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, 2013

OR

[  ] 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, 2013, the registrant’s membership interests were not, and are not currently, listed on an exchange or otherwise publicly traded 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	6
Item 1A. Risk Factors	11
Item 1B. Unresolved Staff Comments	25
Item 2. Properties	25
Item 3. Legal Proceedings	25
Item 4. Mine Safety Disclosures	25
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity    Securities	26
Item 6. Selected Financial Data	26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	35
Item 8. Financial Statements and Supplementary Data	36
Item 9. Changes and Disagreements With Accountants on Accounting and Financial Disclosure	54
Item 9A. Controls and Procedures	54
Item 9B. Other Information	54
PART III
Item 10.  Directors, Executive Officers and Corporate Governance	55
Item 11. Executive Compensation	57
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	63
Item 13. Certain Relationships and Related Transactions, and Director Independence	64
Item 14. Principal Accountant Fees and Services	65
PART IV
Item15. Exhibits, Financial Statement Schedules	66
SIGNATURES	69

CAUTIONARY STATEMENT REGARDINGFORWARD-LOOKING STATEMENTS

U.S. Well Services, LLC's (together with its subsidiary, “we,” “us,” or “our”) 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 Annual Report on Form 10-K 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 thisAnnual Report on Form 10-K, including the following:

" our limited operating history;

" concentration of our customer base;

" our ability to fulfill, renew or replace our existing customer contracts and enter into additional service contracts;

" dependence on entering into additional service contracts to grow our business;

" our ability to obtain raw materials and specialized equipment;

" deployment of new and unproven technologies;

" 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;

" the control of our sponsor over voting and management;

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

" 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;

" 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 Jumpstart Our Business Startups 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 on Form 10-K are made only as of the date of this Annual Report on Form 10-K, 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 on Form10-K. You should read this Annual Report on Form 10-K 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 and Williamsport, Pennsylvania. 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 operate and 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.

Industry Overview

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

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 1,146 (65% of the total operating rigs) as of December 27, 2013, 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 Corporation ("Antero") to perform services in the Marcellus and Utica Shales in Ohio, West Virginia and Pennsylvania and with Inflection Energy LLC (“Inflection”) to perform services in the Marcellus Shale in 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. Our contract, as amended, with Antero provides for minimum performance requirements related to the number of stages to be completed quarterly, over the term of the contract. For the year ended December 31, 2013, Antero accounted for 86.0% of our consolidated revenues. Our contract with Inflection also provides a minimum number of stages to be performed during the term of the contract. For the year ended December 31, 2013, Inflection accounted for 4.6% of our consolidated revenues.

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, and other formations in Texas, New Mexico, Colorado, Wyoming, Nebraska and 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, LLC 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.

Employees

As of December 31, 2013, we had 315 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 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 on public and Indian lands 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 rulemaking, 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 currently operate (Ohio, West Virginia 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.  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 in this Annual Report on 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 contracts could cause our revenue to decline substantially and adversely affect our business.

Our business is highly dependent on our contracts and relationships with Antero and Inflection.  A significant portion of our 2013 revenues were generated through the services provided to Antero and Inflection. A reduction in business from these customers resulting from reduced demand for their own products and services, a work stoppage or delays in customer customer drilling programs, 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 or Inflection 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.

Our agreement with Inflection does not obligate Inflection to order additional work from us beyond those currently contracted for.

We may not be able to successfully fulfill, renew or replace our contracts with Anteroor Inflection, 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 or Inflection on or prior to their expiration on terms satisfactory to us, Antero or Inflection, as applicable, 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 and Inflection, 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.

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 contracts with Antero and Inflection, as well as under 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 contracts with Antero and Inflection and our ability to generate new customers. In addition, our existing contracts with Antero and Inflection provide 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.

We are deploying new and unproven technologies, which make evaluation of our business and prospects difficult, and our agreement with Antero may be terminated if we do not develop commercially successful products.

Some of the services we are to provide under our contract with Antero are to be performed by a hydraulic fracturing fleet  (the “Clean Fleet”) to be powered by electricity generated from natural gas. The Clean Fleet will be constructed for us under the terms of a contract with a certain vendor. The technology involved in the construction of and the services to be performed from our Clean Fleet of hydraulic fracturing equipment is at an early stage of commercialization and has not been field proven. In order to successfully commercialize our Clean Fleet equipment, we will have to make significant investments, including investments in research and development and testing, to demonstrate its technical benefits and cost-effectiveness. Problems frequently encountered in connection with the commercialization of products using new and unproven technologies might limit our ability to develop and commercialize services provided by our Clean Fleet equipment. For example, our products may be found to be ineffective, unreliable or otherwise unsatisfactory to current and potential customers. We may experience unforeseen technical complications in the processes we use to develop, customize and receive orders for services performed by our Clean Fleet. These complications could materially delay or limit the use of Clean Fleet equipment that we attempt to commercialize, substantially increase the anticipated cost of our Clean Fleet or prevent us from implementing our processes at appropriate quality and scale levels, thereby causing our business to suffer.

In particular, our contract with Antero requires that we deliver services from our Clean Fleet products by June 12, 2014, and our failure to do so would permit Antero to terminate the agreement or grant an extension to the commencement date of the agreement, at Antero’s discretion.

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 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 and Eastern Europe;  

" 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 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 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 contract with Antero has a remaining term of approximately three years until April 2017, 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.

Our contract with Inflection terminates on December 31, 2014, and does not obligate Inflection to order additional work from us beyond such current term.

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 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.

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

ORB, 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.

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.

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 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 also generate and dispose of hazardous waste. Therefore, our operations are 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 or other approvals 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 or other approvals 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 need to operate trucks and other heavy equipment. We are therefore 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 possible 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 rulemaking, 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 many 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 are 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 have incurred and will continue 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. This included 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 and maintain the corporate infrastructure appropriate for a public company requires 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 is 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.

As our business grows, we may no longer satisfy the conditions of an emerging growth company. In addition, 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, 2013, we had approximately $121,327,903 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 our 14.50% Senior Secured Notes due 2017 (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 the Credit Agreement and under certain indebtedness that we may incur in the future.

Holders of our first lien indebtedness will have claims that are prior to the claims of the holders of the Notes to the extent of the value of the assets securing that other priority lien indebtedness. Notably, we are a party to our Credit and Security Agreement with a bank (the “Credit Agreement”), which is secured by liens on substantially all of our assets. The Notes will be effectively subordinated to any first lien indebtedness incurred under the Credit Agreement to the extent of the value of the assets securing the Credit Agreement. In the event of any distribution or payment of our assets in any foreclosure, dissolution, winding-up, liquidation, reorganization or other bankruptcy proceeding, holders of first lien indebtedness will have a prior claim to those assets that constitute their collateral. Pursuant to the terms of the intercreditor agreement, holders of first lien indebteness, including the lender under the Credit Agreement, are entitled to receive all proceeds from the sale or other disposition of the collateral until such claims are paid in full. As a result, the Notes are effectively subordinated to all priority lien claims. If there is insufficient collateral to cover all claims, noteholders may receive less, ratably, than holders of first lien indebtedness.

The indenture governing the Notes, as well as the Credit Agreement, impose, 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 and the Credit Agreement contain, 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 Credit Agreement requires, and 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 Credit Agreement, 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 has not developed, and 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.

On December 9, 2013, we entered into an agreement for the lease of a 24,600 square foot building on approximately 4.03 acres in Muncy, Pennsylvania for our fleet operations.  The total amount of monthly payments over the term of 24 months beginning January 8, 2014 is $660,000.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of our business. As of the date of this report, no legal proceedings are pending against us that we believe individually or collectively could have a materially adverse effect upon our financial condition, results of operations or cash flows.

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 28, 2014, the following membership interests in the Company were issued and outstanding: 630,000 Series B Units held by 2 holders, 192,500 Series C Units held by 2 holders, 157,794 Series D Units held by 3 holders, 663,195 Series E Units held by 2 holders, and 760,000 Senior Mandatorily Redeemable Financial Interests (the “SMRF Interests”) held by 7 holders.

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 229,605 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 Units, in the Sponsor Equity Investment, to ORB for $30 million. 

On October 18, 2013, we entered into a subscription agreement with one of our existing investors and an affiliate thereof, pursuant to which we received approximately $14 million aggregate gross proceeds in exchange for 663,195 Series E Units subscribed. On February 10, 2014, the Company issued 663,195 Series E Units to the investors.The Series E Units are governed by and issued pursuantto the First Amendment to theAmended and Restated Limited Liability Company Agreement adopted on February 10, 2014 but made effective as of October 18, 2013.

On February 18, 2014, the Company issued 760,000 SMRF Interests(“SMRF Interests Issuance”) pursuant to the Second Amendment to theAmended and Restated Limited Liability Company Agreement. The SMRF Interests Issuance resulted in aggregate gross proceeds to the Company of approximately $30 million, which was used by the Company to redeem the Series A Units and to pay related fees and expenses.

The sale of securities in the Unit Offering, the Series E Issuance and the SMRF Interests Issuancewas 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 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 andresults of operations together with our consolidated financial statements and therelated notes and other financial information included elsewhere in this Annual Report on Form 10-K. Some of the information contained in this discussion and analysis or setforth elsewhere in this Annual Report on Form 10-K, including information with respect to ourplans and strategy for our business and related financing, include forward-lookingstatements that involve risks and uncertainties. You should review thesection entitled “Risk Factors” included in Item 1A of this Annual Report on Form 10-K for a discussion ofimportant factors that could cause actual results to differ materially from theresults described in or implied by the forward-looking statements contained in thefollowing 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 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.

We believe our hydraulic fracturing fleets 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 are a  Delaware limited liability company. Our corporate office is 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, we were in the development stage. We currently perform services in the Marcellus and Utica Shales in Ohio, West Virginia and Pennsylvania.  We are also evaluating opportunities with existing and new customers to expand our operations into new areas throughout North America, 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, and other formations in Texas, New Mexico, Colorado, Wyoming, Nebraska, Oklahoma and Canada.

Recent Developments

Second Amendment to Antero Contract.  On January 24, 2014, we entered into a Second Amendment to Contract to Provide Dedicated Fleet(s) for Fracturing Services (the “Antero Contract Second Amendment”), with Antero, which augmented and amended the pricing terms applicable to up to three conventional fleets provided by us to perform fracturing services for Antero pursuant to the Antero Contract.  The pricing terms set forth in the Antero Contract Second Amendment are effective until April 12, 2017.

Amendments to the Company Agreement. On February 10, 2014, the Company adopted a First Amendment to the Amended and Restated Limited Liability Company Agreement of the Company (the “First Amendment to Company Agreement”), which was made effective as of October 18, 2013.  Pursuant to the First Amendment to Company Agreement, a new series of membership interest units were issued and created designated as “Series E Units.”The Company received approximately $14 million in exchange for the Series E Units.

On February 18, 2014, the Company adopted a Second Amendment to the Amended and Restated Limited Liability Company Agreement of the Company (the “Second Amendment to Company Agreement”), pursuant to which a new series of membership interest, the Senior Mandatorily Redeemable Financial Interests (the “SMRF Interests”) was issued.  The Company received approximately $30 million in exchange for the SMRF Interests, which was used by the Company to redeem the Series A Units and to pay related fees and expenses.

Redemption of Series A Units.On February 18, 2014, the Company purchased from the Sponsor, and the Sponsor sold to the Company, all of its 600,000 Series A Units in exchange for an amount equal to $30,000,000 less all related fees and expenses incurred by the Company (the “Series A Redemption”).  Following the Series A Redemption, there are no Series A Units of the Company issued and outstanding.

Amendment to the Credit Agreement. On February 18, 2014, the Company entered into a Second Amendment (the “Second Amendment to Credit Agreement”) to Credit and Security Agreement (as amended from time to time, including the Second Amendment to Credit Agreement, the “Credit Agreement”) with Wells Fargo Bank, National Association (the “Lender”), pursuant to which the Lender agreed to (i) consent to (A) the adoption of the Second Amendment to Company Agreement to implement the SMRF Interests Issuance and (B) the consummation of the Series A Redemption and (ii) make certain amendments to the Credit Agreement in connection with such transactions.

Current Contracts

Original Antero Contract. Our Original Antero Contract provided 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 Original Antero 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 Original Antero Contract and standby time rates under certain circumstances, dedicated fracturing fleet charges ("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 Original Antero 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 Original Antero 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 Original Antero 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 Rider No. 1 to Contract to Provide Dedicated Fleet(s) for Fracturing Services with Antero (the "Rider").  The Rider amended certain terms of our Original Antero Contract and gave Antero, in its sole discretion, a right of first refusal to engage all or any portion of our second hydraulic fracturing fleet at negotiated rates.  In addition, the Rider modified our Original Antero Contract 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 strengthened our relationship with Antero and provides us with the opportunity to grow revenues by participating in Antero's expanding drilling program.

Amendment to Original Antero Contract.  On October 9, 2013, we entered into an Amendment to Contract to Provide Dedicated Fleet(s) for Fracturing Services effective September 30, 2013 (the “Antero Contract Amendment”), with Antero. The Antero Contract Amendment extended the term of the Original Antero Contract for three years to April 12, 2017.

The Antero Contract Amendment includes minimum performance requirements related to the number of stages to be completed quarterly and requires that the services will be provided by a dedicated fleet to be acquired by us. The Antero Contract Amendment provides that Antero (i) has a right of first refusal to engage any of our additional fleets that are available to provide services similar to those to be performed for Antero at market rates, (ii) may terminate the agreement upon the payment of an early termination fee and (iii) may terminate the agreement, or grant an extension to the commencement date at Antero’s discretion, if the Company does not commence services utilizing a proprietary designed fleet by June 12, 2014.

Second Amendment to Antero Contract.  On January 24, 2014, we entered into the Antero Contract Second Amendment.  The Antero Contract Second Amendment augmented and amended the pricing terms applicable to up to three conventional fleets provided by us to perform fracturing services for Antero pursuant to the Antero Contract.  The pricing terms set forth in the Antero Contract Second Amendment are effective until April 12, 2017. 

Contract with Inflection Energy LLC.  On September 23, 2013, we entered into a Dedicated Fracturing Fleet Agreement, effective November 1, 2013 (the “Inflection Agreement”), with Inflection Energy LLC (“Inflection”), pursuant to which the Company agreed to provide a dedicated fleet, consisting of certain specified equipment and materials, to perform fracturing services for Inflection in the Marcellus Shale in Pennsylvania. The Inflection Agreement terminates on December 31, 2014, unless terminated earlier pursuant to its terms.

Pursuant to the Inflection Agreement, the Company is to provide a minimum number of stages during the term of the Inflection Agreement. In the event that Inflection does not provide the Company with the minimum number of stages, Inflection will pay the Company an agreed upon dedicated fleet charge per stage for any stage less than the minimum number of stages. If the Company does not provide the minimum number of stages, then the Company will pay Inflection an agreed upon dedicated fleet charge per stage for any stage less than the minimum number of stages. If the Company performs the minimum number of stages, then Inflection has the option to extend the term of the Inflection Agreement. The Company will be paid an agreed upon mobilization fee (applied to the first stage of each pad) and an agreed upon operating rate for the provision of services under the Inflection Agreement. The Inflection Agreement also provides for force majeure payment rates.

Spot Market Projects. Although we have entered into term contractswith Antero and Inflection, we also have the flexibility to pursue spot market projects.  Our agreements with Antero and Inflection allow us to supplement monthly contract revenue by deploying equipment on short-term spot market jobs on those days when Antero or Inflection do not require our services or are not entitled to our services. When providing these types of short-term services we will charge prevailing market

prices 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.

Chemicals and Proppants. 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 a vendor to purchase a hydraulic fracturing fleet to service our original contract with Antero.  This was 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 first fracturing fleet began in February 2012 and were completed in April 2012.

In July and August 2012, we entered into agreements with various 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.

In April 2013, we entered into agreements with various vendors for the purchase of a third hydraulic fracturing fleet. The fleet includes twelve F-2500 Trailer-Mounted Fracturing Units with Quintuplex Pumps with 2,500 brake horsepower ("BHP") per pump, two Trailer Mounted 130bpm Fracturing Blenders, one data van, and one CT 250bbl hydration unit. Delivery of the equipment was completed in May 2013.

In April 2013, we entered into an agreement with a vendor for the purchase of additional fracturing equipment.  The fracturing equipment includes seven FT-2251Q Trailer Mounted Fracturing Units with Quintuplex Pumps with 2,250 BHP per pump, and one MT-132 Trailer Mounted 130bpm Fracturing Blender with AccuFrac System.  Delivery of the equipment was completed in early October 2013.

In October 2013, we entered into agreements with various vendors for the purchase of a fourth hydraulic fracturing fleet. The fleet includes nine Trailer-Mounted Fracturing Units with Quintuplex Pumps with 2,500 BHP per pump, three Trailer Mounted 1,600 BHP Fracturing Blenders, one data van, and one 250bbl hydration unit. Delivery of the equipment was completed in November 2013.

In October 2013, we entered into agreements with various vendors for the purchase of a fifth hydraulic fracturing fleet, which will be a proprietary designed “Clean Fleet.” The Clean Fleet is a proprietary, patent-pending design that incorporates existing industry equipment configured in a novel manner to provide fracturing services at a lower cost with a smaller environmental and physical footprint, as well as with enhanced safety features, compared to traditional fracturing equipment. The Clean Fleet is expected to consist of 16 fracturing pumps and associated heavy equipment powered by electric motors, with electricity produced by mobile turbine generators that can burn a variety of hydrocarbon fuels, including natural gas.We anticipate delivery of the fifth fleet in May 2014.

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.  In addition, we believe that we are well positioned to capitalize on the current 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 sections titled “Cautionary Statement Regarding Forward-Looking Statements” and "Risk Factors" in this Annual Report on Form 10-K 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 United States Environmental Protection Agency (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.  In Colorado and some other states, courts are in the process of determining whether local bans or other regulation of oil and gas exploration and production activity are preempted by state-wide regulatory programs. A state ballot initiative has also been introduced in Colorado that, if successful, would amend the state constitution to give local governments control over oil and natural gas drilling in their areas. In Pennsylvania, the Pennsylvania Supreme Court recently issued a ruling that some local environmental and safety regulations are enforceable under a specific Pennsylvania constitutional amendment, despite existing state regulation of such matters. 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 cost 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, the Sponsor Equity Investment, the offering of additional tack-on Notes  in April 2013 and October 2013, the Credit and Security Agreement pursuant to which the lender agreed to extend credit in the form of  a  revolving credit facility (the “Revolving Credit Facility”), the offering of Series E Units, and cash flows generated from operations to acquire five hydraulic fracturing fleets, with delivery of the fifth fleet expected in May 2014. 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 continue 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

Year ended December 31, 2013vs February 21, 2012 (inception) to December 31, 2012

	Successor				Predecessor
		Year Months		February 21, 2012		January 1, 2012
		Ended		(inception) to		to
		December 31, 2013		December 31, 2012		February 20, 2012
		(unaudited)		(unaudited)		(unaudited)
Revenue	$	174,312,102	$	52,134,830	$	-
Costs and expenses:
Cost of services		127,723,228		43,008,477		-
Depreciation and amortization		13,379,692		6,310,943		-
Selling, general and administrative expenses		9,389,378		3,783,989		432,773
Other operating expenses		-		-		40,587
Income (loss) from operations		23,819,804		(968,579)		(473,360)
Interest expense, net		(17,934,335)		(16,960,349)		-
Other income		145,746		-		-

Income (loss) before income taxes		6,031,215		(17,928,928)		(473,360)
Income tax expense		-		-		-
Net income (loss)	$	6,031,215	$	(17,928,928)	$	(473,360)

Revenues increased $122.2 million, or 234.3%, to $174.3 million for the year ended December 31, 2013 from $52.1 million for the period from February 21, 2012 (inception) to December 31, 2012. The increase is primarily due to increased hydraulic fracturing activity with four fleets being operational by the end of 2013, as compared to only two fleets in service for the period from February 21, 2012 to December 31 2012, with the second fleet only operational beginning in August 2012.

Cost of services for the year ended December 31, 2013 increased $84.7 million, or 197.0%, to $127.7 million from $43.0 million for the period from February 21, 2012 (inception) to December 31, 2012. The increase was a direct result of increased hydraulic fracturing activity. 

Depreciation and amortization increased $7.1 million, or 112.0%, to $13.4 million for the year ended December 31, 2013 from $6.3 million for the period from February 21, 2012 (inception) to December 31, 2012. The increase is primarily due to depreciation expense for four fleets compared to only two fleets for the period from February 21, 2012 to December 31, 2012.

Selling, general and administrative expenses increased $5.6 million, or 148.1%, to $9.4 million during the year ended December 31, 2013 from $3.8 million during the period from February 21, 2012 (inception) to December 31, 2012. The increase was primarily due to vesting of unit-based awards, professional fees and settlement of litigation.

Interest expense for theyear ended December 31, 2013 increased $1.0 million, or 5.7%, to $17.9 million from $17.0 million for the period from February 21, 2012 (inception) to December 31, 2012. The increase is primarily due to increased debt balance with the issuance of $12.0 million in aggregate principal amount of Notes in April 2013 (the “April 2013 Additional Notes”) and $46.0 million in aggregate principal amount of Notes in October 2013 (the “October 2013 Additional Notes”).

The operating activities of our predecessor for the period from January 1, 2012 to February 20, 2012, primarily consisted of start-up activities. Consequently, no revenues were earned during this period. Selling, general and administrative expenses for the period from January 1, 2012 to February 20, 2012 were $0.4 million and were primarily for salaries and wages to officers and various professional fees.

Liquidity and Capital Resources

Our primary sources of liquidity were the proceeds we received in February 2012 from the Unit Offering, the Sponsor Equity Investment, the proceeds we received in April 2013 for the offering of April 2013 Additional Notes, the Revolving Credit Facility, the proceeds we received in October 2013 for the offering of October 2013 Additional Notes, the proceeds from the issuanceof the Series E Units, and cash flows generated from operations.  Our primary uses of capital have been the acquisition of our four hydraulic fracturing fleets, downpayments for a fifth fleet, working capital requirements, and interest payments.  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, 2013, we had a balance of cash and cash equivalents totaling approximately $45.5 million.  

While we continue to be 100% leveraged as of December 31, 2013, we have no scheduled debt maturities on our 14.50% Senior Secured Notes due 2017 in 2014. Additionally, subsequent to December 31, 2013 we have redeemed the Series A Units using the proceeds from the issuance of the SMRF Interests,which has no scheduled maturities within the next one to three years.

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, our available borrowing capacity from our Revolving Credit Facility, and future cash flows from operating activities related to our five 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 contract with Antero continues, as we gain new customers, such as Inflection, and as 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 budget of approximately $50.4 million for 2014, which primarily relates to the acquisition of the fifth hydraulic fracturing fleet.  

Our capital expenditure 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 2014 will be subject to covenants under our indenture governing our Notes and the Credit Agreement, 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.

Contractual Obligations

The following table summarizes our future contractual cash obligations as of December 31, 2013. Certain amounts included in this table are based on our estimates and assumptions about these obligations, including their duration, anticipated actions by third parties and other factors. The contractual cash obligations we will actually pay in future periods may vary from those reflected in the table because the estimates and assumptions are subjective.

	Payments Due by Period
		Total		Less than 1 year		1 - 3 years		4 - 5 years		After 5 years
14.50% Senior Secured Notes due 2017 (the "Notes') (1)	$	126,414,660	$	-	$	-	$	126,414,660	$	-
Interest associated with the Notes (2)		64,155,440		18,330,126		36,660,251		9,165,063		-
Equipment financing agreement		1,356,591		482,806		873,785		-		-
Interest associated with Equipment financing agreement		124,284		73,664		50,620		-		-
Redeemable Series A Units (3)		29,994,000		-		-		29,994,000		-
Interest associated with the Redeemable Series A Units (3)		26,213,401						26,213,401
Borrowings under Revolving credit facility		-		-		-		-		-
Non-cancelable operating leases (4)		1,440,102		743,549		655,684		40,869		-
Equipment purchase commitment (5)		42,256,438		42,256,438		-		-
Other purchase commitment (6)		3,718,750		3,718,750		-		-		-
	$	295,673,666	$	65,605,333	$	38,240,340	$	191,827,993	$	-
(1) Amounts represent the expected cash payments for the principal amounts related to our Notes. Amounts do not include the $2.5 million treasury bonds held by USWS, the unamortized discounts or deferred issuance costs. Expected cash payments for interest are excluded from these amounts.
(2) Amounts represent the expected cash payments for interest on our Notes.
(3) Amount was refinanced in February 2014 for the 100% redemption of the principal amount and accrued interest related to the Series A Units. The Series A Units were redeemed through the proceeds from the issuance of the SMRF Interests of approximately $30.0 million on February 18, 2014. The SMRF Interests are due on the earlier of May 17, 2017 or upon the occurrence of a liquidation event.
(4) Non-cancelable operating leases consist of agreements in excess of one year for office space.
(5) Equipment purchase commitment relates to agreements we entered into with various vendors for the construction of a fifth hydraulic fracturing fleet, which we anticipate will be delivered in May 2014.
(6) Other purchase commitment relates to our sand purchase agreement that specifies all significant terms, including: minimum quantities to be purchased at a fixed price, and the approximate timing of the transaction.

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
		Year Months		February 21, 2012		January 1, 2012
		Ended		(inception) to		to
		December 31, 2013		December 31, 2012		February 20, 2012
Cash flow provided by (used in):		(unaudited)		(unaudited)		(unaudited)
Operating activities	$	25,521,720	$	(3,835,487)	$	-
Investing activities		(59,317,208)		(66,055,460)		-
Financing activities		67,434,091		81,702,662		-
Change in cash and cash equivalents	$	33,638,603	$	11,811,715	$	-

Cash Provided By (Used In) Operating Activities.  Net cash provided by operating activities was $25.5 million for the year ended December 31, 2013 compared to operating cash outflows of $3.8 million for the period February 21, 2012 (inception) through December 31, 2012. The increase was due primarily to improved operating activity, as a result of four fleets being operational by the end of 2013, as compared to only two fleets in service during the period from February 21, 2012 to December 31, 2012.

Cash Flows Used in Investing Activities.  Net cash used in investing activities for the year ended December 31, 2013 was $59.3 million and was primarily due to the acquisition of the third and fourth hydraulic fracturing fleet. Investing cash outflows for the period from February 21, 2012 (inception) through December 31, 2012 was $66.1 million, which primarily relates to the acquisition of the first and second fleets.

Cash Flows Provided by Financing Activities.  Net cash provided byfinancing activities for the year ended December 31, 2013 was $67.4 million and was due primarily to proceeds from the issuance of April 2013 Additional Notes and October 2013 Additional Notes, and proceeds from the issuance of the Series E Units.

Net cash provided by financing activities was $81.7 million for the period February 21, 2012 (inception) through December 31, 2012 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 repurchase and retirement of $21,066,046 aggregate principal amount of the Notes on August 12, 2012.  

Off-Balance Sheet Arrangements

As of December 31, 2013, we had no off-balance sheet arrangements other than the operating leases discussed in Note 12 - Commitments and Contingencies in the notes to our 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 the awards is estimated using the Black-Scholes option-pricing model, or probability-weighted discounted cash flow model and market valuation approaches. These valuation models require 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, the April 2013 Additional Notes, the October 2013 Additional Notes, and Fixed Rate LIBOR Loans on our Revolving Credit Facility, 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	37
Consolidated Balance Sheets	38
Consolidated Statement of Operations	39
Consolidated Statement of Cash Flows	40
Consolidated Statement of Stockholders’ Equity/Members’ Equity	42
Notes to Consolidated Financial Statements	43

Report of Independent Registered Public Accounting Firm

The Board of Managers

U.S. Well Services, LLC

We have audited the accompanying consolidated balance sheets of U.S. Well Services, LLC (Successor)  as of December 31, 2013 and 2012 and the related consolidated statements of operations, members' equity, and cash flows for the year ended December 31, 2013 and for the period from February 21, 2012 (inception) to December 31, 2012, and the related statements of operations, stockholders' equity, and cash flows of U.S. Well Services, Inc. (Predecessor) for the period from 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, 2013 and 2012, and the results of its operations and its cash flows for the year ended December 31, 2013, and for the period from February 21, 2012 (inception) to December 31, 2012, and the results of U.S. Well Services, Inc.’s (Predecessor) operations and cash flows for the period from January 1, 2012 to February 20, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Houston, Texas

March 28, 2014

U.S. WELL SERVICES, LLC

CONSOLIDATED BALANCE SHEETS

	December 31,		December 31,
	2013		2012
ASSETS
Current assets:
Cash and cash equivalents	$	45,450,318	$	11,811,715
Restricted cash		-		166,205
Accounts receivable		26,048,354		8,010,321
Inventory		3,859,163		3,355,213
Prepaids and other current assets		1,508,272		1,154,672
Total current assets		76,866,107		24,498,126
Property and equipment, net		116,919,464		61,780,627
Deferred financing costs		6,395,472		4,723,049
TOTAL ASSETS	$	200,181,043	$	91,001,802
LIABILITIES, MEZZANINE EQUITY & MEMBERS' EQUITY
Current liabilities:
Accounts payable	$	15,837,341	$	3,290,358
Accrued liabilities		9,948,785		1,859,152
Accrued interest		6,880,069		3,657,984
Current portion of long-term debt		482,806		415,070
Total current liabilities		33,149,001		9,222,564
Long-Term Debt		122,201,688		65,484,582
Redeemable Series A Units, 600,000 units authorized, issued and outstanding		29,994,000		29,994,000
Accrued interest, non-current		7,938,917		3,461,260
TOTAL LIABILITIES		193,283,606		108,162,406
Commitments and Contingencies
MEZZANINE EQUITY:
Redeemable Series E Units, 663,195 units subscribed; redemption value $14 million plus accrued and unpaid dividends at December 31, 2013		14,374,111		-
MEMBERS' EQUITY:
Members' interest		4,795,150		768,324
Accumulated deficit		(12,271,824)		(17,928,928)
Total Members' Equity		(7,476,674)		(17,160,604)
TOTAL LIABILITIES, MEZZANINE EQUITY & MEMBERS' EQUITY	$	200,181,043	$	91,001,802

See accompanying notes to consolidated financial statements.

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

	Successor				Predecessor
		Year		February 21, 2012		January 1, 2012
		Ended		(inception) to		to
		December 31, 2013		December 31, 2012		February 20, 2012
Revenue	$	174,312,102	$	52,134,830	$	-
Costs and expenses:
Cost of services		127,723,228		43,008,477		-
Depreciation and amortization		13,379,692		6,310,943		-
Selling, general and administrative expenses		9,389,378		3,783,989		432,773
Other operating expenses		-		-		40,587
Income (loss) from operations		23,819,804		(968,579)		(473,360)
Interest expense, net		(17,934,335)		(16,960,349)		-
Other income		145,746		-		-
Income (loss) before income taxes		6,031,215		(17,928,928)		(473,360)
Income tax expense		-		-		-
Net income (loss)	$	6,031,215	$	(17,928,928)	$	(473,360)

See accompanying notes to consolidated financial statements.

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Successor				Predecessor
		Year		February 21, 2012		January 1, 2012
		Ended		(inception) to		to
		December 31, 2013		December 31, 2012		February 20, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	6,031,215	$	(17,928,928)	$	(473,360)
Adjustments to reconcile net income (loss) to cash used in operating activities:
Depreciation and amortization		13,379,692		6,310,943		-
Loss on disposal of asset		22,743		-		-
Loss on extinguishment of debt		-		2,638,570		-
Bond discount amortization		422,658		246,740		-
Deferred financing costs amortization		1,421,875		1,156,103		-
Unit-based compensation expense		4,026,826		280,901		-
Changes in assets and liabilities:		-
Accounts receivable		(18,038,033)		(8,010,321)		-
Inventory		(503,950)		(3,355,213)		-
Prepaids and other current assets		(353,600)		(1,154,672)		-
Accounts payable		3,322,919		2,605,788		-
Accrued liabilities		8,089,633		1,774,651		473,360
Accrued interest		7,699,742		11,599,951		-
Net cash provided by (used) in operating activities		25,521,720		(3,835,487)		-
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment		(59,349,130)		(66,055,460)		-
Insurance proceeds from damaged property and equipment		31,922		-		-
Net cash used in investing activities		(59,317,208)		(66,055,460)		-
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of note payable		1,748,721		2,023,019		-
Repayments of note payable		(1,748,721)		(2,023,019)
Proceeds from issuance of long-term debt		57,309,600		80,287,200		-
Repayments of long-term debt		(416,916)		(23,744,149)		-
Proceeds from issuance of Series E Units		14,000,000		-		-
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		(3,094,298)		(3,824,677)		-
Consent fee paid to bondholders		(530,500)		(850,000)		-
Restricted cash		166,205		(166,205)		-
Net cash provided by financing activities		67,434,091		81,702,662		-
Net increase (decrease) in cash and cash equivalents		33,638,603		11,811,715		-
Cash and cash equivalents, beginning of period		11,811,715		-		-
Cash and cash equivalents, end of period	$	45,450,318	$	11,811,715	$	-

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)

	Successor				Predecessor
	Year		February 21, 2012		January 1, 2012
	Ended		(inception) to		to
	December 31, 2013		December 31, 2012		February 20, 2012
Supplemental cash flow disclosure:
Interest paid	$	10,918,267	$	1,613,736	$	-
Non-cash investing and financing activities:
Accrued and unpaid capital expenditures	$	9,224,064	$	84,500	$	-
Increase in bond principal 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	$	-

See accompanying notes to consolidated financial statements.

U.S. WELL SERVICES, LLC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/MEMBERS’ EQUITY

						Deficit
						Accumulated		Total
Predecessor:	Common Stock			Additional		during		Stockholders'
	Units	Amount		Paid-In Capital		Development		Equity
BALANCE, January 1, 2012	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							Total
	Series Units			Members'		Accumulated		Members'
	Units	Amount		Interest		Deficit		Equity
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)
Accrued preferred return on Series E Units	-		-		-		(374,111)		(374,111)
Unit-based compensation	130,294		-		4,026,826		-		4,026,826
Net income	-		-		-		6,031,215		6,031,215
BALANCE, December 31, 2013	980,294	$	6,493	$	4,788,657	$	(12,271,824)	$	(7,476,674)

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. ("USW Finance") 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 "Original Notes") 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 Corporation (“Antero”), commencing on April 12, 2012 to perform hydraulic fracturing services in the Marcellus and Utica Shales in Ohio, West Virginia and Pennsylvania (the “Original Antero Contract”). Prior to beginning operations in the second quarter of 2012, the Company was in the development stage.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

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”).

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 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.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

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 or recoverable cost. 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.

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.

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, 2013:  

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 dates.  

14.50% 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, 2013. The carrying value of these notes as of December 31, 2013 was $126.4 million, and the fair value was $128.9 million (102.0% of carrying value). The carrying value of these notes as of December 31, 2012 was $68.4 million, and the fair value was $62.9 million (92.0% of carrying value).

Redeemable Series A Units. The fair value of the Redeemable Series A Units is estimated using discounted cash flow methodology based on Level 3 inputs. The accreted value of the Redeemable Series A Units was $37.9 million and $33.5 million as of December 31, 2013 and 2012, respectively. The fair value of the Redeemable Series A Units was $36.0 million (95% of the accreted value) and $29.1 million (87% of the accreted value) as of December 31, 2013 and 2012, respectively.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

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, 2013.

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.

Antero accounted for approximately 86.0% and 90.2% of our consolidated revenues for the year ended December 31, 2013 and 2012, respectively. No customer other than Antero accounted for more than 10% of our consolidated revenues during the year ended December 31, 2013 and the period from February 21, 2012 (inception) through December 31, 2012.

Receivables outstanding from Antero were approximately 79.9% and 43.6%of our total accounts receivable as of December 31, 2013. One other customer accounted for approximately 19.8% of our total accounts receivable as of December 31, 2013.  One other customer accounted for approximately 56.3% of our total accounts receivable as of 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 the awards is estimated using the Black-Scholes option-pricing model, or probability-weighted discounted cash flow model and market valuation approaches. 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

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

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 3 – PROPERTY AND EQUIPMENT

Property and equipment consisted of the following:

	Estimated
	Useful Lives	December 31, 2013		December 31, 2012
Fracturing equipment	7 years	$	109,469,988	$	63,491,282
Light duty vehicles	5 years		2,436,378		1,512,144
Furniture and fixtures	5 years		116,361		84,435
IT equipment	3 years		601,806		192,061
Auxiliary equipment	2 to 20 years		4,141,753		2,404,156
Leasehold improvements	Term of lease		470,081		407,492
Construction in progress			-		-
Non-refundable deposits on equipment			19,347,479		-
			136,583,846		68,091,570
Less: accumulated depreciation and amortization			(19,664,382)		(6,310,943)
Property and equipment, net		$	116,919,464	$	61,780,627

Depreciation and amortization expense for the year ended December 31, 2013 was $13,379,692. Depreciation and amortization expense for the period February 21, 2012 (inception) through December 31, 2012 was $6,310,943.  

The Company capitalized interest of $735,039 for the year ended December 31, 2013 and $248,226 for the period February 21, 2012 (inception) through December 31, 2012.  

NOTE 4 – SHORT-TERM NOTE PAYABLE

On March 15, 2013, the Company obtained insurance for its general liability, workers' compensation, 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 is $1,748,721 at an interest rate of 3.9%.  Under the terms of the agreement, the Company has agreed to pay 9 equal monthly payments of $197,473 beginning April 15, 2013 through maturity on December 15, 2013.  The note was fully repaid as of December 31, 2013.

NOTE  5 – REVOLVING CREDIT FACILITY

On May 9, 2013, we entered into a Credit and Security Agreement, as amended by the First Amendment to Credit and Security Agreement and the Second Amendment to Credit and Security Agreement (collectively, the “Credit Agreement”) with Wells Fargo Bank, National Association (the “Lender”) pursuant to which the Lender agreed to extend credit to us in the form of a revolving credit facility up to $15.0 million (the “Revolving Credit Facility”). The Revolving Credit Facility includes a sublimit for the issuance of letters of credit in an aggregate amount of up to $1.0 million.OnNovember 14, 2013,the First Amendment to Credit and Security Agreement became effective,  pursuant to which the Lender agreed to increase the Company’s borrowing base from $7.5 million to $15.0 million.

The Lender will make revolving loans (“Loans”) by way of Fixed Rate LIBOR Loans and Variable Rate LIBOR Loans to the Company in aggregate amounts outstanding at any time not to exceed an amount (the “Borrowing Base”) that is the lesser of (i) $15.0 million less the sum of (A) the aggregate undrawn amount of all outstanding letters of credit, and (B) the aggregate amount of outstanding reimbursement obligations with respect to letters of credit, which remain unreimbursed or which have not been paid through a Loan, or (ii) an amount equal to the result of: (A) the lesser of (y) 85% (less the amount, if any, of the

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

Dilution Reserve (as defined in the Credit Agreement), if applicable) of the amount of Eligible Accounts (as defined in the Credit Agreement), and (z) $15.0 million, minus (B)$500,000, as such amount may be adjusted by the Lender from time to time, in its sole discretion, minus (C) the aggregate amount of Reserves (as defined in the Credit Agreement), if any, established by the Lender in its Permitted Discretion (as defined in the Credit Agreement). Loans may be repaid by the Company and, subject to the terms and conditions of the Credit Agreement, reborrowed at any time during the term of the Credit Agreement.

The interest rate per annum on the Revolving Credit Facility is equal to (i) at our option, (A) the daily three month LIBOR with respect to Variable Rate LIBOR loans, which interest rate shall change whenever daily three month LIBOR changes, or (B) LIBOR for the specified interest period with respect to Fixed Rate LIBOR loans, and (ii) the applicable margin. The applicable margin is determined as one percentage point when the Interest Rate is based on the Prime Rate, or three percentage points with respect to Fixed Rate LIBOR loans or Variable Rate LIBOR loans. 

The Credit Agreement contains financial covenants, which require us to:

maintain a fixed charge coverage ratio, measured monthly on a trailing twelve-month basis at the end of each month, commencing no later than the month ended May 31, 2014, of not less than 1.0:1.0.

     maintain (i) liquidity of at least $5 million, (ii) gross availability of at least $1 million, and (iii) cash plus availability of at least $1 million, in each case, at all times during the period commencing on August 1, 2013, through and including the date upon which the Company has maintained a fixed charge coverage ratio of not less than 1.0:1.0 for two consecutive calendar months.  After the Company has maintained a fixed charge coverage ratio of not less than 1.0:1.0 for two consecutive calendar months, the Lender shall not test the covenants set forth in Section 8.1(b) of the Credit Agreement regarding maintenance of liquidity, gross availability and cash plus availability.

All obligations of the Company under the Credit Agreement are secured by a continuing security interest in all of the Company's right, title, and interest in and to substantially all of the Company's assets.

All of the Company's obligations outstanding under the Credit Agreement shall be payable in full on the earliest of (i) May 9, 2017, or (ii) ninety days prior to the maturity date of the Company's 14.50% Senior Secured Notes due 2017, or (iii) ninety days prior to the maturity date of the Company's Senior Mandatorily Redeemable Financial Interests, or (iv) the date the Company terminates the Revolving Credit Facility, or (v) the date the Revolving Credit Facility terminates pursuant to the Credit Agreement following an Event of Default.

As of December 31, 2013, we had no borrowings outstanding under the Revolving Credit Facility, leaving $14.5 million of available borrowing capacity under our current Borrowing Base.

NOTE  6 – LONG TERM DEBT

Long-term debt consisted of the following:

	December 31,		December 31,
	2013		2012
Senior Secured Notes	$	126,414,660	$	68,414,660
Equipment financing agreement		1,356,591		1,773,507
Less current maturities of long-term debt		(482,806)		(415,070)
Unamortized discount on Senior Secured Notes		(2,586,757)		(1,788,515)
Treasury bonds		(2,500,000)		(2,500,000)
Total long-term debt	$	122,201,688	$	65,484,582

Senior Secured Notes.On October 18, 2013, the Company completed the issuance and sale of $46.0 million in aggregate principal amount of 14.50% Senior Secured Notes due 2017 (the “October 2013 Additional Notes” and together with the Original Notes and the April 2013 Additional Notes (as defined below), the "Notes").  On April 10, 2013, the Company completed an offering of $12.0 million in aggregate principal amount of 14.50% Senior Secured Notes due 2017 (the "April 2013 Additional Notes"). We issued the October 2013 Additional Notes and the April 2013 Additional Notes as additional notes under the Indenture dated February 21, 2012 (the “Base Indenture”), by and among us, the guarantors party thereto, and

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

The Bank of New York Mellon Trust Company, N.A., as trustee and collateral agent, as supplemented by that First Supplemental Indenture dated as of July 16, 2012 (the “First Supplemental Indenture”), and as further supplemented by that Second Supplemental Indenture dated as of April 10, 2013 (the “Second Supplemental Indenture”) and by that Third Supplemental Indenture dated as of October 18, 2013 (the “Third Supplemental Indenture” and, together with the Base Indenture, the First Supplemental Indenture and the Second Supplemental Indenture, the “Indenture”). On February 21, 2012, we issued $85.0 million aggregate principal amount of the Original Notes under the Base Indenture. In August 2012, we repurchased and retired $21,066,046 aggregate principal amount of the Original Notes (the “Second Contract Repurchase”) and made our first interest payment on the Original Notes by increasing the principal amount of the outstanding notes by $4,480,706. In November 2012, we repurchased but did not retire $2.5 million aggregate principal amount of the Original Notes. As of December 31, 2013, we had outstanding $126.4 million aggregate principal amount of 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.  Accrued interest on the Notes was $6,873,797 at December 31, 2013.  

Our sole subsidiary, USW Finance, 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.  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 but not including March 31, 2014, 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.

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, 2013, the financing agreement had a balance of $1,356,591, of which $482,806 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, 2013:

		Principal Amount of Long-term Debt
2014	$	482,806
2015		515,089
2016		358,696
2017		126,414,660
		127,771,251
Treasury bonds		(2,500,000)
Unamortized discount on Senior Secured Notes		(2,586,757)
Less current maturities on long-term debt		(482,806)

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

Total long-term debt $ 122,201,688 

NOTE 7 - REDEEMABLE SERIES A UNITS

As part of the Sponsor Equity Investment, the Company authorized and issued600,000 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 (the “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 which 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.

The Series A Units have an optional redemption feature pursuant to which, 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 include a date certain redemption feature)that unconditionally obligate 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, 2013, 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 $7,938,917.  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 of $29,994,000 and interest to be accrued of $26,213,401.

As discussed in Note 13 – Subsequent Events, the Company redeemed all of its 600,000 Series A Units in February 2014.  

NOTE 8 - REDEEMABLE SERIES E UNITS (MEZZANINE EQUITY)

Concurrently with the issuance and sale of the October 2013 Additional Notes, the Company entered into a subscription agreement (the “Series E Subscription Agreement”) with one of our existing investors and an affiliate thereof. Pursuant to the Series E Subscription Agreement, the investors agreed to purchase, and the Company agreed to issue, $14.0 million of Series E Units, provided that the number of Series E Units to be issued to such investors will be subject to reduction as a result of any other participating investors.  The Series E Units are governed by and issued pursuant to the First Amendment to the Company Agreement adopted on February 10, 2014 but made effective as of October 18, 2013,  which, among other things, entitles the holders of Series E Units to a 13% preferred return on their equity contribution compounded semiannually and payable upon the occurrence of certain liquidation or exit events. The investors contributed the $14.0 million in cash on October 13, 2013. As discussed in Note 13 – Subsequent Events, 663,195 Series E Units were issued to the investors on February 10, 2014.

Because of the preferred nature of the Series E Units (which include redemption features outside the control of the issuer and do not include a date certain redemption feature) that unconditionally obligates the Company to provide each holder an internal rate of return of 13% on their investment, the Series E Units meet the condition for temporary or “Mezzanine Equity” classification.

At December 31, 2013, the redemption value of the Series E Units amounted to $14,374,111, which includes the face value of the units subscribed of $14,000,000 and unpaid dividends in the amount of $374,111. 

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

NOTE 9 – MEMBERS’ INTEREST

As of December 31, 2013, the Company’s equity consisted 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 8 - 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 generally do not have. Series D Units granted to certain officers have anti-dilution protections. 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, and are granted to certain officers and employees of the Company as performance incentives.  See Note 10 - Unit-Based Compensation for further discussion of the Series D Units.

As of December 31, 2013 and December 31, 2012, there were 630,000 Series B Units and192,500 Series C Units issued and outstanding. Series D Units issued and outstanding were 157,794 and 27,500 as of December 31, 2013 and 2012, respectively.

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 warrants have anti-dilution protections. The warrants became exercisable after they separated from the Notes on April 21, 2012 and will expire on February 21, 2019.  As of December 31, 2013, none of these warrants had been exercised.

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.

NOTE 10 – UNIT-BASED COMPENSATION

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. 

In October and November 2013, the Company entered into Amended and Restated Series D Unit agreements (“Amended Agreements”) with certain officers and key employees, pursuant to which 110,088 units became vested upon the execution of the Amended Agreements. Compensation related to the vested Series D Units was recognized equal to the fair market value of the units at the date of the Amended Agreements,as the amendment is treated as a modification due to the units not vesting under the original performance condition.Fair value is determined using probability-weighted discounted cash flow model and market valuation approaches. A total of 65,064 units remain unvested until the occurrence of a liquidation or exit event. The vesting of such Series D Units triggered certain anti-dilution protections granted to the holders of our Series B Units in our Company Agreement and certain of our executive officers in their Series D Unit Agreements.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

During the year ended December 31, 2013, we recognized unit-based compensation expense totaling $4,026,826,  of which $2,204,775 was included in cost of services and $1,822,051 was included in selling, general and administrative expenses. For the period from February 21, 2012(inception) to 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.

As of December 31, 2013, the total unrecognized compensation cost related to unvested awards was approximately $246,780, which is expected to be recognized over a weighted-average period of 0.71 years.

The following table summarizes the information for the year ended December 31, 2013 and for the period from February 21, 2012 (inception) to December 31, 2012 about the unit-based awards:

	Year ended December 31, 2013
		Weighted-average				Weighted-average
	Unvested	grant-date fair value			Vested	grant-date fair value
Units at beginning of period	235,771	$	7.77		27,500	$	7.77
Granted	-		-		-		-
Vested	(130,294)		30.94		130,294		30.94
Forfeited	-		-		-		-
Units at end of period	105,477	$	22.06	(1)	157,794	$	26.90
(1) 40,413 units valued at $7.77/share, and 65,064 units valued at $30.94/share due to the Amended Agreements.
	February 21, 2012 (inception) to December 31, 2012
		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 estimated the fair value at the grant date of the 2012 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	51.60%
Expected dividend yield	0%

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.

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

NOTE 11 – EMPLOYEE BENEFIT PLAN

On March 1, 2013, the Company established the U.S. Well Services 401(k) Plan. We match 100% of employee contributions up to 6% of the employee’s salary, subject to cliff vesting after two years of service. Our matching contributions were $459,266 for the year ended December 31, 2013. 

NOTE 12 – 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 WellServices, 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 upthe Company's predecessor. Further, Calfrac sought actual and compensatory damages in connection with allegations of breachof contract and certain duties by certain of the Company's officers. On June 28, 2013, the Company entered into a settlementagreement and mutual release with Calfrac. The Company recorded a loss relating to the settlement during the second quarter of2013.

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 year ended December 31, 2013, the total amount purchased under the agreement was $15.7 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.

On December 9, 2013, we entered into an agreement for the lease of a 24,600 square foot building on approximately 4.03 acres in Muncy, Pennsylvania for our fleet operations.  The total amount of monthly payments over the term of 24 months beginning January 8, 2014 is $660,000.

Rent expense for the year ended December 31, 2013 was $417,333, of which $321,735 is recorded as part of Cost of Services and $95,598 is recorded as part of Selling, General and Administrative expenses in the Statements of Operations. 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.

The following is a schedule by years of minimum future rentals on noncancelable operating leases as of December 31, 2013:

2014	$	743,549
2015		515,560
2016		140,124
2017		40,869

U.S. WELL SERVICES, LLC

Notes to Consolidated Financial Statements

December 31, 2013

Total minimum future rentals $ 1,440,102 

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 13 – SUBSEQUENT EVENTS

Amendments to the Company Agreement

On February 10, 2014, the Company adopted a First Amendment to the Amended and Restated Limited Liability Company Agreement of the Company (the “First Amendment to Company Agreement”), which was made effective as of October 18, 2013.  Pursuant to the First Amendment to Company Agreement,the Company issued the663,195 Series E Units that were subscribed for pursuant to a subscription agreement in October 2013.

On February 18, 2014, the Company adopted a Second Amendment to the Amended and Restated Limited Liability Company Agreement of the Company (the “Second Amendment to Company Agreement”), pursuant to which a new series of membership interest, the SMRF Interests was issued.We received approximately $30 million in aggregate gross proceeds in exchange for 760,000 SMRF Interests issued. We used the proceeds from the issuance of the SMRF Interests to redeem the Series A Units.

Redemption of Series A Units

On February 18, 2014, the Company purchased from ORB, and ORB sold to the Company, all of its 600,000 Series A Units in exchange for an amount equal to $30.0 million less all related fees and expenses incurred by the Company (the “Series A Redemption”).  Following the Series A Redemption, there are no Series A Units of the Company issued and outstanding.

Amendment to the Credit Agreement

On February 18, 2014, the Company entered into a Second Amendment (the “Second Amendment to Credit Agreement”) to Credit and Security Agreement (as amended from time to time, including the Second Amendment to Credit Agreement, the “Credit Agreement”) with Wells Fargo Bank, National Association (the “Lender”), pursuant to which the Lender agreed to (i) consent to (A) the adoption of the Second Amendment to Company Agreement to implement the issuance of the SMRF Interests and (B) the consummation of the Series A Redemption and (ii) make certain amendments to the Credit Agreement in connection with such transactions.

Equipment Purchase Commitment

In March 2014, we entered into an agreement with a vendor for the purchase of additional hydraulic fracturing equipment, amounting to approximately $4.9 million. We made an initial down payment of  $1.2 million for the equipment on March 12, 2014.  Delivery of the equipment is expectedto be completed in April 2014.

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

We implemented a new Enterprise Resource Planning (“ERP”) system on October 1, 2013. This implementation has resulted in certain changes to business processes and internal controls impacting financial reporting. We believe that the new ERP system and related changes to internal controls will enhance our internal controls over financial reporting. We have taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of system change and will continue to evaluate the operating effectiveness of related controls during subsequent periods.

Other than the implementation of our new ERP system discussed above, there were no changes in our internal control over financial reporting during the last quarter of 2013 that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. As defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, internal control over financial reporting is a process designed by, or under the supervision of, a company’s principal executive and principal financial officers, and effected by a company’s board of managers, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

The Company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records, that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of the Company’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management conducted an evaluation of the effectiveness of our internal control over financial reporting using the framework in Internal Control—2013 Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based upon the evaluation under this framework, management concluded that our internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the SEC that permit the Company to provide only management’s report in this annual report.

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.................................	58	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...............................	62	Chairman of the Board of Managers
Matthew Bernard	42	Member of the Board of Managers
Joel Broussard.................................	47	Member of the Board of Managers
Gregg H. Falgout	55	Member of the Board of Managers
Steve Orlando.................................	58	Member of the Board of Managers
Todd Danos...................................	51	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 Stewarthas 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 Universityin 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.

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.

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, Mr. Broussard is owner of Gulf Offshore Logistics, L.L.C., a provider of offshore service vessels and vessel brokerage services primarily in the Gulf of Mexico. 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 of Texas and is currently a member of the Western Region Advisory Board of the Northern Trust Corporation. 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.

Steve Orlandohas been a member of our Board of Managers since May 2012. Mr. Orlando is 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.

Todd Danos has been a member of our Board of Managers since March 2014. Mr. Danos co-founded Gulf Offshore Logistics, LLC in 2003 and serves as its Marketing Director. Mr. Danos also manages the sales force and oversees the daily vessel traffic activities and pricing decisions. Prior to founding Gulf Offshore Logistics, LLC, Mr. Danos worked at Galliano Tugs, a family business engaged in the offshore tug boat business. Mr. Danos has served on the Board of Directors of the Offshore Marine Service Association for seven years and on the Board of Directors of the Coalition of Maritime Employers of Louisiana for two years, in addition to lobbying on behalf of the maritime industry through his work with the Louisiana Association of Business and Industry.

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 Todd Danos.  

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 and Mr. Dupre.

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 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 2013.

Name and Principal Position	Year	Salary		Bonus		Equity Awards (5)		Option Awards	Non-equity incentive plan compensation		Nonqualified deferred compensation earnings		All other compensation (6)		Total
Brian Stewart - President and CEO (1)	2013	$	300,937	$	-	$	-	$	$	-	$	-	$	3,000	$	303,937
	2012		148,958		-		269,906			-		-		1,845		420,709
Kenneth Sill - CFO (2)	2013		250,000		-		-			-		-		3000		253,000
	2012		70,192		-		201,103			-		-		960		272,255
Jeffrey McPherson - Vice President of Operations (3)	2013		209,167		-		1,433,234			-		-		3,000		1,645,400
	2012		233,333		-		77,700			-		-		3,720		314,753
Edward S. Self III -Vice President of Business Development (4)	2013		200,000		-		1,433,234			-		-		3,000		1,636,234
	2012		233,333		-		77,700			-		-		3,720		314,753
(1)     Employed as President and CEO on June 18, 2012.
(2)     Employed as CFO on September 19, 2012.
(3)     Employed as Vice President of Operations on February 21, 2012.
(4)     Employed as Vice President of Business Development on February 21, 2012.
(5)     The amount in this column reflects the grant date fair value of all unit awards 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-10. Unit-Based/Share-Based Compensation” for further information.
(6)   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.  On December 1, 2013, we provided notice to Mr. McPherson extending the term of his employment through December 31, 2014. Pursuant to the employment agreement, we are required to pay Mr. McPherson an annual base salary of $225,000 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 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. On December 1, 2013, we provided notice to Mr. Self extending the term of his employment through December 31, 2014.  Pursuant to the employment agreement,we are required to pay Mr. Self an annual base salary of $225,000 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 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 vested 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 vested 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 “Original McPherson Equity Agreement”).  The Series D Units are intended to constitute “profits interests” under the Code.  On November 8, 2013 (the “Execution Date”), we entered into an Amended and Restated Series D Unit Agreement with Mr. McPherson (the “McPherson Amended and Restated Equity Agreement”),  which was made effective as of the date of the Original McPherson Equity Agreement.Pursuant to the McPherson Amended and Restated Equity Agreement, of the 84,493 Series D Units granted to Mr. McPherson, two thirds (66.66%) vested on the Execution Date. The remaining one third (33.34%) will vest upon the occurrence of a liquidation event or an exit event.If Mr. McPherson’s employment with the Company is terminated for any reason, then Mr. McPherson will forfeit to the Company all of his unvested Series D Units on the date of such termination.  The McPherson Amended and Restated Equity Agreement also provides that during the term of Mr. McPherson’s employment with the Company and for two years after the termination of Mr. McPherson’s employment (for whatever reason), Mr. Self will not compete with us or solicit our customers or employees.  If Mr. McPherson breaches the non-competition and non-solicitation covenants in the McPherson Amended and Restated Equity Agreement, then he will forfeit to the Company all of his vested Series D Units.

On February 11, 2014, we executed a Series D Unit Agreement with Mr. McPherson(the “2014 McPherson Equity Agreement”), which was made effective as of September 30, 2012 (the “Series D Unit Effective Date”). Pursuant to the 2014 McPherson Equity Agreement, the Company issued 12,443 Series D-1 Units to Mr. McPherson on the Series D Unit Effective Date. Of the Series D-1 Units granted to Mr. McPherson, one hundred percent (100%) will vest upon the occurrence of a liquidation event or an exit event. If Mr. McPherson’s employment with us is terminated for any reason, then Mr. McPherson will forfeit to the Company all of his unvested Series D-1 Units on the date of such termination.  If Mr. McPherson breaches the non-competition and non-solicitation covenants in the 2014 McPherson Equity Agreement, then he will forfeit to the Company all of his vested Series D-1 Units.

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 “Original Self Equity Agreement”).  On November 8, 2013, we entered into an Amended and Restated Series D Unit Agreement with Mr.Self (the “Self Amended and Restated Equity Agreement”),  which was made effective as of the date of the Original Self Equity Agreement.The terms of the Self Amended and Restated Equity Agreement, including the vesting provisions, are identical to those of the McPherson Amended and Restated Equity Agreement.

On February 13, 2014, the Company also entered into a Series D Unit Agreement with Mr. Self (the “2014Self Equity Agreement”), which was made effective as of the Series D Unit Effective Date.  Pursuant to the 2014Self Equity Agreement, the Company issued 12,443 Series D-1 Units to Mr. Self on the Series D Unit Effective Date. The terms of the Self Series D Unit Agreement are identical to those of the 2014 McPherson Equity 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, 2013.  

	Outstanding Equity Awards at 2013 Fiscal Year End
	Option Awards					Stock Awards
Name	Number of securities underlying unexercised options	Number of securities underlying unexercised options	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	Equity incentive plan awards: number of unearned shares, units or other rights that have not vested	Equity incentive plan awards: market or payout value of unearned shares, units or other rights that have not vested
	(#)	(#)	(#)	($)		(#)	($) (5)	(#)	(#)
	exercisable	unexercisable						(i)
Brian Stewart	—	—	—	—	—	23,158 Series D Units (1)	—	—	—
Kenneth Sill	—	—	—	—	—	17,255 Series D Units (2)	—	—	—
Jeffery McPherson	—	—	—	—	—	40,613 Series D Units (3)	—	—	—
Edward S. Self III	—	—	—	—	—	40,613 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 September 19, 2013, September 19, 2014 and September 19, 2015.

(3)                 Mr. McPherson was granted 84,493 Series D Units on February 21, 2012, of which 10,000 vested immediately. On November 8, 2013, we entered into an Amended and Restated Series D Unit Agreement, pursuant to which two thirds of the 84,493 Series D Units vested.  The remaining one third or 28,170 Series D Units will vest upon the occurrence of a liquidation event or exit event. On February 11, 2014, Mr. McPherson was granted 12,443 Series D Units, which will vest upon the occurrence of a liquidation event ot exit event.

(3)                 Mr. Self was granted 84,493 Series D Units on February 21, 2012, of which 10,000 vested immediately. On November 8, 2013, we entered into an Amended and Restated Series D Unit Agreement, pursuant to which two thirds of the 84,493 Series D Units vested.  The remaining one third or 28,170 Series D Units will vest upon the occurrence of a liquidation event or exit event. On February 11, 2014, Mr. Self was granted 12,443 Series D Units, which will vest upon the occurrence of a liquidation event ot exit event.

(5)                There was no established public trading market for our membership interests as of December 31, 2013 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 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-10. 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, 2013. 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, 2013.

Nonqualified

Fees Earned

Non-Equity

Deferred

or Paid

Stock

Option

Incentive Plan

Compensation

All Other

Name

in Cash

Awards

Awards

Compensation

Earnings

Compensation

Total

Cornelius Dupre

$

-

$

-

$

-

$

-

$

-

$

-

$

-

Matthew Bernard

-

-

-

-

-

-

-

Joel Broussard

-

-

-

-

-

-

-

Gregg H. Falgout

-

-

-

-

-

-

-

Steve Orlando

-

-

-

-

-

-

-

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

The following table sets forth, as of March 7, 2014, 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 2.5 million 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)	1,421,133	57.1%
Joel Broussard(1)	1,421,133	57.1%
Gregg H. Falgout(1)	1,421,133	57.1%
Matthew Bernard(1)	1,421,133	57.1%
Cornelius Dupre(1)	1,421,133	57.1%

Steve Orlando(1)	1,421,133	57.1%
Todd Danos(1)	1,421,133	57.1%
USWS Inc.(2)	167,500	6.7%
Brian Stewart(3)	74,655	3.0%
Kenneth I. Sill(4)	49,770	2.0%
Jeffrey McPherson(5)	124,426	5.0%
Edward S. Self III(6)	124,426	5.0%
Executive Officers and members of the Board of Managers as a Group	1,794,411	72.1%
(1)Messrs. Broussard, Bernard, Falgout, Dupre and Orlando, each a member of the Board of Managers, are also members of ORB Investments, LLC. Additionally, an entity controlled by Mr. Danos, a member of the Board of Managers, is also a member  of ORB Investments, LLC. The securities attributable to Messrs. Broussard, Bernard, Falgout, Dupre, Orlando and Danos 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)Mr. McPherson's units are not fully vested and vest in accordance with the terms of his Series D Unit Agreements.  Further, the number of Series D Units granted to Mr. McPherson represents the right to receive five percent (5%) of all distributions made on our Series B, Series C and Series D Units.  The number of Series D Units granted pursuant to Mr. McPherson'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 five percent (5%) of all distributions on our Series B, Series C and Series D Units.  For a summary Mr. McPherson's Series D Unit Agreement see “Item 11. Executive Compensation - Restricted Equity Agreements.”
(5)   Mr. Self's units are not fully vested and vest in accordance with the terms of his Series D Unit Agreements.  Further, the number of Series D Units granted to Mr. Self represents the right to receive five percent (5%) of all distributions made on our Series B, Series C and Series D Units.  The number of Series D Units granted pursuant to Mr. Self'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 five percent (5%) of all distributions on our Series B, Series C and Series D Units.  For a summary 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. 

Issuance of Series E Units

Pursuant to a subscription agreement we entered into with ORB and ORB Investments No. 2, LLC (“ORB 2”), we issued 663,195 Series E Units to ORB and ORB 2 in exchange for $14 million in cash, effective as of October 18, 2013.  Messrs. Broussard, Bernard, Falgout, Dupre and Orlando are each members of our Board of Managers and are also members of ORB and ORB 2. Additionally, an entity controlled by Mr. Danos, a member of our Board of Managers, is also a member of ORB

Redemption of Series A Units

On February 18, 2014, we purchased from ORB, and ORB sold to the Company, all of its 600,000 Series A Units in exchange for an amount equal to $30 million less all related fees and expenses incurred by us.

Director Independence

Our Board of Managers consists of six 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 five 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
	January 1, 2013		February 21, 2012		January 1, 2012
	to		(inception) to		to
	December 31, 2013		December 31, 2012		February 20, 2012
Audit Fees	$	361,731	$	375,450	$	-
Audit-Related Fees		-		-		-
Tax Fees		-		87,200		-
All Other Fees		-		-		-
	$	361,731	$	462,650	$	-

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)).
3.3	First Amendment to Amended and Restated Limited Liability Company Agreement of U.S. Well Services, LLC dated February 10, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 10, 2014).
3.4	Second Amendment to Amended and Restated Limited Liability Company Agreement of U.S. Well Services, LLC dated February 18, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on February 20, 2014).
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	Second Supplemental Indenture dated April 10, 2013, among U.S. Well Services, LLC, USW Financing Corp., the guarantors party thereto, and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-k filed with the SEC on April 15, 2013).
4.4	Third Supplemental Indenture dated October 18, 2013, among U.S. Well Services, LLC, USW Financing Corp., the guarantors party thereto, and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.4 to the Company's Current Report on Form 8-k filed with the SEC on October 18, 2013).
4.5	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)).
4.6	Registration Rights Agreement dated April 8, 2013, among U.S. Well Services, LLC, USW Financing Corp., the individual purchasers named therein, and Global Hunter Securities, LLC (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed with the SEC on April 15, 2013).
4.7	Registration Rights Agreement dated October 18, 2013, among U.S. Well Services, LLC, USW Financing Corp., the individual purchasers named therein, and Global Hunter Securities, LLC (incorporated by reference to Exhibit 4.5 to the Company's Current Report on Form 8-k filed with the SEC on October 18, 2013).
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#*	Amendment to Contract to  Provide Dedicated Fleet(s) for Fracturing Services effective September 30, 2013, between U.S. Well services, LLC and Antero Resources Corporation.
10.4#*	Second Amendment to Contract to Provide Dedicated Fleet(s) for Fracturing Services dated January 24, 2014, between U.S. Well services, LLC and Antero Resources Corporation.
10.5@	Dedicated Fracturing Fleet Agreement dated September 23, 2013, between U.S. Well Services, LLC and Inflection Energy LLC
10.6^	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)).
10.7^	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)).
10.8^	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)).
10.9^	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)).
10.10^	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)).
10.11^	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)).
10.12^	Amended and Restated Series D Unit Agreement, executed and agreed to as of November 8, 2013, but made effective as of February 21, 2012, by and between U.S. Well Services, LLC and Jeff McPherson (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-k filed with the SEC on November 14, 2013).
10.13^	Amended and Restated Series D Unit Agreement, executed and agreed to as of November 8, 2013, but made effective as of February 21, 2012, by and between U.S. Well Services, LLC and Edward Self III (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-k filed with the SEC on November 14, 2013).
10.14	Credit and Security Agreement dated May 9, 2013, by and between U.S. Well Services, LLC, and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the SEC on May 15, 2013).
10.15	First Amendment to Credit and Security Agreement dated November 12, 2013, by and between U.S. Well Services, LLC, and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-k filed with the SEC on November 19, 2013).
21.1	Subsidiaries of U.S. Well Services, LLC (incorporated by reference to Exhibit 21.1 to the Company's Annual Report on Form 10-k filed with the SEC on March 19, 2013).
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
* Filed herewith.
@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.

# Confidential treatment has been requested 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.

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 28, 2014	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 and Chief Executive Officer (Principal executive	March 28, 2014
	Brian Stewart	officer) and Member of the Board of Managers
By:	/s/ Kenneth I. Sill	Chief Financial Officer	March 28, 2014
	Kenneth I. Sill	(Principal financial officer)
By:	/s/ Cornelius Dupre	Member of the Board of Managers	March 28, 2014
	Cornelius Dupre
By:	/s/ Joel Broussard	Member of the Board of Managers	March 28, 2014
	Joel Broussard
By:	/s/ Gregg H. Falgout	Member of the Board of Managers	March 28, 2014
	Gregg H. Falgout
By:	/s/ Matthew Bernard	Member of the Board of Managers	March 28, 2014
	Matthew Bernard
By:	/s/ Steve Orlando	Member of the Board of Managers	March 28, 2014
	Steve Orlando
By:	/s/ Todd Danos	Member of the Board of Managers	March 28, 2014
	Todd Danos