and directors. These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiation of such proposals could result in an improvement of their terms.

Undesignated preferred stock. The ability to authorize and issue undesignated preferred stock may enable our board of directors to render more difficult or discourage an attempt to change control of us by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary obligations, the board of directors were to determine that a takeover proposal is not in our best interest, the board of directors could cause shares of preferred stock to be issued without stockholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer or insurgent stockholder or stockholder group.

Stockholder meetings. Our certificate of incorporation and bylaws provide that a special meeting of stockholders may be called only by the Chairman of the Board, the Chief Executive Officer or by a resolution adopted by a majority of our board of directors.

Requirements for advance notification of stockholder nominations and proposals. Our bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors.

Stockholder action by written consent. Our bylaws provide that, except as may otherwise be provided with respect to the rights of the holders of preferred stock, no action that is required or permitted to be taken by our stockholders at any annual or special meeting may be effected by written consent of stockholders in lieu of a meeting of stockholders, unless the action to be effected by written consent of stockholders and the taking of such action by such written consent have expressly been approved in advance by our board. This provision, which may not be amended except by the affirmative vote of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, makes it difficult for stockholders to initiate or effect an action by written consent that is opposed by our board.

Amendment of the bylaws. Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our certificate of incorporation and bylaws grant our board the power to adopt, amend and repeal our bylaws at any regular or special meeting of the board on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by an affirmative vote of holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Removal of Director. Our certificate of incorporation and bylaws provide that members of our board of directors may only be removed by the affirmative vote of holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Amendment of the Certificate of Incorporation. Our certificate of incorporation provides that, in addition to any other vote that may be required by law or any preferred stock designation, the affirmative vote of the holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, is required to amend, alter or repeal, or adopt any provision as part of our certificate of incorporation inconsistent with the provisions of our certificate of incorporation dealing with distributions on our common stock, related party transactions, our board of directors, our bylaws, meetings of our stockholders or amendment of our certificate of incorporation.

The provisions of our certificate of incorporation and bylaws could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions which stockholders may otherwise deem to be in their best interests.

Prior to this offering, there has been no public market for our common stock. Future sales of substantial amounts of our common stock in the public market, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. We cannot predict the effect, if any, that future sales of shares, or the availability of shares for future sales, will have on the market price of our common stock prevailing from time to time.

Upon completion of this offering, we will have shares of common stock outstanding. Of these shares of common stock, the shares of common stock being sold in this offering, plus any shares sold upon exercise of the underwriters’ option to purchase additional shares, will be freely tradable without restriction under the Securities Act, except for any such shares held or acquired by an “affiliate” of ours, as that term is defined in Rule 144 promulgated under the Securities Act, which shares will be subject to the volume limitations and other restrictions of Rule 144 described below. The remaining shares of common stock held by our existing stockholders upon completion of this offering, or shares if the underwriters exercise their option to purchase additional shares in full, will be “restricted securities,” as that phrase is defined in Rule 144, and may be resold only after registration under the Securities Act or pursuant to an exemption from such registration, including, among others, the exemptions provided by Rule 144 and 701 under the Securities Act, which rules are summarized below. These remaining shares of common stock held by our existing stockholders upon completion of this offering will be available for sale in the public market after the expiration of the lock-up agreements described in “Underwriting,” taking into account the provisions of Rules 144 and 701 under the Securities Act.

In general, under Rule 144 as currently in effect, persons who became the beneficial owner of shares of our common stock prior to the completion of this offering may sell their shares upon the earlier of (1) the expiration of a six-month holding period, if we have been subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for at least 90 days prior to the date of the sale and have filed all reports required thereunder, or (2) the expiration of a one-year holding period.

At the expiration of the six-month holding period, assuming we have been subject to the Exchange Act reporting requirements for at least 90 days and have filed all reports required thereunder, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock, and a person who was one of our affiliates at any time during the three months preceding a sale would be entitled to sell, within any three-month period, a number of shares of common stock that does not exceed the greater of either of the following:

At the expiration of the one-year holding period, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock without restriction. A person who was one of our affiliates at any time during the three months preceding a sale would remain subject to the volume restrictions described above.

Sales under Rule 144 by our affiliates are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us.

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchased shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering, or who purchased shares from us after that date upon the exercise of options granted before that date, are eligible to resell such shares in reliance upon Rule 144 beginning 90 days after the date of this prospectus. If such person is not an affiliate, the sale may be made subject only to the manner-of-sale restrictions of Rule 144. If such a person is an affiliate, the sale may be made under Rule 144 without compliance with its one-year minimum holding period, but subject to the other Rule 144 restrictions.

Prior to the closing of this offering, we will enter into registration rights agreements with Wexford and Gulfport. Under the registration rights agreements, each of Redback Holdings and Gulfport has demand and “piggyback” registration rights. The demand rights require us to register the demanding holder’s shares of our common stock with the SEC at any time, subject to the 180-day lock-up agreement it has entered into in connection with this offering. The piggyback rights will allow the holder to register the shares of our common stock that it owns along with any shares that we register with the SEC. These registration rights are subject to customary conditions and limitations, including the right of the underwriters of an offering to limit the number of shares.

We intend to file one or more registration statements on Form S-8 under the Securities Act to register shares of our common stock issued or reserved for issuance under our equity incentive plan. The first such registration statement is expected to be filed soon after the date of this prospectus and will automatically become effective upon filing with the SEC. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described below.

We, each of our directors and executive officers, Stingray Holdings and Gulfport have agreed that, without the prior written consent of Credit Suisse Securities (USA) LLC, we and they will not, directly or indirectly, for a period of 180 days after the date of the offering, offer, pledge, sell, contract to sell or otherwise transfer or dispose of any shares of our common stock (other than the shares of our common stock subject to this offering) or any other securities convertible into or exercisable or exchangeable for our common stock (subject to certain exceptions). For additional information, see “Underwriting.”

The following is a general discussion of material U.S. federal income and estate tax consequences of the ownership and disposition of our common stock by a non-U.S. holder (as defined below). This discussion deals only with common stock purchased in this offering that is held as a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended, or the Code (generally, property held for investment), by a non-U.S. holder. Except as modified for estate tax purposes, the term “non-U.S. holder” means a beneficial owner of our common stock that is not a “U.S. person” or a partnership for U.S. federal income and estate tax purposes. A U.S. person is any of the following:

An individual may generally be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of the 183-day calculation, all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year are counted. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens.

This discussion is based upon provisions of the Code, and Treasury Regulations, administrative rulings and judicial decisions, all as of the date hereof. Those authorities may be changed, perhaps retroactively, so as to result in U.S. federal income and estate tax consequences different from those discussed below. No ruling has been or will be sought from the Internal Revenue Service, or IRS, with respect to the matters discussed below, and there can be no assurance the IRS will not take a contrary position regarding the tax consequences of the acquisition, ownership or disposition of our common stock, or that such contrary position would not be sustained by a court. This discussion does not address all aspects of U.S. federal income and estate taxation, including the impact of the unearned income Medicare contribution tax and does not deal with other U.S. federal tax laws (such as gift tax laws) or foreign, state, local or other tax considerations that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this discussion does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the U.S. federal income tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holding our common stock, you should consult your tax advisor.

THIS DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE AND GIFT TAX LAWS TO THEIR PARTICULAR SITUATION AS WELL AS THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS OR TAX TREATIES AND ANY OTHER U.S. FEDERAL TAX LAWS.

We do not expect to pay any cash distributions on our common stock in the foreseeable future. However, in the event we do make such cash distributions, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. If any such distribution exceeds our current and accumulated earnings and profits, the excess will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Common Stock” below. Dividends paid to a non-U.S. holder of our common stock that are not effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States will be subject to U.S. withholding tax at a 30% rate, or if an income tax treaty applies, a lower rate specified by the treaty. In order to receive a reduced treaty rate, a non-U.S. holder must provide to us or our withholding agent IRS Form W-8BEN (or applicable substitute or successor form) properly certifying eligibility for the reduced rate. Non-U.S. holders that do not timely provide us or our withholding agent with the required certification, but that qualify for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under an applicable income tax treaty.

Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty so requires, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons. In that case, we or our withholding agent will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements (which may generally be met by providing an IRS Form W-8ECI). In addition, a “branch profits tax” may be imposed at a 30% rate (or a lower rate specified under an applicable income tax treaty) on a foreign corporation’s effectively connected earnings and profits for the taxable year, as adjusted for certain items. Non-U.S. holders should consult any applicable income tax treaties that may provide for different rules.

Subject to the discussion below regarding backup withholding, a non-U.S. holder generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe we currently are a USRPHC. If we are or become a USRPHC, a non-U.S. holder nonetheless will not be subject to U.S. federal income tax or withholding in respect of any gain realized on a sale or other disposition of our common stock so long as (i) our common stock is “regularly traded on an established securities market” for U.S. federal income tax purposes and (ii) such non-U.S. holder does not actually or constructively own, at any time during the applicable period described in the third bullet point, above, more than 5% of our outstanding common stock. We expect our common stock to be “regularly traded” on an established securities market, although we cannot guarantee it will be so traded. Accordingly, a non-U.S. holder who actually or constructively owns more than 5% of our common stock would be subject to U.S. federal income tax in respect of any gain realized on any sale or other disposition of common stock (taxed in the same manner as gain that is effectively connected income, except that the branch profits tax would not apply). If we are or become an USRPHC, and if our common stock ceases to be regularly traded on an established securities market, a non-U.S. holder generally would be subject to U.S. federal income tax on any gain from the disposition of our common stock, and the transferee of such common stock generally would be required to withhold 10% of the gross proceeds payable to the non-U.S. holder. Non-U.S. holders should consult their own advisor about the consequences that could result if we are, or become, a USRPHC.

Dividends paid to you will generally be subject to information reporting and may be subject to U.S. backup withholding. You will be exempt from backup withholding if you properly provide an IRS Form W-8BEN or applicable successor form certifying under penalties of perjury that you are a non-U.S. holder or otherwise meet documentary evidence requirements for establishing that you are a non-U.S. holder, or you otherwise establish an exemption. Copies of the information returns reporting such dividends and the tax withheld with respect to such dividends also may be made available to the tax authorities in the country in which you reside.

The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If you receive payments of the proceeds of a disposition of our common stock to or through a U.S. office of a broker, the payment will be subject to both U.S. backup withholding and information reporting unless you properly provide an IRS Form W-8BEN or applicable successor form certifying under penalties of perjury that you are a non-U.S. person (and the payor does not have actual knowledge or reason to know that you are a U.S. person) or you otherwise establish an exemption. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that

payment. However, U.S. information reporting, but not backup withholding, will generally apply to a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that has certain relationships with the United States unless the broker has documentary evidence in its files that you are a non-U.S. person and certain other conditions are met, or you otherwise establish an exemption.

Backup withholding is not an additional tax. You may obtain a refund or credit of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability, if any, provided the required information is timely furnished to the IRS.

Our common stock that is owned (or treated as owned) by an individual who is not a citizen or resident of the United States (as specially defined for U.S. federal estate tax purposes) at the time of death will be included in such individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise, and, therefore, may be subject to U.S. federal estate tax.

Under the Foreign Account Tax Compliance Act, or FATCA, a 30% withholding tax will generally apply to dividends on, and gross proceeds from the sale or other disposition of, common stock paid to a foreign financial institution unless the foreign financial institution (i) enters into an agreement with the U.S. Treasury to, among other things, undertake to identify accounts held by certain U.S. persons or U.S.-owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to account holders whose actions prevent it from complying with these reporting and other requirements, (ii) is resident in a country that has entered into an intergovernmental agreement with the United States in relation to such withholding and information reporting and the financial entity complies with related information reporting requirements of such country, or (iii) qualifies for an exemption from these rules. A foreign financial institution generally is a foreign entity that (i) accepts deposits in the ordinary course of a banking or similar business, (ii) as a substantial portion of its business, holds financial assets for the benefit of one or more other persons, or (iii) is an investment entity that, in general, primarily conducts as a business on behalf of customers trading in certain financial instruments, individual or collective portfolio management or otherwise investing, administering, or managing funds, money or certain financial assets on behalf of other persons. In addition, FATCA generally imposes a 30% withholding tax on the same types of payments to a non-financial foreign entity unless the entity certifies that it does not have any substantial U.S. owners, furnishes identifying information regarding each substantial U.S. owner, or otherwise qualifies for an exemption from these rules. In either case, such payments would include U.S.-source dividends and the gross proceeds from the sale or other disposition of stock that can produce U.S.-source dividends. By its terms, FATCA generally applies to payments of dividends on, and gross proceeds from the sale or disposition of, common stock made after December 31, 2012. However, the Treasury Department has issued final Treasury regulations and subsequent guidance that defer the application of FATCA’s withholding obligations to payments of dividends made on or after July 1, 2014, and payments of gross proceeds made on or after January 1, 2017.

The final Treasury regulations and subsequent guidance provide detailed guidance regarding the reporting, withholding and other obligations under FATCA. Investors should consult their tax advisors regarding the possible impact of the FATCA rules on their investment in our common stock, including, without limitation, the process and deadlines for meeting the applicable requirements to prevent the imposition of the 30% withholding tax under FATCA.

THE SUMMARY OF MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS ABOVE IS INCLUDED FOR GENERAL INFORMATION PURPOSES ONLY. POTENTIAL PURCHASERS OF OUR COMMON STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS TO DETERMINE THE U.S. FEDERAL, STATE, LOCAL AND NON-U.S. TAX CONSIDERATIONS OF PURCHASING, OWNING AND DISPOSING OF OUR COMMON STOCK.

Under the terms and subject to the conditions contained in an underwriting agreement with respect to the common stock being offered, we and the selling stockholders have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC is acting as representative, the following respective numbers of shares of common stock:

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated. Each of the selling stockholders in this offering may be deemed to be an underwriter within the meaning of Section 2(a)(11) of the Securities Act.

We and the selling stockholders have granted to the underwriters a 30-day option to purchase up to an aggregate of additional shares at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock. To the extent that the underwriters exercise this option, each underwriter will purchase additional shares from us and the selling stockholders in approximately the same proportion as they purchased the shares shown in the table above.

The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $ per share. The underwriters and selling group members may allow a discount of $ per share on sales to other broker/dealers. After the initial public offering the representatives may change the public offering price and concession and discount to broker/dealers. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The following table summarizes the compensation and estimated expenses we will pay:

We estimate that our out of pocket expenses for this offering, excluding underwriting discounts and commissions, will be approximately $ million. The selling stockholders will not bear any portion of these expenses.

The representative has informed us that it does not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the shares of common stock being offered.

We have agreed that, subject to certain exceptions, we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act relating to any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus.

Our officers, directors and Stingray Holdings and Gulfport, which are the selling stockholders in this offering, have each agreed that, subject to certain exceptions, they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus. Credit Suisse Securities (USA) LLC, in its sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release the common stock and other securities from lock-up agreements, Credit Suisse Securities (USA) LLC will consider, among other factors, the holder’s reasons for requesting the release and the number of shares of common stock or other securities for which the release is being requested.

The underwriters have reserved for sale at the initial public offering price up to % of the common stock being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares. Any shares sold in the directed share program to directors and executive officers will be subject to the 180-day lock-up agreements described above.

We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

We intend to apply to list the shares of our common stock on The NASDAQ Global Market under the symbol “SRAY.”

In connection with the listing of our common stock on The NASDAQ Global Market, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 400 beneficial owners.

Prior to this offering, there has been no public market for our common stock. The initial public offering price for our common stock will be determined by negotiation between us and the underwriters. The principal factors to be considered in determining the initial public offering price include the following: the general condition of the securities markets;

We cannot assure you that the initial public offering price will correspond to the price at which our common stock will trade in the public market subsequent to this offering or that an active trading market will develop and continue after this offering.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have from time to time performed, and may in the future perform, various financial advisory, commercial banking and investment banking services for us and for our affiliates in the ordinary course of business for which they have received and would receive customary compensation.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investments and securities activities may involve securities and/or instruments of the issuer. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Market or otherwise and, if commenced, may be discontinued at any time.

A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representative may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each such state being referred to herein as a Relevant Member State), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (each such date being referred to herein as a Relevant Implementation Date) it has not made and will not make an offer of shares to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

(d) in any other circumstances which do not require the publication by the Company of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of shares to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

(a) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000, or the FSMA, received by it in connection with the issue or sale of the shares in circumstances in which Section 21(1) of the FSMA does not apply to the Company; and

(b) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

The shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan, or the Financial Instruments and Exchange Law, and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

The validity of the shares of common stock that are offered hereby by us and the selling stockholders will be passed upon by Akin Gump Strauss Hauer & Feld LLP. The underwriters have been represented by Latham & Watkins LLP, Houston, Texas.

The combined financial statements of Redback Energy Services as of December 31, 2013 and 2012 and for the years then ended included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The combined financial statements of Stingray Pressure Pumping LLC and Affiliates as of December 31, 2013 and 2012 and for the year ended December 31, 2013 and the period from March 20, 2012 (inception) to December 31, 2012 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The balance sheet of Stingray Energy Services, Inc. as of February 5, 2014 included in this prospectus and elsewhere in the registration statement has been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The statements of revenues and direct operating expenses of Certain Drilling Rigs of Lantern Drilling Company acquired by Bison Drilling and Field Services, LLC for the years ended December 31, 2013 and 2012, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

We have filed with the SEC a registration statement on Form S-1 under the Securities Act covering the securities offered by this prospectus. This prospectus, which constitutes a part of that registration statement, does not contain all of the information that you can find in that registration statement and its exhibits. Certain items are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information about us and the common stock offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance such statement is qualified by reference to each such contract or document filed as part of the registration statement. When we complete this offering, we will be required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read any materials we file with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

Blowout. An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface. A blowout may consist of salt water, oil, natural gas or a mixture of these. Blowouts can occur in all types of exploration and production operations, not just during drilling operations. If reservoir fluids flow into another formation and do not flow to the surface, the result is called an underground blowout. If the well experiencing a blowout has significant open-hole intervals, it is possible that the well will bridge over (or seal itself with rock fragments from collapsing formations) down-hole and intervention efforts will be averted.

Bottomhole assembly. The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collar, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms. The bottomhole assembly must provide force for the bit to break the rock (weight on bit), survive a hostile mechanical environment and provide the driller with directional control of the well. Oftentimes the assembly includes a mud motor, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other specialized devices.

Coiled tubing. A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and rewound to coil the pipe back onto the transport and storage spool. Depending on the pipe diameter (1 in. to 4 1/2 in.) and the spool size, coiled tubing can range from 2,000 ft. to 15,000 ft. (610 m to 4,570 m) or greater length.

Completion. A generic term used to describe the assembly of down-hole tubulars and equipment required to enable safe and efficient production from an oil or gas well. The point at which the completion process begins may depend on the type and design of the well.

Directional drilling. The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken down-hole to the surface, mud motors and special BHA components and drill bits, including rotary steerable systems, and drill bits. The directional driller also exploits drilling parameters such as weight on bit and rotary speed to deflect the bit away from the axis of the existing wellbore. In some cases, such as drilling steeply dipping formations or unpredictable deviation in conventional drilling operations, directional-drilling techniques may be employed to ensure that the hole is drilled vertically. While many techniques can accomplish this, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is through the use of a bend near the bit in a down-hole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drillstring is not rotating. By pumping mud through the mud motor, the bit turns while the drillstring does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drillstring (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes.

Down-hole. Pertaining to or in the wellbore (as opposed to being on the surface).

Down-hole motor. A drilling motor located in the drill string above the drilling bit powered by the flow of drilling mud. Down-hole motors are used to increase the speed and efficiency of the drill bit or can be used to steer the bit in directional drilling operations. Drilling motors have become very popular because of horizontal and directional drilling applications and the increase of day rates for drilling rigs.

Drillpipe. Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.

Drillstring. The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.

Horizontal drilling. A subset of the more general term “directional drilling,” used where the departure of the wellbore from vertical exceeds about 80 degrees. Note that some horizontal wells are designed such that after reaching true 90-degree horizontal, the wellbore may actually start drilling upward. In such cases, the angle past 90 degrees is continued, as in 95 degrees, rather than reporting it as deviation from vertical, which would then be 85 degrees. Because a horizontal well typically penetrates a greater length of the reservoir, it can offer significant production improvement over a vertical well.

Hydraulic fracturing. A stimulation treatment routinely performed on oil and gas wells in low-permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture extend away from the wellbore in opposing directions according to the natural stresses within the formation. Proppant, such as grains of sand of a particular size, is mixed with the treatment fluid to keep the fracture open when the treatment is complete. Hydraulic fracturing creates high-conductivity communication with a large area of formation and bypasses any damage that may exist in the near-wellbore area.

Hydrocarbon. A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.

Mud motors. A positive displacement drilling motor that uses hydraulic horsepower of the drilling fluid to drive the drill bit. Mud motors are used extensively in directional drilling operations.

Natural gas liquids. Components of natural gas that are liquid at surface in field facilities or in gas-processing plants. Natural gas liquids can be classified according to their vapor pressures as low (condensate), intermediate (natural gasoline) and high (liquefied petroleum gas) vapor pressure.

Nitrogen pumping unit. A high-pressure pump or compressor unit capable of delivering high-purity nitrogen gas for use in oil or gas wells. Two basic types of unit are commonly available: a nitrogen converter unit that pumps liquid nitrogen at high pressure through a heat exchanger or converter to deliver high-pressure gas at ambient temperature, and a nitrogen generator unit that compresses and separates air to provide a supply of high-pressure nitrogen gas.

Plugging. The process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Plugging work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging work.

Plug. A down-hole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.

Pressure pumping. Services that include the pumping of liquids under pressure.

Producing formation. An underground rock formation from which oil, natural gas or water is produced. Any porous rock will contain fluids of some sort, and all rocks at considerable distance below the Earth’s surface will initially be under pressure, often related to the hydrostatic column of ground waters above the reservoir. To produce, rocks must also have permeability, or the capacity to permit fluids to flow through them.

Proppant. Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

Resource Play. Accumulation of hydrocarbons known to exist over a large area.

Shale. A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.

Tight sands. A type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.

Tubulars. A generic term pertaining to any type of oilfield pipe, such as drillpipe, drill collars, pup joints, casing, production tubing and pipeline.

Unconventional resource. An umbrella term for oil and natural gas that is produced by means that do not meet the criteria for conventional production. What has qualified as “unconventional” at any particular time is a complex function of resource characteristics, the available exploration and production technologies, the economic environment, and the scale, frequency and duration of production from the resource. Perceptions of these factors inevitably change over time and often differ among users of the term. At present, the term is used in reference to oil and gas resources whose porosity, permeability, fluid trapping mechanism, or other characteristics differ from conventional sandstone and carbonate reservoirs. Coalbed methane, gas hydrates, shale gas, fractured reservoirs, and tight gas sands are considered unconventional resources.

Wellbore. The physical conduit from surface into the hydrocarbon reservoir.

Well stimulation. A treatment performed to restore or enhance the productivity of a well. Stimulation treatments fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the reservoir formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the reservoir fracture pressure and generally are designed to restore the natural permeability of the reservoir following damage to the near-wellbore area. Stimulation in shale gas reservoirs typically takes the form of hydraulic fracturing treatments.

Wireline. A general term used to describe well-intervention operations conducted using single-strand or multi-strand wire or cable for intervention in oil or gas wells. Although applied inconsistently, the term commonly is used in association with electric logging and cables incorporating electrical conductors.

Workover. The process of performing major maintenance or remedial treatments on an oil or gas well. In many cases, workover implies the removal and replacement of the production tubing string after the well has been killed and a workover rig has been placed on location. Through-tubing workover operations, using coiled tubing, snubbing or slickline equipment, are routinely conducted to complete treatments or well service activities that avoid a full workover where the tubing is removed. This operation saves considerable time and expense.

We have audited the accompanying combined balance sheets of Redback Energy Services (the “Company”) as of December 31, 2013 and 2012, and the related combined statements of comprehensive loss, shareholders’ and members’ equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Redback Energy Services as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

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

Redback Energy Services (“Company”) is a combination of entities under the common control of Wexford Capital LP (“Wexford”). The following operating entities are included in these combined financial statements: Bison Drilling and Field Services, LLC (“Bison”), formed November 15, 2010; Bison Trucking LLC, formed August 9, 2013; Panther Drilling Systems LLC (“Panther”), formed December 11, 2012; (Redback Energy Services, LLC (“Energy Services”), formed October 6, 2011; Redback Coil Tubing, LLC (“Coil Tubing”), formed May 15, 2012; Muskie Proppant LLC (“Muskie”), formed September 14, 2011; and Great White Sand Tiger Lodging Ltd. (“Lodging”), formed October 1, 2007; collectively referred to as the “Operating Entities”. Under the organizational documents of the Operating Entities, equity holders are not liable for the debts and obligations of the Company. Stingray Energy Services, Inc. (formerly Redback Inc.) (“Stingray”) is a company that was formed by Wexford in February 2014 and is planning an initial public offering (“IPO”). Immediately prior to the completion of the IPO, Wexford will cause all of the outstanding equity interests in the Operating Entities to be contributed to Stingray in exchange for shares of Stingray’s common stock. Stingray will not conduct any material business operations prior to the IPO.

The contribution of the Operating Entities will be treated as a combination of entities under common control. The accompanying combined financial statements and related notes of the Company include the assets and liabilities of the Operating Entities at their historical carrying values and the results of their operations and cash flows as if they were combined for all periods presented, or for the periods from their inception, if formed after December 31, 2011.

The Company provides contract land and directional drilling services and completion and production services for oil and natural gas exploration and production. The Company’s contract land and directional drilling services provides drilling rigs and directional tools for both vertical and horizontal drilling of oil and natural gas wells. The Company’s completion and production services includes coil tubing units used to enhance the flow of oil or natural gas, equipment and personnel used in connection with the completion and early production of oil and natural gas wells, and the production of natural sand proppant that is used primarily for hydraulic fracturing in the oil and gas industry. The Company also provides lodging and related services for people working in the oil sands located in Northern Alberta, Canada.

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

The combined financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). All material intercompany accounts and transactions have been eliminated.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the 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.

All highly liquid investments with a maturity of three months or less when acquired are considered cash equivalents. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. Cash balances from time to time may exceed the insured amounts; however the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks on such accounts. The Company had $755,596 and $525,053 of restricted cash included in other current assets in the accompanying Combined Balance Sheets at December 31, 2013 and 2012, respectively, which represented monies held in trust for letters of credit issued to rail car lessors for future lease payments.

The Company records trade accounts receivable at the amounts invoiced to customers, net of an allowance for doubtful accounts. All of the Company’s trade accounts receivable are due from companies in the oil and gas industry, and credit is extended under standard industry terms and conditions, and the Company does not require collateral. Trade accounts receivable are generally due within 30 days of invoicing and are considered past due if not collected in accordance with contractual terms. The Company considers a number of factors in determining the amount of an allowance, including the length of time trade accounts receivable are past due, the customer’s current ability to pay, and the condition of the general economy and industry as a whole. If the Company determines that a customer may not be able to pay, the Company would increase the allowance for doubtful accounts through a charge to income in the period in which that determination is made. If a final determination is made that an account is not collectible, a charge would be made directly to the allowance for doubtful accounts.

Following is a roll forward of the allowance for doubtful accounts for the years ended December 31, 2013 and 2012:

Inventory consists of raw sand and processed sand available for sale, chemicals and other products sold as a bi-product of coil tubing operations, and supplies used in performing services. Inventory is stated at the lower of cost or market (net realizable value) on a first-in, first-out basis.

Inventory also consists of coil tubing strings of various widths, diameters, and lengths that are used in providing specialized services to customers who are primarily operators of oil or gas wells. The strings are used at various rates based on factors such as well conditions (i.e. pressure and friction), vertical and horizontal length of the well, running speed of the string in the well, and total running feet accumulated to the string. The Company obtains usage information from data acquisition software and other established assessment methods and attempts to amortize the strings over their estimated useful life. In no event will a string be amortized over a period longer than 12 months. Amortization is included in cost of revenue on the Combined Statements of Comprehensive Loss and amounted to $585,964 and $172,670, for the years ended December 31, 2013 and 2012, respectively.

Prepaid expenses primarily consist of insurance costs and payments made to a sand supplier (see Note 11). Insurance costs are expensed over the periods that these costs benefit. The payments made to the sand supplier will be recovered through future sand purchases and delivery to the Company over approximately five years. A portion of the prepayments to the sand supplier are included in other non-current assets in the accompanying Combined Balance Sheets.

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

The Company reviews long-lived assets for recoverability in accordance with the provisions of FASB Accounting Standard Codification (“ASC”) Topic 360, Impairment or Disposal of Long-Lived Assets, which requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Recoverability of assets is measured by comparing the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. These evaluations for impairment are significantly impacted by estimates of revenues, costs and expenses, and other factors. If long-lived assets are considered to be impaired, the impairment to be recognized is measured by the amount in which the carrying amount of the assets exceeds the fair value of the assets. In 2013, the Company recognized an impairment loss of $937,803 in the accompanying Combined Statements of Comprehensive Loss for two spudder rigs and related equipment from its drilling segment. The Company made the decision in late 2013, to discontinue offering spudder rig drilling services and has classified the carrying value of the spudder rigs and related equipment in other non-current assets as “held for sale” at December 31, 2013. The impairment was determined by comparing the

fair market value, as determined through an appraisal, with the carrying values of the spudder rigs and related equipment. The impairment charge also includes estimates for the costs to sell. The appraisal primarily relied on the market approach to value, which utilized a sales comparison approach based on research of secondary markets for similar assets. As a result of a moratorium on mining for sand on certain properties in the completion and production segment, the Company recognized an impairment loss of $2,435,716 in the accompanying Combined Statements of Comprehensive Loss for the year ended December 31, 2012. The impairment was determined by comparing the fair values of the long-lived assets, as determined through a market analysis, with the carrying values of the related assets. The market analysis was based on the per acre price of properties adjacent to the Company’s properties. The original carrying value of the Company’s property was based on per acre costs ranging from $7,989 to $17,787; whereas the price per acre of adjacent properties averaged $2,500. Based on this market analysis, the Company reduced the carrying amount of its properties to $2,500 per acre.

Goodwill is tested for impairment as of October 1 each year, or more frequently if events or changes in circumstances indicate that goodwill might be impaired. The impairment test is a two-step process. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the implied value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities as if the reporting unit had been acquired in a business combination. The fair value of the reporting unit is determined using the discounted cash flow approach, excluding interest. The impairment for goodwill is measured as the excess of its carrying value over its implied value. No impairments existed in the years ended December 31, 2013 or 2012.

Intangible assets subject to amortization include customer relationships. Customer relationships are amortized based on an estimated attrition factor of their useful life.

The Company’s financial instruments consist of cash and cash equivalents, trade receivables, trade payables, amounts receivable from or payable to related parties, lines of credit, and long-term debt. The carrying amount of cash and cash equivalents, trade receivables, and trade payables approximates fair value because of the short-term nature of the instruments. The fair value of the lines of credit and long-term debt approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities.

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

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.

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. 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.

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.

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”). The Company had $2,367,491 and $1,617,271 of unbilled revenue included in trade accounts receivable at December 31, 2013 and 2012, respectively. The Company had $107,316 of deferred revenue included in accrued expenses and other current liabilities at December 31, 2012. There was no deferred revenue at December 31, 2013.

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

Except for Lodging, no provision for federal income tax is included in the accompanying financial statements as federal income taxes, if any, are payable by the members. Limited liability companies are subject to taxation in Texas where the Company does business; therefore, the Company may provide for income taxes attributable to that state on a current basis.

Lodging is subject to corporate income taxes, and such taxes are provided in the financial statements pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 740, Income Taxes. Under FASB ASC 740, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of deferred tax assets and liabilities as a result of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

The Company evaluates tax positions taken or expected to be taken in preparation of its tax returns and disallows the recognition of tax positions that do not meet a “more likely than not” threshold of being sustained upon examination by the taxing authorities. As of December 31, 2013 and 2012, no uncertain tax positions existed. Penalties and interest, if any, are recognized in general and administrative expense. The Company’s 2012, 2011 and 2010 income tax returns remain open to examination by the applicable taxing authorities.

For foreign operations, assets and liabilities are translated at the year-end exchange rate, and income statement items are translated at the average exchange rate for the year. Resulting translation adjustments are recorded within accumulated other comprehensive income (loss). Assets and liabilities denominated in foreign currencies, if any, are re-measured at the balance sheet date. Resulting transaction gains or losses are included as a component of current period earnings.

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

Prior to the completion of a proposed IPO by Stingray of its common stock, all of the equity interest in the Operating Entities will be contributed to Stingray and the Operating Entities will become wholly-owned subsidiaries of Stingray (the “Proposed Contribution Transaction”). Stingray, a holding company formed in February 2014, that will not conduct any material business operations prior to the Proposed Contribution Transaction, will be treated as a C-Corp under the Internal Revenue Code and will be subject to income taxes. Accordingly, a pro forma income tax provision has been disclosed as if the Company were a C-Corp for all periods presented. The tax rate is based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. Additionally, upon the Company becoming a subsidiary of Stingray, the Company will establish a net deferred tax liability for differences between the tax and book basis of the Company’s assets and liabilities, and record a corresponding one time charge to net loss. On a pro forma basis at December 31, 2013, the amount of this charge would have been approximately $26.9 million.

In contemplation of a proposed IPO, the Company has presented pro forma loss per share for the most recent annual period. Pro forma basic and diluted loss per share has been computed by dividing net loss attributable to the Company by the number of shares of common stock determined as if the share were outstanding for all of 2013.

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents in excess of federally insured limits and trade receivables. The Company’s accounts receivable have a concentration in the oil and gas industry and the customer base consists primarily of independent oil and natural gas producers. At December 31, 2013, one external customers from the remote accommodation services segment accounted for 11% of our trade accounts receivable balance. At December 31, 2012, one external customers from the completion and production services segment accounted for 18% of the trade accounts receivable balance. No external customers accounted for greater than 10% of the Company’s total revenue for the years ended December 31, 2013 or 2012.

Depreciation and amortization expense was $18,894,379 and $8,121,672 for the years ended December 31, 2013 and 2012, respectively.

As of December 31, the Company had the following definite lived intangible asset recorded:

The original life of customer relationship was 10 years and remaining average useful life is 7.79 years. Amortization expense was $27,500 for both years ended December 31, 2013 and 2012 and is estimated to reflect the pattern of economic benefits of the intangible assets to the Company. Aggregate expected amortization expense for future periods is expected to be as follows:

Goodwill was $88,248 at December 31, 2013 and 2012. There were no changes to the carrying value of goodwill in 2013 or 2012.

Financed insurance premiums are due in monthly installments, bear interest at rates ranging from 1.79% to 3.00% in 2013 and 3.03% to 3.43% in 2012, are unsecured, and mature within the twelve month period following the close of the year.

Certain of the Company’s Operating Entities have entered into lines of credit and long-term debt agreements with banks. All debt is collateralized by substantially all assets of the respective Operating Entities. The debt also contains various customary affirmative and restrictive covenants. At December 31, 2013, Bison was in violation of a restrictive covenant under its long term debt with a bank that requires a minimum tangible net worth of $30 million. Bison’s actual tangible net worth was $28.9 million. The Company received a one-time waiver from the bank for the December 31, 2013 violation. Bison expects to be fully compliant in future periods. There were no debt covenant violations at December 31, 2012.

In July 2012, Bison entered into a $5.0 million revolving credit facility with a bank. Borrowings under the revolving credit facility were subject to a borrowing limitation based on 80% of eligible accounts receivable balances which are further limited to a concentration of 40% of total accounts receivable for a related party and 20% of total accounts receivable for all other customers. Bison made quarterly interest payments on

amounts borrowed under the facility at the prime rate plus an interest rate spread ranging from 1.75% to 2.75% (based on the senior leverage ratio). At December 31, 2012, the Company had outstanding borrowings of $3,670,000 under this facility with a maturity date of July 15, 2013. In May, 2013, Bison terminated its revolving credit facility and repaid all amounts outstanding with the proceeds from a new $5.0 million credit facility entered into with a different bank. Borrowings under the new revolving credit facility are subject to a borrowing limitation based on 80% of eligible accounts receivable balances which are further limited to a concentration of 40% of total accounts receivable for a related party and 20% of total accounts receivable for all other customers. Bison makes monthly interest payments on amounts borrowed under the facility at the greater of prime rate plus .75% or 4.25% (4.25% at December 31, 2013). At December 31, 2013, Bison had outstanding borrowings of $3,350,154 under this facility and the amount available for borrowing was $510,660. The revolving credit facility matures on June 1, 2014.

In April 2012, Energy Services entered into a $1.5 million revolving credit facility with a bank, and in March 2013, Energy Services amended its revolving credit facility and increased its size from $1.5 million to $2.0 million and extended the maturity date to March 17, 2014. Borrowings under the revolving credit facility are subject to a borrowing base equal to 75% of the outstanding trade receivables of Energy Services. Interest is payable monthly at the greater of the prime rate plus 1.00% or 6.00% (6.00% at December 31, 2013). At December 31, 2013 and 2012, Energy Services had outstanding borrowings of $769,175 and $150,000 under this facility. Energy Services had $1,131,612 available for borrowing under this facility at December 31, 2013. The facility was renewed for one year on April 1, 2014, under substantially the same terms.

In June 2013, Energy Services formed a new division known as Redback Pump Downs (“Pump Downs”) and entered into a $1.5 million revolving credit facility with a bank. Borrowings under the revolving credit facility are secured by 75% of the outstanding eligible trade receivables of Pump Downs. Interest is payable monthly at the greater of the prime rate plus 1.00% or 5.25% (5.25% at December 31, 2013). At December 31, 2013, Pump Downs had outstanding borrowings of $282,500 under this facility and the amount available for borrowing was $112,484. The revolving credit facility matures on June 20, 2014.

In October 2013, Energy Services entered into an $8.5 million revolving credit facility with a bank. Borrowings under the revolving credit facility are subject to a borrowing base equal to 60% of the aggregate amount of certain eligible equipment of Energy Services and Pump Downs. Interest is payable monthly at the greater of prime rate plus 1.00% or 5.25% (5.25% at December 31, 2013). As of December 31, 2013, Energy Services had $2,816,550 outstanding under this facility and the amount available for borrowing was $5,691,150. The revolving credit facility matures on October 9, 2014.

In October 2012, Coil Tubing entered into a secured loan agreement with a bank which contained a revolving credit facility in the amount of $3.0 million maturing on October 5, 2013, with interest payable monthly at the greater of the prime rate or 4.50%. There was no balance outstanding against the revolving line of credit at December 31, 2012. The revolving credit facility was refinanced with a different bank in October 2013 with a maximum borrowing amount of $3.0 million. Borrowings under the revolving credit facility are subject to a borrowing base equal to 80% of Coil Tubing’s eligible accounts receivable. Interest is payable monthly at the greater of prime rate of 4.45% (4.45% at December 31, 2013). At December 31, 2013 Coil Tubing had $1,556,897 outstanding under this facility and the amount available for borrowing was $233,858. The revolving credit facility matures on October 9, 2014.

On January, 2013, Muskie entered into a line of credit with a bank in the amount of $3,000,000. This credit facility is secured by a real estate mortgage. The Company makes monthly interest payment on the amounts borrowed under the facility at the prime rate plus 1.5% (4.75% at December 31, 2013). At December 31, 2013, Muskie had $2,138,032 outstanding under the line of credit, which matured on February 1, 2014. In January 2014, this line of credit was renewed through February 1, 2015.

In July 2012, Bison entered into a $10.0 million term loan agreement with a bank. The Company began making quarterly interest payment on September 30, 2012 and quarterly principal and interest payments of $625,000 on December 1, 2012. Amounts borrowed bore interest at LIBOR plus an interest rate spread ranging from 2.5% to 3.5% (based on the senior leverage ratio). As of December 31, 2012, $9,375,000 was outstanding under this agreement, with a maturity date of July 16, 2016. In May 2013, Bison terminated its $10.0 million term loan agreement and repaid all amounts outstanding with the proceeds from a new $30.0 million term loan agreement entered into with a different bank. The new term loan bears interest at the greater of prime plus 0.75% or 4.50% (4.50% at December 31, 2013). Bison was required to make principal payments of $175,000, plus interest, beginning July 1, 2013 and on the first day of each month thereafter through the last day of September 2013. Beginning on October 1, 2013 and on the first day of each month thereafter, Bison was required to make monthly payments pursuant to a 42 month amortization of the remaining principal balance. At December 31, 2013, $27,519,817 was outstanding under this agreement with a maturity date of April 1, 2017. The term loan was increased by $25.0 million in January 2014 in connection with a drilling rig acquisition (see Note 13).

In April 2012, Energy Services entered into a secured loan agreement with a bank which has an aggregate maximum credit amount of $1.5 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 6.00%. The agreement allowed for a 6-month period of loan advances, during which only interest payments were due, followed by 30 monthly installments of principal and interest beginning November 30, 2012 and maturing May 30, 2014. The total amount advanced during the advancing period was $1,004,612. At December 31, 2012, $868,889 was outstanding under this agreement. In April 2013, Energy Services amended its secured loan agreement with a bank and increased its aggregate maximum credit amount from $1.5 million to $3.0 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 6.00%. The loan was converted from an amortizing note to an interest only advancing note with a maturity date of March 31, 2014, which would automatically be extended six months if Energy Services was in compliance with all required covenants. In October 2013, this secured loan agreement was terminated and repaid in full with proceeds from the $8.5 million revolving credit facility entered into with a different bank as described more fully in the “Lines of Credit” section of this footnote.

In October 2012, Coil Tubing entered into a secured loan agreement with a bank which has an aggregate maximum credit amount of $1.2 million. The outstanding borrowings bear interest at the greater of the prime rate or 4.50% (4.50% at December 31, 2012). The agreement allowed for a 6-month period of loan advances, during which only interest payments were due, followed by 29 monthly installments of principal and interest beginning May 5, 2013 and maturing October 5, 2015. There we no amounts outstanding under this agreement at December 31, 2012. In February, 2013 Coil Tubing amended its secured loan agreement with a bank and increased its aggregate maximum credit amount from $1.2 million to $2.4 million. The outstanding borrowings bore interest at the greater of the prime rate or 4.50%. The agreement allowed for a period of loan advances, whereby only monthly interest payments were due and the advancing period was extended from April 5, 2013 to July 31, 2013. Beginning on August 31, 2013 monthly installments of principal and interest were due through a maturity date of July 31, 2016. This secured loan agreement was terminated and repaid in full in October 2013, and Coil Tubing entered into a new secured loan agreement with a different bank and increased the available credit to $8.0 million and extended the period for which advances may be made through June 14, 2014. The note bears interest at a floating rate of the greater of prime plus a margin that ranges from 0.00% to 1.00% based on the ratio of funded debt to EBITDA, or 4.45% (4.45% at December 31, 2013), and requires monthly interest payments through June 14, 2014. After that time, monthly principal and interest payments will be made through the maturity date of October 14, 2017. At December 31, 2013, $4,096,459 was outstanding under this secured loan agreement.

In June 2013, Energy Services entered into a secured loan agreement with a bank in connection with its formation of Pump Downs which had an aggregate maximum credit amount of $4.0 million. The outstanding borrowings bore interest at the greater of the prime rate plus 1.00% or 5.25%. The agreement allowed for a six month period of loan advances, during which only monthly interest payments were due. Beginning on July 21, 2014, monthly installments of principal and interest were to be paid through the maturity date of June 21, 2016. In October 2013, this secured loan agreement was terminated and repaid in full with proceeds from the $8.5 million revolving credit facility entered into with a different bank as described more fully in the “Lines of Credit” section of this footnote.

The components of income tax expense attributable to the Company for the years ended December 31, are as follows:

As of December 31, deferred tax assets and liabilities attributable to the Company consisted of the following:

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the Company’s ability to generate future taxable income during the periods in which those deferred income tax assets would be deductible. The Company considers the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. The Company determined that no valuation allowance was required at December 31, 2013 and 2012. In 2012, the net change in the valuation allowance was $208,931.

At December 31, 2012, Lodging had unused tax loss carryforwards of $1,286,550 which were fully utilized in 2013. There were no unused tax loss carryforwards at December 31, 2013.

The reconciliation of the income tax provision computed at the Company’s effective tax rate is as follows:

All of the Operating Entities, except for Lodging, operate under limited liability company agreements (the “Agreements”) which define the rights and responsibilities of the members and provide for prioritization of the allocation of profits and losses and capital distributions.

Upon formation of certain Operating Entities, specified members of management were granted the right to receive distributions from their respective Operating Entity, after each contributing member’s unreturned capital balance is reduced to zero—referred to as “Pay-out”. The specified member’s right to receive a post Pay-out distribution is generally subject to continued employment. The Company has valued the post Pay-out distribution rights using the option pricing method as of the grant dates that coincide with the formation of the respective Operating Entities. The exercise price was based on the contributing members’ contribution at the formation date. No dividend yield was included because the Company does not plan to pay dividends. For Coil Tubing, valuation assumptions included a risk free interest rate of 0.59%, and expected life of four years, and an expected volatility of 53.26%. For Energy Services, valuation assumptions included a risk free interest rate of 0.83%, an expected life of four years, and an expected volatility of 70.72%. For Panther, valuation assumptions included a risk free interest rate of 0.47%, and expected life of four years, and an expected volatility of 37.27%. No compensation cost has been recognized during the years ended December, 31, 2013 and 2012, because Pay-out was not deemed probable, and the post Pay-out right does not vest until Pay-out is reached. At December 31, 2013 and 2012, the Company had $1,262,129 in unrecognized compensation costs associated with these post Pay-out distribution rights.

One member of management of Energy Services was granted post Pay-out distribution rights that vest in 50 equal installments over a 50 month period commencing on November 30, 2011, subject to continued employment. If full vesting occurs prior to Pay-out, the member would retain the full right without regard to continued employment. The Company has valued the post Pay-out distribution right using the option pricing method as of the October 7, 2011 grant date and has recognized $26,904 of compensation expense in

selling, general and administrative expense in the accompanying Combined Statements of Comprehensive Loss in each of the years ended December 31, 2013 and 2012. Unrecognized compensation cost was $53,807 and $80,711 at December 31, 2013 and 2012, respectively.

On September 30, 2012, two specified members of Bison management were each granted 72,917 restricted stock units (“RSU”) in Bison. The RSU’s vest in 4 equal installments beginning on January 1, 2013 and each anniversary date thereafter. The RSU’s were valued at cost which was based on a transaction by a prior member selling its interest at cost in June 2012. Vesting is subject to continued employment; however, the specified members of Bison would retain full rights to any vested RSU’s without regard to employment. The Company has recognized $336,500 of compensation expense in selling, general and administrative expense in the accompanying Combined Statements of Comprehensive Loss in each of the years ended December 31, 2013 and 2012. Unrecognized compensation cost was $673,000 at December 31, 2013.

The Company provides contract land drilling, directional drilling and completion and production services to an entity under common ownership with Wexford. For the years ended December 31, 2013 and 2012, the Company recognized $14,353,916 and $16,921,070 of revenue, respectively from this entity. Receivables from related parties included $1,064,250 and $2,276,140 from this entity at December 31, 2013 and 2012, respectively.

The Company provides lodging and related services to an entity under common ownership with Wexford. For the years ended December 31, 2013 and 2012, the Company recognized $12,789,152 and $6,541,273 of revenue, respectively, from this entity. Receivables from related parties included $3,596,891 and $962,935 from this entity at December 31, 2013 and 2012, respectively.

The Company sells natural sand proppant and completion and production services to entities under common ownership with Wexford. For the year ended December 31, 2013, the Company recognized $10,012,446 of revenue from the sale of sand and $57,990 for the sale of services to this related party. Receivables from related parties included $1,634,189 at December 31, 2013. There was no revenue or receivables from related parties for sand sales at December 31, 2012.

The Company provided directional drilling services to a member. During the years ended December 31, 2013 and 2012, the Company recognized $12,906,194 and $138,725 of revenue, respectively, for the sale of directional drilling services to this member. Receivables from related parties included $1,849,897 and $138,725 for these services at December 31, 2013 and 2012, respectively.

The Company pays fees to an entity under common ownership with Wexford to transload sand at a rail transloading facility. During the year ended December 31, 2013, the Company incurred $297,067 in costs which are included in product cost of revenue-related parties in the accompanying Combined Statements of Comprehensive Loss. Accounts payable-related parties included $31,509 of transloading fees at December 31, 2013. No such fees were incurred during year ended December 31, 2012.

The Company purchases equipment and contracts for repairs and maintenance on equipment from an entity under common ownership with Wexford. During the year ended December 31, 2013 and 2012, the Company purchased $1,681,672 and $7,982,825 of equipment from this entity. The Company also contracted for repairs and maintenance services of $245,204 for the year ended December 31, 2013. At December 31, 2013 and 2012, payables to related parties included $1,335,819 and $1,436,723, respectively, related to repairs and maintenance and equipment purchases.

The Company rents rotary steerable equipment in connection with its directional drilling services from an entity under common ownership with Wexford. At December 31, 2013, Cost of services—related parties in

the accompanying Combined Statements of Comprehensive Loss included $1,425,860 of such equipment rental costs.

In July 2013, Muskie received a $3,500,000 loan from its members. Muskie accrues interest for the loan at the prime rate plus 2.5% (5.75% at December 31, 2013). The loan matures on July 31, 2014. Amounts payable to related parties includes $3,607,236 for the loan and unpaid interest at December 31, 2013.

Entities under common management with the Company and Wexford provide technical, administrative and payroll services to the Company. The cost of these services primarily relate to payroll expenses. The reimbursement amount for indirect expenses is generally based on estimates of office space provided and time devoted to the Company. During the years ended December 31, 2013 and 2012, the Company incurred total costs under these arrangements of $25,092,243 and $15,235,222, respectively. Of the total costs incurred, $20,231,853 and $13,868,119 is included in Services cost of revenue—related parties for the years ended December 31, 2013 and 2012, respectively, and $1,502,940 is included in Product cost of revenue—related parties for the year ended December 31, 2013, in the accompanying Condensed Combined Statements of Comprehensive Loss. The remaining $3,357,450 and $1,280,577 of costs are included in Selling, general and administrative expenses—related parties for the years ended December 31, 2013 and 2012, respectively. As of December 31, 2013 and 2012, the Company owed the administrative services affiliate $1,435,332 and $1,340,140, respectively, and such amounts are included in payables to related parties in the accompanying balance sheets.

Wexford provides certain administrative and analytical services to the Company. For the years ended December 31, 2013 and 2012, Selling, general and administrative expenses—related parties in the accompanying Combined Statements of Comprehensive Loss included $295,299 and $70,384, respectively, related to these services, and payables to related parties at December 31, 2013 and 2012 included $798,867 and $210,158 due to Wexford for administrative and analytical services, respectively.

From time to time, the Company pays for goods and services on behalf of related party entities under common control, or these related parties pay for goods and services on behalf of the Company. During the years ended December 31, 2013 and 2012, the Company incurred $1,333,757 and $774,881, respectively, of costs from an affiliated entity. Of those amounts, $569,636 and $353,958, respectively, were included in Cost of revenue—related parties, and the remaining costs of $614,962 and $420,923, respectively, were included in Selling, general and administrative expenses—related parties, in the accompanying Combined Statements of Comprehensive Loss. At December 31, 2013 and 2012, receivables from related parties included $0 and $201,889, respectively, and payables to related parties included $1,503,157 and $2,846,898, respectively, related to these arrangements.

In September 2010, Windsor Permian, LLC (now known as Diamondback O&G LLC) (“Windsor Permian”) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with Robert A. Stein the (“Plaintiff”), and Windsor Permian purchased the property subject to that agreement. Windsor Permian subsequently contributed the property to the Company. In an amended complaint filed November 2012 by the Plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the Plaintiff seeks damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a

determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with Plaintiff’s contract but that the interference did not cause the Plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference. The parties involved have agreed upon a schedule for pretrial activities. Subsequently, the Plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss Plaintiff’s claims on the grounds that the damage claim is speculative and that Plaintiff cannot prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013, and on March 13, 2014, the first judicial district court of Goodhue County, Minnesota, issued a decision in favor of the defendants. On April 9, 2014, counsel for both Plaintiff and the defendants have agreed that neither party will pursue an appeal from any order issued in the case, and that each side would likewise waive any entitlement to taxable costs. If there is no appeal within 60 days, of the decision, than the case will be closed. Management has determined that the possibility of loss is remote; however litigation is inherently uncertain and management cannot determine the amount of loss, if any that may result.

The Company is routinely involved in various legal matters arising from the normal course of business. There were no legal matters outstanding, other than what is described in the immediately preceding paragraph, which are expected to have a material adverse effect on the financial position or results of operations of the Company.

The Company entered into a purchase agreement on August 15, 2012, with a sand supplier. The Company is subject to a monthly commitment for the purchase of a minimum amount of sand. The Company must purchase 548 tons per day which equates to 200,020 tons of sand on an annual basis. If the minimum purchase requirement is not met, the shortfall is settled on a monthly basis. Future commitments related to this agreement are:

Shortfall expense incurred under this purchase agreement for the period ended December 31, 2012 was $585,750. The Company purchased the monthly minimum amount of sand in 2013. The Company has identified an alternative source for sand and does not believe the loss of the primary supplier under the purchase agreement would have a material adverse effect on the Company.

In October 1, 2013, a specified member of management was granted a long-term incentive award (“LTIA”) equal to 2% of the net proceeds from the sale or other disposition of Muskie and/or Lodging. The distribution of the LTIA is subject to certain adjustments, including deductions for costs and expenses related to the disposition and recovery of specified capital by members’ or equity holders, as applicable. The LTIA vests in 4 equal installments on December 31 of each year, beginning on December 31, 2013. Vesting is subject to continued employment; however the specified member of management would retain full right to any vested portion without regard to employment. No amounts have been accrued or disclosed for the LTIA as the sale or disposition of Muskie and/or Lodging is not deemed probable and the LTIA distribution is not estimable.

The Company leases real estate, rail cars and other equipment under long-term operating leases with varying terms and expiration dates through 2022. Aggregate future minimum lease payments under these non-cancelable operating leases in effect at December 31, 2013 are as follows:

For the years ended December 31, 2013 and 2012, the Company recognized rent expense of $2,011,365 and $219,550, respectively.

The Company has entered into employment contracts with certain key employees for remaining periods up to two years. In the event of termination without good cause, these employees may receive compensation owed under the contracts. The maximum that could be paid under the contracts at December 31, 2013 is $890,000.

The Company has entered into an agreement in which certain key employees would receive bonuses in the event of a sale or initial public offering. The maximum amount that could be paid under the agreement at December 31, 2013 is $3.0 million upon a sale or $1.5 million upon an initial public offering.

The Company is organized into four reportable segments based on the nature of services provided and the basis in which management makes business and operating decisions. The Company principally provides oilfield services in connection with on-shore drilling of oil and natural gas wells for small to large domestic independent oil and natural gas producers.

The Company’s four segments consist of contract land and directional drilling services, completion and production—services, completion and production—natural sand proppant production, and remote accommodation services. The drilling segment provides contract land and directional drilling services. The completion and production—services segment provides pressure control services, flowback services, and equipment rental services. The completion and production—natural sand proppant production segment produces and sells sand for use in hydraulic fracturing. The remote accommodation services business provides housing, kitchen and dining, and recreational service facilities for oilfield workers that are located in remote areas away from readily available lodging.

During 2012 and 2013, the drilling segment primarily served customers in the Permian Basin in West Texas and the Utica Shale in Eastern Ohio. The completion and production operations primarily served customers in the Permian Basin in West Texas, the Eagle Ford Shale in South Texas the Granite Wash in Oklahoma and Texas, and the Cana Woodford Shale and the Cleveland Sand in Oklahoma. The remote accommodation operation served customers in the oil sands of Northern Alberta, Canada.

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

The Company has evaluated the period after December 31, 2013 through May 14, 2014, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

On January 29, 2014, Bison acquired five used drilling rigs for $50.6 million. The acquisition will be accounted for as a business combination and was financed through $25.6 million of member contributions and $25.0 million of additional long-term debt. Bison amended its existing long-term debt agreement with a bank to add $25.0 million in borrowings, suspend monthly principal payments until May 31, 204, and extend the maturity date to April 30, 2017. All other terms of the debt agreement remained substantially the same.

We have audited the accompanying combined financial statements of Stingray Pressure Pumping LLC and Affiliates (Stingray Cementing LLC, Stingray Logistics LLC and Stingray Energy Services LLC) (all Delaware limited liability companies), which comprise the combined balance sheets as of December 31, 2013 and 2012, and the related combined statements of operations, members’ equity, and cash flows for the year ended December 31, 2013 and the period from March 20, 2012 (inception) to December 31, 2012, and the related notes to the financial statements.

Management is responsible for the preparation and fair presentation of these combined financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the combined financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the combined financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Stingray Pressure Pumping LLC and Affiliates as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the year ended December 31, 2013 and the period from March 20, 2012 (inception) to December 31, 2012 in accordance with accounting principles generally accepted in the United States of America.

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

Note A – Nature of Operations and Summary of Significant Accounting Policies

Stingray Pressure Pumping LLC (“Pressure Pumping”) was formed March 20, 2012 (“Inception”) as a Delaware limited liability company and is based in Oklahoma. Stingray Cementing LLC (“Cementing”) was formed May 29, 2012 as a Delaware limited liability company and is based in Oklahoma. Stingray Logistics LLC (“Logistics”) was formed November 19, 2012 as a Delaware limited liability company and is based in Oklahoma. Stingray Energy Services LLC (“Energy Services”) was formed February 5, 2013 as a Delaware limited liability company and is based in Oklahoma. All of the entities were formed by Wexford Capital LP (“Wexford”) and Gulfport Energy Corporation (“Gulfport”), are under common control and are referred to collectively as “Stingray” or the “Company”.

Stingray provides production and completion services and oilfield rentals for oil and natural gas exploration companies. Production and completion services include the hauling of proppant and other goods, cementing in the casing pipe, and hydraulic fracturing and other pressure pumping services. The Company operates primarily within the Utica Shale in Ohio and surrounding areas.

The combined financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP). All material accounts and transactions between the entities within the Company have been eliminated in the combined financial statements.

Certain prior year balances have been reclassified to conform to the current year presentation. The reclassifications had no effect on our previously reported results of operations.

All highly liquid investments with a maturity of three months or less when acquired are considered cash equivalents. The Company maintains its cash in accounts which may, at times, exceed federally insured limits. At December 31, 2013, the Company had approximately $17,764,000 of its cash and cash equivalents with three financial institutions. The Company had no restricted cash included in its cash or current asset balances at December 31, 2013. The Company has not experienced any losses in these accounts and believes it is not exposed to any significant credit risk.

Accounts receivable include amounts due from customers for services performed and are recorded as the work progresses. The Company grants credit to customers in the ordinary course of business and generally does not require collateral. Most areas in which the Company operates provide for a mechanic’s lien against the property on which the service is performed if the lien is filed within the statutorily specified time frame. Customer balances are generally considered delinquent if unpaid by the 30^th day following the invoice date and credit privileges may be revoked if balances remain unpaid. At December 31, 2013 and 2012, substantially all of the Company’s accounts receivable are due from a related party (See Note M- Related Party Transactions).

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

The Company did not recognize any allowance for doubtful accounts as of December 31, 2013 and December 31, 2012.

Inventories are stated at the lower of cost or market, determined on a weighted average cost basis. Inventories consist of consumable supplies. The Company assesses the valuation of its inventories based upon specific usage and future utility. A charge to results of operations is taken when factors that would result in a need for a reduction in the valuation, such as excess or obsolete inventory, are determined. As of December 31, 2013 and 2012 the reserves were $50,000 and $0, respectively.

Property and equipment are recorded at cost. Expenditures for major additions and improvements are capitalized while minor replacements, maintenance and repairs, which do not increase the capacity, improve the efficiency or safety, or extend the useful life of such assets, are charged to operations as incurred. Disposals are removed at cost, less accumulated depreciation, and any resulting gain or loss is reflected in operations.

Depreciation is calculated using the straight-line method over the shorter of the estimated useful life, or the remaining lease term, as applicable. The useful lives of the major classes of property and equipment are as follows:

Long-lived assets, primarily property and equipment 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 flows from the assets are not sufficient to recover the carrying amount of such assets, the assets are adjusted to their estimated values. There was no impairment recorded for the year ended December 31, 2013 or the period from Inception to December 31, 2012.

The Company capitalizes certain costs in connection with obtaining its borrowings, such as lender’s fees and related attorney’s fees. These costs are charged to interest expense over the contractual term

The Company recognizes revenue when services are performed, collection of the receivable is probable, persuasive evidence of an arrangement exists, and the price if fixed and determinable. Services are sold without warranty or right of return. Taxes assessed on revenue transactions are presented on a net basis and are not included in revenue.

Pressure Pumping services are typically provided pursuant to a per stage pricing agreement, hourly or spot market basis. Each stage is short-term in nature and is typically completed over the course of or within a few hours of starting the stage. Revenue is recognized upon the completion of each day’s work based upon a completed field ticket. The field ticket includes charges for the mobilization of equipment to location, the services performed, the personnel on the job and any additional equipment used on the job. Additional revenue is generated through the sale of consumable supplies that are incidental to the service being performed. Revenue from consumable supplies is recognized as the consumables are used in the delivery of the overall services. The use of consumable supplies is reflected on completed field tickets.

Logistics, Energy Services, and Cementing typically generate revenues on a day rate, hourly rate or contracted basis, and revenue is recognized when the services are completed and collectability is reasonably assured. Additional revenue may be generated through labor charges and the sale of consumable supplies that are incidental to the service being performed. Revenue from labor charges are recognized as labor is performed and revenue from consumable supplies is recognized as the consumables are used in the delivery of the overall services. Proceeds from customers for the cost of oilfield rental equipment that is involuntarily damaged or lost down-hole are reflected as revenues and typically recognized upon completion of the job.

The primary components of cost of services are those salaries, consumable supplies, repairs and maintenance and general operational costs that are directly associated with the services performed for the customers. Cost of services – related parties reflects expenses from related parties.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include but are not limited to the allowance for doubtful accounts, depreciation and amortization of property and equipment and the future cash flows and fair values used to assess recoverability and impairment of long-lived assets.

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

Each of the operating entities comprising the Company are limited liability companies and as such are treated as pass-through entities for income tax purposes. As a pass-through entity, income taxes on net earnings are payable by the members and are not reflected in the financial statements.

As required by Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 740, Income Taxes, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. During the years ended December 31, 2013 and 2012, there were no financial statement benefits or obligations recognized related to uncertain tax positions.

The Company’s accounting policy relating to income tax penalties and interest assessments is to accrue for these costs and record a charge to selling, general and administrative expense for tax penalties and a charge to interest expense for interest assessments during the period the Company has unrecognized tax benefits. The pass-through entities are not subject to tax examinations by tax authorities for years before 2012.

The Company’s financial instruments consist primarily of cash and cash equivalents, trade receivables, related party receivables, trade accounts payable, related party payables and long-term debt. The carrying value of cash and cash equivalents, trade receivables, related party receivables, trade payables and related party payables are considered representative of their fair value due to the short term nature of these instruments. The fair value of long-term debt is deemed representative of fair value based on bearing interest rates and having terms comparable to market conditions.

Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents occasionally in excess of federally insured limits and trade receivables. The Company’s accounts receivable have a concentration in the oil and natural gas industry and the customer bases consists primarily of independent oil and natural gas producers.

Sales to one related party customer accounted for 99.9% of net sales and substantially all of accounts receivable for the year ended December 31, 2013 and 100% for the period from Inception to December 31, 2012.

Pressure Pumping relies on a limited number of suppliers for sand and chemicals. These key materials are critical for certain of the Company’s operations. The loss of one or more of these suppliers or the limited availability of these materials may negatively impact the Company’s revenues or increase the operating costs.

Estimated remediation costs are accrued using currently available facts, existing environmental permits, technology and enacted laws and regulations. For sites where we are primarily responsible for remediation, our cost estimates are developed based on internal evaluations and are not discounted. Accruals are recorded when it is probable that we will be obligated to pay for environmental sit

evaluation, remediation or related activities, and such costs can be reasonably estimated. As additional information becomes available, accruals are adjusted to reflect current cost estimates. Ongoing environmental compliance costs, such as obtaining environmental permits, installation of pollution control equipment and waste disposal are expensed as incurred.

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

Depreciation expense charged to operations totaled $9,858,443 and $1,260,391 for the year ended December 31, 2013 and the period from Inception to December 31, 2012, respectively.

Accrued and other current liabilities consisted of the following as of December 31:

On July 3, 2013, the Company entered into a $50,000,000 term loan with a third party lender. The loan subjects the Company to certain financial reporting requirements and financial covenants. The loan requires maintenance of a minimum tangible net worth of $30,000,000. The loan also requires that debt to tangible net worth not to exceed 1.75 to 1.00. The loan is secured by certain specified equipment. The loan matures over 36 months and

requires a monthly payments of principal and interest. As of December 31, 2013, the monthly payments were $1,488,000. The maturity date is August 1, 2016. The loans bears interest at the rate of New York Prime Rate plus 0.75% and is subject to a floor of 4.50%. The outstanding balance at December 31, 2013 was $43,424,095. The interest rate at December 31, 2013 was 4.50%. The Company was in compliance with the financial covenants at December 31, 2013.

On July 17, 2013, the Company entered into a $500,000 term loan with a third party lender. The loan is secured by certain specified equipment. The loan matures over 60 months and requires a monthly payments of principal and interest. As of December 31, 2013, the monthly payments were $9,514. The maturity date is July 15, 2018. The outstanding balance at December 31, 2013 was $463,231. The loans bears interest at a fixed rate of 5.34%.

On December 4, 2013, the Company entered into an $8,543,142 term loan with a third party lender. The loan subjects the Company to certain financial reporting requirements and financial covenants. The loan requires maintenance of a minimum tangible net worth of $5,000,000 plus 50% of all earnings beginning 12/31/2013. The loan also requires a debt service coverage ratio in excess of 1.25 to 1.00. The loan is secured by certain specified equipment. The loan matures over 42 months and requires a monthly payments of interest beginning in January 2014 and monthly payments of principal and interest beginning in January 2015. The maturity date is June 5, 2016. The loans bears interest at a rate of the prime lending rate for large US Money Center Commercial banks plus 1.00% and is subject to a floor of 4.95%. The outstanding balance at December 31, 2013 was $4,315,428. The interest rate at December 31, 2013 was 4.95%. The Company was in compliance with the financial covenants at December 31, 2013.

On various dates between November 26, 2012 and October 25, 2013, the Company entered into borrowing agreements to finance the purchase of certain vehicles and trailers. The agreements are secured by certain specified vehicles. The cost of the vehicles and trailers serving as collateral for the borrowing agreements was $3,224,465 at December 31, 2013. The loan agreements are for 48 months and require monthly payments of principal and interest. As of December 31, 2013, the monthly payments were $43,312. The outstanding balance at December 31, 2013 and December 31, 2012 was $1,486,092 and $1,363,894, respectively. The interest rates on the loans are fixed and range from 5.25% to 5.99%.

At December 31, 2013, the aggregate maturities of long-term debt are as follows:

The Company incurs loan origination fees that are initially capitalized and are included in “other current assets” and “other noncurrent assets” in the combined balance sheets. The balance of unamortized origination fees were $490,446 and $0 as of December 31, 2013 and 2012, respectively. These costs are amortized as a charge to interest expense using the effective interest method. The Company recorded amortization of $129,630 and $0 for the year ended December 31, 2013 and the period ended December 31, 2012, respectively.

The Company has committed to various housing, facility and equipment leases some of which have renewal and purchase options. The lease terms vary from one to six months.

Rent expense for the year ended December 31, 2013 and the period from Inception to December 31, 2012 was $1,668,240 and $224,726, respectively.

Each of Pressure Pumping, Cementing, Logistics, and Energy Services operates under a limited liability company agreement (the “Agreement”) and will continue perpetually until terminated pursuant to statute or any provision of the Agreements. No member shall be liable for the expenses, liabilities or obligations of the Company.

Each Agreement provides for specific voting rights of the members. For matters that require vote, members shall have one vote for each whole percentage interest held by the member at the time of vote.

Distributions and profit and loss allocations are based on the pro rata share of each member’s ownership percentages.

Each Agreement places limits on the transfer of members’ interests. Encumbrances are prohibited unless they are a Permitted Encumbrance, as defined in the Agreement.

The Company is, from time to time, involved in routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims and employment related disputes. In the opinion of management, none of the pending litigation, disputes or claims against the Company, if decided adversely, is expected to have a material effect on the Company’s financial condition, results of operations, or cash flows.

The Company has entered into contracts with a certain key employee that in the event of either an initial public offering (“IPO”) or sale of substantially all of the assets of the Company to a third party buyer this employee would receive a cash payment in the amount of 1% of the difference between the net proceeds from a sale of the Company and the total investment in the Company of its owners or a stock grant in the event of an IPO. The amount of any grant of stock would be determined by the Company’s approved stock plan.

The Company has firm purchase commitments for equipment of approximately $2,218,338 as of December 31, 2013.

Upon formation of each Stingray entity, specified members of management were granted the right to receive capital distributions under the various Agreements, after each contributing member’s unreturned capital balance is reduced to zero – referred to as “Pay-out”. The specified member’s right to receive a post Pay-out distribution is generally subject to continued employment. The Company has valued the post Pay-out distribution rights using the option pricing method as of the grant dates that coincide with the formation of the respective entities. The exercise price was based on the contributing members’ contributions at the formation date. No dividend yield was included because the Company does not plan to pay dividends. For Pressure Pumping, valuation assumptions included a risk free interest rate of 0.95%, expected life of four years, and an expected volatility of 49.39%. For Cementing, valuation assumptions included a risk free interest rate of 0.64%, an expected life of four years, and an expected volatility of 54.69%. For Logistics, valuation assumptions included a risk free interest rate of 0.47%, an expected life of four years, and an expected volatility of 45.91%. For Energy Services, valuation assumptions included a risk free interest rate of 0.61%, an expected life of four years, and an expected volatility of 37.91%.

No compensation cost has been recognized during the year ended December 31, 2013 and from Inception through December 31, 2012, because Pay-out was not deemed probable, and the post Pay-out right does not vest until Pay-out is reached. At December 31, 2013, the Company had $2,070,082 in unrecognized compensation costs associated with these post Pay-out distribution rights.

The Company provides certain services to Gulfport Energy Corporation, a member of the Company (“Gulfport”). For the year ended December 31, 2013, $95,071,548 of the Company’s revenues were generated through transactions with Gulfport. During the period from Inception through December 31, 2012, all of the Company’s revenues were generated through transactions with Gulfport. Accounts receivable from Gulfport as of December 31, 2013 and 2012 were $14,109,129 and $5,329,427, respectively.

Gulfport also provided administrative and payroll services to the Company under a shared services agreement. These amounts totaled $568,974 during 2013 and $2,447,151 for the period from Inception through December 31, 2012. During the year ended December 31, 2013, the entire amount was for selling, general and administrative activities. During the period from Inception from December 31, 2012, $1,211,530 was for cost of services revenue activities and $1,235,621 was for selling, general and administrative activities. As of December 31, 2013 and 2012, the Company owed Gulfport $0 and $928,020, respectively.

The Company purchases sand used in its hydraulic fracturing operations from an affiliate. During the year ended December 31, 2013, the Company purchased $9,266,078 in sand and the entire amount is included in cost of services revenue activities. As of December 31, 2013, related party accounts payable included $1,576,199 payable to the affiliate.

The Company rented certain equipment used in its hydraulic fracturing operations from an affiliate. During the year ended December 31, 2013, the Company rented $65,410 in equipment from the affiliate and the entire amount is included in cost of services revenue activities. As of December 31, 2013, related party accounts payable included $65,410 payable to the affiliate.

The Company purchases equipment and contracts for repairs and maintenance on equipment from an affiliate. During the year ended December 31, 2013 and for the period from Inception through December 31, 2012, the Company purchased equipment, including deposits for equipment not yet delivered of $10,400,705 and $21,028,452, respectively. The Company also contracted for repairs and maintenance services during the year ended December 31, 2013 of $1,666,229. As of December 31, 2013 and 2012, related party accounts payable included $3,023,742 and $170,144, respectively.

The Company receives some administrative services from certain affiliates. These amounts totaled $2,220 during 2013. Of this amount, $455 was for cost of services revenue activities and $1,765 was for selling, general and administrative activities. As of December 31, 2013, related party accounts payable included $2,220.

A tabular summary of transactions with related parties for the year ended December 31, 2013 and the period from Inception to December 31, 2012 follows:

The Company provides a 401(k) retirement plan that enables workers to defer up to specific percentages of their annual compensation and contribute such amount to the plan. The Company provides a contribution of 3% for each employee and could also contribute additional amounts at their sole discretion. For the year ended December 31, 2013 and the period from Inception to December 31, 2012, the contributions were $319,406 and $99,542, respectively.

The Company has evaluated events and transactions that occurred subsequent to December 31, 2013 through May 14, 2014, the date these financials were available to be issued, for potential disclosure in these financial statements.

On January 16, 2014 the Company paid down all outstanding principal and interest of $489,217 on the term loan dated July 17, 2013 using a portion of the proceeds from the term loan dated December 4, 2013.

We have audited the accompanying Statements of Revenues and Direct Operating Expenses of Certain Drilling Rigs (the “Statements”) of Lantern Drilling Company (“Lantern Rigs”) acquired by Bison Drilling and Field Services, LLC (“Bison”) for the years ended December 31, 2013 and 2012, and the related notes to the statements.

Bison management is responsible for the preparation and fair presentation of these statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of statements that are free from material misstatement, whether due to fraud or error.

Our responsibility is to express an opinion on these statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Lantern Rigs as described in Note A for the years ended December 31,2013 and 2012, in accordance with accounting principles generally accepted in the United States of America.

As described in Note A, the accompanying statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and are not intended to be a complete financial presentation of the Lantern Rigs’ revenues and expenses. Our opinion is not modified with respect to this matter.

The accompanying statements present the revenues and direct operating expenses for five drilling rigs (the “Rigs”) that were operated by Lantern Drilling Company (“Lantern”) in Texas and Louisiana during the years ended December 31, 2013 and 2012. Lantern is a wholly-owned subsidiary of Forest Oil Permian Corporation (“Forest Permian”) and provides contract land drilling services for oil and natural gas exploration and production. Forest Permian is a wholly-owned subsidiary of Forest Oil Corporation (“Forest Oil”). As discussed in Note E, the Rigs were acquired by Bison Drilling and Field Services, LLC (“Bison”) on January 29, 2014.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Lantern. The historical statements presented are not indicative of the financial condition or results of operations of the Lantern Rigs due to the omission of certain operating expenses, and such amounts may not be indicative of future operations. The statements do not include depreciation because the Rigs were owned by third party financial institutions that leased the Rigs to Forest Oil under operating leases and Forest Oil sub-leased the Rigs to Lantern. The statements also do not include corporate overhead, interest expense or income taxes because those costs are not directly related to revenue producing activities of the Rigs and are not separately identifiable by rig.

Historical financial statements reflecting the financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented because Lantern did not own the Rigs and such information was not available to prepare the full financial statements required by Securities and Exchange Commission Regulation S-X, Rule 3-05. Accordingly, the historical statements of revenues and direct operating expenses of the Rigs are presented in lieu of financial statements required under Rule 3-05.

The preparation of the accompanying statements in conformity with generally accepted accounting principles requires making estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. The estimates include revenue and expense accruals and estimates for allocations of certain operating expenses to individual rigs. Actual results could materially differ from these estimates.

Lantern earns contract drilling revenue, mobilization revenue and equipment rental revenue, primarily under day work contracts. Revenues on day work contracts are recognized based on the days completed at the day rate each contract specifies.

Lantern provided drilling services to Forest Oil. For the years ended December 31, 2013 and 2012, contract drilling services revenue included $25,057,254 and $29,543,396, respectively, from Forest Oil.

Certain employees of Forest Oil provided direct management services to Lantern. General and administrative expenses in the accompanying Statements of Direct Revenues and Operating Expenses represents

the management fee charged by Forest to Lantern for such services. The management fee was based on payroll, benefits and overhead for the direct management employees.

In August 2007 Forest Oil sold one of the five rigs to a financial institution, and between June and December 2010 Forest Oil sold the other four rigs to various financial institutions. In all cases Forest Oil leased the rigs back from the financial institutions under long-term non-cancellable operating leases having varying terms and expiration dates through July 2017. Lantern sub-leased the rigs from Forest Oil. For the years ended December 31, 2013 and 2012, Lantern recognized $13,602,448 and $13,434,164, respectively, of operating lease rental expense. The operating leases were paid in full and terminated in January 2014.

Lantern has evaluated the period after December 31, 2013 through May 14, 2014, the date the statements of revenues and direction operating expenses were available to be issued, noting no subsequent events other than what is identified below.

On January 29, 2014, Bison, a third party, acquired the Rigs directly from the financial institutions that leased the Rigs to Lantern. The amounts paid by Bison to acquire the Rigs along with approximately $3.1 million paid by Forest Oil, were used to pay off the operating leases in their entirety and terminate the lease agreements.

We have audited the accompanying balance sheet of Stingray Energy Services, Inc., (a Delaware corporation) (the “Company”), as of February 5, 2014. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

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

In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Stingray Energy Services, Inc. as of February 5, 2014, in conformity with accounting principles generally accepted in the United States of America.

Stingray Energy Services, Inc. (“Stingray Energy”) is a Delaware corporation formed by Wexford Capital LP (“Wexford”) on February 4, 2014 and capitalized on February 5, 2014. The name of the corporation was previously Redback Inc. The name was changed on May 12, 2014.

Stingray Energy intends to offer common stock pursuant to an initial public offering. Prior to the effectiveness of the registration statement, Wexford will cause the equity interest in Redback Energy Services LLC, Redback Coil Tubing LLC, Muskie Proppant LLC and Great White Sand Tiger Lodging Ltd. to be contributed to Stingray Energy in return for shares of common stock and, and as a result, such entities will become wholly-owned subsidiaries of Stingray Energy. In addition, at the same time, four other entities, Stingray Pressure Pumping LLC, Stingray Cementing LLC, Stingray Logistics LLC and Stingray Energy Services LLC, in which Wexford and its affiliates currently own, in the aggregate, a non-controlling 50% interest, will be contributed to Stingray Energy by the holders of all of the equity interests in these entities in return for shares of common stock, at which time these entities will also become wholly-owned subsidiaries of Stingray Energy.

Through February 5, 2014, Stingray Energy had not earned any income and had incurred only nominal expenses; therefore, the statements of income, stockholder’s equity and cash flows have been omitted.

The Company has evaluated events and transactions that occurred subsequent to February 5, 2014 through February 14, 2014, the date the financials were available to be issued, for potential recognition or disclosure in this financial statement.

Until , 2014 (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

The following table sets forth the fees and expenses in connection with the issuance and distribution of the securities being registered hereunder. Except for the SEC registration fee and FINRA filing fee, all amounts are estimates.

Section 102(b)(7) of the Delaware General Corporation Law, or the DGCL, permits a corporation, in its certificate of incorporation, to limit or eliminate, subject to certain statutory limitations, the liability of directors to the corporation or its stockholders for monetary damages for breaches of fiduciary duty, except for liability:

In accordance with Section 102(b)(7) of the DGCL, Section 9.1 of our certificate of incorporation provides that that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by Section 102(b)(7) of the DGCL. However, this provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

If the DGCL is amended to authorize corporate action further eliminating or limiting the liability of directors, then, in accordance with our certificate of incorporation, the liability of our directors to us or our stockholders will be eliminated or limited to the fullest extent authorized by the DGCL, as so amended. Any repeal or amendment of provisions of our certificate of incorporation limiting or eliminating the liability of directors, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to further limit or eliminate the liability of directors on a retroactive basis.

Section 145 of the DGCL permits a corporation, under specified circumstances, to indemnify its directors, officers, employees or agents against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlements actually and reasonably incurred by them in connection with any action, suit or proceeding brought by third parties by reason of the fact that they were or are directors, officers, employees or agents of the corporation, if such directors, officers, employees or agents acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reason to believe their conduct was unlawful. In a derivative action, i.e., one by or in the right of the corporation, indemnification may be made only for expenses actually and reasonably incurred by directors, officers, employees or agents in connection with the defense or settlement of an action or suit, and only with respect to a matter as to which they shall have acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation, except that no indemnification shall be made if such person shall have been adjudged liable to the corporation, unless and only to the extent that the court in which the action or suit was brought shall determine upon application that the defendant directors, officers, employees or agents are fairly and reasonably entitled to indemnity for such expenses despite such adjudication of liability.

Our certificate of incorporation provides that we will, to the fullest extent authorized or permitted by applicable law, indemnify our current and former directors and officers, as well as those persons who, while directors or officers of our corporation, are or were serving as directors, officers, employees or agents of another entity, trust or other enterprise, including service with respect to an employee benefit plan, in connection with any threatened, pending or completed proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss (including, without limitation, attorney’s fees, judgments, fines, ERISA excise taxes and penalties and amounts paid in settlement) reasonably incurred or suffered by any such person in connection with any such proceeding. Notwithstanding the foregoing, a person eligible for indemnification pursuant to our certificate of incorporation will be indemnified by us in connection with a proceeding initiated by such person only if such proceeding was authorized by our board of directors, except for proceedings to enforce rights to indemnification.

The right to indemnification conferred by our certificate of incorporation is a contract right that includes the right to be paid by us the expenses incurred in defending or otherwise participating in any proceeding referenced above in advance of its final disposition, provided, however, that if the DGCL requires, an advancement of expenses incurred by our officer or director (solely in the capacity as an officer or director of our corporation) will be made only upon delivery to us of an undertaking, by or on behalf of such officer or director, to repay all amounts so advanced if it is ultimately determined that such person is not entitled to be indemnified for such expenses under our certificate of incorporation or otherwise.

The rights to indemnification and advancement of expenses will not be deemed exclusive of any other rights which any person covered by our certificate of incorporation may have or hereafter acquire under law, our certificate of incorporation, our bylaws, an agreement, vote of stockholders or disinterested directors, or otherwise.

Any repeal or amendment of provisions of our certificate of incorporation affecting indemnification rights, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing at the time of such repeal or amendment or adoption of such inconsistent provision with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision. Our certificate of incorporation also permits us, to the extent and in the manner authorized or permitted by law, to indemnify and to advance expenses to persons other that those specifically covered by our certificate of incorporation.

Our bylaws include the provisions relating to advancement of expenses and indemnification rights consistent with those set forth in our certificate of incorporation. In addition, our bylaws provide for a right of indemnitee to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full

by us within a specified period of time. Our bylaws also permit us to purchase and maintain insurance, at our expense, to protect us and/or any director, officer, employee or agent of our corporation or another entity, trust or other enterprise against any expense, liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under the DGCL.

Any repeal or amendment of provisions of our bylaws affecting indemnification rights, whether by our board of directors, stockholders or by changes in applicable law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing thereunder with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision.

We will enter into indemnification agreements with each of our current directors and executive officers. These agreements will 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.

Under the Underwriting Agreement, the underwriters are obligated, under certain circumstances, to indemnify directors and officers of the registrant against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or the Securities Act. Reference is made to the form of Underwriting Agreement to be filed as Exhibit 1.1 to this Registration Statement.

In connection with the contribution described in this registration statement, we intend to issue shares of our common stock to Redback Holdings and shares of our common stock to Gulfport, in each case prior to the effective date of this registration statement. The shares of our common stock described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(2) of the Securities Act as sales by an issuer not involving any public offering.

All schedules are omitted because the required information is (i) not applicable, (ii) not present in amounts sufficient to require submission of the schedule or (iii) included in our financial statements and the accompanying notes included in the prospectus to this Registration Statement.

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification by the Registrant for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer, or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered hereunder, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Oklahoma City, Oklahoma, on , 2014.

KNOW ALL MEN BY THESE PRESENT, that each person whose signature appears below constitutes and appoints , and each of them, his true and lawful attorney-in-fact and agents, with full power of substitution and resubstitution, from such person and in each person’s name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to the Registration Statement, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission and to sign and file any other registration statement for the same offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on , 2014.



Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price^{( 2)}	Amount of Registration Fee
Common Stock, par value $0.01 per share⁽¹⁾	$	$


	Page
PROSPECTUS SUMMARY		1

RISK FACTORS		15

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		39

USE OF PROCEEDS		40

DIVIDEND POLICY		41

CAPITALIZATION		42

DILUTION		43

SELECTED HISTORICAL COMBINED FINANCIAL DATA		44

PRO FORMA FINANCIAL INFORMATION		47

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		51

BUSINESS		65

MANAGEMENT		88

RELATED PARTY TRANSACTIONS		94

PRINCIPAL AND SELLING STOCKHOLDERS		98

DESCRIPTION OF CAPITAL STOCK		99

SHARES ELIGIBLE FOR FUTURE SALE		102

MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS		104

UNDERWRITING		108

LEGAL MATTERS		113

EXPERTS		113

WHERE YOU CAN FIND MORE INFORMATION		113

GLOSSARY OF OIL AND NATURAL GAS TERMS		A-1

INDEX TO FINANCIAL STATEMENTS		F-1


Facility		Amount
March 2013 Redback facility
June 2013 Redback facility
September 2013 Redback facility
October 2013 Coil Tubing facility
January 2013 Muskie facility
May 2013 Bison facility


	As of December 31, 2013
	Actual⁽¹⁾			Pro Forma		Pro Forma As Adjusted⁽²⁾
	(in thousands)
Cash and cash equivalents	$	8,284		$		$

Long-term debt (including current maturities)⁽³⁾	$	31,616		$		$
Member’s equity		95,169			—		—
Stockholders’ equity:
Common stock, par value $0.01; 1,000 shares authorized and 100 shares issued and outstanding actual; shares authorized and shares issued and outstanding as adjusted for the offering		—
Additional paid-in capital		21,201
Accumulated earnings⁽⁴⁾		5,929
Accumulated other comprehensive loss		(1,585	)

Total stockholders’ equity		25,545

Total capitalization	$	152,330		$		$


Assumed initial public offering price per share		$
Net tangible book value per share as of December 31, 2013	$
Increase per share attributable to new investors	$

As adjusted net tangible book value per share after the offering		$

Dilution per share to new investors		$


	Shares Purchased				Total Consideration				Average Price
	Number	Percent			Amount	Percent			Per Share
Existing stockholders				%	$			%	$
New investors				%				%

Total			100.0	%	$		100.0	%	$


	Year Ended December 31,
	2013			2012
	(in thousands, except per share data)
Reconciliation of Adjusted EBITDA to net loss:
Net loss	$	(13,972	)	$	(2,058	)
Depreciation and amortization expense		18,995			8,149
Impairment of long-lived assets		938			2,435
Equity based compensation		518			363
Interest expense		2,013			274
Other (income) expense, net		215			49
Provision for income taxes		2,715			1,013

Adjusted EBITDA	$	11,422		$	10,225


	Redback Energy Services Historical		Stingray Historical		Drilling Transaction		Pro Forma Adjustments			Pro Forma
Assets
Cash and cash equivalents	$	8,284	$	17,096	$	—	$	—		$
Other current assets		35,643		16,565		—		(1,634	)(a)

Total current assets		43,927		33,661		—		(1,634	)
Property and equipment, net		155,244		91,872		47,000
Other assets		3,472		223		3,557

Total assets	$	202,643	$	125,756	$	50,557	$	(1,634	)	$

Liabilities and Shareholders’ and Members’ Equity
Current liabilities		57,147		44,137		—		(1,634	)(a)
Long-term debt, net of current maturities		22,905		32,800		25,000		—
Other long-term liabilities		1,877		—		—		39,452	(b)
Shareholders’ and members’ equity		120,714		48,819		25,557		(39,452	)(b)

Total liabilities and shareholders’ and members’ equity	$	202,643	$	125,756	$	50,557	$	(1,634	)	$


	Redback Energy Services Historical			Stingray Historical			Drilling Transaction			Pro Forma Adjustments			Pro Forma
Revenue:
Completion and production services	$	47,731		$	95,140		$	—		$	(9,266	)(c)	$
Contract land and directional drilling services		59,790			—			33,102
Remote accommodation services		25,027			—			—			—

Total	$	132,548		$	95,140			33,102		$	(9,266	)	$

Cost of revenue, excluding depreciation, amortization and impairment:
Completion and production services		42,627			77,708			—			(9,266	)(c)
Contract land and directional drilling services		53,987			—			35,831			(13,602	)(d)
Remote accommodation services		11,416			—			—			—
Selling, general and administrative expenses		13,614			1,997			497			(497	)(d)
Depreciation and amortization		18,995			9,858			—			6,889	(d)
Impairment of long-lived assets		938			—

Total	$	141,577		$	89,563		$	36,328		$	(16,476	)	$

Operating income (loss)		(9,029	)		5,577			(3,226	)		7,210
Interest expense		(2,013	)		(1,123	)		—			(1,135	)(d)
Other income (expense), net		(215	)		—			—			—

Income loss before income taxes		(11,257	)		4,454			(3,226	)		6,075
Provision for income taxes		2,715			—			—			—

Net income (loss)	$	(13,972	)	$	4,454		$	(3,226	)	$	6,075		$

Pro forma income (loss) before income taxes													$
Pro forma provision for income taxes (e)

Pro forma net loss													$

Pro forma income (loss) per common share—basic and diluted (f)													$

Weighted average pro forma shares outstanding—basic and diluted (f)


	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	$	22,904	$	—	$	—
Operating lease obligations⁽²⁾		11,225		2,539		4,153		2,022		2,511
Purchase commitment to sand supplier⁽³⁾		3,329		1,000		2,329		—		—

	$	46,170	$	12,251	$	29,386	$	2,022	$	2,511


Acquirer	Seller	Play	Date	Deal Value ($mm)
Devon Energy	GeoSouthern	Eagle Ford	11/20/2013	$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	4,688.3
Denbury Resources	Encore Acquisition Company	Permian	11/1/2009	4,464.9
STO	BEXP	Bakken	10/17/2011	4,400.0
Chevron	Atlas Energy Inc	Marcellus	11/9/2010	4,307.6
MRO	Hilcorp Resources	Eagle Ford	6/1/2011	3,500.0
CONSOL Energy Incorporated	Dominion Resources Inc	Marcellus	3/15/2010	3,475.0
Statoil ASA	Chesapeake Energy Corporation	Marcellus	11/11/2008	3,375.0
Chevron, EnerVest, Shell	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	Consol Energy	Marcellus	8/18/2011	3,200.0
Apache Corporation	BP plc	Permian	7/20/2010	3,100.0
Total S.A.	Chesapeake, EnerVest	Utica	12/30/2011	2,320.0
CNOOC	Chesapeake	Eagle Ford	10/10/2010	2,160.0
Exxon	Denbury	Bakken	9/20/2012	2,000.0


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


Underwriter		Number of Shares
Credit Suisse Securities (USA) LLC

Total


Redback Energy Services
Report of Independent Registered Public Accounting Firm			F-2
Combined Balance Sheets as of December 31, 2013 and 2012			F-3
Combined Statements of Comprehensive Loss for the Years Ended December 31, 2013 and 2012			F-4
Combined Statement of Changes in Shareholders’ and Members’ Equity for the Years Ended December 31, 2013 and 2012			F-5
Combined Statements of Cash Flows for the Years Ended December 31, 2013 and 2012			F-6
Notes to Combined Financial Statements			F-7

Stingray Pressure Pumping LLC and Affiliates
Report of Independent Certified Public Accountants			F-24
Combined Balance Sheet as of December 31, 2013 and 2012			F-25
Combined Statements of Operations for the year ended December 31, 2013 and for the Period from March 20, 2012 (inception) to December 31, 2012			F-26
Combined Statement of Members’ Equity for the year ended December 31, 2013 and for the Period from March 20, 2012 (inception) to December 31, 2012			F-27
Combined Statement of Cash Flows for the year ended December 31, 2013 and for the Period from March 20, 2012 (inception) to December 31, 2012			F-28
Notes to Combined Financial Statements			F-29

Certain Drilling Rigs of Lantern Drilling Company
Report of Independent Certified Public Accountants			F-39
Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2013 and 2012			F-40
Notes to the Statements of Revenues and Direct Operating Expenses			F-41

Stingray Energy Services, Inc.
Report of Independent Registered Public Accounting Firm			F-43
Balance Sheet as February 5, 2014			F-44
Notes to Balance Sheet			F-45


	December 31,
	2013			2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	8,284,231			9,074,919
Accounts receivable, net		17,290,449			9,828,958
Receivables from related parties		8,157,727			3,639,220
Inventories		3,468,442			908,877
Prepaid expenses		4,593,679			3,183,391
Other current assets		2,133,130			814,665

Total current assets		43,927,658			27,450,030

Property and equipment, net		155,244,177			117,655,811
Goodwill		88,248			88,248
Intangible assets, net		214,271			241,771
Other non-current assets		3,168,766			3,065,822

Total assets	$	202,643,120			148,501,682

LIABILITIES AND SHAREHOLDERS’ AND MEMBERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	18,711,992			18,332,614
Accrued expenses and other current liabilities		9,433,582			2,101,249
Income taxes payable		2,138,425			9,138
Payables to related parties		7,238,119			3,773,361
Line of credit		10,913,308			3,820,000
Current maturities of long-term debt		8,711,671			3,030,527

Total current liabilities		57,147,097			31,066,889

Long-term debt, net of current maturities		22,904,605			7,213,362
Deferred income taxes		1,481,412			1,060,474
Other liabilities		395,888			364,228

Total liabilities		81,929,002			39,704,953

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS’ AND MEMBERS’ EQUITY
Common stock, par value $0.01 per share, unlimited authorized shares; issued and outstanding 100 shares		1			1
Contributed capital—common shareholders		21,201,185			21,071,120
Members’ equity		95,168,922			89,637,066
Retained earnings (accumulated deficit)		5,928,873			(1,926,111	)
Accumulated other comprehensive (loss) income		(1,584,863	)		14,653

Total shareholders’ and members’ equity		120,714,118			108,796,729

Total liabilities and shareholders’ and members’ equity	$	202,643,120			148,501,682


	Common Stock				Contributed Capital— Common Shareholders		Members’ Equity			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive (Loss) Income			Total
	Shares		Amount		Contributed Capital— Common Shareholders		Members’ Equity			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive (Loss) Income			Total
Balance at January 1, 2012		100	$	1	$	18,871,120	$	38,172,981		$	(5,651,453	)	$	(293,004	)	$	51,099,645
Capital contributions		—		—		2,200,000		56,894,537			—						59,094,537
Equity based compensation		—		—		—		363,404									363,404
Dividends paid		—		—		—		—			(10,089	)		—			(10,089	)
Other comprehensive income, net of tax of $0														307,657			307,657
Net (loss) income		—		—		—		(5,793,856	)		3,735,431			—			(2,058,425	)

Balance at December 31, 2012		100	$	1	$	21,071,120	$	89,637,066		$	(1,926,111	)	$	14,653		$	108,796,729
Capital contributions		—		—		—		26,979,347			—			—			26,979,347
Equity based compensation		—		—		130,065		388,260									518,325
Dividends paid		—		—		—		—			(9,878	)		—			(9,878	)
Other comprehensive loss, net of tax of $0														(1,599,516	)		(1,599,516	)
Net (loss) income		—		—		—		(21,835,751	)		7,864,862			—			(13,970,889	)

Balance at December 31, 2013		100	$	1	$	21,201,185	$	95,168,922		$	5,928,873		$	(1,584,863	)	$	120,714,118


Balance, January 1, 2012	$	—
Additions charged to expense		13,000
Deductions for uncollectible receivables written off		—

Balance, December 31, 2012		13,000
Additions charged to expense		1,608,147
Deductions for uncollectible receivables written off		—

Balance, December 31, 2013	$	1,621,147


	Useful Life	December 31,
	Useful Life	2013		2012
Land		$	1,637,595	$	1,324,344
Land improvements	15 years or life of lease		3,717,810		3,310,439
Buildings	15-20 years		30,207,179		24,891,622
Drilling rigs and related equipment	3-15 Years		69,671,150		49,012,821
Coil tubing equipment	4-10 years		17,326,676		14,329,973
Other machinery and equipment	7-20 years		40,279,358		24,430,584
Vehicles, trucks and trailers	5-10 years		14,391,824		6,340,114
Other property and equipment	3-12 years		2,243,513		793,638

			179,475,105		124,433,535
Buildings and equipment not yet in service			8,741,116		8,127,828

			188,216,221		132,561,363
Less: accumulated depreciation and amortization			32,972,044		14,905,552

Property, plant and equipment, net		$	155,244,177	$	117,655,811


	2013		2012
Customer relationships	$	275,000	$	275,000
Less: accumulated amortization		60,729		33,229

	$	214,271	$	241,771


Year ended December 31:	Amount
2014	$	27,500
2015		27,500
2016		27,500
2017		27,500
2018		27,500
Thereafter		76,771

	$	214,271


	2013		2012
U.S. current income tax expense	$	5,211	$	8,690
U.S. deferred income tax expense		86,209		41,332
Foreign current income tax expense		2,207,649		1,024
Foreign deferred income tax expense		415,953		961,778

	$	2,715,022	$	1,012,824


	2013			2012
Deferred tax assets:
Loss carryforwards	$	—		$	321,158
Other		73,855			35,198

Total deferred tax assets		73,855			356,356
Less: valuation allowance		—			—

Total deferred tax assets, net		73,855			356,356

Deferred tax liabilities:
Property, plant, and equipment		(1,525,687	)		(1,390,399	)
Other		(29,980	)		(26,431	)

Total deferred tax liabilities		(1,555,667	)		(1,416,830	)

Net deferred tax liabilities	$	(1,481,812	)	$	(1,060,474	)


2014	$	1,000,100
2015		1,000,100
2016		1,000,100
2017		328,800

Total Commitments	$	3,329,100


2014	$	2,538,504
2015		2,375,407
2016		1,776,865
2017		1,216,448
2018		805,600
Thereafter		2,511,700

Total minimum lease payments	$	11,224,524


				Completion and Production
	Contract Land and Directional Drilling Services			Services			Natural Sand Proppant Production			Remote Accommodation Services		Total
2013
Revenue from external customers	$	36,587,676		$	25,833,044		$	7,753,438		$	12,237,844	$	82,412,002
Revenue from related parties	$	23,202,563		$	4,132,207		$	10,012,446		$	12,789,152	$	50,136,368
Interest expense	$	1,566,327		$	254,165		$	191,809		$	—	$	2,012,301
Depreciation and amortization expense	$	9,942,018		$	4,201,754		$	3,542,751		$	1,308,877	$	18,995,400
Impairment of long-lived assets	$	937,803		$	—		$	—		$	—	$	937,803
Income tax provision	$	60,564		$	35,682		$	(4,826	)	$	2,623,602	$	2,715,022
Net income (loss)	$	(11,757,041	)	$	(1,097,151	)	$	(8,981,559	)	$	7,864,862	$	(13,970,889	)
Total expenditures for property plant and equipment	$	36,487,192		$	20,519,804		$	1,400,382		$	5,549,051	$	63,956,429
Goodwill	$	—		$	88,248		$	—		$	—	$	88,248
Intangible assets, net	$	—		$	214,271		$	—		$	—	$	214,271
Total Assets	$	86,498,444		$	46,693,764		$	37,342,376		$	32,108,536	$	202,643,120

2012
Revenue from external customers	$	13,606,762		$	13,044,251		$	—		$	7,628,022	$	34,279,035
Revenue from related parties	$	13,235,323		$	3,847,272		$	—		$	6,541,273	$	23,623,868
Interest expense	$	211,845		$	61,899		$	—		$	—	$	273.744
Depreciation and amortization expense	$	5,267,479		$	1,590,147		$	291,175		$	1,000,371	$	8,149,172
Impairment of long-lived assets	$	—		$	—		$	2,435,716		$	—	$	2,435,716
Income tax provision	$	47,276		$	2,746		$	—		$	962,802	$	1,012,824
Net income (loss)	$	(1,537,305	)	$	(83,460	)	$	(4,173,091	)	$	3,735,431	$	(2,058,425	)
Total expenditures for property, plant and equipment	$	28,954,479		$	17,939,950		$	19,241,826		$	5,447,575	$	71,583,830
Goodwill	$	—		$	88,248		$	—		$	—	$	88,248
Intangible assets, net	$	—		$	241,771		$	—		$	—	$	241,771
Total Assets	$	55,231,386		$	35,168,097		$	34,047,339		$	24,054,860	$	148,501,682


	Year ended December 31, 2013			March 20, 2012 (inception) to December 31, 2012
Revenue—related party	$	95,071,548		$	8,506,191
Revenue		68,216			—

		95,139,764			8,506,191

Costs and expenses
Cost of services		66,709,335			6,710,602
Cost of services—related parties		10,998,172			1,211,530
Selling, general and administrative		1,426,452			529,603
Selling, general and administrative—related parties		570,739			1,235,621
Depreciation		9,858,443			1,260,391

Total costs and expenses		89,563,141			10,947,747

Operating income (loss)		5,576,623			(2,441,556	)

Other income (expense)
Interest expense		(1,122,613	)		(10,923	)
Other		267			(1,660	)

		(1,122,346	)		(12,583	)

Net income (loss)	$	4,454,277		$	(2,454,139	)


Balance at March 20, 2012 (inception)	$	—
Members’ contributions		37,511,329
Stock subscriptions receivable		7,288
Net loss		(2,454,139	)

Balance at December 31, 2012		35,064,478
Members’ contributions		9,300,000
Net income		4,454,277

Balance at December 31, 2013	$	48,818,755


	Year ended December 31, 2013			March 20, 2012 (inception) to December 31, 2012
Cash flows from operating activities
Net income (loss)	$	4,454,277		$	(2,454,139	)
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation		9,858,443			1,260,391
Amortization of debt issuance costs		129,630			—
Gain on disposal of property and equipment		(265	)		—
Change in operating assets and liabilities
Trade receivables		(68,216	)		—
Related party receivables		(8,779,702	)		(5,329,427	)
Inventories		1,895,558			(2,863,873	)
Prepaid expenses and other assets		(583,676	)		(568,446	)
Accounts payable		12,006,298			4,797,401
Accounts payable—related parties		1,840,578			1,098,164
Accrued expenses and other liabilities		1,367,295			1,071,040

Net cash provided by (used in) operating activities		22,120,220			(2,988,889	)

Cash flows from investing activities
Purchase of property and equipment		(63,737,260	)		(32,370,057	)
Cash proceeds from sale of equipment		35,805			—

Net cash used in investing activities		(63,701,455	)		(32,370,057	)

Cash flows from financing activities
Proceeds from debt		54,815,428			—
Principal payments on debt		(6,977,542	)		(654	)
Debt issuance costs		(620,076	)		—
Members’ contributions		9,307,288			37,511,329

Net cash provided by financing activities		56,525,098			37,510,675

Net increase in cash and cash equivalents		14,943,863			2,151,729

Cash and cash equivalents at beginning of period		2,151,729			—

Cash and cash equivalents at end of period	$	17,095,592		$	2,151,729

Supplemental Disclosure of Non-Cash Investing and Financing Activities:
Seller-financed vehicle acquisitions	$	487,067		$	1,364,548
Fixed assets in accounts payable at period end	$	5,067,935		$	121,916
Cash paid for interest, net of capitalized	$	817,789		$	10,923


Buildings		39 years
Office equipment, furniture and fixtures		3-5 years
Machinery and equipment		3-5 years


	2013		2012
Proppant	$	55,900	$	—
Chemicals		459,261		2,863,873
Cement		453,154		—

	$	968,315	$	2,863,873


	2013		2012
Insurance	$	970,284	$	399,484
Materials		—		114,303
Repairs/Maintenance		—		96,964
Freight		—		103,145
Payroll		1,300,051		110,000
Fuel		—		202,920
Interest		175,194		—
Commercial Activity Taxes		250,000		—
Other		34,437		44,224

	$	2,729,966	$	1,071,040


	2013		2012
Term loans	$	48,202,754	$	—
Vehicle loans		1,486,092		1,363,894

		49,688,846		1,363,894

Less current portion		16,888,811		337,979

Total	$	32,800,035	$	1,025,915


	2013		2012
Revenues	$	95,071,548	$	8,506,191
Purchased materials	$	9,266,078	$	—
Purchased services	$	2,302,833	$	2,447,151
Capital asset purchases	$	10,400,705	$	21,028,452