U.S. Well Services 10K 2012 Annual report

UNITED STATES OF AMERICA

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number: 333-184491

U.S. WELL SERVICES, LLC

(Exact name of registrant as specified in its charter)



Delaware	90-0794304
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

770 South Post Oak Lane, Suite 405, Houston, Texas	77056
(Address of principal executive offices)	(Zip Code)

(832) 562-3730
(Registrant’s telephone number, including area code )

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
None	None
Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check-mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [x]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [x]

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or Section 15(d) of the Securities Exchange Act of 1934. during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [x] No [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [x] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part II of this Form 10-K or any amendment to this Form 10-K. [x]

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 definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes[ ] No [x]

As of June 30, 2012, the registrant’s membership interests are currently not listed on an exchange and, therefore, the aggregate market value of the registrant’s membership interests held by non-affiliates on such date cannot be reasonably determined.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

TABLE OF CONTENTS



PART I

Item 1	Business	4

Item 1A	Risk Factors	8

Item 1B	Unresolved Staff Comments	22

Item 2	Properties	23

Item 3	Legal Proceedings	23

Item 4	Mine Safety Disclosures	23

PART II

Item 5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24

Item 6	Selected Financial Data	24

Item 7	Management's Discussion and Analysis of Financial Condition and Results of Operations	24

Item 7A	Quantitative and Qualitative Disclosures About Market Risk	33

Item 8	Financial Statements and Supplementary Data	34

Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	51

Item 9A	Controls and Procedures	51

Item 9B	Other Information	51

PART III

Item 10	Directors, Executive Officers and Corporate Governance	52

Item 11	Executive Compensation	54

Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	60

Item 13	Certain Relationships and Related Transactions, and Director Independence	61

Item 14	Principal Accountant Fees and Services	62

PART IV

Item 15	Exhibits, Financial Statement Schedules	63

SIGNATURES		65

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

U.S. Well Services, LLC's reports, filings and other public announcements may from time to time contain certain forward-looking statements. When used, statements which are not historical in nature, including those containing words such as “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should,” “will,” “future” and similar expressions are intended to identify forward-looking statements in this report regarding us and our subsidiary.

These forward-looking statements reflect our current views with respect to future events and are based on assumptions and subject to risks and uncertainties. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements. Among the factors that could cause actual results to differ materially are the risks and uncertainties described under “Risk Factors” included in Part I, Item 1A of this Annual Report, including the following:


•	our limited operating history;


•	concentration of our customer base;


•	our ability to renew our existing customer contract and enter into additional service contracts;


•	fulfillment of our existing customer contract;


•	a potential adverse decision in a currently pending legal proceeding;


•	our ability to obtain raw materials and specialized equipment;


•	dependence on the spending levels and drilling activity of the onshore oil and natural gas industry;


•	the availability of water;


•	our ability to maintain pricing;


•	competition within the oilfield services industry;


•	the cyclical nature of the oil and natural gas industry;


•	changes in customer ownership or management;


•	delays in obtaining required permits;


•	our ability to raise additional capital to fund future capital expenditures;


•	increased vulnerability to adverse economic conditions due to our levels of indebtedness;


•	technological developments or enhancements affecting us or our competitors;


•	asset impairment and other charges;


•	the potential for excess capacity in the oil and natural gas industry;


•	our identifying, making and integrating acquisitions;


•	the loss of key executives;


•	potential conflicts of interest faced by our managers, sponsors and members;


•	the control of our sponsor over voting and management;


•	our ability to employ skilled and qualified workers;


•	work stoppages or other labor disputes;


•	hazards and environmental risks inherent to the oil and natural gas industry;


•	inadequacy of insurance coverage for certain losses or liabilities;


•	product liability, personal injury, property damage and other claims against us;


•	laws and regulations affecting the oil and natural gas industry;


•	costs and liabilities associated with environmental, health and safety laws, including any changes in the interpretation or enforcement thereof;


•	future legislative and regulatory developments;


•	federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing;


•	changes in trucking regulations;


•	changing demand for oil and natural gas due to conservation measures;


•	the effects of climate change or severe weather;


•	terrorist attacks and armed conflict;


•	additional obligations and increased costs associated with being a reporting company;


•	evaluations of internal controls required by Sarbanes-Oxley;


•	the status of available exemptions for emerging growth companies under the JOBS Act; and


•	the risks described elsewhere in our reports and registration statements filed from time to time with the United States Securities and Exchange Commission (“SEC”).

Given these risks and uncertainties, you should not place undue reliance on these forward-looking statements.

Many of these factors are beyond our ability to control or predict. Any, or a combination, of these factors could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

All forward-looking statements included in this Annual Report are made only as of the date of this Annual Report, and we do not undertake any obligation to publicly update or correct any forward-looking statements to reflect events or circumstances that subsequently occur, or of which we become aware after the date of this Annual Report. You should read this Annual Report completely and with the understanding that our actual future results may be materially different from what we expect. We may not update these forward-looking statements, even if our situation changes in the future. All forward-looking statements attributable to us are expressly qualified by these cautionary statements.

PART I

ITEM 1. BUSINESS

Our Company

On February 21, 2012, U.S. Well Services, LLC (the “Company,” “we,” “our” or “USWS”) was formed as a Delaware limited liability company. The predecessor to the Company, U.S. Well Services, Inc. (“USWS, Inc.”), was incorporated in Delaware on August 18, 2011. The Company was capitalized via a contribution by USWS, Inc. of substantially all of the assets and contracts of USWS, Inc. in exchange for 167,500 of the Company’s Series C Units (the “Restructuring”). Contemporaneously with the formation of the Company, ORB Investments, LLC, a Louisiana limited liability company (“ORB”), made a $30 million equity investment in the Company (the “Sponsor Equity Investment”), in exchange for 600,000 of the Company’s Series A Units and 600,000 of the Company’s Series B Units. In addition, concurrently with the formation of the Company, USW Financing Corp., a Delaware corporation, was formed as a wholly-owned finance subsidiary of the Company for the purpose of acting as a co-obligor for an offering of 85,000 units with each unit consisting of $1,000 principal amount of 14.50% Senior Secured Notes due 2017, the old notes, and a warrant to purchase the Company’s Series B Units (the “Unit Offering”).

Our Services

We are an oilfield service provider engaged in pressure pumping and related services, including high-pressure hydraulic fracturing in unconventional oil and natural gas basins. We are headquartered in Houston, Texas with primary field operations based in Jane Lew, West Virginia. We believe our pressure pumping fleets are reliable and high performing fleets and that they are capable of meeting the most demanding pressure and flow rate requirements in the field. Our management team has extensive industry experience providing completion services to exploration and production companies.

Hydraulic fracturing services enhance the production of oil and natural gas from formations with restricted natural flow of hydrocarbons. The fracturing process consists of pumping a specially formulated fluid into perforated well casing, tubing or open holes under high pressure causing the underground formation to crack or fracture, allowing the hydrocarbon to flow more freely. Sand, bauxite, resin-coated sand or ceramic particles, each referred to as a proppant or propping agent, are suspended in the fracturing fluid and prop open the cracks created by the hydraulic fracturing process in the underground formation. The extremely high pressure required to stimulate wells in many of the regions in which we intend to operate presents a challenging environment for achieving a successfully fractured horizontal well. As a result, an important element of the services we provide to oil and natural gas producers is designing the optimum well completion, which includes determining the proper fluid, proppant and injection specifications to maximize production. We focus on the most active shale and unconventional oil and natural gas plays in the United States, where we believe we have a competitive advantage due to the high performance and durability of our equipment and our ability to support high asset utilization that results in more efficient operations.

The delivery of our initial hydraulic fracturing fleet, consisting of a total of 20 Stewart & Stevenson, LLC ("Stewart & Stevenson") fracturing pumps and associated heavy equipment from various suppliers, was completed in April 2012. Our second hydraulic fracturing fleet, consisting of 14 Stewart & Stevenson fracturing pumps and associated heavy equipment from various suppliers, was delivered in August 2012. With the new equipment, we believe that we will be able to provide our existing customers and future customers with one of the most effective levels of service in the industry.

Industry Overview

The pressure pumping industry provides hydraulic fracturing, cementing and other well stimulation services to exploration and production companies.

The total size of the North American pressure pumping market, on a revenue basis, was approximately $7 billion in 2009, approximately $15 billion in 2010 and approximately $27 billion in 2011 based on data from a January 2012 report by Spears and Associates, Inc.

The main factors influencing the increased demand for fracturing services in North America are the increased levels of horizontal drilling activity by exploration and production companies, as well as the fracturing requirements in the respective shale and unconventional oil and natural gas plays in which such drilling activity is being conducted. There has been a dramatic increase in the development of shale formations in the U.S. resulting in a significant increase in horizontal drilling activity. The number of horizontal drilling rigs in the United States has climbed from 48 (6% of the total operating rigs) at the end of 1999 to 1,111 (63% of the total operating rigs) as of December 28, 2012, based on data from Baker Hughes Incorporated.

As a result of depressed natural gas prices, there has been increasing horizontal drilling and completion related activity in oil and liquids-rich formations such as the Eagle Ford Shale, Permian Basin, Granite Wash, Utica Shale, Bakken Shale and Niobrara Shale. We believe that the oil and liquids content in these plays significantly enhance the returns for our customers

relative to opportunities in dry gas basins due to the significant disparity between oil and natural gas prices on a Btu basis. Based on industry data, we believe the price disparity will continue over the near to mid-term with such disparity resulting in an increased demand for services in oil and liquids-rich formations. We expect to continue to benefit from increased horizontal drilling and completion-related activity in those complex unconventional resource plays that are oil- and liquids-rich, even as those areas absorb drilling and completion capacity moving from regions with higher dry gas content.

Customers

We are currently under contract with Antero Resources Appalachian Corporation ("Antero") to perform services in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania. Antero Resources LLC (with its subsidiaries including Antero) is an oil and natural gas company engaged in the acquisition, development and production of unconventional natural gas properties primarily located in the Appalachian Basin in West Virginia and Pennsylvania, the Piceance Basin in Colorado and the Arkoma Basin in Oklahoma. Our original contract with Antero provides for minimum performance requirements related to the number of stages to be completed quarterly, over the term of the contract.

Our current customer base also includes several large independent exploration and production companies active in the Marcellus and Utica Shales.

We may expand our business to include other unconventional oil and natural gas formations, which may include certain areas of the Bakken Shale in North Dakota and Montana, the Haynesville Shale in northwestern Louisiana and eastern Texas, the Eagle Ford Shale in southern Texas, the Permian Basin in western Texas and southeastern New Mexico, the Niobrara Shale in Colorado, Wyoming and Nebraska and the Granite Wash formation in Oklahoma.

Competition

Our competition includes multi-national oilfield service companies as well as regional competitors. Our major multi-national competitors include Halliburton Company, Schlumberger Ltd., Baker Hughes Incorporated, Weatherford International Ltd., Trican Well Service Ltd. and Calfrac Well Services Ltd. Our multi-national competitors typically have more diverse product and service offerings than us. In addition, we compete against a number of smaller, regional operators, such as Superior Well Services, Inc. (a subsidiary of Nabors Industries Ltd.), Go Frac, and Frac Tech International, LLC, which offer products and services similar to the products and services we offer.

Raw Materials

We purchase various raw materials, parts and component parts for use in delivering our services. The principal materials we purchase include gels, proppants, and hydrochloric acid. We are not dependent on any single source of supply for those materials, parts and supplies.

Seasonality

Our operations can be affected by seasonal factors, such as inclement weather, holidays and road restrictions, which can temporarily affect the performance of our services. During periods of heavy snow, ice or rain, we may not be able to move our equipment between locations, thereby reducing our ability to provide services and generate revenues. During the fourth quarter of 2012, we also experienced reduced activity levels due to the Thanksgiving and Christmas holiday seasons.

Employees

As of December 31, 2012, we had 123 full-time employees and no part-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we will utilize the services of independent contractors to perform various field and other services.

Environmental Matters

Our hydraulic fracturing operations are subject to various federal, regional, state and local laws and regulations and initiatives respecting health and safety, the discharge of materials into the environment or otherwise relating to the protection of the environment or natural resources. These laws and regulations may, among other things, require the acquisition of permits to conduct our operations; restrict the amounts and types of substances that may be released into the environment; cause us to incur significant capital expenditures to install pollution control or safety-related equipment at our operating facilities; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; impose specific health and safety criteria addressing worker protection and impose substantial liabilities on us for pollution resulting from our operations. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of investigatory and remedial obligations, denial or revocation of permits, imposition of new operational requirements, or limitations on our areas of operations, which could materially impair our financial condition or ability to operate in particular locations and the issuance of orders enjoining some or all of our operations in affected areas.

While these environmental, health and safety laws and regulations are revised from time to time and can in some cases result in more stringent regulatory or liability standards, enforcement initiatives, limitations or restrictions on locations or methods of oil and natural gas exploration and production operations, we cannot predict the level of enforcement of existing laws or regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. We also cannot predict whether additional laws and regulations affecting our business will be adopted, or the effect such changes might have on us, our financial condition or our business. However, any changes that result in more stringent and costly requirements for the oil and natural gas industry could have a significant impact on our operations and financial position. We may be unable to pass along such increased compliance costs to our customers. We are not aware of any environmental obligations that will require material capital expenditures or that will have a material impact on our financial position or results of operations in the future. However, we cannot provide any assurance that we will be able to remain in compliance with existing or new environmental requirements in the future or that future compliance will not have a material adverse effect on our business and operating results.

The following is a summary of certain key existing environmental, health and safety laws and regulations to which our operations are subject and for which compliance may have a material adverse impact on our results of operations, financial position or cash flows.

Hazardous Substances and Waste. The federal Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) or the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain defined persons, including current and prior owners or operators of a facility where there is a release or threatened release of hazardous substances, certain transporters of hazardous substances, and entities that arranged for disposal of the hazardous substances at the site. Under CERCLA, these “responsible persons” may be held jointly and severally liable for the costs of cleaning up the hazardous substances, as well as for damages to natural resources and for the costs of certain health studies, relocation expenses and other response costs.

CERCLA generally exempts “petroleum” from the definition of hazardous substance; however, in the course of our operations, we have generated and will generate or otherwise handle materials that are considered “hazardous substances”. Further, hazardous substances or hazardous wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these substances or wastes were taken for treatment or disposal. To our knowledge, neither we nor our predecessors have been identified as a potentially responsible person (“PRP”) with regard to any release of hazardous substances; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site of which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for response costs under CERCLA or comparable state laws.

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate solid and hazardous waste. Waste generated from oil and natural gas exploration generally is exempt from federal regulation as hazardous waste under RCRA. However, our hydraulic fracturing operations will generate certain “hazardous wastes” and “solid wastes” that are subject to the requirements of RCRA and those of comparable state statutes or regulations, including those which pertain to the treatment, storage, and disposal of such wastes.

Air Emissions. The federal Clean Air Act (“CAA”) and similar state laws and regulations restrict the emission of air pollutants and impose various monitoring and reporting requirements. These laws and regulations may require us or our customers to obtain approvals or permits for construction, modification or operation of certain projects or facilities and may require the use of technological controls to limit emissions of air pollutants. The U.S. Environmental Protection Agency

(“EPA”) has imposed new emission control requirements on new or modified natural gas wells developed with the use of hydraulic fracturing, including a requirement to use green completion technology by 2015. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies can bring lawsuits for civil or criminal penalties or require us to forego construction, modification or operation of certain air emission sources.

Global Warming and Climate Change. In response to certain scientific studies suggesting that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs” and including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic changes, the U.S. Congress has considered legislation to reduce such emissions and many states, either individually or through multi-state initiatives, have begun taking actions to control or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories or regional GHG cap and trade programs. Although it is not possible at this time to predict Congressional action on climate change legislation, when adopted such legislation could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas that our current customer or future customers produce.

In addition, the EPA published its finding that emissions of GHGs present an endangerment to public health and the environment, a finding that would authorize the EPA to proceed with a process to restrict emissions of GHGs under existing provisions of the CAA. Subsequently, the EPA promulgated rules requiring certain sources, including certain large stationary sources in the natural gas production industry, to report GHG emissions and other rules to address a phase-in of certain permit requirements over time based on the quantity of emissions (the so-called “tailoring” rule). The EPA’s GHG rulemakings have been challenged in court and we cannot predict the outcome of any such challenges. However, the adoption and implementation of any legislation or regulations imposing obligations on, or limiting emissions of GHGs from, our equipment and operations could result in increased compliance costs or additional operating restrictions for us and our customers, and could have a material adverse effect on our business or demand for our services.

Water Discharges. Our services and the facilities to which we provide our services are subject to requirements of the federal Clean Water Act (“CWA”), and analogous state laws that impose restrictions and controls on the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into regulated waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a state agency. Wastewater generated in the course of our operations and, in some cases, stormwater associated with our operations must be permitted before discharge to regulated waters. The EPA has announced that it will develop new wastewater discharge standards for the shale gas extraction industry. Although we cannot predict the outcome of the EPA’s plans to develop such standards, more stringent standards may result in increased operational costs or otherwise further limit our wastewater discharge options. In addition, the CWA and various state authorities mandate measures, including contingency plans, to prevent, and in some cases, remediate spills of oil or hazardous substances to regulated waters. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for noncompliance with wastewater discharge and spill-related requirements.

Occupational Safety and Health Act. The federal Occupational Safety and Health Act (“OSHA”) and comparable state laws regulate the protection of employee health and safety. The agency that administers OSHA has promulgated standards to protect employees from various equipment and other workplace hazards. In addition, OSHA’s hazard communication standard, community-right-to-know regulations promulgated by the EPA under Title III of CERCLA and similar state statutes require that information about hazardous materials used or produced in our operations be maintained and provided to employees, and to state and local government authorities and citizens.

Safe Drinking Water Act and Underground Injection. The federal Safe Drinking Water Act (“SDWA”) regulates, among other things, underground injection operations, including hydraulic fracturing operations that use diesel in their fracturing fluids. As a result of an exemption to the SDWA enacted by Congress in 2005, hydraulic fracturing injections that do not contain diesel are not regulated under the SDWA. More recently, Congress has considered legislation known as the FRAC Act that would remove the general exemption for hydraulic fracturing operations and impose additional regulation under the SDWA. If enacted, the legislation could impose permit and financial assurance requirements on hydraulic fracturing operators and require well operators to adhere to certain construction specifications and meet monitoring, reporting and recordkeeping obligations, as well as plugging and abandonment requirements. A federal requirement for disclosure of the chemicals contained in hydraulic fracturing fluids used is also being considered, although a number of states have already imposed disclosure requirements. Disclosure could facilitate efforts by third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. If the FRAC Act or similar legislation is enacted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct our fracturing operations.

Materials Transportation. For the transportation and relocation of our hydraulic fracturing equipment, sand and chemicals, as well as hazardous materials, we operate trucks and other heavy equipment. We are therefore subject to regulation as a motor carrier by the United States Department of Transportation (the "DOT") and by various state agencies, whose

regulations include certain permit requirements of state highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements and containerization, placarding and handling requirements for the transportation of hazardous materials. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations by requiring changes in fuel emissions limits, the hours of service regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters. Also, national fuel efficiency and emissions standards for medium and heavy-duty engines and vehicles have been promulgated under the CAA for vehicles made between 2014 and 2018. Due to this ruling, we may experience an increase in costs related to truck purchases or maintenance. Additionally, the EPA’s Tier IV regulations apply to certain off-road diesel engines that are needed to power our equipment in the field. Under these regulations, we are limited in the number of non-compliant off-road diesel engines we can purchase. If Tier IV-compliant engines that meet our needs are not available, these regulations could limit our ability to acquire a sufficient number of diesel engines to expand our fleet and to replace existing engines as they are taken out of service. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. We cannot predict whether, or in what form, any legislative or regulatory changes applicable to our trucking operations will be enacted.

Drilling and Hydraulic Fracturing. Authorization from one or more governmental agencies is generally required to perform drilling and completion activities, including hydraulic fracturing, and increased restrictions are being imposed on gas exploration operations. State permits directed toward preventing adverse impacts to drinking water, among other things, are required in the states in which we intend initially to operate (Ohio, West Virginia, New York and Pennsylvania), as well as in other states to which we may expand our operations. State permit requirements and other regulatory standards vary from state to state, but often establish stringent well design and construction standards, restrict well locations, impose investigation and response requirements in the event of mishaps or accidents, and mandate disclosure of well data (including the chemical content of fracturing fluids). Hydraulic fracturing activities are controversial with the public both in the states in which we operate and elsewhere, and new regulatory initiatives aimed at banning or restricting hydraulic fracturing are being developed not only at the state levels, but also at the federal and local levels. For example, in New York, zoning provisions have been adopted by some municipalities that effectively ban or temporarily prohibit certain exploration and production activity including hydraulic fracturing within their jurisdictions, and to date challenges to these local provisions largely have not been successful in the courts. At the federal level, the Bureau of Land Management (“BLM”) has proposed regulations that would impose requirements on hydraulic fracturing operations on federal lands. Increased seismic activity that has been alleged to have occurred as a result of disposal of wastewater from drilling activities by injection has prompted consideration of regulatory restrictions on injection wells to address such concerns. Various federal, state and local limitations may prohibit or restrict drilling and hydraulic fracturing operations in certain locales including geographic locales considered environmentally sensitive such as wetlands, endangered species habitats, floodplains, and the like. Such limitations have been imposed through executive or legislative moratoria, local zoning or land use restrictions, permit conditions and other mechanisms. These developments may result in increased costs of our operations, increased enforcement activities by governmental authorities, and otherwise adversely impact our business and that of our customers.

Available Information

We make available free of charge, or through the “Investor Relations-SEC Filings” section of our website at www.uswellservices.com, access to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 15(d) of the Exchange Act as soon as reasonably practicable after such material is filed, or furnished to the Securities and Exchange Commission. Our Code of Business Conduct and Ethics is also available through the “Investor Relations - Corporate Governance” section of our website or in print upon request. We expect that any amendments to our Code of Business Conduct and Ethics, or any waivers of its requirements, will be disclosed on our website.

ITEM 1A. RISK FACTORS

In addition to other reports and materials that we file with the SEC and the other information included or incorporated by reference in this Form10-K, the risks described below should be considered in evaluating us and our business. The risks and uncertainties described below are not intended to be exhaustive but represent the risks that we believe are material. Additional risks and uncertainties not presently known to us, or which we currently deem immaterial, may also have a material adverse effect on our business, financial condition and operating results.

Risks Relating to Our Company and the Industry

Our operating history may not be sufficient for investors to evaluate our business and prospects.

We have a short operating history, which may make it more difficult for investors to evaluate our business and prospects and to forecast our future operating results.

Our customer base is concentrated within the oil and natural gas production industry and loss of our existing customer contract could cause our revenue to decline substantially and adversely affect our business.

Our business is highly dependent on our contract and relationship with Antero. Substantially all of our 2012 revenues were generated through the services provided to Antero. A reduction in business from this customer resulting from reduced demand for its own products and services, a work stoppage, sourcing of products from other suppliers or other factors could have a material impact on our business, financial condition and results 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, particularly Antero, failed to pay us or decided not to continue to use our services, revenue would decline and our operating results, liquidity position and financial condition could be harmed. Our agreements with Antero do not obligate Antero to order additional services from us beyond those currently contracted for. In addition, Antero is entitled to terminate our agreements with it at any time, subject to the obligation to make certain early termination payments if such termination is not for cause.

We may not be able to successfully fulfill, renew or replace our contract with Antero, which could adversely impact our results of operations, financial condition and cash flows.

We may not be able to successfully fulfill, renew or replace our agreements with Antero on or prior to their expiration on terms satisfactory to us or Antero, or we may not be able to continue to provide services under such agreements without service interruption. Furthermore, discussions to provide services to additional customers may not result in our entering into additional service contracts.

We will be dependent on entering into additional service contracts to grow our business.

We face strong competition from a wide variety of competitors, including competitors that have considerably greater financial, marketing and technological resources, which may make it difficult for us to enter into new contracts and compete successfully. Certain competitors operate larger facilities, have longer operating histories and presences in key markets, greater name recognition, larger customer bases and significantly greater financial, sales and marketing, manufacturing, distribution, technical and other resources than us. As a result, these competitors may affect our ability to compete for new contracts, which is essential for our growth.

If we cause disruptions to our customers’ businesses or provide inadequate service, particularly by failing to meet our delivery deadlines, our customers may have claims for damages against us, which could cause us to lose customers, have a negative effect on our reputation and adversely affect our results of operations.

If we fail to provide services under our contracts with our customers, including with Antero, we may disrupt such customers’ businesses, which could result in a termination of the applicable contract, reduction in our revenues or a claim for substantial damages against us. In addition, a failure or inability to meet a contractual requirement could seriously damage our reputation and affect our ability to attract new business. The termination of a contract or the successful assertion of one or more large claims against us in amounts greater than those covered by our current insurance policies could materially and adversely affect our business, financial condition and results of operations. Even if such assertions against us are unsuccessful, we may incur reputational harm and substantial legal fees.

The outcome of litigation in which we have been named as a defendant is unpredictable and an adverse decision in any such matter could subject us to damage awards or we could be enjoined from pursuing certain activities, which may harm our business, overall financial condition and operating results.

We are one of the defendants in a litigation matter with Calfrac described in Part I. Item 3, “Legal Proceedings” of this Annual Report on Form 10-K. This and any other future litigation may divert management's attention and our resources that would otherwise be used to benefit our operations. Although we intend to contest the lawsuit vigorously, we cannot assure you that the results of the litigation will be favorable to us. The injunctive relief requested by Calfrac in this litigation, if awarded by the court, could adversely impact our revenues. An adverse resolution of the lawsuit or others in the future, including the results of any amicable settlement, could subject us to material damage awards or settlement payments or otherwise harm our business, overall financial condition and operating results.

Our business depends upon our ability to obtain key specialized equipment and raw materials from suppliers.

The overall number of hydraulic fracturing equipment suppliers in the industry is limited. Should we be unable to enter into agreements for timely delivery of finished equipment, or should our current or future suppliers be unable to provide the necessary finished products (such as pumps, workover rigs or fluid-handling equipment) or otherwise fail to deliver the products in a timely manner and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows, including our ability to perform our obligations under our existing contract with Antero and future customer contracts.

In addition, there is also high demand for water, sand, guar and other fracturing inputs, which may increase the risk of delay or failure to deliver under our customer contracts, as well as limit our ability to find alternative suppliers. We may not be

able to mitigate shortages of finished products, which could impair our performance of our existing contract with Antero and our ability to generate new customers. In addition, our existing contract with Antero provides for adjustments to service or materials fees payable thereunder based on changing market conditions, and we anticipate similar provisions will exist in contracts with future customers, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our business depends on spending and drilling activity by the onshore oil and natural gas industry and particularly on the level of activity for North American oil and natural gas. Our markets may be adversely affected by industry conditions that are beyond our control.

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in North America, particularly in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania. If these expenditures decline, our business may suffer. Our customers’ willingness to explore for, develop and produce oil and natural gas depends largely upon prevailing industry conditions that are influenced by numerous factors over which management has no control, such as:


•	the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage;


•	the supply of and demand for hydraulic fracturing and other well service equipment in the United States;


•	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, including fracturing services;


•	the expected rate of decline in current oil and natural gas production;


•	the discovery rates of new oil and natural gas reserves;


•	available pipeline and other transportation capacity;


•	lead times associated with acquiring equipment and products and availability of personnel;


•	global weather conditions, including hurricanes, tornadoes, flooding, winter storms, wildfires, drought or man-made disasters that can affect oil and natural gas operations over a wide area;


•	domestic and worldwide economic conditions;


•	contractions in the credit market;


•	political instability in oil and natural gas producing countries;


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


•	regulation of drilling activity;


•	public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;


•	governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves;


•	the level of oil production by non-OPEC countries and the available excess production capacity within OPEC;


•	oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;


•	potential acceleration of development of alternative fuels;


•	the availability of water resources for use in hydraulic fracturing operations;


•	technical advances affecting energy consumption;


•	the price and availability of alternative fuels;


•	the access to and cost of capital for oil and natural gas producers; and


•	merger and divestiture activity among oil and natural gas producers.

Demand for our services and products will be particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil

companies in North America, particularly in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania. Demand will directly be affected by trends in oil and natural gas prices, which, historically, have been volatile and are likely to continue to be volatile.

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of other economic factors that are beyond our control. Any prolonged reduction in oil and natural gas prices will depress the immediate levels of exploration, development and production activity. Perceptions of longer-term lower oil and natural gas prices by oil and natural gas companies can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects.

Our ability to successfully operate depends on the availability of water.

Hydraulic fracturing, and pressure pumping more generally, requires a significant supply of water, and water supply and quality are important requirements to our operations. Our water requirements will be met by our customers from sources on or near their sites, but our customers may not be able to obtain a sufficient supply of water from sources in these areas, some of which are prone to drought. If our customers are unable to secure water on or near their sites, they may not be able to obtain water through other means on economically feasible terms. Any of these factors could have a material adverse effect on our results and financial condition and our ability to sustain our operations.

We may be unable to maintain pricing on our core services.

Pressures stemming from fluctuating market conditions and oil and natural gas prices may make it increasingly difficult to maintain our prices. We face pricing pressure from our competitors. We may be compelled to make price concessions in order to gain or maintain market share.

Our industry is highly competitive and 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 highly competitive and have relatively few barriers to entry and the competitive environment has intensified as recent mergers among exploration and production companies have reduced the number of available customers. The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. We face competition from 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 face competition from several 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. As a result of competition, we may lose market share or be unable to maintain or increase prices for our 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, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. We may not be able to maintain our competitive position.

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.

Because the oil and natural gas industry is cyclical, our operating results may fluctuate.

Oil and natural gas prices are volatile. The recent decline in natural gas prices has resulted in, and future fluctuations in such prices may result in, a decrease in the expenditure levels of oil and natural gas companies and drilling contractors which in turn adversely affects us. Unexpected material declines in oil and natural gas prices, or drilling or completion activity in the northern United States oil and natural gas shale regions, particularly in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania, could have a material adverse effect on our customers’ businesses, financial conditions, results of operations and cash flows. In addition, a decrease in the development rate of oil and natural gas reserves in our customers’ market areas may also have an adverse impact on their businesses, even in an environment of stronger oil and natural gas prices. We may experience significant fluctuations in operating results as a result of the reactions of our customers to actual and anticipated changes in oil and natural gas prices.

Our original contract with Antero has a term of 24 months commencing on the start of our services, which we began in April 2012, and does not obligate Antero to order additional work from us beyond such current term. Our agreements with Antero contain provisions whereby Antero may terminate the agreements at any time upon payment of an early termination fee. We expect that additional contracts going forward will have similar provisions.

Because we currently rely primarily on only one customer for our fracturing services, the change in ownership and management of such customer may adversely affect our business, financial condition and results of operations.

Our success will depend on developing and maintaining close working relationships with our customers. Currently, we expect to generate a substantial majority of our revenue from the hydraulic fracturing and related services we will provide to Antero. We expect that our agreements with Antero will account for a substantial portion of our revenue in the near term. Changes in the business of this customer, particularly with respect to a change in its management or ownership, could change the dynamics of our current relationship and subject us to the risk of new management or ownership choosing to enter into relationships with preferred service providers. If we are not able to establish a strategic relationship with the new management or ownership, or if new management or ownership chooses to enter into relationships with preferred service providers, it may materially and adversely affect our business, financial condition and results of operations.

Regulatory compliance costs and restrictions, as well as delays in obtaining permits by our customer for its operations, such as for hydraulic fracturing, or by us for our operations, could impair our business.

Our operations and the operations of our customer and any future customers are subject to or impacted by a wide array of regulations in the jurisdictions in which we and our customers operate. As a result of regulations and laws relating to the oil and natural gas industry, including hydraulic fracturing, or changes in such regulations or laws, our and our customers’ operations could be disrupted or curtailed by governmental authorities. For example, oil and natural gas exploration and production may become less cost-effective and decline as a result of increasingly stringent environmental requirements (including bans or moratoria on drilling in specific areas, land use policies responsive to environmental concerns and delays or difficulties in obtaining environmental permits). Our customers generally will be required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities, including hydraulic fracturing. Such permits are typically required by state agencies, but can also be required by federal and local governmental authorities. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions which may be imposed in connection with the granting of the permit. The high cost of compliance with applicable regulations and delays in obtaining required permits may cause our customer and other companies with similar operations to discontinue or limit their operations, and may discourage our customer and other companies from continuing exploration and production activities which could result in a decrease in demand for our services and, in turn, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We participate in a capital intensive business. We may not be able to finance future growth of our operations.

If we do not generate sufficient cash from our business to continue to fund operations, including the mobilization of new core operating equipment, our growth could be limited unless we are able to obtain additional capital through equity or debt financings. In the future, we may not be able to obtain funding through these sources or otherwise obtain sufficient bank debt at competitive rates or complete equity and other debt financings. Our inability to grow may reduce our chances of maintaining or improving profitability and attracting new customers for our services.

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

Our current level of indebtedness, taking into account our future indebtedness and other future needs to finance equipment acquisitions and working capital, may adversely affect operations and limit our growth, and we may have difficulty making debt service payments on our indebtedness as such payments become due. Our level of indebtedness may affect our operations in several ways, including the following:


•	our vulnerability to general adverse economic and industry conditions;


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


•	any failure to comply with the financial or other covenants of our debt could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable; and


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

New technology may cause us to become less competitive.

The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. If competitors and others use or develop new technologies in the future that are more efficient or productive than our own, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and implement new technologies before we can. We may not be able to implement new

technologies or products on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition or results of operations.

Our future financial results could be adversely impacted by asset impairments or other charges.

We evaluate our long-term assets including property, plant and equipment in accordance with U.S. GAAP. In performing this assessment, we project future cash flows on an undiscounted basis for long-term assets, and compare these cash flows to the carrying amount of the related net assets. The cash flow projections are based on our operating plan, estimates and judgmental assessments. We perform this assessment of potential impairment whenever facts and circumstances indicate that the carrying value of the net assets may not be recoverable due to various external or internal factors, termed a “triggering event.” If we determine that our estimates of future cash flows were inaccurate or our actual results are materially different from what we have predicted, we could record impairment charges in future periods, which could have a material adverse effect on our business, financial condition and results of operations.

Our industry can be affected by excess equipment inventory levels.

Because of the long-life nature of oilfield service equipment and the lag between when a decision to build additional equipment is made and when the equipment is placed into service, the inventory of oilfield service equipment in the industry does not always correlate with the level of demand for service equipment. Periods of high demand often spur increased capital expenditures on equipment, and those capital expenditures may add capacity that exceeds actual demand. Such a capital overbuild could cause our competitors to lower their rates and could lead to a decrease in rates in the oilfield services industry generally, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

There is significant potential for excess capacity in our industry, which could adversely affect our business and operating results.

Significant increases in overall market capacity could cause our competitors to lower their rates and could lead to a decrease in rates in the oilfield services industry generally. Additionally, the recent decline in natural gas prices has resulted in reduced drilling activity in natural gas shale plays, which has driven oilfield services companies operating in natural gas shale plays to relocate their equipment to more oil and liquids rich shale plays, including markets which we hope to enter in the future. As the number of crews and equipment in these areas increases, the increase in supply relative to demand may result in lower prices and utilization of our services and could adversely affect our business and results of operations.

Our inability to control the inherent risks of acquiring and integrating businesses in the future could adversely affect our operations.

Our management believes acquisitions could potentially be a key element of our business strategy in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. We may not be able to secure additional capital to fund acquisitions. If we are able to obtain financing, such additional debt service requirements may impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to members. Acquisitions may not perform as expected when the acquisition is made and may be dilutive to our overall operating results. Additional risks relating to acquisitions we expect to face include:


•	retaining and attracting key employees;


•	retaining and attracting new customers;


•	increased administrative burden of acquisitions;


•	managing our growth effectively;


•	integrating operations;


•	operating a new line of business; and


•	increased logistical problems common to large, expansive operations.

If we fail to manage these risks successfully, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We depend on the services of key executives, the loss of whom could materially harm our business.

Our senior executives are important to our success because they are instrumental in setting our strategic direction, operating our business, identifying, recruiting and training key personnel and identifying expansion opportunities. Losing the services of any of these individuals could adversely affect our business, operating results and financial condition until a suitable replacement could be found. We do not maintain key man life insurance on any of our senior executives. As a result, we are not insured against any losses resulting from the death of our key executives.

Certain of the members of our Board of Managers, our sponsors and our members may allocate some portion of their time to, and in certain instances owe fiduciary, contractual or other obligations to, other businesses, thereby causing conflicts of interest in their determination as to how much time to devote to our affairs and whether to present opportunities to us. This conflict of interest could have a negative impact on our operations.

Certain of the members of our Board of Managers, our sponsors and our members who are not members of management of the Company are not required to commit their full time to our affairs, which could create a conflict of interest when allocating their time between our operations and their other commitments. These individuals currently are employed by or are managers or directors of other entities, including entities with which we may compete, and are not obligated to devote any specific number of hours to our affairs. These individuals may also be subject to fiduciary, contractual or other obligations that would require them to present an opportunity to another company in addition to us or generally may be deemed to conflict with their other obligations, which may in turn cause them to recuse themselves from participating in decisions on our behalf. Such individuals may also be required to refrain from presenting an opportunity to us or from assisting us with existing opportunities. Further, certain members of our Board of Managers are subject to non-competition agreements with various third parties that limit their ability to operate in certain sectors of the oilfield services industry. We do not currently anticipate expanding our business into these sectors of the industry. Any of the foregoing could have a negative impact on our operations. Certain opportunities may not be presented to us or potential conflicts may not be resolved in our favor.

Our sponsor may take actions that conflict with interests of noteholders.

ORB Investments, LLC, our sponsor, has the power to elect our Board of Managers, to appoint members of management and to approve all actions requiring the approval of the holders of our voting equity, including adopting amendments to our limited liability company agreement and approving mergers, acquisitions or sales of all or substantially all of our assets. The interests of our controlling equity holders could conflict with the interests of our noteholders. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of our controlling equity holders might conflict with the interests of the noteholders. Our controlling equity holders also may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in their judgment, could enhance their equity investment, even though such transactions might involve risks to the noteholders.

We may be unable to employ a sufficient number of skilled and qualified workers.

The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield service 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. The demand for skilled workers in our industry is high and the supply is limited.

Potential inability or lack of desire by workers to commute to our facilities and job sites and competition for workers from competitors or other industries are factors that could affect our ability to attract and retain workers. 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.

Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers and at times of high demand we may not be able to retain, recruit and train an adequate number of workers. In addition, our ability to expand our operations will depend in part on our ability to increase the size of our skilled labor force. Our inability to attract and retain skilled workers in sufficient numbers to satisfy our existing service contract and enter into new contracts could materially adversely affect our business, financial condition and results of operations.

We may be adversely impacted by work stoppages or other labor matters.

We currently do not have any employees represented by a labor union. However, it is possible that we may experience work stoppages or other labor disruptions from time to time. Any prolonged labor disruption involving our employees could have a material adverse impact on our combined results of operations and financial condition by disrupting our ability to perform hydraulic fracturing and other services for our current customer or future customers under our service contracts. Moreover, unionization efforts have been made from time to time within our industry, with varying degrees of success. Any such unionization could increase our costs or limit our flexibility.

Our operations are subject to hazards and environmental risks inherent in the oil and natural gas industry.

We provide hydraulic fracturing services, a process involving the injection of fluids—typically consisting mostly of water and also including several chemical additives—as well as sand in order to create fractures extending from the well bore through the rock formation to enable oil or natural gas to move more easily through the rock pores to a production well. Risks inherent to our industry create the potential for significant losses associated with damage to the environment or natural resources. Equipment design or operational incidents, or vehicle operator error can result in explosions, and spills and

discharges of toxic gases, releases of chemicals and hazardous substances, and, in rare cases, uncontrollable flows of gas or well fluids into environmental media, as well as personal injury, loss of life, long-term suspension or cessation of operations and interruption of our business or the business or livelihood of third parties, damage to geologic formations (including possible increased seismicity), environmental media and natural resources, equipment, facilities and property. We use hazardous substances and will generate hazardous wastes in our operations and must comply with environmental requirements relating to proper use, handling, storage, disposal and transport of such. We also may become subject to claims or other liabilities relating to the release of such substances or wastes into the environment or human exposure to such. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. Depending on the frequency and severity of such liabilities or losses, it is possible that our operating costs, profitability, insurability, competitive position and relationships with customers, employees and regulators could be materially impaired. In particular, our customers may elect not to purchase our services if they view our safety or environmental record as unacceptable. This could also cause us to lose customers and substantial revenues.

Our business involves certain operating risks and our insurance may not be adequate to cover all losses or liabilities that we might incur in our operations.

Our operations are subject to many hazards and risks, including the following:


•	accidents resulting in serious bodily injury and the loss of life or property;


•	liabilities from accidents or damage by our equipment;


•	pollution and other damage to the environment;


•	reservoir damage;


•	increased seismicity;


•	blow-outs or the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere, an underground formation or other environmental media; and


•	fires and explosions.

If any of these hazards occur, it could result in suspension of operations and other business interruptions, damage to or destruction of our equipment and the property of others or injury or death to our or a third party’s personnel.

Our insurance may not adequately protect us against liability from all of the hazards of our business. We also are subject to the risk that we may not be able to maintain or obtain insurance of the type and amount we desire at a reasonable cost. If we were to incur a significant liability for which we were uninsured or for which we were not fully insured, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

We will 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, contractor’s pollution, downhole, umbrella liability and excess liability insurance policies, all subject to certain limitations, deductibles and caps. We are not fully insured against all risks, either because insurance is not available or because of the high premium costs relative to perceived risks. 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. 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 intend to operate with most of our customers through master service agreements (“MSAs”). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. We expect that our MSAs generally will provide for indemnification in our favor for liability for pollution or environmental claims arising from subsurface conditions or resulting from the drilling activities of our customers or their operators, unless resulting from our gross negligence or willful misconduct. We may have liability in such cases if we are negligent or commit willful acts and, although the actual terms may vary among our various contracts, typically we expect to be allocated liability under the MSAs for pollution or contamination caused by us or attributable to our equipment or vessels, or otherwise resulting from our negligence. We expect that our customers generally will also agree to indemnify us against claims arising from their employees’ personal injury or death, without regard to fault.

Similarly, we expect to agree to indemnify our customers for liabilities arising from personal injury or death of any of our employees, without regard to fault. In addition, we expect that our customers will agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, for us to agree to indemnify our customers for loss or destruction of property or equipment we own, without regard to fault. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer, unless resulting from our gross negligence or willful misconduct. However, despite this anticipated 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 that could materially and adversely affect our financial condition and results of operations.

We may incur significant costs and liabilities as a result of environmental, health and safety laws and regulations that govern our operations.

As part of our business we will handle, transport and dispose of a variety of fluids and substances used by our current and future customers in connection with their oil and natural gas exploration and production activities. We will also generate and dispose of hazardous waste. Therefore, our operations will be subject to stringent laws and regulations governing the release or disposal of materials into the environment or otherwise relating to environmental protection. We may be required to make significant capital and operating expenditures or perform other corrective actions at wells we service and at properties we own, lease or operate in order to comply with the requirements of these environmental, health and safety laws and regulations or the terms or conditions of permits issued pursuant to such requirements, and our compliance with future laws or regulations, or with any adverse change in the interpretation or enforcement of existing laws and regulations, could increase such compliance costs. Regulatory limitations and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

The costs of compliance with or liabilities imposed under these laws can be significant. Failure to comply with these and other applicable laws and regulations or the terms or conditions of required environmental permits may result in the assessment of damages, including natural resource damages, administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations including corrective actions, revocation of permits and the issuance of injunctions limiting or prohibiting some or all of our operations. In addition, claims for damages to persons, property or natural resources may result from environmental and other impacts of our operations. Future spills or releases of regulated substances or accidents or the discovery of currently unknown contamination could expose us to material losses, expenditures and environmental or health and safety liabilities, including liabilities resulting from lawsuits brought by private litigants or neighboring property owners or operators for personal injury or property damage related to our operations or the land on which our operations are conducted. Such claims, damages, penalties or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition and results of operations.

Future legislative and regulatory developments at both the federal and state level could materially increase our operating costs or adversely affect our competitive position.

Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in our costs for future environmental compliance and remediation. Future changes in relevant laws, regulations or enforcement policies could significantly increase our compliance costs or liabilities or limit our future business opportunities in presently unforeseen ways. In such an event, our business, financial condition and results of operations could be materially impaired.

In addition to changes in existing environmental health or safety laws or regulations, various new and more stringent regulatory requirements directed to the gas exploration industry, and hydraulic fracturing in particular, are being imposed or considered at the federal, state and local levels. The EPA is undertaking a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. The first progress report was issued in December 2012 and the final report is expected in 2014. The results of this study could spur further initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Such measures could subject us to increased costs, limits on the productivity of certain wells and limits on our ability to deploy our technology at or in the vicinity of sensitive areas. The adoption of any such laws or implementing regulations imposing additional permitting, disclosure or regulatory obligations related to, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

For the transportation and relocation of our hydraulic fracturing equipment, sand and chemicals, as well as hazardous materials, we will need to operate trucks and other heavy equipment. We therefore will be subject to regulation as a motor carrier by the DOT and by various state agencies, whose regulations include certain permit requirements of state highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications, insurance

requirements, and containerization, placarding and handling requirements for the transportation of hazardous materials. The DOT 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. Currently, we are operating with a “satisfactory” rating.

The trucking industry is subject to other regulatory changes that may impact our operations by requiring changes in fuel emissions limits, the hours of service regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters. New national fuel efficiency and emissions standards have been promulgated by the EPA for medium- and heavy-duty engines and vehicles. The rule covers vehicles made between 2014 and 2018. Associated with this ruling, we may experience an increase in costs related to truck purchases or maintenance. Additionally, the EPA’s Tier IV regulations apply to certain off-road diesel engines that are needed to power our equipment in the field. Under these regulations, we are limited in the number of non-compliant off-road diesel engines we can purchase. If Tier IV-compliant engines that meet our needs are not available, these regulations could limit our ability to acquire a sufficient number of diesel engines to expand our fleet and to replace existing engines as they are taken out of service. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. We cannot predict whether, or in what form, any legislative or regulatory changes applicable to our trucking operations will be enacted.

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

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. Changing demand for oil and natural gas services and products, and any other major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Compliance with climate change legislation or initiatives could negatively impact our business.

The U.S. Congress is considering legislation to reduce emissions of GHGs and more than half of the states, either individually or through multi-state initiatives, have already begun implementing legal measures to reduce emissions of GHGs. The U.S. Supreme Court has held that carbon dioxide may be regulated as an “air pollutant” under the CAA, and EPA has proceeded with regulatory initiatives to curb emissions of GHGs even in the absence of Congressional action. The EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such GHGs are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These EPA findings allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the CAA. The EPA has proposed and finalized a number of rules requiring various industry sectors to track and report, and, in some cases, control GHG emissions, including a GHG rule applicable to certain sources in the oil and natural gas industry. Several of the EPA rules relating to control of GHG emissions and climate change concerns are subject to challenge in court. We cannot predict either the outcome of these challenges or the impact that EPA’s GHG regulatory initiatives would have on our operations or those of our customers if upheld.

The U.S. Congress has considered climate change initiatives that would, among other things, establish a cap-and-trade system to regulate GHG emissions, but such initiatives have been unsuccessful to date. However, even without federal legislation of GHG emissions, U.S. regions and states have undertaken regulatory action to address GHG emissions. 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, therefore, could reduce the demand for our products and services.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas our current customer or future customers produce. Consequently, although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions for us and our customers, and could have a material adverse effect on our business or demand for our services, our financial condition and results of operations.

The effects of climate change or severe weather could adversely affect our operations.

Changes in climate could adversely affect our operations by limiting or increasing the costs associated with equipment or product supplies. In addition, flooding and adverse weather conditions could impair our ability to operate in affected regions of the country. Oil and natural gas operations of our existing or future customers may be adversely affected by severe weather events, resulting in reduced demand for our services. Repercussions of severe weather conditions may include: curtailment of services; weather-related damage to facilities and equipment, resulting in suspension of operations; inability to deliver

equipment, personnel and products to job sites in accordance with contract schedules; and loss of productivity. These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters also adversely affect the demand for our services by decreasing the demand for natural gas.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas-related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to operations of our customers 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.

The obligations associated with being a public company require significant resources and management attention and may divert management’s focus from our business operations.

We have recently become subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as well as certain provisions of the Sarbanes-Oxley Act of 2002, as amended (“Sarbanes-Oxley”). The Exchange Act requires that we file annual, quarterly and current reports with the Securities and Exchange Commission. Sarbanes-Oxley requires, among other things, that we establish and maintain effective internal controls and procedures for financial reporting. We will have to incur significant costs to comply with these laws, including hiring additional personnel, implementing more complex reporting systems, and paying higher fees to our third party consultants and independent registered public accounting firm. These will include both upfront costs to establish compliance as well as higher annual costs, each of which may be material to investors. Furthermore, the need to establish the corporate infrastructure appropriate for a public company will require our management to engage in complex analysis and decision making, which may divert their attention away from the other aspects of our business. This could prevent us from implementing our growth strategy or may otherwise adversely affect our business, results of operations and financial condition.

We may be exposed to risks relating to evaluations of controls required by Sarbanes-Oxley.

Pursuant to Section 404(a) of Sarbanes-Oxley, our management will be in the future required to furnish a report on the effectiveness of our internal controls over financial reporting. Our internal controls may not be deemed to be effective and our assessment may need to disclose any material weakness identified by us. If we conclude that there are one or more material weaknesses and we are not able to complete remediation in a timely manner, we will not be able to report that our internal controls are effective.

When we cease being an emerging growth company, our auditors will be required to express an opinion on the effectiveness of our internal controls over financial reporting. If either assessment results in a conclusion that internal controls are not effective, these outcomes could damage investor confidence in the accuracy and reliability of our financial statements.

As an “emerging growth company” under the JOBS Act, we are permitted to, and intend to, rely on exemptions from certain disclosure requirements.

As an “emerging growth company” under the Jumpstart Our Business Startups Act of 2012 (the "JOBS Act"), we are permitted to, and intend to, rely on exemptions from certain disclosure requirements that are applicable to other public companies that are not emerging growth companies. We are an emerging growth company until the earliest of: (i) the last day of the fiscal year during which we had total annual gross revenues of $1 billion or more, (ii) the last day of the fiscal year following the fifth anniversary of the date of the first sale of our equity securities pursuant to an effective registration statement, (iii) the date on which we have, during the previous 3-year period, issued more than $1 billion in non-convertible debt or (iv) the date on which we are deemed a “large accelerated filer” as defined under the federal securities laws. For so long as we remain an emerging growth company, we will not be required to:


•	have an auditor report on our internal control over financial reporting pursuant to Section 404(b) of Sarbanes-Oxley;


•	comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial statements (auditor discussion and analysis);


•	submit certain executive compensation matters to shareholder advisory votes, such as “say on pay” and “say on frequency;” and


•	include detailed compensation discussion and analysis in our filings under the Exchange Act, and instead may provide a reduced level of disclosure concerning executive compensation.

The exact implications of the JOBS Act for us are still subject to interpretations and guidance by the SEC and other regulatory agencies. In addition, as our business grows, we may no longer satisfy the conditions of an emerging growth company. We are currently evaluating and monitoring developments with respect to these new rules and we cannot assure you that we will be able to take advantage of all of the benefits from the JOBS Act.

In addition, as an “emerging growth company,” we have elected under the JOBS Act to delay adoption of new or revised accounting pronouncements applicable to public companies until such pronouncements are made applicable to private companies. Therefore, our financial statements may not be comparable to those of companies that comply with standards that are otherwise applicable to public companies.

Risks Related to the Notes

Our substantial level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes and other indebtedness.

As of December 31, 2012, we had approximately $68,414,660 in outstanding indebtedness. Our substantial indebtedness could have important consequences for you and significant effects on our business. For example, it could:


•	make it more difficult for us to satisfy our financial obligations, including with respect to the notes;


•	increase our vulnerability to general adverse economic, industry and competitive conditions;


•	reduce the availability of our cash flow to fund working capital and capital expenditures because we will be required to dedicate a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness;


•	limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;


•	prevent us from raising funds necessary to repurchase notes tendered to us if there is a change of control which would constitute a default under the indenture governing the notes and under any future permitted first lien indebtedness;


•	place us at a competitive disadvantage compared to our competitors that are less highly leveraged and that, therefore, may be able to take advantage of opportunities that our leverage prevents us from exploiting; and


•	limit our ability to borrow additional funds.

Each of these factors may have a material and adverse effect on our financial condition and viability. Our ability to make payments with respect to the notes and to satisfy any other debt obligations will depend on our future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors affecting us and our industry, many of which are beyond our control.

Despite current indebtedness levels, we may still be able to incur substantially more debt, which would increase the risks associated with our substantial leverage.

Even with our existing debt levels, we and our subsidiaries may be able to incur substantial additional indebtedness in the future. Although the indenture governing the notes does, and we anticipate that the agreements that will govern our future indebtedness will, contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions and, under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If we incur additional indebtedness, the related risks that we now face would intensify. In addition, the indenture governing the notes does not prevent us from incurring obligations that do not constitute indebtedness under that agreement and we anticipate that any agreement governing our future indebtedness will similarly not prevent us from incurring obligations that do not constitute indebtedness under those agreements and could further exacerbate the risks associated with our substantial leverage.

We may not be able to generate sufficient cash flow to meet our debt service and other obligations, including the notes, due to events beyond our control.

Our ability to generate cash flows from operations and to make scheduled payments on or refinance our indebtedness, including the notes, and to fund working capital needs and planned capital expenditures will depend on our future financial performance and our ability to generate cash in the future. Our future financial performance will be affected by a range of economic, financial, competitive, business and other factors that we cannot control, such as general economic and financial conditions in the capital or commodity markets, the economy generally or other risks summarized herein. Our inability to execute our strategy in a timely manner could have a material adverse effect on our business, financial condition, results of operations and prospects, including our ability to generate positive cash flow in the future and our ability to service our debt and other obligations, including the notes. If we are unable to service our indebtedness or to fund our other liquidity needs, we

may be forced to take actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing our indebtedness, seeking additional capital, or any combination of the foregoing. If we raise additional debt, it would increase our interest expense, leverage and operating and financial costs. Any of these actions may not be effected on satisfactory terms, if at all, or may not yield sufficient funds to make required payments on the notes and any other indebtedness or to fund our other liquidity needs. In addition, the terms of existing or future debt agreements, including the indenture governing the notes may restrict us from adopting any of these alternatives. Our business may not generate sufficient cash flows from operations or future borrowings may not be available in an amount sufficient to enable us to pay our indebtedness, including the notes, or to fund our other liquidity needs.

The failure to generate sufficient cash flow or to effect any of these alternatives could significantly and adversely affect the value of the notes and our ability to pay amounts due under the notes. If for any reason we are unable to meet our debt service and repayment obligations, including under the notes and under our other debt facilities, we would be in default under the terms of the agreements governing our indebtedness, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable. This would likely in turn trigger cross-acceleration or cross-default rights between our applicable debt agreements. Under these circumstances, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the notes. In addition, these lenders could then seek to foreclose on our assets that are their collateral. If the amounts outstanding under the notes or under our other debt facilities were to be accelerated, or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to our debt holders, including you as a noteholder.

The liens on the collateral securing the notes will be junior and subordinate to liens on the collateral securing obligations under certain indebtedness that we may incur in the future.

The indenture under which the notes were issued permits us to incur certain indebtedness, which we call first lien indebtedness, and to grant the lenders of such indebtedness a lien on our assets that is senior, pursuant to the terms of an intercreditor agreement, to the lien securing the notes. The intercreditor agreement will provide, among other things and subject to certain exceptions, that the holders of the first lien indebtedness will control substantially all matters related to the collateral that secures the first lien indebtedness and the notes; the holders of first lien indebtedness may foreclose on or take other actions with respect to such collateral with which holders of the notes may disagree or that may be contrary to the interests of holders of the notes; to the extent such collateral is released from securing first lien indebtedness to satisfy such indebtedness, the liens securing the notes will also automatically be released without any further action by the trustee, the collateral agent or the holders of the notes; and the holders of the notes waive certain of their rights in connection with a bankruptcy or insolvency proceeding involving us or any guarantor of the notes. Further, the intercreditor agreement will provide that amounts received upon a realization of the collateral securing the notes will be applied first to amounts due under the first lien indebtedness before any amounts will be available to pay the holders of the notes. The collateral may not generate sufficient proceeds to repay all first lien indebtedness and the notes, and as a result holders of the notes may lose a substantial portion of or all of their investment.

The indenture governing the notes imposes, and the agreements governing our future indebtedness may impose, significant operating and financial restrictions, which may prevent us from pursuing certain business opportunities and restrict our ability to operate our business.

The indenture governing the notes contains, and the documentation governing our future indebtedness may contain, customary restrictions on our activities, including covenants that limit our and our restricted subsidiaries’ ability to:


•	transfer or sell assets or use asset sale proceeds;


•	incur or guarantee additional debt or issue preferred equity securities;


•	pay dividends, redeem subordinated debt or make other restricted payments;


•	make certain investments;


•	create or incur certain liens on our assets;


•	incur dividend or other payment restrictions affecting our restricted subsidiaries;


•	enter into certain transactions with affiliates;


•	merge, consolidate or transfer all or substantially all of our assets;


•	engage in a business other than a business that is the same or similar to our current business and reasonably related businesses; and


•	take or omit to take any actions that would adversely affect or impair in any material respect the collateral securing the notes.

In addition, the documentation governing our future indebtedness may require us to meet certain financial ratios, including fixed charge coverage, total leverage or other similar such ratios.

The restrictions in the indenture governing the notes and the anticipated restrictions in our future indebtedness may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We also may incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. We may not be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements, or we may not be able to refinance our debt on terms acceptable to us, or at all. The breach of any of these covenants and restrictions could result in a default under the indenture governing the notes or under our future indebtedness. An event of default under debt agreements would permit some of our lenders to declare all amounts borrowed from them to be due and payable.

Our failure to comply with the agreements relating to our outstanding indebtedness, including as a result of events beyond our control, could result in an event of default that could materially and adversely affect our results of operations and our financial condition.

If there were an event of default under any of the agreements relating to our outstanding indebtedness, the holders of the defaulted debt could cause all amounts outstanding with respect to that debt to be due and payable immediately. Our assets or cash flow may not be sufficient to fully repay borrowings under our outstanding debt instruments if accelerated upon an event of default. Further, if we are unable to repay, refinance or restructure our indebtedness under our secured debt, the holders of such debt could proceed against the collateral securing that indebtedness. In addition, any event of default or declaration of acceleration under one debt instrument could also result in an event of default under one or more of our other debt instruments. Last, we could be forced into bankruptcy or liquidation. As a result, any default by us on our indebtedness could have a material adverse effect on our business and could impact our ability to make payments under the notes.

We may be unable to repay or repurchase the notes at maturity.

At maturity, the entire outstanding principal amount of the notes, together with accrued and unpaid interest, will become due and payable. We may not have the funds to fulfill these obligations or the ability to refinance these obligations. If the maturity date occurs at a time when other arrangements prohibit us from repaying the notes, we could try to obtain waivers of such prohibitions from the lenders and holders under those arrangements, or we could attempt to refinance the borrowings that contain the restrictions. If we could not obtain the waivers or refinance these borrowings, we would be unable to repay the notes.

The notes and the guarantees will be structurally subordinated to indebtedness and other liabilities of any of our future non-guarantor subsidiaries.

The notes and the guarantees will be structurally subordinated to the indebtedness and other liabilities of any of our future non-guarantor subsidiaries and holders of the notes will not have any claim as a creditor against any non-guarantor subsidiary. In addition, subject to certain limitations, the indenture governing the notes permits non-guarantor subsidiaries to incur additional indebtedness, which indebtedness could be significant.

Our ability to repurchase the notes with cash upon a change of control, upon an offer to repurchase the notes in the case of an asset sale or if we have excess cash, if required by the indenture, may be limited.

Upon the occurrence of a change of control, as defined in the indenture governing the notes, we will be required to offer to repurchase all of the outstanding notes at 101% of the aggregate principal amount of the notes repurchased, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase. In addition, upon the occurrence of certain asset sales, as defined in the indenture governing the notes, we will be required to offer to repurchase all of the outstanding notes at 100% of the aggregate principal amount of the notes repurchased, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase. In addition, if we have excess cash as of certain determination dates, each as defined in the indenture governing the notes, we will be required to offer to repurchase an aggregate amount of notes equal to the amount of excess cash at 100% of the aggregate principal amount of the notes repurchased, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

However, it is possible that we will not have sufficient funds at the time of the change of control, upon an asset sale or if we have excess cash, to the extent required by the indenture, to make the required repurchase of notes.

Moreover, the agreements governing any future indebtedness we incur may restrict our ability to repurchase the notes, including following a change of control event or upon an asset sale, as required by the indenture. As a result, following such an event, we would not be able to repurchase notes unless we first repay all such indebtedness or obtain a waiver from the holders of such indebtedness to permit us to repurchase the notes. We may be unable to repay all of that indebtedness or obtain such a waiver. Our failure to purchase notes following a change of control, an asset sale or if we have excess cash, to the extent

required by the indenture, would be an event of default under the indenture, which could cause a cross-default under our other indebtedness, if any, and could have a material adverse effect on our financial condition.

Any requirement to offer to repurchase outstanding notes may therefore require us to refinance any other outstanding debt, which we may not be able to do on commercially reasonable terms, if at all. These repurchase requirements may also delay or make it more difficult for others to obtain control of us.

In addition, certain important corporate events, such as takeovers, recapitalizations, restructurings, mergers or similar transactions, may not constitute a change of control under the indenture governing the notes and, therefore, would not permit the holders of the notes to require us to repurchase the notes.

In addition, the definition of change of control includes a phrase relating to the sale or other transfer of “all or substantially all” of our properties or assets and our subsidiaries, taken as a whole. There is no precise definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty in ascertaining whether a particular transaction would involve a disposition of “all or substantially all” of our assets, and, therefore, it may be unclear as to whether a change of control has occurred and whether the holders of the notes have the right to require us to repurchase such notes.

The value of the noteholders’ security interest in the collateral may not be sufficient to satisfy all our obligations under the notes.

The notes and the guarantees of the notes will be secured by a lien on certain of our future domestic subsidiaries’ (other than any unrestricted subsidiaries’) assets, subject to certain permitted liens and certain excluded assets.

If we default on the notes, the holders of the notes will be secured only to the extent of the value of the assets underlying their security interest after taking into account any first lien obligations. Upon enforcement against any collateral or insolvency, under the terms of the intercreditor agreement, proceeds of such enforcement will be used first to pay obligations outstanding under first lien indebtedness in full (including post-petition interest, whether or not allowable in any bankruptcy case) and second to pay the notes. To prevent foreclosure, we may be motivated to commence voluntary bankruptcy proceedings, or the holders of the notes or various other interested persons may be motivated to institute bankruptcy proceedings against us. The commencement of such bankruptcy proceedings would expose the holders of the notes to additional risks, including additional restrictions on exercising rights against collateral.

The indenture governing the notes allows us to incur additional obligations secured by liens in amounts that may be significant. Any additional indebtedness or obligations secured by a lien on the collateral securing the notes could adversely affect the relative position of the holders of the notes with respect to the collateral securing the notes.

Accordingly, there may not be sufficient collateral to pay all or any of the amounts due on the notes. Any claim for the difference between the amount, if any, realized by holders of the notes from the sale of the collateral securing the notes and the obligations under the notes will rank equally in right of payment with all of our other unsecured unsubordinated indebtedness and other obligations, including trade payables.

There is no established market for the notes.

The notes are not listed on any securities exchange. Although the placement agent in the Unit Offering may make a market in the notes, it is not obligated to do so, and it may discontinue any market-making at any time without notice. An active market for the notes may not develop or, if it does develop, it may not continue. Further, if a market for the notes does develop, then the notes could trade at prices that may be higher or lower than the initial offering price thereof depending upon a number of factors, including prevailing interest rates, our operating results, events in the United States and the market for similar securities.

If a market for the notes does not develop or continue, then noteholders may be unable to resell the notes for an extended period of time at their fair market value, if at all. Future trading prices of the notes will depend on many factors, including, among other things, prevailing interest rates, our operating results and the market for similar securities. Consequently, a purchaser of the notes may not be able to liquidate its investment readily, and the notes may not be readily accepted as collateral for loans.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

On March 1, 2012, we entered into an agreement for the lease of a 70,500 square foot field office/operations facility on 10.844 acres in Jane Lew, West Virginia for our fleet operations. The total amount of monthly payments over the term of 36 months is $881,395. The lease agreement has annual rent escalations of 2% on each anniversary.

On April 1, 2012, we entered into an agreement for the lease of approximately 2,584 square feet of office space in Houston, Texas to serve as our corporate headquarters. The total amount of monthly payments over the term of 36 months is $176,358.

On October 1, 2012, we entered into an agreement to lease approximately 1,457 square feet of additional office space immediately adjacent to our leased corporate headquarters, located in the same building in Houston, Texas. The total amount of monthly payments over the term of the 30 months is $84,817.

ITEM 3. LEGAL PROCEEDINGS

We, along with two of our officers, Jeffrey McPherson and Edward Self III, are co-defendants in an action styled Calfrac Well Services Ltd. and Calfrac Well Services Corp. v. Edward S. Self, Jeffrey D. McPherson, Robert C. Kurtz, Charles Johnson and U.S. Well Services, Inc. d/b/a U.S. Well Services LLC, Civil Action No. 12-1260, in the United States District Court for the Western District of Pennsylvania. Calfrac Well Services Ltd. and Calfrac Well Services Corp. (collectively, “Calfrac”) filed the complaint against us on August 30, 2012 for injunctive and other relief. Calfrac alleges that while employees at Calfrac, Messrs. Self and McPherson, along with certain other individuals, formed U.S. Well Services, Inc., our predecessor, in order to compete with Calfrac. The complaint alleges that the defendants conspired to steal Calfrac's trade secrets, proprietary business and confidential information, customers and employees, in order to help set up the new company for their own benefit. As employees of Calfrac, it is alleged that Messrs. Self and McPherson each entered into confidentiality agreements, which Calfrac alleges that they breached by copying confidential information residing on Calfrac's computers and information technology systems, in connection with forming our predecessor. Calfrac seeks to enjoin each of the defendants from soliciting or communicating with certain clients and employees of Calfrac, as well as from using or disclosing certain information of Calfrac. Calfrac further seeks actual and compensatory damages in connection with its allegations of breaches of contract and certain duties by Messrs. Self, McPherson, Kurtz and Johnson. We deny the allegations and intend to vigorously defend this action.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Markets

We are a privately held company and there is no established public trading market for our membership interests.

Holders

As of March 19, 2013, there were 600,000 Series A Units, 630,000 Series B Units, 192,500 Series C Units, and 27,500 Series D Units issued and outstanding.

Dividends

The Indenture governing the 14.50% Senior Secured Notes Due 2017 limits the payment of dividends by us.

Equity Compensation Plans

We have no outstanding equity compensation plans under which our securities are authorized for issuance. Certain of our officers entered into restricted equity agreements with us, pursuant to which 293,323 Series D Units were granted as performance incentives. The Series D Units are subject to vesting and forfeiture under circumstances set forth in the agreements between us and each officer. For a summary of the restricted equity agreements see “Item 11. Executive Compensation - Restricted Equity Agreements.”

Unregistered Sales of Securities

In February 2012, we sold, in the Unit Offering, 85,000 units, with each unit consisting of $1,000 principal amount of 14.50% Senior Secured Notes due 2017 and a warrant to purchase the Company's Series B Units, to certain accredited investors. Concurrently with the offering of the units, we sold 600,000 of the Company's Series A Units and 600,000 of the Company's Series B Investments, in the Sponsor Equity Investment, to ORB for $30 million.

The sale of securities in the Unit Offering was deemed to be exempt from registration under the Securities Act in reliance upon Section 4(2) of the Securities Act and Regulation S promulgated thereunder, and the sale of securities in the Sponsor Equity Investment was deemed to be exempt from registration under the Securities Act in reliance upon Section 4(2) of the Securities Act, as a transactions by an issuer not involving a public offering.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

ITEM 6. SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, is not applicable to a smaller reporting company.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations together with our consolidated financial statements and the related notes and other financial information included elsewhere in this Form 10-K. Some of the information contained in this discussion and analysis or set forth elsewhere in this Form 10-K, including information with respect to our plans and strategy for our business and related financing, include forward-looking statements that involve risks and uncertainties. You should review the section entitled “Risk Factors” included in Item 1A of this Annual Report for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

Overview

We are a Houston, Texas based oilfield services provider of well stimulation services to the upstream oil and gas industry. We currently perform high-pressure hydraulic fracturing services in unconventional oil and natural gas reservoirs. The fracturing process consists of pumping a specially formulated fluid into perforated well casing, tubing, or open holes under high pressure, causing the underground formation to crack or fracture, allowing nearby hydrocarbons to flow more freely up the wellbore.

We believe our hydraulic fracturing fleets purchased from Stewart & Stevenson are reliable and high performing fleets with the capability to meet the most demanding pressure and flow rate requirements in the field. Our management team has

extensive industry experience providing completion services to exploration and production companies. We intend to focus on the most active shale and unconventional oil and natural gas plays in the United States.

We currently perform services in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania. We are also evaluating opportunities with existing and new customers to expand our operations into new areas throughout the United States, which may include the Bakken Shale in North Dakota and Montana, the Haynesville Shale in northwestern Louisiana and eastern Texas, the Eagle Ford Shale in southern Texas, the Barnett Shale in North Texas, the Permian Basin in western Texas and southeastern New Mexico, the Niobrara Shale in Colorado, Wyoming and Nebraska and the Granite Wash formation in Oklahoma.

We are a Delaware limited liability company. Our principal executive offices are located at 770 South Post Oak Lane, Suite 405, Houston, Texas 77056 and our main telephone number is (832) 562-3730.

We began operations under a take or pay contract, our original contract, with Antero, for a 24-month service period commencing on April 12, 2012. Prior to beginning operations in the second quarter of 2012, the Company was in the development stage.

Formation Transactions

Unit Offering. On February 21, 2012, we and USW Financing Corp., our wholly-owned subsidiary, completed the Unit Offering. Approximately $47.5 million of the proceeds from the Unit Offering were used to acquire a substantial amount of our core operating equipment and for related fees and expenses and for general corporate purposes. The remainder of the proceeds of the Unit Offering were used to consummate the Second Contract Repurchase Offer and for general corporate purposes, including the acquisition of our second hydraulic fracturing fleet. The Unit Offering was made to institutional accredited investors pursuant to Section 4(2) of the Securities Act of 1933, as amended, and Regulation S.

Senior Secured Notes. The notes were part of the units issued in the Unit Offering and will mature on February 15, 2017. The notes have a fixed annual interest rate of 14.50% per annum. We will pay interest on the notes semi-annually, on February 15 and August 15 of each year they are outstanding, commencing on August 15, 2012. The first interest payment on the Notes was paid on August 15, 2012 by increasing the principal amount of the outstanding notes by $4,480,706, the amount of the first interest payment. Subsequent interest payments will be payable in cash. The notes may be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of our future domestic subsidiaries, other than subsidiaries designated as unrestricted subsidiaries. None of our future foreign subsidiaries will guarantee the notes. As of the date hereof, our sole subsidiary, USW Financing Corp., was a co-issuer of the notes. The notes and any future guarantees are subject to a lien on substantially all of our and our future subsidiaries' assets, subject to certain exceptions. If and when we incur permitted first lien indebtedness, the liens on the assets securing the notes and any future guarantees will likely be contractually subordinated and junior to liens securing such permitted first lien indebtedness pursuant to an intercreditor agreement. The notes are also subject to optional redemption features whereby: (a) on or after February 15, 2015, we may redeem some or all of the notes at a premium that will decrease over time, (b) prior to February 15, 2015, we may, at our option, redeem up to 35% of the aggregate principal amount of the notes using the net proceeds of certain equity offerings at a price equal to 110% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any, to the date of redemption; provided that, following any and all such redemptions, at least 65% of the aggregate principal amount of the notes originally issued under the indenture remain outstanding and the redemption occurs within 90 days of the closing of such equity offering, and (c) at any time prior to February 15, 2015, we may, at our option, redeem all or a part of the notes, upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the notes redeemed, plus a specified make-whole premium, plus accrued and unpaid interest and additional interest, if any, to the applicable date of redemption. The notes are also subject to a mandatory redemption provision whereby within 45 days after each March 31 or September 30 beginning on March 31, 2013, for which our cash and cash equivalents are greater than $12.1 million, we are required to offer to repurchase notes in the amount of such excess cash amount at an offer price in cash equal to 100% of their principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

Warrants. The warrants were part of the units issued in the Unit Offering, and are exercisable at a price of $0.01 per Series B Unit, subject to adjustment. The warrants expire at 5:00 p.m., New York City time, on February 21, 2019. We have granted holders of warrants certain “piggyback” registration rights for the resale of our Series B Units underlying the warrants. Holders of the warrants have preemptive and other equity protection rights identical to those granted to the purchasers in the Sponsor Equity Investment described below. Upon exercise of the warrants, the holders thereof will be required to become a party to our then-existing limited liability company agreement.

Sponsor Equity Investment. Concurrent with the closing of the Unit Offering, we received a $30 million equity investment from ORB, in exchange for (a) 600,000 Series A Units which, among other things, entitle the holders thereof to a 13% preferred return on their capital contribution compounded semi-annually and payable upon the occurrence of certain liquidation or exit events or on February 21, 2017 and (b) 600,000 Series B Units. The securities issued as part of the Sponsor

Equity Investment were issued to institutional accredited investors pursuant to Section 4(2) of the Securities Act of 1933, as amended.

Restructuring. In order to facilitate the Unit Offering and the Sponsor Equity Investment, we completed a corporate restructuring. Prior to the closing of the Unit Offering and the Sponsor Equity Investment, U.S. Well Services, Inc., our former parent, formed us and USW Financing Corp. U.S. Well Services, Inc. then sold substantially all of its assets to us in exchange for 167,500 Series C Units representing, in the aggregate, 16.75% of our common equity immediately following the closing of the Unit Offering.

Resignation of Donald E. Stevenson. On March 19, 2012, at the request of our Board of Managers, Donald E. Stevenson resigned from his role as our President and Chief Executive Officer and as a member of our Board of Managers, effective March 22, 2012. There was no disagreement with Mr. Stevenson on any matter relating to our operations, policies or practices.

Recent Developments

Delivery of Initial Hydraulic Fracturing Fleet. We used a portion of the net proceeds of Unit Offering to purchase our initial hydraulic fracturing fleet from Stewart & Stevenson. We received final delivery of our initial hydraulic fracturing fleet from Stewart & Stevenson in April 2012.

Performance under Original Antero Contract. On November 1, 2011, our predecessor entered into a Contract to Provide Dedicated Fracturing Fleet(s) for Fracturing Services with Antero. In April 2012 we began performing hydraulic fracturing and related services under our contract with Antero. Our initial operations under our contract with Antero have been focused in West Virginia. See "Current Contracts - Original Antero Contract" below for a description of our original contract with Antero.

Delivery of Second Hydraulic Fracturing Fleet. We purchased our second hydraulic fracturing fleet from Stewart & Stevenson and other vendors. The fleet includes fourteen FT-2251T Trailer Mounted Fracturing Units with Triplex Pumps with 2,000 HHP per pump, two MT-132 Trailer Mounted 130bpm Fracturing Blenders with AccuFrac Systems, one data van and two CT-5CAS/HYD hydration units. Delivery of the equipment was completed in August 2012.

Rider to the Original Antero Contract. On June 5, 2012, we entered into the Rider to Original Antero Contract (the "Rider"). See "Current Contracts - Rider to Original Antero Contract" below for a description of the Rider. The Rider amends certain terms of our contract with Antero. The Rider gives Antero, in its sole discretion, a right of first refusal to engage all or any portion of our second hydraulic fracturing fleet. Any work performed by our second hydraulic fracturing fleet will be governed under the terms of our original contract with Antero as modified by the Rider. In addition, the Rider modifies our original contract with Antero to discount all services performed by us for Antero (whether such services are performed under our original contract with Antero or in the future by our second hydraulic fracturing fleet) by ten percent. We believe that entering into the Rider strengthens our relationship with Antero and provides us with the opportunity to grow revenues by participating in Antero's expanding drilling program.

Hiring of Brian Stewart. On June 18, 2012, Brian Stewart was hired as our President and Chief Executive Officer. Mr. Stewart, 57, retired from Devon Energy Corporation, a publicly traded independent energy company, in 2012, after 35 years of service. Mr. Stewart’s last five years of service at Devon Energy Corporation were as the Vice President of Well Engineering for the Offshore Division. In this role he was responsible for Gulf of Mexico and international drilling and completion activities.

Second Contract Repurchase Offer. Pursuant to the terms of the indenture governing the notes, a total of $37.5 million of the net proceeds from the Unit Offering were placed into an escrow account to either be released to us upon our entrance into a second fracturing contract on terms similar to our original contract with Antero or to be used to repurchase notes if we were unable to enter into a second fracturing contract on terms similar to our original contract with Antero on or prior to June 30, 2012. We did not enter into a second fracturing contract on terms similar to our original contract with Antero on or prior to June 30, 2012. As a result, on July 10, 2012, pursuant to the indenture governing the notes, we commenced the Second Contract Repurchase Offer as well as the consent solicitation described below. On July 16, 2012, after obtaining the requisite consents in the consent solicitation, the maximum aggregate purchase price of the Second Contract Repurchase Offer was reduced from $37.5 million to $22.5 million. In conjunction with the Second Contract Repurchase Offer, $22.5 million was paid on August 10, 2012 for the principal and accrued interest of the repurchased notes.

Consent Solicitation. On July 10, 2012, we commenced a consent solicitation to obtain the consent of at least a majority in aggregate principal amount of the outstanding notes to approve the proposed amendments (the "Proposed Amendments"). The Proposed Amendments, among other things, (a) amended the definition of “Second Fracturing Contract” in the indenture governing the notes to mean Rider No. 1 to Contract to Provide Dedicated Fracturing Fleet(s) for Fracturing Services dated June 5, 2012, between the U.S. Well Services, LLC and Antero Resources Appalachian Corporation, (b) added a definition to the indenture governing the notes for “First Release of Funds,” (c) deleted Section 4.09(b)(1) of the indenture

governing the notes in its entirety and replaced it with a new Section 4.09(b)(1) that modifies the definition of “Permitted Debt,” (d) deleted Section 4.19 of the indenture governing the notes in its entirety and replaced it with a section entitled “Partial Release of Escrowed Funds; Second Contract Repurchase Offer,” (e) deleted Section 7(d) of the notes in its entirety and replaced it with a new Section 7(d), and (f) amended the escrow agreement in accordance with the above. On July 16, 2012, we obtained the requisite consents needed to adopt the Proposed Amendments and executed and delivered the first supplemental indenture to the indenture governing the notes and an amendment to the escrow agreement effecting the Proposed Amendments. As a result of the Proposed Amendments, among other things, the amount of funds in the escrow account were reduced to $22.5 million and all other funds in the escrow account (approximately $15 million) were released to us.

Resignation of Leonard Travis. On August 6, 2012, the Company's Board of Managers accepted the resignation of Leonard Travis, Senior Vice President and Chief Financial Officer effective immediately. On August 7, 2012, Matthew Bernard, a member of the Board of Managers, was appointed as our Interim Chief Financial Officer.

Hiring of Kenneth Sill. On September 19, 2012, Kenneth Sill was hired as our Chief Financial Officer and Matthew Bernard resigned his position as Interim Chief Financial Officer. Immediately prior to being hired by us, Mr. Sill was a director and industry analyst for Tudor Pickering Holt Asset Management from December 2010 to September 2012, where he focused on the oilfield services industry, as well as the coal and alternative energy equity markets.

Sand Purchase Agreement. On November 9, 2012, we entered into an agreement with a supplier to purchase sand for use in our hydraulic fracturing operations. The agreement is effective on November 1, 2012 for a term of two years, subject to renewal options. Under the terms of this agreement, we are required to purchase from this supplier a quarterly minimum quantity of sand at a fixed price, amounting to approximately $1.1 million per quarter. In the event we fail to purchase any portion of sand required to be purchased on a quarterly basis, we are required to make payments to the supplier for amounts not taken, up to the contractual minimum and subject to the terms of the agreement.

Repurchase of notes. On November 14, 2012, we paid $2.6 million to a noteholder to repurchase $2.5 million of our notes at 100% of face value, including $0.1 million in accrued interest. The repurchased notes were not cancelled and are currently held in reserve with the option to resell as a source of capital funding.

How We Generate Our Revenues

Hydraulic fracturing services enhance the production of oil and natural gas from formations with restricted natural flow of hydrocarbons. The fracturing process consists of pumping a specially formulated fluid into perforated well casing, tubing or open holes under high pressure, causing the underground formation to crack or fracture, allowing nearby hydrocarbons to flow more freely up the wellbore. Sand, bauxite, resin-coated sand or ceramic particles, each referred to as a proppant or propping agent, are suspended in the fracturing fluid and prop open the cracks created by the hydraulic fracturing process in the underground formation. The extremely high pressure required to stimulate wells in many of the regions in which we intend to operate presents a challenging environment for achieving a successfully fractured horizontal well. As a result, an important element of the services we provide to oil and natural gas producers is designing the optimum well completion, which includes determining the proper fluid, proppant and injection specifications to maximize production. We intend to focus on the most active shale and unconventional oil and natural gas plays in the United States.

We are currently party to a two-year take or pay contract with Antero to perform services in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania. Antero Resources LLC (with its subsidiaries including Antero) is an oil and natural gas company engaged in the acquisition, development and production of unconventional natural gas properties primarily located in the Appalachian Basin in West Virginia and Pennsylvania and the Piceance Basin in Colorado. Our original contract with Antero includes minimum performance requirements related to the number of stages to be completed daily, monthly and quarterly. If Antero does not provide us with the minimum quarterly stages through no fault of ours, Antero will owe us an agreed upon rate of dedicated fracturing fleet charges ("DFFCs") per stage for any stages less than the minimum quarterly stages. We may expand our business to include other unconventional oil and natural gas formations, which may include certain areas of the Bakken Shale in North Dakota and Montana, the Haynesville Shale in northwestern Louisiana and eastern Texas, the Eagle Ford Shale in southern Texas, the Permian Basin in western Texas and southeastern New Mexico, the Niobrara Shale in Colorado, Wyoming and Nebraska and the Granite Wash formation in Oklahoma.

Current Contracts

Original Antero Contract. Our original contract with Antero provides for a 24-month service period commencing when services began on April 12, 2012. The contract is renewable for one additional year upon the mutual written consent of both parties. The contract includes minimum performance requirements related to the number of stages to be completed quarterly.

If Antero requires more than the minimum agreed upon fracturing days per quarter, it will give us written notice thereof, and we will charge a per-stage price for such additional services at the same rate. We will operate on a 24-hour service schedule. We will be paid mobilization fees (based on mileage from the location of our fleet, charged at the initial stage of each

job), as well as operating stage/well rates described in the contract and standby time rates under certain circumstances, DFFCs and agreed upon down-time rates per stage. If Antero does not provide us with the minimum quarterly stages through no fault of ours, Antero will owe us an agreed upon rate of DFFCs per stage for any stages less than the minimum quarterly stages. The contract also provides for force majeure payment rates and payments in the event a governmental body or regulatory agency issues a mandate that either makes it impossible for us to continue operations or causes an increase in our rate. Antero may terminate the contract on 60 days’ written notice, in which case it must pay us a lump sum payment of up to a maximum agreed upon amount within an agreed upon time. The contract also allows Antero to direct the stoppage of services on reasonable written notice to us, in which case it must pay us a standby time rate. The rates described in the contract are to be revised on an agreed upon schedule to reflect certain cost increases or decreases if the costs exceed an agreed upon percentage of start date costs.

Rider to Original Antero Contract. On June 5, 2012, we entered into the Rider. The Rider amends certain terms of our original contract with Antero. The Rider gives Antero, in its sole discretion, a right of first refusal to engage all or any portion of our second hydraulic fracturing fleet. Any work performed by our second hydraulic fracturing fleet will be governed under the terms of our original contract with Antero as modified by the Rider. In addition, the Rider modifies our original contract with Antero to discount all services performed by us for Antero (whether such services are performed under our original contract with Antero or in the future by our second hydraulic fracturing fleet) by ten percent. We believe that entering into the Rider strengthens our relationship with Antero and provides us with the opportunity to grow revenues by participating in Antero's expanding drilling program.

Although we have entered into a term contract for our first hydraulic fracturing fleet, we also have the flexibility to pursue spot market projects. Our agreements with Antero allow us to supplement monthly contract revenue by deploying equipment on short-term spot market jobs on those days when Antero does not require our services or is not entitled to our services. When providing these types of short-term services we will charge prevailing market prices per hour for spot market work. We may also charge fees for the set up and mobilization of equipment depending on the job. These fees and other charges vary depending on the equipment and personnel required for the job and the market conditions in the region in which the services are performed. We believe our ability to provide services in the spot market allows us to develop new customer relationships.

We may also source chemicals and proppants that are consumed during the fracturing process and charge our customers a fee for providing such materials. We may also charge our customers a handling fee for chemicals and proppants supplied by the customer. Such charges for materials will generally reflect the cost of the materials plus a markup and will be based on the actual quantity of materials used in the fracturing process.

How We Obtain Our Equipment

On November 9, 2011, we entered into an agreement with Stewart & Stevenson to purchase a hydraulic fracturing fleet to service our original contract with Antero. This is our initial hydraulic fracturing fleet and was manufactured to our specifications. This hydraulic fracturing fleet is equipped to perform all aspects of hydraulic fracturing operations, including acid stimulation, high-pressure pumping and pressure testing. The fleet includes twenty FT-2251T Trailer Mounted Fracturing Units with Triplex Pumps with 2,000 hydraulic horsepower ("HHP") per pump, three MT-132 Trailer Mounted 130bpm Fracturing Blenders with AccuFrac Systems, two data trailers, one chemical additive trailer and two CT-5CAS/HYD hydration units. Initial deliveries of our fracturing fleet began in February 2012 and were completed in April 2012.

We entered into agreements with Stewart & Stevenson and other vendors for the purchase of our second hydraulic fracturing fleet. The fleet includes fourteen FT-2251T Trailer Mounted Fracturing Units with Triplex Pumps with 2,000 HHP per pump, two MT-132 Trailer Mounted 130bpm Fracturing Blenders with AccuFrac Systems, one data van and two CT-5CAS/HYD hydration units. Delivery of the equipment was completed in August 2012.

Our Challenges

We face many challenges and risks in the industry in which we operate. Although many factors contributing to these risks are beyond our ability to control, we continuously monitor these risks, and we have taken steps to mitigate them to the extent practicable. We believe that we are well positioned to capitalize on future growth opportunities in the hydraulic fracturing market. However, we may be unable to capitalize on our competitive strengths to achieve our business objectives and, consequently, our results of operations may be adversely affected. Please read the section titled “Cautionary Statement Regarding Forward-Looking Statements” and the "Risk Factors" included in Item 1A in this Annual Report for additional information about the risks we face.

Hydraulic Fracturing Legislation and Regulation. Congress has from time to time, including during the current session, considered legislation to provide for the federal regulation of hydraulic fracturing and to require public disclosure of the chemicals used in the fracturing process. If such current or any future legislation becomes law, it could establish an additional level of regulation that could lead to us experiencing operational delays or increased operating costs. The EPA

promulgated rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Among other controls, the rules require operators to use “green completions” for hydraulic fracturing by January 1, 2015 (unless required earlier under a state or local law), meaning operators will have to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. In addition, various state and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing. The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, increase our and our customers’ costs of compliance and adversely affect the quality of the hydraulic fracturing services that we provide for our customers. Additionally, if hydraulic fracturing becomes further regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or if states or localities impose additional regulatory requirements, fracturing activities could become subject to additional permitting or regulatory requirements and also to permitting delays and potential costs increases all of which could adversely affect our business and results of operations.

Financing Future Growth. To date we have used the proceeds of the Unit Offering and the Sponsor Equity Investment to acquire two hydraulic fracturing fleets and to fund our operations. The successful execution of our business strategy depends on our ability to raise capital as needed to, among other things, finance the purchase of additional hydraulic fracturing fleets and to maintain the equipment we have already purchased. If we are unable to generate sufficient cash flows from operations or obtain additional capital, we may be unable to sustain or increase our current level of growth in the future. There is no guarantee that we will be able to raise the additional capital that will be needed to grow our business on favorable terms or at all.

Outlook

While the demand for hydraulic fracturing services has increased significantly in recent years, the pressure pumping market currently has excess capacity. We believe the following trends, among others, will lead to increased demand for our services and have the potential to support the growth of our business going forward:


•	Increased Horizontal Drilling. Drilling has increased in unconventional resource basins, particularly liquids-rich formations, through the application of horizontal drilling and completion technologies. Horizontal wells generally are completed with multiple stages, resulting in increased demand for pressure pumping services.


•	Implementation of New Drilling Technologies. New horizontal drilling and completion technologies which use hydraulic fracturing to produce oil and natural gas from unconventional resources plays have been implemented across the United States.


•	Improvements to Fracturing Processes. Hydraulic fracturing utilization is greater due to increasingly longer laterals equating to a greater number of fracturing stages. Utilization has further increased due to new horizontal well completion techniques incorporating the use of sliding sleeves as opposed to more conventional "plug and perf" wireline techniques.

Results of Operations

Period from February 21, 2012 (inception) to December 31, 2012



	Successor			Predecessor
	February 21, 2012			January 1, 2012			August 18, 2011
	(inception) to			to			(inception) to
	December 31, 2012			February 20, 2012			December 31, 2011

Revenue	$	52,134,830		$	—		$	—
Costs and expenses:
Cost of services	43,008,477			—			—
Depreciation and amortization	6,310,943			—			—
Selling, general and administrative expenses	3,783,989			432,773			283,729
Other operating expenses	—			40,587			104,015
Loss from operations	(968,579		)	(473,360		)	(387,744		)
Interest expense, net	(16,960,349		)	—			—
Loss before income taxes	(17,928,928		)	(473,360		)	(387,744		)
Income tax expense	—			—			—
Net loss	$	(17,928,928	)	$	(473,360	)	$	(387,744	)

Our operating activities for the period from February 21, 2012 (inception) to December 31, 2012 consisted of overseeing the construction of our two hydraulic fracturing fleets, establishing a field office in West Virginia and the performance of services by our two fleets under our contract with Antero, which commenced in April 2012. During the period, we completed 474 stages and recognized revenues totaling $52.1 million. Cost of services totaled $43.0 million and were primarily for cost of proppant and chemicals used in the fracturing process, salaries and wages, operating materials and supplies, and various operating expenses. Depreciation and amortization totaled $6.3 million for the period from February 21, 2012 (inception) to December 31, 2012 and was primarily for depreciation of our two fleets, which were placed into service in April and August 2012. Our selling, general and administrative expenses totaled $3.8 million and were primarily for salaries and wages and professional fees. Interest expense totaled $17.0 million and was due primarily to the interest expense accrued in conjunction with the Notes and the mandatorily redeemable Class A Units, and to the loss on extinguishment of debt in connection with the Second Contract Repurchase Offer in August 2012.

The operating activities of our predecessor for the period from January 1, 2012 to February 20, 2012, primarily consisted of start-up activities, including ordering equipment and acquiring financing. Consequently, no revenues were earned during this period. For the period January 1, 2012 to February 20, 2012, USWS, Inc. recognized a loss from operations of approximately $0.5 million directly as a result of the expenses incurred. Selling, general and administrative expenses totaled $0.4 million for the period from January 1, 2012 to February 20, 2012 and were primarily for salaries and wages to officers and various professional fees.

The operating activities of our predecessor for the period August 18, 2011 to December 31, 2011, primarily consisted of start-up activities, including acquiring equipment and securing a customer contract. Consequently, no revenues were earned during this period. For the period August 18, 2011 to December 31, 2011, USWS, Inc. recognized a loss from operations of approximately $0.4 million directly as a result of the expenses incurred. Selling, general and administrative expenses totaled $0.3 million for the period August 18, 2011 to December 31, 2011 and were primarily for salaries and wages to officers and various professional fees. Other operating expenses totaled $0.1 million and were primarily for share-based payments to officers, a director and a vendor.

Liquidity and Capital Resources

Our primary sources of liquidity are the proceeds we received from the Unit Offering and the Sponsor Equity Investment. Our primary uses of capital have been the acquisition of our two hydraulic fracturing fleets, newly hired operations labor, and selling, general and administrative expenses. We continually monitor potential sources of capital, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. As of December 31, 2012, we had a balance of cash and cash equivalents totaling approximately $11.8 million.

Our ability to meet our future liquidity requirements for satisfying our debt service obligations, funding operations and funding future capital expenditures will depend in large part on our future performance, some of which are subject to factors beyond our control. However, we believe that our cash on hand after capital spending, coupled with future cash flows from

operating activities related to our two hydraulic fracturing fleets, are sufficient to fund ongoing operations and to meet our debt servicing obligations. We expect future cash flows from operating activities to improve as our original contract with Antero continues and we improve efficiencies regarding the number of stages completed, billed and collected. We also expect future gross margin to improve as we gain synergies from operating multiple fleets in the same region.

We have a total capital expenditure and repairs budget of approximately $2.5 million for 2013.

Our capital budget may be adjusted as business conditions warrant. While we maintain some discretion related to our capital budget, the amount, timing and allocation of capital expenditures for 2013 will be subject to covenants under our indenture governing our notes and our agreements with Antero. We will routinely monitor our capital expenditures in response to changes in prices, availability of financing, equipment acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack thereof in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside of our control.

Capital Requirements

The energy services business is capital intensive, requiring significant investment to expand, upgrade and maintain equipment. Our capital requirements have consisted primarily of, and we anticipate will continue to be:


•	Growth capital expenditures, such as those to acquire additional equipment and other assets or upgrade our existing equipment to grow our business; and


•	Maintenance capital expenditures, which are capital expenditures made to extend the useful life of our assets. There have been no maintenance capital expenditures to date.

Additionally, we continually monitor new advances in hydraulic fracturing equipment and down-hole technology as well as technologies that may complement our business, and opportunities to acquire additional equipment to meet our customers’ needs. Our ability to make any significant acquisition for cash would likely require us to obtain additional equity or debt financing, which may not be available to us on favorable terms or at all.

Financial Condition and Cash Flows

The net cash provided by or used in our operating, investing and financing activities is summarized below:



	Successor			Predecessor
	February 21, 2012			January 1, 2012		August 18, 2011
	(inception) to			to		(inception) to
	December 31, 2012			February 20, 2012		December 31, 2011
	(unaudited)
Cash flow provided by (used in):
Operating activities	$	(3,835,487	)	$	—	$	—
Investing activities	(66,055,460		)	—		—
Financing activities	81,702,662			—		—
Change in cash and cash equivalents	$	11,811,715		$	—	$	—

Cash Used by Operating Activities. Net cash used in operating activities was $3.8 million for the period February 21, 2012 (inception) through December 31, 2012 and was due primarily to our net loss, outstanding receivables associated with activity performed in December 2012, the purchase of inventory, partially offset by the accrued interest on the debt.

Cash Flows Used in Investing Activities. Net cash used in investing activities for the period was $66.1 million and was due to capital expenditures, primarily related to the acquisition of our two hydraulic fracturing fleets.

Cash Flows Provided by Financing Activities. Net cash provided by financing activities was $81.7 million and was due primarily to the net proceeds received from the Unit Offering and the Sponsor Equity Investment, partially offset by the principal repayment as part of the Second Contract Repurchase Offer.

Off-Balance Sheet Arrangements

As of December 31, 2012, we had no off-balance sheet arrangements other than the operating leases discussed in Note 11 - Commitments and Contingencies in notes to consolidated financial statements.

Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting standards have developed. Accounting standards generally do not involve a

selection among alternatives, but involve the implementation and interpretation of existing standards, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable standards on or before their adoption, and we believe the proper implementation and consistent application of the accounting standards are critical.

Our discussion and analysis of our financial condition and results of operations is based upon our condensed consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these condensed consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, expenses and related disclosures. We base our estimates and assumptions on historical experience and on various other factors that we believe to be reasonable under the circumstances. We evaluate our estimates and assumptions on an ongoing basis. The results of our analysis form the basis for making assumptions about the carrying values of assets and liabilities that are not readily apparent from other sources. Our actual results may differ from these estimates under different assumptions or conditions.

Pursuant to the JOBS Act, we are reporting in accordance with certain reduced public company reporting requirements permitted by this act. As a result of this, our financial statements may not be comparable to companies that are not emerging growth companies or elect to avail themselves of this provision.

We believe the following critical accounting policies involve significant areas of management’s judgments and estimates in the preparation of our consolidated financial statements.

Property and Equipment. Fixed asset additions are recorded at cost. Cost of units manufactured consists of products, components, labor and overhead. Expenditures for renewals and betterments that extend the lives of the assets are capitalized. An allocable amount of interest on borrowings is capitalized for self-constructed assets and equipment during their construction period. Amounts spent for maintenance and repairs are charged against operations as incurred. Costs of fixed assets are depreciated on a straight-line basis over the estimated useful lives of the related assets which range from two to seven years for service equipment. Leasehold improvements will be depreciated over the lesser of the estimated useful life of the improvement or the remaining lease term. Management is responsible for reviewing the carrying value of property and equipment for impairment whenever events and circumstances indicate that the carrying value of an asset may not be recoverable from estimated future cash flows expected to result from its use and eventual disposition. In cases where undiscounted expected future cash flows are less than the carrying value, an impairment loss is recognized equal to the amount by which the carrying value exceeds the fair value of assets. When making this assessment, the following factors are considered: current operating results, trends and prospects, as well as the effects of obsolescence, demand, competition and other economic factors.

Revenue Recognition. Revenues are recognized as services are completed and collectability is reasonably assured. With respect to our hydraulic fracturing services, we recognize revenue and invoice our customers upon the completion of each fracturing stage. We typically complete multiple fracturing stages per day during the course of a job.

Unit-Based Payments. We account for unit-based awards issued to employees and non-employees in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 718, Stock Compensation. Accordingly, employee unit-based compensation is measured at the grant date, based on the fair value of the award, and is recognized as an expense over the requisite service period, or upon the occurrence of certain vesting events. Certain unit-based awards only vest if there is a liquidation or exit event which results in a distribution to the holders of all of the Company’s equity units, where the value of the equity of the Company falls within certain predetermined levels, and subject to the holder remaining continuously actively employed with the Company through the date of the qualifying event. The Company does not recognize any compensation expense on these awards until the qualifying event is deemed probable. The Company does not deem the qualifying event probable until it occurs. Additionally, unit-based awards to nonemployees are expensed over the period in which the related services are rendered. The grant-date fair value of awards is estimated using the Black-Scholes option-pricing model, which requires the use of highly subjective assumptions such as the estimated market value of our units, expected term of the award, expected volatility and the risk-free interest rate. Since the Company’s Series D Units are not publicly traded and have not been traded privately, the value of the Series D Units is estimated based on significant unobservable inputs, primarily consisting of the estimated value of the start-up activities completed as of the grant date, as well as other inputs that are estimated based on similar entities with publicly traded securities. We also need to apply significant judgment to estimate the forfeiture rate, which affects the amount of aggregate compensation that we are required to record as an expense. We estimate our forfeiture rate based on an analysis of our actual forfeitures, to the extent available, and will continue to evaluate the appropriateness of, and possible adjustments to, the forfeiture rate based on actual forfeiture experience, analysis of employee turnover and other factors. We have had limited employee turnover to date, therefore quarterly changes in the estimated forfeiture rate will likely have a significant effect on reported unit-based compensation expense, as the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed. If a revised forfeiture rate is higher or lower than the previously estimated forfeiture rate, an adjustment is made that will result in a decrease or increase to the unit-based compensation expense recognized in the financial statements. We continue to use judgment in evaluating the expected term, volatility and forfeiture rate related to our unit-based

compensation on a prospective basis and incorporate these factors into our option-pricing model. Each of these inputs is subjective and generally requires significant management judgment. If, in the future, we determine that another method for calculating the fair value of our unit-based awards is more reasonable, or if another method for calculating these input assumptions is prescribed by authoritative guidance, and, therefore, should be used to estimate expected volatility or expected term, the fair value calculated for our employee unit-based awards could change significantly. Higher volatility and longer expected terms generally result in an increase to unit-based compensation expense determined at the date of grant.

Income Taxes. The Company is a limited liability company and is treated as a partnership for federal and certain state income tax purposes. No provision or benefit for federal or certain state income taxes is included in the financial statements of the Company because the results of operations are allocated to the members for inclusion in their income tax returns. In certain state jurisdictions the Company may be subject to income-based taxes. In such instances, the Company accounts for them using the asset and liability method. 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 basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted 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 on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The financial statements have been prepared in accordance with U.S. GAAP which may differ from the accounting practices that will be used in the members’ tax returns.

Recently Issued Accounting Pronouncements. We do not expect the adoption of recently issued accounting pronouncements to have a material impact on our consolidated results of operations, balance sheet or cash flows.

New Accounting Pronouncements. As an “emerging growth company” under the JOBS Act, we have elected to delay adoption of new or revised accounting pronouncements applicable to public companies until such pronouncements are made applicable to private companies. Therefore, our financial statements may not be comparable to those of companies that comply with standards that are otherwise applicable to public companies.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to a variety of market risks including credit risk, interest rate risk and commodity price risk. The principal market risk to which we are exposed is the risk related to increases in the prices of fuel and raw materials consumed in performing our services. We do not engage in commodity price hedging activities. To a lesser extent, we are also exposed to risks related to interest rate fluctuations.

Credit Risk. We monitor our exposure to counterparties on service contracts and the collectability of our accounts receivable, primarily by reviewing our counterparties' credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty's creditworthiness. Antero is our primary customer to date. Our current customers are, and our future customers will be, engaged in the oil and natural gas industry. This concentration of customers may impact our overall exposure to credit risk, either positively or negatively, in that our current customers and any future customers may be similarly affected by changes in economic and industry conditions.

Interest Rate Risk. Our exposure to changes in interest rates relates primarily to our long-term debt obligations. We may be exposed to changes in interest rates as a result of any future indebtedness. We do not believe our interest rate exposure warrants entry into interest rate hedges and have, therefore, not hedged our interest rate exposure. The notes issued as part of the Unit Offering, like all fixed rate securities, will be subject to interest rate risk and will likely fall in value if market interest rates increase.

Commodity Price Risk. Our fuel and material purchases expose us to commodity price risk. Our material costs primarily include the cost of inventory consumed while performing our stimulation services such as fracturing sand, fracturing chemicals and fluid supplies. Our fuel costs consist primarily of diesel fuel used by our various tractors and other motorized equipment. The prices for fuel and the materials in our inventory are volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

U.S. WELL SERVICES, LLC

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



	Page
Report of Independent Registered Public Accounting Firm	35
Consolidated Balance Sheets	36
Consolidated Statements of Operations	37
Consolidated Statements of Cash Flows	38
Consolidated Statements of Stockholders'/Members' Equity	40
Notes to Consolidated Financial Statements	41

Report of Independent Registered Public Accounting Firm

The Board of Managers

U.S. Well Services, LLC

We have audited the accompanying consolidated balance sheet of U.S. Well Services, LLC (Successor) as of December 31, 2012 and the related consolidated statements of operations, members' equity, and cash flows for the period from February 21, 2012 (inception) to December 31, 2012, and balance sheet of U.S. Well Services, Inc. (Predecessor) as of December 31, 2011 and the related statements of operations, stockholders' deficit, and cash flows for the periods from August 18, 2011 (inception) to December 31, 2011 and January 1, 2012 to February 20, 2012. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of U.S. Well Services, LLC (Successor) as of December 31, 2012, and the results of its operations and its cash flows for the period from February 21, 2012 (inception) to December 31, 2012, and the financial position of U.S. Well Services, Inc. (Predecessor) as of December 31, 2011, and the results of its operations and its cash flows for the periods from August 18, 2011 (inception) to December 31, 2011 and January 1, 2012 to February 20, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

March 19, 2013

U.S. WELL SERVICES, LLC

CONSOLIDATED BALANCE SHEETS



	Successor			Predecessor
	December 31, 2012			December 31, 2011

ASSETS
Current assets:
Cash and cash equivalents	$	11,811,715		$	—
Restricted cash	166,205			—
Accounts receivable	8,010,321			—
Inventory	3,355,213			—
Prepaids and other current assets	1,154,672			—
Total current assets	24,498,126			—
Property and equipment, net of accumulated depreciation of $6,310,943 at December 31, 2012	61,780,627			—
Deferred financing costs	4,723,049			—
TOTAL ASSETS	$	91,001,802		$	—

LIABILITIES & STOCKHOLDERS'/MEMBERS' EQUITY
Current liabilities:
Accounts payable	$	3,290,358		$	—
Payable to a related party	—			29,700
Accrued state and local taxes	500,000			—
Accrued liabilities	1,359,152			181,510
Accrued interest	3,657,984			—
Short-term note payable	—			—
Current portion of long-term debt	415,070			—
Total current liabilities	9,222,564			211,210
Long-Term Debt	65,484,582			—
Redeemable Series A Units, 600,000 units authorized, issued and outstanding	29,994,000			—
Accrued interest, non-current	3,461,260			—
TOTAL LIABILITIES	108,162,406			211,210
Commitments and Contingencies
STOCKHOLDERS'/MEMBERS' EQUITY:
Common stock: par value $0.001 per share; 10,000 shares authorized, 9,598 shares issued and outstanding	—			10
Additional paid-in capital	—			176,524
Members' interest	768,324			—
Accumulated deficit	(17,928,928		)	(387,744		)
Total Stockholders'/Members' Equity	(17,160,604		)	(211,210		)
TOTAL LIABILITIES & STOCKHOLDERS'/MEMBERS' EQUITY	$	91,001,802		$	—

See accompanying notes to consolidated financial statements.

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS



	Successor			Predecessor
	February 21, 2012			January 1, 2012			August 18, 2011
	(inception) to			to			(inception) to
	December 31, 2012			February 20, 2012			December 31, 2011
Revenue	$	52,134,830		$	—		$	—
Costs and expenses:
Cost of services	43,008,477			—			—
Depreciation and amortization	6,310,943			—			—
Selling, general and administrative expenses	3,783,989			432,773			283,729
Other operating expenses	—			40,587			104,015
Loss from operations	(968,579		)	(473,360		)	(387,744		)
Interest expense, net	(16,960,349		)	—			—
Loss before income taxes	(17,928,928		)	(473,360		)	(387,744		)
Income tax expense	—			—			—
Net loss	$	(17,928,928	)	$	(473,360	)	$	(387,744	)

See accompanying notes to consolidated financial statements.

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Successor			Predecessor			Predecessor
	February 21, 2012			January 1, 2012			August 18, 2011
	(inception) to			to			(inception) to
	December 31, 2012			February 20, 2012			December 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(17,928,928	)	$	(473,360	)	$	(387,744	)
Adjustments to reconcile net loss to cash used in operating activities:
Depreciation and amortization	6,310,943			—			—
Loss on extinguishment of debt	2,638,570			—			—
Bond discount amortization	246,740			—			—
Deferred financing costs amortization	1,156,103			—			—
Unit-based/share-based compensation expense	280,901			—			176,530
Changes in assets and liabilities:
Accounts receivable	(8,010,321		)	—			—
Inventory	(3,355,213		)	—			—
Prepaids and other current assets	(1,154,672		)	—			—
Accounts payable	2,605,788			—			—
Due to related party	—			—			29,704
Accrued state and local taxes	500,000			—			—
Accrued liabilities	1,274,651			473,360			181,510
Accrued interest	11,599,951			—			—
Net cash used in operating activities	(3,835,487		)	—			—

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment	(66,055,460		)	—			—
Net cash used in investing activities	(66,055,460		)	—			—

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of note payable	2,023,019			—			—
Repayments on note payable	(2,023,019		)	—			—
Proceeds from issuance of long-term debt	80,287,200			—			—
Repayments of long-term debt	(23,744,149		)	—			—
Proceeds from issuance of Series A Units	29,994,000			—			—
Proceeds from issuance of Series B and Series C Units	6,493			—			—
Deferred financing costs	(3,824,677		)	—			—
Consent fee paid to bondholders	(850,000		)	—			—
Restricted cash	(166,205		)	—			—
Net cash provided by financing activities	81,702,662			—			—

Net increase in cash and cash equivalents	11,811,715			—			—
Cash and cash equivalents, beginning of period	—			—			—
Cash and cash equivalents, end of period	$	11,811,715		$	—		$	—

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)



	Successor		Predecessor		Predecessor
	February 21, 2012		January 1, 2012		August 18, 2011
	(inception) to		to		(inception) to
	December 31, 2012		February 20, 2012		December 31, 2011
Supplemental cash flow disclosure:
Interest paid	$	1,613,736	$	—	$	—
Non-cash investing and financing activities:
Bond units issued as payment of interest	$	4,480,706	$	—	$	—
Bond units exchanged for debt placement services	$	3,964,800	$	—	$	—
Value of convertible bond warrants issued	$	1,165,500	$	—	$	—
Discount on notes payable	$	1,913,500	$	—	$	—
Long-term debt for purchases of equipment	$	1,951,610	$	—	$	—
Short-term liabilities assumed from USWS, Inc	$	684,570	$	—	$	—
Accrued and unpaid capital expenditures	$	84,500	$	—	$	—

See accompanying notes to consolidated financial statements.

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS'/MEMBERS' EQUITY




Predecessor:				Additional Paid-In Capital			Deficit Accumulated during Development Stage			Total Stockholders' Equity

	Common Stock
	Units	Amount
BALANCE, August 18, 2011 (inception)	3,950	$	4	$	—		$	—		$	4
Share-based payments	5,648	6		176,524			—			176,530
Deficit accumulated during development stage	—	—		—			(387,744		)	(387,744		)
BALANCE, December 31, 2011	9,598	$	10	$	176,524		$	(387,744	)	$	(211,210	)
Deficit accumulated during development stage	—	—		—			(473,360		)	(473,360		)
BALANCE, February 20, 2012	9,598	$	10	$	176,524		$	(861,104	)	$	(684,570	)


Successor:
	Members' Interest						Accumulated Deficit			Total Members' Equity
	Series Units			Members' Interest
	Units	Amount		Members' Interest
BALANCE, February 21, 2012 (inception)	—	$	—	$	—		$	—		$	—
Issuance of Series B Units	630,000	6,300		—			—			6,300
Issuance of Series C Units	192,500	193		—			—			193
Unit-based compensation	27,500	—		280,901			—			280,901
Non-cash distribution to member	—	—		(684,570		)	—			(684,570		)
Issuance of convertible bond warrants	—	—		1,165,500			—			1,165,500
Net loss	—	—		—			(17,928,928		)	(17,928,928		)
BALANCE, December 31, 2012	850,000	$	6,493	$	761,831		$	(17,928,928	)	$	(17,160,604	)

See accompanying notes to consolidated financial statements.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

NOTE 1 - DESCRIPTION OF BUSINESS

On February 21, 2012, U.S. Well Services, LLC (the “Company,” “we,” “our” or “USWS”) was formed as a Delaware limited liability company. The Company is a Houston, Texas based oilfield service provider of well stimulation services to the upstream oil and natural gas industry. We engage in high-pressure hydraulic fracturing in unconventional oil and natural gas basins. The fracturing process consists of pumping a specially formulated fluid into perforated well casing, tubing or open holes under high pressure, causing the underground formation to crack or fracture, allowing nearby hydrocarbons to flow more freely up the wellbore.

The predecessor to the Company was U.S. Well Services, Inc. (“USWS, Inc.”) which was incorporated in Delaware on August 18, 2011. The Company was capitalized via a contribution by USWS, Inc. of substantially all of the assets and contracts of USWS, Inc. in exchange for 167,500 of the Company’s Series C Units (the “Restructuring”). Contemporaneously with the formation of the Company, ORB Investments, LLC, a Louisiana limited liability company (“ORB”), made a $30 million equity investment in the Company (the “Sponsor Equity Investment”), in exchange for 600,000 of the Company’s Series A Units and 600,000 of the Company’s Series B Units. In addition, concurrently with the formation of the Company, USW Financing Corp. was formed as a wholly-owned finance subsidiary of the Company for the purpose of acting as a co-obligor for an offering of 85,000 units with each unit consisting of $1,000 principal amount of 14.50% Senior Secured Notes due 2017 and a warrant to purchase the Company’s Series B Units (the “Unit Offering”).

The predecessor company was a development stage enterprise and had primarily been involved in start-up activities, including acquiring property and equipment and securing customer contracts.

The Company began operations under a take or pay contract with Antero Resources Appalachian Corporation (“Antero”), for a 24 month service period commencing on April 12, 2012 to perform hydraulic fracturing services in the Marcellus and Utica Shales in Ohio, West Virginia, New York and Pennsylvania. Prior to beginning operations in the second quarter of 2012, the Company was in the development stage.

NOTE 2 - BASIS OF PRESENTATION

The consolidated financial statements included in this Annual Report on Form 10-K present our financial position, results of operations and cash flows, for the periods presented in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”).

Risks and uncertainties

We commenced operations in April 2012 and for the period ended December 31, 2012 we have not generated positive cash flow from operations. Our ability to meet our liquidity needs is dependent on cash generated from operating activities and cash on hand. We do not have other committed sources of financing at this time.

Major Customer and Concentration of Credit Risk

The concentration of our customers in the oil and natural gas industry may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. We perform ongoing credit evaluations of our customers and do not generally require collateral in support of our trade receivables.

During the period from February 21, 2012 (inception) to December 31, 2012, Antero accounted for approximately 90.2% of our consolidated revenues. No other customer accounted for more than 10% of our consolidated revenues for the period from February 21, 2012 (inception) to December 31, 2012.

Receivables outstanding from Antero were approximately 43.6% of our total accounts receivable as of December 31, 2012. One other customer accounted for 56.3% of our total accounts receivable as of December 31, 2012.

NOTE 3 – SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

These consolidated financial statements include the accounts of the Company and its subsidiary, USW Financing Corp. All significant intercompany transactions and accounts have been eliminated upon consolidation.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. We

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

regularly evaluate estimates and judgments based on historical experience and other relevant facts and circumstances. Significant estimates included in these financial statements primarily relate to estimated useful lives of property and equipment and the valuation of unit-based compensation. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with an original maturity at the date of acquisition of three months or less. Cash and cash equivalents consist of cash on deposit with domestic banks and, at times, may exceed federally insured limits.

Restricted Cash

We classify as restricted cash, highly liquid investments that otherwise would qualify as cash equivalents, but are restricted in usage and are, therefore, unavailable to us for general purposes.

Inventory

Inventory consists of proppant, chemicals, and other consumable materials and supplies used in our pressure pumping and related services, including our high-pressure hydraulic fracturing operations. Inventories are stated at the lower of cost (weighted-average cost method) or market. All inventories are purchased and used by the Company in the delivery of its services with no inventory being sold separately to outside parties.

Property and Equipment

Property and equipment are carried at cost, with depreciation provided on a straight line basis over their estimated useful lives. Expenditures for renewals and betterments that extend the lives of the assets are capitalized. Amounts spent for maintenance and repairs, which do not improve or extend the life of the related asset, are charged to expense as incurred. An allocable amount of interest on borrowings is capitalized for assets and equipment during their construction period.

Impairment of Long-Lived Assets

Long-lived assets, such as property and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable from estimated future cash flows expected to result from its use and eventual disposition. In cases where undiscounted expected future cash flows are less than the carrying value, an impairment is recognized equal to the amount by which the carrying value exceeds the fair value of assets. When making this assessment, the following factors are considered: current operating results, trends and prospects, as well as the effects of obsolescence, demand, competition and other economic factors.

Fair Value of Financial Instruments

Fair value is defined under Accounting Standards Codification (ASC) 820, Fair Value Measurement, as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 also establishes a three-level hierarchy, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels are defined as follows:

Level 1–inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2–inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

Level 3–inputs are unobservable for the asset or liability.

The following is a summary of the carrying amounts and estimated fair values of our financial instruments as of December 31, 2012:

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities. These carrying amounts approximate fair value because of the short maturity of the instruments or because the carrying value is equal to the fair value of those instruments on the balance sheet date.

14.5% Senior Secured Notes due 2017. The fair value of the notes is estimated using level 2 inputs by obtaining from the broker the quoted price as of December 31, 2012. The carrying value of these notes as of December 31, 2012 was $68.4 million, and the fair value was $62.9 million (92% of carrying value).

Deferred Financing Costs

Costs incurred to obtain financing are capitalized and amortized to interest expense using the effective interest method over the contractual term of the debt.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

Revenue Recognition

Revenues are recognized as services are completed and collectability is reasonably assured. With respect to our hydraulic fracturing services, we recognize revenue and invoice our customers upon the completion of each fracturing stage. We typically complete multiple fracturing stages per day during the course of a job.

Accounts Receivable

Accounts receivable are recorded at their outstanding balances adjusted for an allowance for doubtful accounts. The allowance for doubtful accounts is determined by analyzing the payment history and credit worthiness of each debtor. Receivable balances are charged off when they are considered uncollectible by management. Recoveries of receivables previously charged off are recorded as income when received. No allowance for doubtful accounts was considered necessary at December 31, 2012.

Unit-Based Compensation

The Company accounts for unit-based awards issued to employees and nonemployees in accordance with the guidance on share-based payments. Accordingly, employee unit-based compensation is measured at the grant date, based on the fair value of the award, and is recognized as an expense over the requisite service period, or upon the occurrence of certain vesting events. Certain unit-based awards only vest if there is a liquidation or exit event which results in a distribution to all of the Company’s equity units, where the value of the equity of the Company falls within certain predetermined levels, and subject to the holder remaining continuously actively employed with the Company through the date of the qualifying event. The Company does not recognize any compensation expense on these awards until the qualifying event is deemed probable. The Company does not deem the qualifying event probable until it occurs. Additionally, unit-based awards to nonemployees are expensed over the period in which the related services are rendered. The grant-date fair value of awards is estimated using the Black-Scholes option-pricing model. Since the Company’s Series D Units are not publicly traded and have not been traded privately, the value of the Series D Units is estimated based on significant unobservable inputs, primarily consisting of the estimated value of the start-up activities completed as of the grant date, as well as other inputs that are estimated based on similar entities with publicly traded securities.

Income Taxes

The Company is a limited liability company and is treated as a partnership for federal and certain state income tax purposes. No provision or benefit for federal or certain state income taxes is included in the financial statements of the Company because the results of operations are allocated to the members for inclusion in their income tax returns. In certain state jurisdictions the Company may be subject to income-based taxes. In such instances, the Company accounts for state income taxes using the asset and liability method. 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 basis and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted 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 on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. The financial statements have been prepared in accordance with U.S. GAAP which may differ from the accounting practices that will be used in the members’ tax returns.

Our predecessor company as a corporate entity was subject to taxation under the provisions of the Internal Revenue Code. Our predecessor used the liability method of accounting for income taxes, whereby deferred tax assets and liabilities are determined based on the expected future tax consequences of temporary differences between the carrying amounts of assets and liabilities for financial and income tax reporting purposes. During the period from August 18, 2011 to December 31, 2011, our predecessor incurred net losses and therefore, had no tax liability. As of December 31, 2011, our predecessor had deferred tax asset of $135,710 relating to amortizable start-up costs. Our predecessor provided a full valuation allowance for the deferred tax asset as of December 31, 2011 because it was not able to conclude that it is more likely than not that it will be able to realize the deferred tax asset.

Recently Issued Accounting Pronouncements

We do not expect the adoption of recently issued accounting pronouncements to have a material impact on the Company’s results of operations, balance sheet or cash flows.

NOTE 4 – PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:



	Estimated Useful Lives	December 31, 2012
Fracturing equipment	7 years	$	63,491,282
Light duty vehicles	5 years	1,512,144
Furniture and fixtures	5 years	84,435
IT equipment	3 years	192,061
Auxiliary equipment	2 years	2,404,156
Leasehold improvements	Term of lease	407,492
		68,091,570
Less: accumulated depreciation and amortization		(6,310,943		)
Property and equipment, net		$	61,780,627

Depreciation and amortization expense for the period February 21, 2012 (inception) through December 31, 2012 was $6,310,943. The Company capitalized interest of $248,226 during the period February 21, 2012 (inception) through December 31, 2012.

NOTE 5 – SHORT-TERM NOTE PAYABLE

On March 15, 2012, the Company obtained insurance for its general liability, umbrella, auto and pollution coverage needs. The Company made an initial down payment and entered into a premium finance agreement with a credit finance institution to pay the remainder of the premiums. The aggregate amount of the premiums financed was $2,023,019 at an interest rate of 3.9%. Under the terms of the agreement, the Company was to pay 10 equal monthly payments of $205,936 beginning April 15, 2012 through maturity on January 15, 2013. The note was fully repaid at December 31, 2012.

NOTE 6 – LONG TERM DEBT

Long-term debt consisted of the following:



	December 31, 2012
Senior Secured Notes	$	68,414,660
Equipment financing agreement	1,773,507
Less current maturities of long-term debt	(415,070		)
Unamortized discount on Senior Secured Notes	(1,788,515		)
Treasury bonds	$	(2,500,000	)
Total long-term debt	$	65,484,582

Senior Secured Notes. As part of the Unit Offering, we issued 14.50% Senior Secured Notes totaling $85 million (the “Notes”). The Notes will mature on February 15, 2017. The Notes have a fixed annual interest rate of 14.50% on the principal amount which is due semi-annually, on February 15 and August 15 of each year, commencing on August 15, 2012. The first interest payment on the Notes was paid on August 15, 2012 by increasing the principal amount of the outstanding Notes by $4,480,706, the amount of the first interest payment. Future interest payments on the Notes will made in cash. Accrued interest on the Notes was $3,657,984 at December 31, 2012.

The Notes were issued at a discount such that cash received was equal to approximately 98% of the principal amount of the Notes. Accordingly, we recognized a discount of $1,913,500 that is being amortized over the term of the Notes using the effective interest method. Unamortized debt issuance costs associated with the Notes was $4,723,049 as of December 31, 2012, which is being amortized to interest expense over the term of the Notes.

Our sole subsidiary, USW Financing Corp., is a co-issuer of the Notes. The Notes may be fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by each of our current and future domestic subsidiaries, other than subsidiaries designated as unrestricted subsidiaries. None of our future foreign subsidiaries will guarantee the Notes. The Notes and any future guarantees are subject to a lien on substantially all of our and our future subsidiaries' assets, subject to certain exceptions.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

If and when we incur permitted first lien indebtedness, the liens on the assets securing the Notes and any future guarantees will likely be contractually subordinated and junior to liens securing such permitted first lien indebtedness pursuant to an intercreditor agreement. The indenture governing the Notes restricts us and our restricted subsidiaries from making certain payments, including dividends and intercompany loans or advances.

The Notes are subject to optional redemption features whereby: (a) on or after February 15, 2015, we may redeem some or all of the Notes at a premium that will decrease over time, (b) prior to February 15, 2015, we may, at our option, redeem up to 35% of the aggregate principal amount of the Notes using the net proceeds of certain equity offerings at a price equal to 110% of the principal amount thereof, plus accrued and unpaid interest and additional interest, if any, to the date of redemption; provided that, following any and all such redemptions, at least 65% of the aggregate principal amount of the Notes originally issued under the indenture remain outstanding and the redemption occurs within 90 days of the closing of such equity offering, and (c) at any time prior to February 15, 2015, we may, at our option, redeem all or a part of the Notes, upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the Notes redeemed, plus a specified make-whole premium, plus accrued and unpaid interest and additional interest, if any, to the applicable date of redemption. The Notes are also subject to certain mandatory redemption provisions whereby within 45 days after each March 31 or September 30 beginning on March 31, 2013, for which our cash and cash equivalents are greater than $12.1 million, we are required to offer to repurchase Notes in the amount of such excess cash amount at an offer price in cash equal to 100% of their principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

Pursuant to the terms of the indenture governing the Notes, a total of $37.5 million of the net proceeds from the Unit Offering were placed into an escrow account to either be released to us upon our entrance into a second fracturing contract on terms similar to our original contract with Antero or to be used to repurchase Notes if we were unable to enter into a second fracturing contract on terms similar to our original contract with Antero on or prior to June 30, 2012. We did not enter into a second fracturing contract on terms similar to our original contract with Antero on or prior to June 30, 2012. On July 10, 2012, pursuant to the indenture governing the Notes, we commenced the Second Contract Repurchase Offer as well as a consent solicitation to approve proposed amendments to the indenture, including the release of a portion of the escrowed funds. On July 16, 2012, after obtaining the requisite consents in the consent solicitation, the maximum aggregate purchase price of the Second Contract Repurchase Offer was reduced from $37.5 million to $22.5 million and all other funds in the escrow account (approximately $15 million) were released to us. In conjunction with the Second Contract Repurchase Offer, $22.5 million was paid on August 10, 2012, of which $21,066,046 relates to the principal repayment and$1,433,954 relates to accrued interest of the repurchased Notes. We recorded a $2,367,559 loss attributed to the write-off of discount on the Notes and debt issuance costs in connection with the repurchased Notes. The loss is recorded in the line item “Interest expense, net” in the consolidated statement of operations.

On November 14, 2012, we paid $2.6 million to a Note holder to repurchase $2.5 million of our Notes at 100% of face value, including $0.1 million in accrued interest. We recorded a $0.3 million charge to Interest Expense relating to the write-off of the pro rata portion of the discount on the Notes and debt issuance costs. The repurchased Notes were not cancelled and are currently held in reserve with the option to resell as a source of capital funding.

Registration Rights Agreement. In connection with the closing of the offering of the Notes, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, for the benefit of the holders of the Notes, at our cost, to do the following:

Upon the SEC's declaring the exchange offer registration statement effective, we agreed to offer new notes in exchange for surrender of the Notes. We agreed to use commercially reasonable efforts to cause the exchange offer registration statement to become and remain effective continuously for a period ending on the earlier of (i) 180 days from the date on which the exchange offer registration statement is declared effective or (ii) the date on which a Broker-Dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities, and to keep the exchange offer open for a period of not less than the minimum period required under applicable federal and state security laws to consummate the exchange offer, provided the period be of not less than 30 days.

The registration rights agreement provides that if (i) the exchange offer registration statement is not filed with the SEC on or prior to the Filing Date (August 19, 2012), (ii) the exchange offer registration statement has not been declared effective by the SEC on or prior to November 16, 2012 (the "Effectiveness Date"), (iii) the exchange offer has not been consummated within 30 business days after the Effectiveness Date (the "Exchange Date"), (iv) any shelf registration statement, if required pursuant to the registration rights agreement, has not been declared effective by the SEC on or prior to the Shelf Effectiveness Deadline (as defined in the registration rights agreement), or (v) any registration statement required by the registration rights agreement has been declared effective but ceases to be effective at any time at which it is required to be effective under the registration rights agreement (each such event referred to in clauses (i) through (v), is a Registration Default), the interest rate on the Notes shall

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

be increased by 0.25% per annum during the 90-day period immediately following the occurrence of any Registration Default and shall increase by 0.25% per annum at the end of each subsequent 90-day period, but in no event shall such increase exceed 1.00% per annum in the aggregate. On the date all Registration Defaults are cured, the interest rate will be reduced to the original interest rate; provided, however, that, if after any such reduction in interest rate, a different Registration Default occurs, the interest rate shall again be increased pursuant to the foregoing provisions. If the interest rate on the outstanding Notes was increased by 1.00% per annum for an entire year, our annual interest expense would increase by approximately $684,000 until the Registration Default is cured. There is no current obligation recorded with respect to the registration rights agreement due to the fact that a default under the agreement is not considered to be probable.

Except as set forth above, after consummation of the exchange offer, holders of the Notes that are the subject of the exchange offer will have no registration or exchange rights under the registration rights agreement.

In October 2012, we filed with the SEC a registration statement on Form S-4 to exchange the old Notes for registered notes having substantially identical terms. We amended the Form S-4 in November 13, 2012 and it was declared effective by the SEC on the same day. The exchange offer was commenced on or about November 13, 2012 and expired on December 14, 2012 with all of the outstanding Notes being tendered.

Equipment financing agreement. On July 30, 2012, the Company entered into a security agreement with a financing institution for the purchase of certain fracturing equipment. The aggregate principal amount of the financing agreement is $1,951,610 and bears effective interest at 6.5%. Under the terms of the agreement, the Company is required to pay 48 equal monthly payments of $46,386, including interest, beginning September 13, 2012 through maturity on September 13, 2016. As of December 31, 2012, the financing agreement had a balance of $1,773,507, of which $415,070 is due within one year.

Presented below is a schedule of the repayment requirements of long-term debt for each of the next five years and thereafter as of December 31, 2012:



	Principal Amount
	of Long-term Debt
2013	$	415,070
2014	481,883
2015	514,451
2016	362,103
2017	68,414,660
	70,188,167
Treasury bonds	(2,500,000		)
Unamortized discount on Senior Secured Notes	(1,788,515		)
Less current maturities of long-term debt	(415,070		)
Total long-term debt	$	65,484,582

NOTE 7 - REDEEMABLE SERIES A UNITS

As part of the Sponsor Equity Investment, the Company authorized and issued 600,000 of its Series A Units. The holders of the Series A Units are not entitled to receive any ordinary distributions from the Company, are subject to certain drag-along rights, and do not have any preemptive rights relating to the Company. Pursuant to the terms of our Amended and Restated Limited Liability Company Agreement, ORB has the right to appoint all of the members of the Company's Board of Managers, except for one position on the Board of Managers that is required to be filled by the Company's Chief Executive Officer. The Board of Managers is to have the discretion to manage and conduct all the business and affairs of the Company.

The holders of Series A Units, in certain instances, are entitled to have their Series A Units redeemed by the Company for a distribution in an amount that provides each Series A Unit holder with an internal rate of return of 13% on their investment with respect to their Series A Units. The payment of the redemption price to Series A Unit holders shall be paid, upon the occurrence of one of the following triggering events: (i) a liquidation of the Company (whether by consent of the Company’s Board of Managers and ORB, or withdrawal of all members or in accordance with Section 18-202 of the Delaware Limited Liability Company Act), (ii) a transfer of all of the assets or units of the Company, a merger or similar transaction or certain initial public offerings of the Company’s or its successor’s securities, or (iii) February 17, 2017. The payment of the redemption price to the Series A Unit holders shall occur before any distribution is made to the holders of the Series B, C or D Units.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

The Series A Units have an optional redemption feature whereas subject to the prior approval of ORB, the Company retains the option to redeem all or any portion of the Series A Units at any time in exchange for payment of an amount that provides each Series A Unit holder with an internal rate of return of 13% on their capital contribution with respect to their Series A Units.

Because of the mandatory redemption features of the Series A Units, which unconditionally obligates the Company to provide each holder with an internal rate of return of 13% on their investment, regardless of the triggering events, the units demonstrate characteristics of debt and therefore are accounted for as a long-term liability.

At December 31, 2012, the mandatorily redeemable Series A Units totaling $29,994,000 are reported as a long-term liability on the balance sheet with accrued interest in the amount of $3,461,260. The maximum amount the Company could be required to pay to redeem the units on the mandatory redemption date of February 17, 2017 includes the face value of the units in the amount of $29,994,000 and interest to be accrued of $26,213,401.

NOTE 8 – MEMBERS’ INTEREST

The Company’s equity consists of four classes of membership interests, each designated with its own series of units. Series A Units are the Company’s preferred equity and Series B, C and D units represent the Company’s common equity. See Note 7 - Redeemable Series A Units for further discussion of Series A Units. The Series B, C and D Units are equal in most respects, except that the Series B Units have anti-dilution protections and pre-emptive rights that the Series C and D Units do not have. Additionally, the Series B Units have more limited transfer restrictions than the Series C and D Units have. The Series D Units constitute profits interests.

Series B Units

As part of the Sponsor Equity Investment, the Company authorized and issued 600,000 of its Series B Units. The Company also authorized and issued 30,000 Series B Units in exchange for a $300 payment by a previous officer of the Company as part of his compensation for the duties performed.

In conjunction with the Unit Offering, the Note holders received 85,000 warrants that entitle each holder to receive 1.7647 Series B Units at an exercise price of $0.01 per unit, representing approximately 150,000 Series B Units in aggregate or 15% of the Company’s common equity interests. The Company recorded an aggregate fair value of the warrants amounting to $1,165,500 as Members' Interest. The fair value of the warrants was determined using the Black-Scholes option pricing model, assuming an expected life of 5 years, risk-free rate of 0.92%, a volatility factor of 51.6% and dividend yield of 0%. The warrants became exercisable after they separated from the Notes on April 21, 2012 and will expire on February 21, 2019. The Company has granted the holders of the warrants certain “piggyback” registration rights for the resale of the Series B Units underlying the warrants. In addition, the holders of the Series B Units have preemptive and other equity protection rights identical to those granted to ORB in the Sponsor Equity Investment. Upon exercise of the warrants, the holders are required to become a party to the Company’s Amended and Restated Limited Liability Agreement dated February 21, 2012.

The holders of the Series B Units are entitled to receive distributions from the Company, in accordance with each such holder’s relative percentage of the total number of Series B, Series C and Series D Units outstanding. The Series B Units are subject to certain transfer restrictions, drag-along rights and have certain preemptive rights relating to the Company.

Series C Units

As part of the Restructuring, the Company issued 167,500 of its Series C Units to USWS, Inc., in exchange for contribution of substantially all of the assets and contracts and certain liabilities of USWS, Inc. Further, the Company issued 25,000 Series C Units to Global Hunter Securities, LLC, in exchange for placement fees incurred in connection with the Unit Offering.

Series D Units

During 2012, the Company entered into various Series D Unit Agreements pursuant to which 293,323 Series D Units were granted to officers of the Company as performance incentives. The Series D Units are subject to vesting and forfeiture under circumstances set forth in the agreements between the Company and each such officer. See Note 9 - Unit-Based Compensation for further discussion of the Series D Units granted to officers of the Company.

NOTE 9 – UNIT‑BASED/SHARE-BASED COMPENSATION

Unit-based Awards granted in 2012

On February 21, 2012, the Company entered into several Series D Unit Agreements pursuant to which 206,538 Series D Units were granted to certain of the Company’s officers as performance incentives. At the time of the awards, 27,500of the granted Series D Units were fully vested with 179,038 units remaining unvested until the occurrence of certain vesting events. On

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

August 6, 2012, due to the resignation of one of the Company's officers, 30,052of the unvested units were forfeited, and only 148,986 units remains unvested. The vesting events will occur when the awarded officer remains continuously employed with the Company, there is a liquidation or exit event which results in a distribution to all of the Company’s equity units, and when the value of the equity of the Company falls within certain predetermined levels. As of December 31, 2012, no such vesting event had occurred.

In March 2012, the Company entered into several Series D Unit Agreements, granting 26,166 unvested units to certain of the Company's officers. The units will vest when the awarded officer remains continuously employed with the Company, there is a liquidation or exit event which results in a distribution to all of the Company’s equity units, and when the value of the equity of the Company falls within certain predetermined levels. As of December 31, 2012, no such vesting event had occurred.

In June and September 2012, the Company entered into agreements with certain of the Company's officers pursuant to which 60,619 Series D Units were granted as performance incentives. The awards vest over a three years service period, beginning on the grant date.

For units that vest immediately upon issuance, we record expense equal to the fair market value of the units on the date of grant. The total fair value of units vested upon issuance during the year was $213,675. For units that do not immediately vest, we recognize compensation expense ratably over the requisite service period of the award, or if applicable, upon the occurrence of certain vesting events as stated in the agreement. During the period February 21, 2012 (inception) through December 31, 2012, we recognized unit-based compensation expense totaling $280,901, of which $77,700 was included in cost of services and $203,201 was included in selling, general and administrative expenses.

For the unvested awards as of December 31, 2012, we anticipate that we will recognize $403,783 of unit-based compensation over the next 1.57 years.

The following table summarizes the information for the period from February 21, 2012 (inception) to December 31, 2012 about the unit-based awards:



			Weighted-average			Weighted-average
	Unvested		grant-date fair value		Vested	grant-date fair value
Units at beginning of period	—		$	—	—	$	—
Granted	293,323		7.77		—	—
Vested	(27,500	)	7.77		27,500	7.77
Forfeited	(30,052	)	7.77		—	—
Units at end of period	235,771		$	7.77	27,500	$	7.77

Valuation assumptions for unit-based awards

The Company estimates the fair value at the grant date of the unit-based awards using the Black-Scholes valuation model. Key input assumptions applied under the Black-Scholes option pricing model are noted below:



		February 21, 2012
		(inception) to
		December 31, 2012
Expected life (in years)		5
Risk-free interest rate		0.92%
Expected volatility		51.6%
Expected dividend yield		—%

The expected life of units represents the period of time that the unit-based awards are expected to be outstanding based on the redemption period of the Company's Series A units. The risk-free interest rate is based on the U.S. Treasury constant maturity interest rate with a term consistent with the expected life of the awards. Expected volatility is based on an analysis of the annual historical volatility of a set of guideline companies.

Share-based payments in 2011

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

On September 30, 2011, our predecessor company granted a total of 5,648 unrestricted, fully vested shares to its officers, a director, and a vendor. The grant-date fair value of each award was estimated on the date of grant using an enterprise valuation model. Under this approach, the value of the shares was estimated based on significant unobservable inputs, primarily consisting of the estimated value of the start-up activities completed as of the grant date, as well as other inputs that were estimated based on similar entities with publicly traded shares. The fair market value of the unrestricted shares was determined to be $31.26 per share. During the period from August 18, 2011 (inception) to December 31, 2011, stock compensation of $109,735 was recognized and included in selling, general and administrative expenses, and $66,795was recognized and included in other operating expenses in the statement of operations.

NOTE 10 – RELATED PARTY TRANSACTIONS

In connection with the Unit Offering, a placement fee of $1,000,000 was paid to the Layton Corporation with the proceeds of the Unit Offering. The Layton Corporation is controlled by a shareholder of USWS, Inc. The placement fee is recorded in the balance sheet as part of the Deferred Financing Costs as of December 31, 2012. Also in connection with the Restructuring, the Company assumed $684,570 in short-term liabilities from USWS, Inc. recorded in members’ equity as a non-cash distribution to a member.

The predecessor company's organizational activities were funded by advances from Layton Corporation. The amount payable to this related party amounted to $29,700 as of December 31, 2011.

NOTE 11 – COMMITMENTS AND CONTINGENCIES

Litigation

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

In August 2012, the Company, together with certain of its officers, became co-defendants in an action filed by Calfrac Well Services, Ltd. and Calfrac Well Services Corp. (collectively, "Calfrac") alleging conspiracy to steal Calfrac's trade secrets, proprietary business and confidential information, customers and employees and other information for the purpose of setting up the Company's predecessor. Further, Calfrac seeks actual and compensatory damages in connection with allegations of breach of contract and certain duties by certain of the Company's officers. The Company denies the allegations and intends to vigorously defend this action. Given the stage of this matter the Company cannot assess the probability of losses, or reasonably estimate a range of any potential losses, related to the ongoing proceedings, although the Company denies that Calfrac is entitled to any damages or other relief.

Sand Purchase Agreement

On November 9, 2012, we entered into an agreement with a supplier to purchase sand for use in our hydraulic fracturing operations. The agreement is effective on November 1, 2012 for a term of two years, subject to renewal options. Under the terms of this agreement, we are required to purchase from this supplier a quarterly minimum quantity of sand at a fixed price, amounting to approximately $1.1 million per quarter. In the event we fail to purchase any portion of sand required to be purchased on a quarterly basis, we are required to make payments to the supplier for amounts not taken, up to the contractual minimum and subject to the terms of the agreement. For the period from November 1, 2012 to December 31, 2012, the total amount purchased under the agreement was$2.6 million. We do not believe that non-performance on our part would have a material impact on our financial position, cash flows or results of operations.

Lease Agreements

On March 1, 2012, the Company entered into an agreement for the lease of a 70,500 square foot field office operations facility on 10.844 acres in Jane Lew, West Virginia for its initial fleet operations. The total amount of monthly payments over the term of 36 months is $881,395. The lease agreement has annual rent escalations of 2% on each anniversary.

On April 1, 2012, the Company entered into an agreement for the lease of approximately 2,584 square feet of office space in Houston, Texas to serve as its corporate headquarters. The total amount of monthly payments over the term of 36 months is $176,358.

On October 1, 2012, the Company entered into an agreement to lease approximately 1,457 square feet of additional office space immediately adjacent to its leased corporate headquarters, located in the same building in Houston, Texas. The total amount of monthly payments over the term of the 30 months is $84,817.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2012

Rent expense for the period from February 21, 2012 to December 31, 2012 was $301,122, of which $245,101 is recorded as part of Cost of Services and$56,021 is recorded as part of Selling, General and Administrative expenses in the Statement of Operations.

The following is a schedule by years of minimum future rentals on noncancelable operating leases as of December 31, 2012:



2013	$	385,513
2014	391,369
2015	73,117
Total minimum future rentals	$	849,999

Employment and Severance Agreements

To retain qualified senior management, we enter into employment agreements with our executive officers. These employment agreements run for periods ranging from one to three years, but can be automatically extended on a yearly basis with written notice of the extension at least 30 days prior to the expiration of then-current term of the agreement. In addition to providing a base salary, discretionary bonus, and equity grant for each executive officer, the agreement also provides for the Company to make certain payments in the event that employment is terminated by the executive for good reason, or by the Company without cause, or in the event of the executive's disability.

The Company has also entered into severance agreements with certain key employees. The severance agreement provides for payment of severance benefits to the employee upon the occurrence of a change in control of the Company (as defined in the severance agreement) or termination of the employee without cause.

NOTE 12 – SUBSEQUENT EVENT

On February 14, 2013, the Company paid $5.0 million in interest due on its 14.50% Senior Secured Notes due 2017.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this Annual Report on Form 10-K, management performed, with the participation of our Chief Executive Officer and our Chief Financial Officer, an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on this evaluation, management concluded that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the last fiscal quarter of 2012 that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

This annual report does not include a report of management's assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to the transition period established by rules of the SEC for newly public companies and pursuant to the JOBS Act for newly public emerging growth companies.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The following table sets forth the names, ages and offices of the members of our Board of Managers and our executive officers. There are no family relationships among any of the members of our Board of Managers or executive officers.

Executive Officers and Board of Managers



Name	Age	Title
Brian Stewart	57	President, Chief Executive Officer and Member of the Board of Managers
Kenneth I. Sill	52	Chief Financial Officer
Jeffrey McPherson	56	Vice President of Operations
Edward S. Self III	32	Vice President of Business Development
Cornelius Dupre	61	Chairman of the Board of Managers
Matthew Bernard	42	Member of the Board of Managers
Joel Broussard	46	Member of the Board of Managers
Gregg H. Falgout	54	Member of the Board of Managers
Steve Orlando	57	Member of the Board of Managers
Shane J. Guidry	42	Member of the Board of Managers

Set forth below is the description of the backgrounds of the members of our Board of Managers and executive officers.

Brian Stewart has been our President, Chief Executive Officer and a member of our Board of Managers since June 2012. Mr. Stewart retired from Devon Energy Corporation, a publicly traded independent energy company, in 2012 after 35 years of service. Mr. Stewart’s last five years of service, from 2007 to 2012, at Devon Energy Corporation were as the Vice President of Well Engineering for the Offshore Division. In this role he was responsible for Gulf of Mexico and international drilling and completion activities. Mr. Stewart has extensive completions experience, including working on some of the first fracture treatments in the Gulf of Mexico. Mr. Stewart received his BS in Petroleum Engineering from Louisiana State University and a MS in Engineering Management from University of Southwestern Louisiana. Mr. Stewart is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Stewart was also the past chairman of the LSU Petroleum Engineering Industry Advisory Council.

Kenneth I. Sill has been our Chief Financial Officer since September 2012. Mr. Sill previously was a director and industry analyst for Tudor Pickering Holt Asset Management from December 2010 to September 2012, where he focused on the oilfield services industry, as well as coal and alternative energy equity markets. From July 2008 to December 2010, Mr. Sill was the Senior Energy Analyst for CAVU Capital Advisors, a Connecticut based long/short equity fund. Prior to joining CAVU Capital Advisors, Mr. Sill was with Credit Suisse/Credit Suisse First Boston Corporation for 12 years, and served there as the Senior Oilfield Services & Equipment Analyst from 2001 to 2008. Prior to joining Credit Suisse/Credit Suisse First Boston Corporation, Mr. Sill held various consulting, auditing and accounting positions, including two years for Solvay America, four years with Price Waterhouse and four years with Arthur Young & Co. Mr. Sill received his M.B.A., with Honors, from the University of Texas in 1989, and his B.A. in Economics and Managerial Studies, cum laude, from Rice University in 1983, and is a Certified Public Accountant.

Jeffrey McPherson has been our Vice President of Operations since February 2012 and served in the same capacity with our predecessor, U.S. Well Services, Inc., from November 2011 to February 2012. Mr. McPherson has a long and extensive record of fracturing management spanning over 25 years. Mr. McPherson served as interim District Manager - Account manager for Calfrac Well Services in West Virginia from 2009 to November 2011, managing fracturing operations in the Marcellus Shale. From 2005 to 2009, Mr. McPherson served as account manager for Weatherford International in Ft. Worth, Texas and was responsible for fracturing and all product development in the Mid-Continent region. Mr. McPherson started at the Western Company of North America in the late 1970s, and then following BJ Services’ acquisition of the Western Company of North America in 1995, Mr. McPherson managed cement operations in Rocky Mountain Region and later in the Gulf of Mexico for BJ Services.

Edward S. Self III has been our Vice President of Business Development since February 2012 and served in the same capacity with our predecessor, U.S. Well Services, Inc., from November 2011 to February 2012. From 2007 to November 2011, Mr. Self was employed by Calfrac Well Services, where he was a Sales Manager from 2007 to 2009 and managed the Northeast Sales and Marketing division from 2009 to 2011. As manager of the Northeast Sales and Marketing division for Calfrac Well Services, Mr. Self’s responsibilities included obtaining new multiyear hydraulic fracturing contracts with oil and gas operators

and maintaining the existing contracts that were in place. Mr. Self was employed by Halliburton Energy Services in Rock Springs, Wyoming and Farmington, New Mexico from 2003 to 2007. Mr. Self also co-founded ODM Services in 2011, which specialized in supplying oil and gas companies with safety equipment during hydraulic fracturing operations. Mr. Self is a member of the Society of Petroleum Engineers and has a Bachelor of Science Degree in Business from Azusa Pacific University.

Cornelius Dupre has been a member and Chairman of our Board of Managers since March 2012. Mr. Dupré is also the Chairman of Dupré Interests, a private equity family office, serving in that capacity since founding the company in 2004. Additionally, Mr. Dupré is the Chairman of Dupré Energy Services, LLC, which encompasses several oil and gas service companies, including KSW Oilfield Rentals, Dolphin Energy Equipment, Catalyst Construction and CSI Inspection, LLC. Mr. Dupré has served on the Board of Directors of Caza Oil & Gas, Inc. since April 2008, Crystal Fuels Inc. since 2006, Domain Energy Partners since February 2005 and Energy XXI since September 2010. Prior to these activities, Mr. Dupré served as owner and Chairman of Venture Transport & Logistics from June 2004 to 2008, as Senior Vice President, Sales and Marketing of National Oilwell, Inc. from July 1999 to May 2004, and as founder, Chairman and CEO of Dupré Companies, a group of oilfield service companies, from November 1981 until the company's merger with National Oilwell, Inc. in July 1999. Mr. Dupré belongs to a number of industry groups, as well as charitable and community organizations, including: Society of Petroleum Engineers, American Petroleum Institute, IPAA, Petroleum Equipment Suppliers Association, International Association Drilling Contractors, Houston Producers Forum, Baylor College of Medicine Partnership Foundation, Board of Western Energy Alliance, National Ocean Industries Association, Sam Houston Area Boy Scouts of America, and Spindletop Charity Foundation. Mr. Dupré has a Bachelor of Science degree from Louisiana State University, a Master of Business Administration from Northeastern University and a Juris Doctor from Louisiana State University Law Center.

Joel Broussard has been a member of our Board of Managers since February 2012 and served as our interim Chief Executive Officer from March 2012 to June 2012. Mr. Broussard is the founding member of ORB Investments, LLC which he founded in February 2012. Mr. Broussard was most recently a principal investor in Go-Coil, LLC, a provider of coiled tubing services both onshore and offshore in the United States. Additionally, since 2003 Mr. Broussard has been the Chief Executive Officer of Gulf Offshore Logistics, L.L.C., a provider of offshore service vessels and vessel brokerage services primarily in the Gulf of Mexico, which he founded. He is also the founder and Chief Executive Officer of GOL Docks, L.L.C., which owns a dock facility that leases space to oil companies. Mr. Broussard founded GOL Docks, L.L.C. in 2007. Prior to founding Gulf Offshore Logistics, L.L.C. and GOL Docks, L.L.C., Mr. Broussard worked in sales and marketing with C&G Marine. Mr. Broussard began his career in the United States Army before working in sales and marketing in the industrial and heavy equipment business.

Gregg H. Falgout has been a member of our Board of Managers since February 2012. Mr. Falgout has been the Chairman, Chief Executive Officer and President of Island Operating Company, Inc., a company he founded in 1986, from July 1986 to present. Island Operating Company is the largest privately-held oil and gas lease operating company in the Gulf of Mexico, servicing over four hundred production platforms in the Gulf. It was awarded the SAFE Award for Excellence by the Secretary of the Interior in 1999 and 2002 and was a finalist for the same award in 2000, 2006 and 2007. Mr. Falgout was awarded the U.S. Department of the Interior, Minerals Management Service’s Corporate Leadership Award in 2006. He has also served on the Advisory Board of Directors of Northern Trust Bank. Mr. Falgout holds a Bachelor of Business Administration from the University of Texas and a Juris Doctor from the University of Houston School of Law.

Matthew Bernard has been a member of our Board of Managers since February 2012 and served as our interim Chief Financial Officer from August 2012 to September 2012. Mr. Bernard has been the President since 2010 of Gulf Offshore Logistics, L.L.C., which he joined in 2007 as Executive Vice President/Chief Financial Officer responsible for finance, accounting, human resources and information technology and was promoted to President/Chief Financial Officer in 2010. Prior to joining Gulf Offshore Logistics, L.L.C., Mr. Bernard served as Corporate Controller for Edison Chouest Offshore from 2002 to 2007 and was responsible for financial reporting, forecasting and management of the accounting department. From 1992 to 2002, Mr. Bernard worked for Ernst & Young’s audit practice in the New Orleans, The Hague (the Netherlands) and Houston offices, rising to the senior manager level prior to his departure. Mr. Bernard holds a bachelor of science in accounting from Nicholls State University.

Steve Orlando has been a member of our Board of Managers since May 2012. Mr. Orlando has been the Chairman, President and Chief Executive Officer of Allison Marine Holdings, LLC, the holdings entity for the group of companies that he started in 1995. Mr. Orlando is on the board of directors for Tarpon Systems International II, LLC, a company acquired from Acergy S.A. in May 2008, which owns several worldwide patents for its proprietary system that provides underwater caisson stabilization. Mr. Orlando is also on the board of directors for JAB Energy Solutions II, LLC, a company that he founded in 2008, which provides integrated turnkey and project management services for large offshore abandonments. Mr. Orlando has been involved with the oil and gas service industry in various sales and management capacities since the late 1970’s. Allison Marine Holdings, LLC, JAB Energy Solutions II, LLC, and Tarpon Systems International II, LLC were acquired by Lincolnshire Management in July 2011 along with other companies formed by Mr. Orlando, including Allison Marine

Contractors II, LLC, Allison Marine Morgan City II, LLC, Allison Offshore Services II, LLC and Allison Land Development II, LLC. Mr. Orlando currently serves on the board of directors for Wellbore Fishing & Rental Tools, LLC and as Chairman of the Board for Alternative Well Intervention, LLC.

Shane J. Guidry has been a member of our Board of Managers since December 2012. Mr. Guidry is the Chairman and Chief Executive Officer of Harvey Gulf Marine, Inc. (“Harvey”), having held the position of Chief Executive Officer of Harvey since 1997. Mr. Guidry has worked in various positions at Harvey since his graduation from De La Salle High School in New Orleans, Louisiana in 1988, and operated in many functions including business development, client management, vessel design, and overseeing Harvey’s vessel safety inspections, vessel maintenance and repair and Harvey’s sales and marketing division. In August 2008, Mr. Guidry and certain other investors acquired Harvey from the Guidry family.

Board Composition

Our business and affairs are managed under the direction of the Board of Managers. Our Board of Managers currently consists of Brian Stewart, Cornelius Dupre, Joel Broussard, Gregg H. Falgout, Matthew Bernard, Steve Orlando and Shane J. Guidry.

The Board of Managers has two standing committees: an audit committee and a compensation committee. The Board does not have a nominating committee, since pursuant to the terms of our Amended and Restated Limited Liability Company Agreement, ORB Investments, LLC has the right to appoint all of the members of the Company's Board of Managers, except for one position on the Board of Managers that is required to be filled by the Company's Chief Executive Officer.

Audit Committee

Our audit committee charter provides that the audit committee assists the Board of Managers in overseeing (a) the integrity of our financial statements, (b) our compliance with legal and regulatory requirements, (c) the assessment of the independent auditor's qualifications and independence, and (d) the performance of our internal and external auditors. In carrying out its responsibilities, the audit committee will, among other things, review our internal controls and risk management process.

Our audit committee meets when necessary to consider our financial reports and other matters relevant to its mandate. It is currently composed of Mr. Bernard, Mr. Dupre and Mr. Guidry.

Compensation Committee

As described in our compensation committee charter, the compensation committee assists our Board of Managers in discharging its responsibilities relating to the compensation of our chief executive officer and other executive officers. The compensation committee has overall responsibility for approving and evaluating all of our compensation plans, policies and programs as they affect the executive officers, including the development and approval of employment agreements or arrangements between us and our officers.

Our compensation committee held one meeting in 2012. It is currently composed of Mr. Dupre, Mr. Falgout, and Mr. Orlando.

Code of Ethics

We have adopted a Code of Business Ethics and Conduct, which sets forth ethical standards for our employees, executive officers and directors. This document is available through the “Investor Relations - Corporate Governance” section of our website or in print upon request. We expect that any amendments to the code, or any waivers of its requirements, will be disclosed on our website.

ITEM 11. EXECUTIVE COMPENSATION

General

We were formed on February 21, 2012. Prior to that date we did not have any operations or employees. As a private company, our executive compensation program has not historically consisted of formal policies or procedures. Instead, compensation decisions were made either in accordance with the terms of existing employment agreements with our executive officers, or on an ad hoc basis and at the discretion of our Board of Managers and certain members of our senior management.

We expect that the future compensation of our executive and non-executive officers will include a significant component of incentive compensation based on our performance. We expect to employ a compensation philosophy that will emphasize pay-for-performance, which will be based on a combination of our performance and the individual’s impact on our performance. Such a system will place a large portion of each officer’s compensation at risk. The performance metrics governing incentive compensation will not be tied in any way to the performance of entities other than us. We believe this pay-for-performance approach generally aligns the interests of our executive officers with that of our equity holders, and at the same time enables us to maintain a lower level of base overhead in the event our operating and financial performance fails to

meet expectations. We expect to design our executive compensation program to attract and retain individuals with the background and skills necessary to successfully execute our business model in a demanding environment, to motivate those individuals to reach near-term and long-term goals in a way that aligns their interests with those of our equity holders, and to reward success in reaching such goals.

We expect that we will use three primary elements of compensation to fulfill this design – salary, cash bonus and long-term equity incentive awards. Cash bonus and equity incentives (as opposed to salary) represent the performance driven elements. They are also flexible in application and can be tailored to meet our objectives. The determination of specific individuals’ cash bonuses will reflect their relative contribution to achieving or exceeding annual goals, and the determination of specific individuals’ long-term incentive awards will be based on their expected contributions in respect to longer-term performance objectives.

The following table sets forth the total compensation awarded to, earned by, or paid to our principal executive officers and other named executive officers for all services rendered in all capacities to us in 2012.



Name and Principal Position	Year	Salary		Bonus		Equity Awards (7)		Option Awards		Non-equity incentive plan compensation		Nonqualified deferred compensation earnings		All other compensation (8)		Total
Donald E. Stevenson - President and CEO (1)	2012	$	75,862	$	300,000	$	—	$	—	$	—	$	—	$	1,750	$	377,612
Brian Stewart - President and CEO (2)	2012	148,958		—		269,906		—		—		—		1,845		420,709
Leonard Travis, CFO (3)	2012	194,038		—		58,275		—		—		—		1,799		254,112
Kenneth Sill - CFO (4)	2012	70,192		—		201,103		—		—		—		960		272,255
Jeffrey McPherson - Vice President of Operations (5)	2012	233,333		—		77,700		—		—		—		3,720		314,753
Edward S. Self III -Vice President of Business Development (6)	2012	233,333		—		77,700		—		—		—		3,720		314,753


(1)	Employed as President and CEO from our inception, on February 21, 2012, to March 19, 2012.


(2)	Employed as President and CEO on June 18, 2012.


(3)	Employed as CFO from our inception, on February 21, 2012, to August 6, 2012.


(4)	Employed as CFO on September 19, 2012.


(5)	Employed as Vice President of Operations on February 21, 2012.


(6)	Employed as Vice President of Business Development on February 21, 2012.


(7)	The amount in this column reflects the grant date fair value of all unit awards in 2012 calculated in accordance with FASB ASC Topic 718. These unit awards vest between 2012 and 2015. See Part II. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements-9. Unit-Based/Share-Based Compensation” for further information.


(8)	The amount in this column represents cellphone allowance and life insurance premiums paid by the Company on behalf of the executive officers.

Employment Agreements

We have entered into employment agreements with each of our named executive officers. The following details those terms of the employment agreements:

Brian Stewart. On June 18, 2012, we entered into an employment agreement with Mr. Stewart that provides for his employment as our President and Chief Executive Officer. The employment agreement provides for a term of employment beginning on June 18, 2012 and ending on June 18, 2015, with a renewal provision that allows us to repeatedly extend the term of Mr. Stewart’s employment for an additional year upon providing Mr. Stewart with written notice of the extension at least 30 days prior to the expiration of then-current term of the agreement. Pursuant to the employment agreement, we are required to pay Mr. Stewart an annual base salary of $275,000 per annum for the first twelve months of the employment agreement and $325,000 per annum thereafter. Mr. Stewart is also eligible to receive a discretionary bonus with the maximum amount of such bonus not to exceed fifty percent (50%) of Mr. Stewart’s then current base salary. If we terminate Mr. Stewart’s employment without “cause” (as such term is defined in his employment agreement), then Mr. Stewart is entitled to (a) his base salary accrued to the date of his termination, (b) the continued payment of his base salary though the end of the then-current term of the agreement, (c) the continuation of his health benefits through the end of the then-current term of the agreement at the same cost as when he was employed by us, and (d) the reimbursement of certain business expenses. These entitlements are also

triggered if Mr. Stewart terminates his employment with us for “good reason” (as such term is defined in his employment agreement). If Mr. Stewart’s employment with us is terminated due to his becoming disabled, Mr. Stewart is entitled to (a) his base salary accrued to the date of his termination, (b) the continuation of the payment of his base salary for the lesser of (i) the then remaining term of his employment agreement, (ii) six consecutive months thereafter, or (iii) the period until disability insurance benefits commence under the disability insurance coverage provided by us to Mr. Stewart (if any), and (c) the continuation of his health benefits through the end of the then-current term of his employment agreement at the same cost as when he was employed by us. If Mr. Stewart’s employment with us is terminated as a result of his death, we are required to pay his estate his base salary accrued through the date of his death and to reimburse his estate for certain business expenses. The employment agreement also provides that during the term of the agreement and for two years after the termination of Mr. Stewart’s employment (for whatever reason), Mr. Stewart will not compete with us or solicit our customers or employees. The employment agreement also provides for the non-disclosure of our confidential information by Mr. Stewart. At the time he executed his employment agreement, Mr. Stewart was also granted 34,737 of the Company’s Series D Units, none of which vested immediately, and the rest of which will vest pursuant to the Series D Unit Agreement between us and Mr. Stewart described below.

Kenneth Sill. On September 19, 2012, we entered into an employment agreement with Kenneth Sill that provides for his employment as our Chief Financial Officer. The employment agreement provides for a term of employment beginning on September 19, 2012 and ending on September 19, 2015, with a renewal provision that allows us to repeatedly extend the term of Mr. Sill's employment for an additional year upon providing Mr. Sill with written notice of the extension at least 30 days prior to the expiration of then-current term of the agreement. Pursuant to the employment agreement, we are required to pay Mr. Sill a base salary of $250,000 per year. Mr. Sill is also eligible to receive a discretionary bonus pursuant to a bonus plan to be determined by our Board of Managers and Mr. Sill. If we terminate Mr. Sill's employment without “cause” (as such term is defined in his employment agreement), or if Mr. Sill terminates his employment with us for “good reason” (as such term is defined in his employment agreement), then Mr. Sill is entitled to (a) his base salary accrued to the date of his termination, (b) the continued payment of his base salary for a period of twelve (12) months after the date of his termination, (c) the continuation of his health benefits for a period of twelve (12) months after the date of his termination at the same cost as when he was employed by us, and (d) the reimbursement of certain business expenses. If Mr. Sill's employment with us is terminated due to his becoming disabled, Mr. Sill is entitled to (a) his base salary accrued to the date of his termination, (b) the continuation of the payment of his base salary for the lesser of (i) the then remaining term of his employment agreement, (ii) six consecutive months thereafter, or (iii) the period until disability insurance benefits commence under the disability insurance coverage provided by us to Mr. Sill (if any), and (c) the continuation of his health benefits through the end of the then-current term of his employment agreement at the same cost as when he was employed by us. If Mr. Sill's employment with us is terminated as a result of his death, we are required to pay his estate his base salary accrued through the date of his death and to reimburse his estate for certain business expenses. The employment agreement also provides that during the term of the agreement and for twelve (12) months after the termination of Mr. Sill's employment (for whatever reason), Mr. Sill will not compete with us or solicit our customers or employees. The employment agreement also provides for the non-disclosure of our confidential information by Mr. Sill. At the time he executed his employment agreement, Mr. Sill was also granted 25,882 of our Series D Units, none of which vested immediately, and the rest of which will vest pursuant to the Series D Unit Agreement between us and Mr. Sill described below.

Jeffrey McPherson. On February 21, 2012, we entered into an employment agreement with Jeffrey McPherson that provides for his employment as our Vice President of Operations. The employment agreement provides for a term of employment beginning on February 21, 2012 and ending on December 31, 2013, with a renewal provision that allows us to repeatedly extend the term of Mr. McPherson’s employment for an additional year upon providing him with written notice of the extension at least 30 days prior to the expiration of then-current term of the agreement. Pursuant to the employment agreement, we are required to pay Mr. McPherson an annual base salary of $200,000 per year, with Mr. McPherson also being eligible to receive a discretionary bonus the amount of which will be determined by the Board of Managers. If we terminate Mr. McPherson’s employment without “cause” (as such term is defined in the agreement), then Mr. McPherson is entitled to (a) his base salary accrued to the date of his termination, (b) the continued payment of his base salary though the end of the then-current term of the agreement, (c) the continuation of his health benefits through the end of the then-current term of the agreement at the same cost as when he was employed by us, and (d) the reimbursement of certain business expenses. These entitlements are also triggered if Mr. McPherson terminates his employment with us for “good reason” (as such term is defined in the agreement). If Mr. McPherson’s employment with us is terminated due to his becoming disabled, Mr. McPherson is entitled to (a) his base salary accrued to the date of his termination, (b) the continuation of the payment of his base salary for the lesser of (i) the then remaining term of his employment agreement, (ii) six consecutive months thereafter, or (iii) the period until disability insurance benefits commence under the disability insurance coverage provided by us to Mr. McPherson (if any), and (c) the continuation of his health benefits through the end of the then-current term of his employment agreement at the same cost as when he was employed by us. If Mr. McPherson’s employment with us is terminated as a result of his death we are required to pay his estate his base salary accrued through the date of his death and to reimburse his estate for certain business expenses. The employment agreement also provides that during the term of the agreement and for four years after the

termination of Mr. McPherson’s employment (for whatever reason), Mr. McPherson will not compete with us or solicit our customers or employees. The employment agreement also provides for the non-disclosure of our confidential information by Mr. McPherson. At the time he executed his employment agreement, Mr. McPherson was also granted 84,493 of our Series D Units, 10,000 of which vested immediately, and the rest of which will vest pursuant to the Series D Unit Agreement between us and Mr. McPherson described below.

Edward S. Self III. On February 21, 2012, we entered into an employment agreement with Edward S. Self III that provides for his employment as our Vice President of Business Development. The employment agreement provides for a term of employment beginning on February 21, 2012 and ending on December 31, 2013, with a renewal provision that allows us to repeatedly extend the term of Mr. Self’s employment for an additional year upon providing him with written notice of the extension at least 30 days prior to the expiration of then-current term of the agreement. Pursuant to the employment agreement, we are required to pay Mr. Self an annual base salary of $200,000 per year, with Mr. Self also being eligible to receive a discretionary bonus the amount of which will be determined by the Board of Managers. If we terminate Mr. Self’s employment without “cause” (as such term is defined in the agreement), then Mr. Self is entitled to (a) his base salary accrued to the date of his termination, (b) the continued payment of his base salary though the end of the then-current term of the agreement, (c) the continuation of his health benefits through the end of the then-current term of the agreement at the same cost as when he was employed by us, and (d) the reimbursement of certain business expenses. These entitlements are also triggered if Mr. Self terminates his employment with us for “good reason” (as such term is defined in the agreement). If Mr. Self’s employment with us is terminated due to his becoming disabled, Mr. Self is entitled to (a) his base salary accrued to the date of his termination, (b) the continuation of the payment of his base salary for the lesser of (i) the then remaining term of his employment agreement, (ii) six consecutive months thereafter, or (iii) the period until disability insurance benefits commence under the disability insurance coverage provided by us to Mr. Self (if any), and (c) the continuation of his health benefits through the end of the then-current term of his employment agreement at the same cost as when he was employed by us. If Mr. Self’s employment with us is terminated as a result of his death we are required to pay his estate his base salary accrued through the date of his death and to reimburse his estate for certain business expenses. The employment agreement also provides that during the term of the agreement and for four years after the termination of Mr. Self’s employment (for whatever reason), Mr. Self will not compete with us or solicit our customers or employees. The employment agreement also provides for the non-disclosure of our confidential information by Mr. Self. At the time he executed his employment agreement, Mr. Self was also granted 84,493 of our Series D Units, 10,000 of which vested immediately, and the rest of which will vest pursuant to the Series D Unit Agreement between us and Mr. Self described below.

Restricted Equity Agreements

We have entered into Restricted Equity Agreements with each of our executive officers . We believe that these agreements appropriately balance our needs to offer a competitive level of severance protection to our executives and to induce our executives to remain in our employ through the potentially disruptive conditions that may exist around the time of a change in control, while not unduly rewarding executives for a termination of their employment. The following details the terms of those Restricted Equity Agreements:

Brian Stewart. On June 18, 2012, we entered into a Series D Unit Agreement with Brian Stewart pursuant to which we granted a total of 34,737 of our Series D Units to Mr. Stewart. The Series D Units are intended to constitute “profits interests” under the Internal Revenue Code of 1986, as amended (the “Code”). Of the Series D Units granted to Mr. Stewart, one-third will vest on June 18, 2013, one-third will vest on June 18, 2014, with the remaining Series D Units vesting on June 18, 2015. However, if the Series D Units granted to Mr. Stewart have not already vested according to the schedule detailed in the previous sentence, then all granted Series D Units will vest upon the occurrence of a liquidation event or exit event. If Mr. Stewart’s employment with us is terminated (a) as a result of his death or disability, (b) as a result of his terminating his employment without “good reason” (as defined in his employment agreement) or (c) for “cause” (as such term is defined in his employment agreement), then on the date of such termination Mr. Stewart shall forfeit all of his unvested Series D Units. Following any termination of employment, all vested Series D Units shall be retained by Mr. Stewart or his estate and held subject to the terms of the Company’s Amended and Restated Limited Liability Company Agreement. The number of Series D Units granted to Mr. Stewart represent as of the date of the Series D Unit Agreement the right to receive three percent (3%) of all distributions made on our Series B, Series C and Series D Units. The number of Series D Units granted pursuant to the Series D Unit Agreement will be adjusted (either up or down) as reasonably determined by the Board of Managers so that such Series D Units, assuming they were to become fully vested, represent the right to receive three percent (3%) of all distributions on our Series B, Series C and Series D Units.

Kenneth Sill. On September 19, 2012, we entered into a Series D Unit Agreement with Kenneth Sill pursuant to which we granted a total of 25,882 of its Series D Units to Mr. Sill. The Series D Units are intended to constitute “profits interests” under the Internal Revenue Code of 1986, as amended. Of the Series D Units granted to Mr. Sill, one-third will vest on September 19, 2013, one-third will vest on September 19, 2014, with the remaining one-third vesting on September 19, 2015. However, if the Series D Units granted to Mr. Sill have not already vested according to the schedule detailed in the previous sentence, then all granted Series D Units will vest upon the occurrence of a First Trigger Event (as such term is defined in Mr. Sill's Series D Unit

Agreement). Upon the occurrence of an exit event or a liquidation event, all unvested Series D Units awarded to Mr. Sill pursuant to the Series D Unit Agreement that have not vested will vest immediately. If Mr. Sill's employment with us is terminated (a) as a result of his death or disability, or (b) as a result of his terminating his employment without “good reason” (as defined in his employment agreement), or (c) for “cause” (as defined in his employment agreement), then on the date of such termination Mr. Sill shall forfeit all of his unvested Series D Units. Following any termination of employment, all vested Series D Units shall be retained by Mr. Sill or his estate and held subject to the terms of the Company's Amended and Restated Limited Liability Company Agreement. The number of Series D Units granted to Mr. Sill represent as of the date of the Series D Unit Agreement the right to receive two percent (2%) of all distributions made on our Series B, Series C and Series D Units. The number of Series D Units granted pursuant to the Series D Unit Agreement will be adjusted (either up or down) as reasonably determined by the our Board of Managers so that such Series D Units, assuming they were to become fully vested, represent the right to receive two percent (2%) of all distributions on the Company's Series B, Series C and Series D Units.

Jeffrey McPherson. On February 21, 2012, we entered into a Series D Unit Agreement with Jeffrey McPherson pursuant to which we granted a total of 84,493 of our Series D Units to Mr. McPherson. The Series D Units are intended to constitute “profits interests” under the Code. Of the Series D Units granted to Mr. McPherson, 10,000 vested immediately. Of the remaining unvested Series D Units, 37,247 will vest upon the occurrence of a First Trigger Event and 37,246 will vest upon the occurrence of a Second Trigger Event. Upon the occurrence of an exit event or a liquidation event (including a First Trigger Event), all unvested Series D Units awarded to Mr. McPherson pursuant to the agreement that have not vested will be forfeited. If Mr. McPherson’s employment with us is terminated (a) as a result of his death or disability, (b) as a result of his terminating his employment without “good reason” (as defined in his employment agreement), (c) for “cause” (as defined in his employment agreement) or (d) the then-current term of his employment agreement expiring, then on the date of such termination Mr. McPherson shall forfeit to us all of his unvested Series D Units. If Mr. McPherson’s employment is terminated without cause or if Mr. McPherson terminates his employment for good reason, then (a) if the First Trigger Event occurs prior to what would have been the expiration of the then-current term of his employment agreement, 37,247 of Mr. McPherson’s unvested Series D Units will vest, (b) if the Second Trigger Event occurs prior to what would have been the expiration of the then-current term of his employment agreement, 74,493 of Mr. McPherson’s unvested Series D Units will vest.

Edward S. Self III. On February 21, 2012, we entered into a Series D Unit Agreement with Edward S. Self III pursuant to which we granted a total of 84,493 of our Series D Units to Mr. Self. The terms of Mr. Self’s Series D Unit Agreement are identical to those of Mr. McPherson’s Series D Unit Agreement.

Other Executive Benefits and Perquisites

We provide the following benefits to our executive officers on the same basis as other eligible employees:


•	cellphone allowance;


•	health insurance;


•	vacation, personal holidays and sick days;


•	life insurance and accidental death and dismemberment insurance; and


•	short-term and long-term disability.

We believe these benefits are generally consistent with those offered by other companies with which we compete for executive talent.

Other Compensation Practices and Policies

Policy regarding the timing of equity awards. As a privately-owned company, there is no market for our common equity. Accordingly, we do not have a program, plan or practice pertaining to the timing of equity grants to executive officers coinciding with the release of material non-public information. We do not, as of yet, have any plans to implement such a program, plan or practice after becoming a reporting company.

Policy regarding restatements. We do not have a formal policy regarding adjustment or recovery of awards or payments if the relevant performance measures upon which they are based are restated or otherwise adjusted in a manner that would reduce the size of the award or payment. Under those circumstances, our Board of Managers or a committee thereof, would evaluate whether adjustments or recoveries of awards were appropriate based upon the facts and circumstances surrounding the restatement.

Equity Ownership Policies. We have not established equity ownership or similar guidelines with regards to our executive officers. All of our executive officers currently have an indirect equity interest in our company through their restricted unit awards and we believe that they regard the potential returns from these interests as a significant element of their potential compensation for services to us.

Pension Benefits

We do not maintain any defined benefit pension plans.

Nonqualified Deferred Compensation

We do not maintain any nonqualified deferred compensation plans.

Relation of Compensation Policies and Practices to Risk Management

In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees, including our named executive officers, are reasonably likely to have a material adverse effect on us.

Outstanding Equity Awards at Fiscal Year End

The following table sets forth certain information concerning outstanding equity awards held by the named executive officers as of December 31, 2012.

Outstanding Equity Awards at 2012 Fiscal Year End

Option Awards

Stock Awards

Name

Number of securities underlying unexercised options

(#)

exercisable

Number of securities underlying unexercised options

(#)

unexercisable

Equity incentive plan awards: number of securities underlying unexercised unearned options

(#)

Option exercise price

($)

Option expiration

date

Number of shares or units of stock that have not vested

(#)

Market value of shares or units of stock that have not vested

($) (5)

Equity incentive plan awards: number of unearned shares, units or other rights that have not vested

(#)

(i)

Equity incentive plan awards: market or payout value of unearned shares, units or other rights that have not vested

(#)

Brian Stewart

—

34,737 Series D Units (1)

—

Kenneth Sill

—

25,882 Series D Units (2)

—

Jeffery McPherson

—

74,493 Series D Units (3)

—

Edward S. Self III

—

74,493 Series D Units (4)

—


(1)	Mr. Stewart's Series D Units vest in three equal installments on June 18, 2013, June 18, 2014 and June 18, 2015.


(2)	Mr. Sill's Series D Units vest in three equal installments on June 18, 2013, June 18, 2014 and June 18, 2015.


(3)	Mr. McPherson was granted 84,493 Series D Units on February 21, 2012, of which 10,000 vested immediately. Of the remaining unvested Series D Units, 37,246 will vest upon the occurrence of a First Trigger Event and 37, 246 will vest upon the occurrence of a Second Trigger Event.


(4)	Mr. Self III was granted 84,493 Series D Units on February 21, 2012, of which 10,000 vested immediately. Of the remaining unvested Series D Units, 37,246 will vest upon the occurrence of a First Trigger Event and 37, 246 will vest upon the occurrence of a Second Trigger Event.

(5)

There was no established public trading market for our membership interests as of December 31, 2012 and thus the market value as of that date is not determinable. For financial accounting purposes, the grant date fair value of all unit awards in 2012 is calculated in accordance with FASB ASC Topic 718. These unit awards vest between 2012 and 2015. See Part II. “Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements-9. Unit-Based/Share-Based Compensation” for further information.

Compensation of the members of the Board of Managers

We did not compensate any of the members of the Board of Managers for their service on our Board during the period ended December 31, 2012. We do, however, reimburse the members of the Board of Managers for reasonable out of pocket expenses incurred in attending meetings of the Board of Managers and other reasonable expenses related to the performance of their duties as members of the Board of Managers.

The following table summarizes the annual compensation for our non-employee members of our Board of Managers during the year ended December 31, 2012.

Name

(a)

Fees Earned or Paid in Cash (b)

Stock Awards (1) (2) (c)

Option Awards (1) (3) (d)

Non-Equity Incentive Plan Compensation (e)

Nonqualified Deferred Compensation Earnings (f)

All Other Compensation(g)

Total (h)

Cornelius Dupre

—

Matthew Bernard

—

Joel Broussard

—

Gregg H. Falgout

—

Steve Orlando

—

Shane J. Guidry

—

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table sets forth, as of January 1, 2013, information with respect to the beneficial ownership of our common equity for: (i) each person that is a member of our Board of Managers and executive officer; (ii) all such members of our Board of Managers and executive officers as a group; and (iii) each person or entity that beneficially owns (directly or together with affiliates) more than 5% of our common equity. We refer to our Series B, Series C and Series D Units as our common equity. To our knowledge, each individual or entity named has sole investment and voting power with respect to units of common equity beneficially owned by them, except as otherwise noted. The number of units of common equity and the percentages of beneficial ownership are based on a total of approximately 1,000,000 units of common equity issued and outstanding and not subject to repurchase, or subject to issuance upon exercise of the warrants.



Name of Beneficial Owner	Units Beneficially Owned	Common Equity Percentage Ownership
ORB Investments, LLC⁽¹⁾	776,471	60.0	%
Joel Broussard⁽¹⁾	776,471	60.0	%
Gregg H. Falgout⁽¹⁾	776,471	60.0	%
Matthew Bernard⁽¹⁾	776,471	60.0	%
Cornelius Dupre⁽¹⁾	776,471	60.0	%
Steve Orlando⁽¹⁾	776,471	60.0	%
USWS Inc.⁽²⁾	167,500	12.9	%
Brian Stewart⁽³⁾	38,824	3.0	%
Kenneth I. Sill⁽⁴⁾	25,882	2.0	%
Jeffrey McPherson⁽⁵⁾	10,000	0.8	%
Edward S. Self III⁽⁶⁾	10,000	0.8	%
Executive Officers and members of the Board of Managers as a Group	861,177	66.6	%


(1)	Messrs. Broussard, Bernard, Falgout, Dupre and Orlando, each a member of the Board of Managers, are also members of ORB Investments, LLC. The securities attributable to Messrs. Broussard, Bernard, Falgout, Dupre and Orlando include all of the units of our common equity held by ORB Investments, LLC.


(2)	Daniel T. Layton has voting and investment power with respect to the units of common equity held by USWS Inc.

(3)

Mr. Stewart's units are not fully vested and vest in accordance with the terms of his Series D Unit Agreement. Further, the number of Series D Units granted to Mr. Stewart represents, as of the date of the Series D Unit Agreement, the right to receive three percent (3%) of all distributions made on our Series B, Series C and Series D Units. The number of Series D Units granted pursuant to Mr. Stewart's Series D Unit Agreement will be adjusted (either up or down) as reasonably determined by the Board of Managers so that such Series D Units, assuming they were to become fully vested, represent

the right to receive three percent (3%) of all distributions on our Series B, Series C and Series D Units. For a summary of Mr. Stewart's Series D Unit Agreement see “Item 11. Executive Compensation - Restricted Equity Agreements.”

(4)

Mr. Sill's units are not fully vested and vest in accordance with the terms of his Series D Unit Agreement. Further, the number of Series D Units granted to Mr. Sill represents the right to receive two percent (2%) of all distributions made on our Series B, Series C and Series D Units. The number of Series D Units granted pursuant to Mr. Sill's Series D Unit Agreement will be adjusted (either up or down) as reasonably determined by the Board of Managers so that such Series D Units, assuming they were to become fully vested, represent the right to receive two percent (2%) of all distributions on our Series B, Series C and Series D Units. For a summary Mr. Sill's Series D Unit Agreement see “Item 11. Executive Compensation - Restricted Equity Agreements.”


(5)	Of the units granted to Mr. McPherson (a) 10,000 vested immediately upon execution of his Series D Unit Agreement, (b) 37,247 will vest upon the occurrence of a First Trigger Event and (c) 37,246 will vest upon the occurrence of a Second Trigger Event. For a summary of Mr. McPherson's Series D Unit Agreement see “Item 11. Executive Compensation - Restricted Equity Agreements.”


(6)	Of the units granted to Mr. Self (a) 10,000 vested immediately upon execution of his Series D Unit Agreement, (b) 37,247 will vest upon the occurrence of a First Trigger Event and (c) 37,246 will vest upon the occurrence of a Second Trigger Event. For a summary of Mr. Self's Series D Unit Agreement see “Item 11. Executive Compensation - Restricted Equity Agreements.”

Securities Authorized for Issuance Under Equity Incentive Plans

We have no outstanding equity compensation plans under which our securities are authorized for issuance.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

In the ordinary course of our business and in connection with our financing activities, we have entered into transactions with certain of our affiliates and significant equity holders. All of the transactions set forth below were approved by the unanimous vote of our predecessor’s Board of Directors. We believe that we have executed all of the transactions set forth below on terms no less favorable to us than could have been obtained from unaffiliated third parties.

During 2011, Layton Corporation, a company owned and controlled by Daniel T. Layton, a shareholder of USWS, Inc., advanced our predecessor certain startup expenses totaling $29,700. This advance was repaid from the proceeds the Unit Offering.

In connection with the Unit Offering, a placement fee of $1,000,000 was paid to the Layton Corporation with the proceeds of the Unit Offering.

Director Independence

Our Board of Managers consists of seven members, one of whom is an employee director. Because we only have debt securities registered with the SEC under the Exchange Act and because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of managers comprised of a majority of independent managers under SEC rules or any listing standards. Accordingly, our Board of Managers has not made any determination as to whether the six non-employee members of the Board of Managers satisfy any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition. However, as required by the Compensation Committee Charter, the members of the Compensation Committee are "outside directors" within the meaning of Section 162(m) of the Internal Revenue Service Code of 1986.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table sets forth the fees paid by us to KPMG LLP, our independent registered public accounting firm:



	Successor		Predecessor
	February 21, 2012		January 1, 2012		August 18, 2011
	(inception) to		to		(inception) to
	December 31, 2012		February 20, 2012		December 31, 2011
Audit Fees	$	375,450	$	—	$	55,000
Audit-Related Fees	—		—		—
Tax Fees	87,200		—		—
All Other Fees	—		—		—
	$	462,650	$	—	$	55,000

Audit fees consist of professional services rendered for the audit of our annual financial statements, and the reviews of the quarterly financial statements. This category also includes fees for issuance of consents, assistance with and review of documents filed with the SEC.

Tax fees consist of fees for services with respect to tax compliance and tax advice. All of these services and related fees were pre-approved by the audit committee.

As provided in the audit committee charter, the audit committee is responsible for pre-approving all auditing services and permitted non-audit services (including the fees and terms thereof) to be performed for the Company by the independent registered public accounting firm. The engagement of the independent registered public accounting firm may also be entered into pursuant to pre-approval policies and procedures established by the audit committee, provided that the policies and procedures are detailed as to the particular services and the audit committee is informed of each service.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

List of Documents filed as part of this Report.

(1) Financial Statements

All financial statements of the Registrant as set forth under Item 8 of this Annual Report on Form 10-K.

(2) Exhibits



Exhibit No.		Description
3.1		Certificate of Formation of U.S. Well Services, LLC dated February 14, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
3.2		Amended and Restated Limited Liability Company Agreement of U.S. Well Services, LLC dated February 21, 2012 (incorporated by reference to Exhibit 3.3 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
4.1		Indenture dated as of February 21, 2012 by and among U.S. Well Services, LLC, USW Financing Corp., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
4.2		First Supplemental Indenture dated as of July 16, 2012 by and among U.S. Well Services, LLC, USW Financing Corp., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
4.3		Registration Rights Agreement dated as of February 17, 2012 among U.S. Well Services, LLC, USW Financing Corp., the individual purchasers named therein, and Global Hunter Securities, LLC (incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
4.4		Escrow Agreement dated as of February 21, 2012 among U.S. Well Services, LLC, USW Financing Corp., and The Bank of New York Mellon Trust Company, N.A., as trustee and escrow agent (incorporated by reference to Exhibit 4.4 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
4.5		Amendment to Escrow Agreement dated as of July 16, 2012 among U.S. Well Services, LLC, USW Financing Corp., and The Bank of New York Mellon Trust Company, N.A., as trustee and escrow agent (incorporated by reference to Exhibit 4.5 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.1@		Contract to Provide Dedicated Fracturing Fleet(s) for Fracturing Services dated November 1, 2011, between U.S. Well Services, Inc. and Antero Resources Appalachian Corporation (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.2		Rider No. 1 to Contract to Provide Dedicated Fracturing Fleet(s) for Fracturing Services dated June 5, 2012, between U.S. Well Services, LLC and Antero Resources Appalachian Corporation (incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.3#		Employment Agreement of Brian Stewart dated June 18, 2012 (incorporated by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.4#		Employment Agreement of Kenneth I. Sill dated September 19, 2012 (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.5#		Employment Agreement of Jeffrey McPherson dated February 21, 2012 (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.6#		Employment Agreement of Edward S, Self III dated February 21, 2012 (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).



10.7#		Series D Unit Agreement of Brian Stewart dated June 18, 2012 (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.8#		Series D Unit Agreement of Kenneth I. Sill dated September 19, 2012 (incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.9#		Series D Unit Agreement of Jeffrey McPherson dated February 21, 2012 (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
10.10#		Series D Unit Agreement of Edward S. Self III dated February 21, 2012 (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-4 filed with the SEC on October 18, 2012 (SEC Registration No. 333-184491)).
21.1*		Subsidiaries of U.S. Well Services, LLC.
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*		Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Taxonomy Extension Schema Document
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

@Confidential treatment has been granted for portions of this exhibit. Omissions are designated with brackets containing asterisks. As part of our confidential treatment request, a complete version of this exhibit has been filed separately with the Securities and Exchange Commission.

#Management contract or compensatory plan.

* Filed herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



			U.S. WELL SERVICES, LLC

Date:	March 19, 2013	By:	/s/ Brian Stewart
			Brian Stewart
			President and Chief Executive Officer

		By:	/s/ Kenneth I. Sill
			Kenneth I. Sill
			Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated.



	Signature	Title	Date

By:	/s/ Brian Stewart	President, Chief Executive Officer (Principal Executive Officer) and Member of the Board of Managers	March 19, 2013
	Brian Stewart		March 19, 2013

By:	/s/ Kenneth I. Sill	Chief Financial Officer (Principal Financial Officer, Principal Accounting Officer)	March 19, 2013
	Kenneth I. Sill		March 19, 2013

By:	/s/ Cornelius Dupre	Member of the Board of Managers	March 19, 2013
	Cornelius Dupre	Member of the Board of Managers	March 19, 2013

By:	/s/ Joel Broussard	Member of the Board of Managers	March 19, 2013
	Joel Broussard	Member of the Board of Managers	March 19, 2013

By:	/s/ Gregg H. Falgout	Member of the Board of Managers	March 19, 2013
	Gregg H. Falgout	Member of the Board of Managers	March 19, 2013

By:	/s/ Matthew Bernard	Member of the Board of Managers	March 19, 2013
	Matthew Bernard	Member of the Board of Managers	March 19, 2013

By:	/s/ Steve Orlando	Member of the Board of Managers	March 19, 2013
	Steve Orlando	Member of the Board of Managers	March 19, 2013

By:	/s/ Shane J. Guidry	Member of the Board of Managers	March 19, 2013
	Shane J. Guidry	Member of the Board of Managers	March 19, 2013

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

U.S. Well Services 10-K2012 FY Annual report

Content analysis