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    UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015 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 001-32693 Basic Energy Services, Inc. (Exact name of registrant as specified in its charter) Delaware 54-2091194 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 801 Cherry Street, Suite 2100 Fort Worth, Texas 76102 (Address of principal executive offices) (Zip code) Registrant’s telephone number, including area code: (817) 334-4100 Securities registered pursuant to Section 12(b) of the Act: Title of Class Name of each exchange on which registered Common Stock, $0.01 par value per share New York Stock Exchange 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 ☑ 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 ☑ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 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 ☑ No ☐ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer ☐ Accelerated Filer ☑ Non-Accelerated filer ☐ (Do not check if a smaller reporting company) Smaller reporting company ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑ The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was approximately$291,466,290 as of June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter (based on a closing price of $7.50 per share and 38,862,172 shares held by non-affiliates). There were 42,195,405 shares of the registrant’s common stock outstanding as ofFebruary 23, 2016. DOCUMENTS INCORPORATED BY REFERENCE Portions of the proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) are incorporated by reference into Part III.


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    BASIC ENERGY SERVICES, INC. Index to Form 10-K Part I 3 Items 1. and 2. Business and Properties 3 Item 1A. Risk Factors 17 Item 1B. Unresolved Staff Comments 25 Item 3. Legal Proceedings 25 Item 4. Mine Safety Disclosures 25 Part II 25 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 25 Item 6. Selected Financial Data 28 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 29 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 45 Item 8. Financial Statements and Supplementary Data 46 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 79 Item 9A. Controls and Procedures 79 Item 9B. Other Information 79 Part III 79 Part IV 80 Item 15. Exhibits, Financial Statement Schedules 80 Signatures 81 1


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    CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends affecting the financial condition of our business. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including, among other things, the risk factors discussed in Item 1A of this annual report and other factors, most of which are beyond our control. The words “believe,” “estimate,” “expect,” “anticipate,” “project,” “intend,” “plan,” “seek,” “could,” “should,” “may,” “potential” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this annual report are forward-looking statements. Although we believe that the forward-looking statements contained in this annual report are based upon reasonable assumptions, the forward- looking events and circumstances discussed in this annual report may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements. Important factors that may affect our expectations, estimates or projections include: • a decline in, or substantial volatility of, oil and natural gas prices, and any related changes in expenditures by our customers; • competition within our industry; • the effects of future acquisitions on our business; • our access to current or future financing arrangements; • changes in customer requirements in markets or industries we serve; • general economic and market conditions; • our ability to replace or add workers at economic rates; and • environmental and other governmental regulations. Our forward-looking statements speak only as of the date of this annual report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. This annual report includes market share data, industry data and forecasts that we obtained from internal company surveys (including estimates based on our knowledge and experience in the industry in which we operate), market research, consultant surveys, publicly available information, industry publications and surveys. These sources include Baker Hughes Incorporated, the Association of Energy Service Companies (“AESC”), and the Energy Information Administration of the U.S. Department of Energy (“EIA”). Industry surveys and publications, consultant surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. Although we believe such information is accurate and reliable, we have not independently verified any of the data from third-party sources cited or used for our management’s industry estimates, nor have we ascertained the underlying economic assumptions relied upon therein. Statements as to our position relative to our competitors or as to market share refer to the most recent available data. 2


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    PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES General We provide a wide range of well site services in the United States to oil and natural gas drilling and producing companies, including completion and remedial services, fluid services, well servicing and contract drilling. These services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well. Our broad range of services enables us to meet multiple needs of our customers at the well site. We were organized in 1992 as Sierra Well Service, Inc., a Delaware corporation, and in 2000 we changed our name to Basic Energy Services, Inc. Our operations are managed regionally and are concentrated in major United States onshore oil and natural gas producing regions located in Texas, New Mexico, Oklahoma, Arkansas, Kansas, Louisiana, Wyoming, North Dakota, Colorado, Utah, Montana, West Virginia, California, Ohio and Pennsylvania. Our operations are focused on liquids-rich basins that have historically exhibited strong drilling and production economics in recent years as well as natural gas- focused shale plays characterized by prolific reserves. Specifically, we have a significant presence in the Permian Basin and the Bakken, Eagle Ford, Haynesville and Marcellus shales. We provide our services to a diverse group of over 2,000 oil and gas companies. Our current operating segments are Completion and Remedial Services, Fluid Services, Well Servicing, and Contract Drilling. These segments were selected based on management’s resource allocation and performance assessment in making decisions regarding the Company. The following is a description of our business segments: • Completion and Remedial Services. Our completion and remedial services segment (38% of our revenues in 2015) operates our fleet of pumping units, an array of specialized rental equipment and fishing tools, coiled tubing units, snubbing units, thru-tubing, air compressor packages specially configured for underbalanced drilling operations, cased-hole wireline units and nitrogen units. The largest portion of this business segment consists of pumping services focused on cementing, acidizing and fracturing services in niche markets. • Fluid Services. Our fluid services segment (32% of our revenues in 2015) utilizes our fleet of 985 fluid service trucks and related assets, including specialized tank trucks, storage tanks, water wells, disposal facilities, water treatment and construction and other related equipment. These assets provide, transport, store and dispose of a variety of fluids, as well as provide well site construction and maintenance services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations. • Well Servicing. Our well servicing segment (27% of our revenues in 2015) operates our fleet of 421 well servicing rigs and related equipment. This business segment encompasses a full range of services performed with a mobile well servicing rig, including the installation and removal of downhole equipment and elimination of obstructions in the well bore to facilitate the flow of oil and natural gas. These services are performed to establish, maintain and improve production throughout the productive life of an oil and natural gas well and to plug and abandon a well at the end of its productive life. Our well servicing equipment and capabilities also facilitate most other services performed on a well. • Contract Drilling. Our contract drilling segment (3% of our revenues in 2015) operates our fleet of12 drilling rigs and related equipment. We use these assets to penetrate the earth to a desired depth and initiate production from a well. Please see Part II Item 8. Business Segment Information for further financial information about our segments. Our Competitive Strengths We believe that the following competitive strengths currently position us well within our industry: Extensive Domestic Footprint in the Most Prolific Basins. Our operations are focused on liquids-rich basins located in the United States that have exhibited strong drilling and production economics in recent years as well as natural gas- focused shale plays characterized by prolific reserves. Specifically, we have a significant presence in the Permian Basin and the Bakken, Eagle Ford, Haynesville and Marcellus shales. We operate in the 48 contiguous states that accounted for approximately 99% of U.S. onshore oil natural gas production. We believe that our operations are located in the most active U.S. well services markets, as we currently focus our operations on onshore domestic oil and natural gas production areas that include both the highest concentration of existing oil and natural gas production activities and the largest prospective acreage for new drilling activity. We believe our extensive footprint allows us to offer our suite of services to more than 2,000 customers who are active in those areas and allows us to redeploy equipment between markets as activity shifts, reducing the risk that a basin-specific slowdown will have a disproportionate impact on our cash flows and operational results. Diversified Service Offering for Further Revenue Growth and Reduced Volatility. We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. Our experience, equipment and network of 146 area offices position us to market our full range of well site services to our existing customers. By utilizing a wider range of our services, our customers can use fewer service providers, which enables them to reduce their administrative costs and simplify their logistics. Furthermore, offering a broader range of services allows us to capitalize on our existing customer base and 3


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    management structure to grow within existing markets, generate more business from existing customers, and increase our operating profits as we spread our overhead costs over a larger revenue base. Significant Market Position. We maintain a significant market share for each of our lines of business within our core operating areas: the Permian Basin of West Texas and Southeast New Mexico; the Gulf Coast region of South Texas and Louisiana; the Mid-Continent region of North Texas, Oklahoma and Kansas; the Ark-La-Tex region of East Texas, North Louisiana and Arkansas; California; and the Rocky Mountain region of North New Mexico, Colorado, Utah, Wyoming, Montana and North Dakota. Our goal is to be one of the top two providers of the services we provide in each of our core operating areas. Our position in each of these markets allows us to expand the range of services performed on a well throughout its life, such as drilling, maintenance, workover, stimulation, completion and plugging and abandonment services. Modern and Competitive Fleet. We operate a modern fleet matched to the needs of the local markets in each of our business segments. We are driven by a desire to maintain one of the most efficient, reliable and safest fleets of equipment in the country, and we have an established program to routinely monitor and evaluate the condition of our equipment. We selectively refurbish equipment to maintain the quality of our service and to provide a safe working environment for our personnel. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets. We believe that by maintaining a modern and active asset base, we are better able to earn our customers’ business while reducing the risk of potential downtime. Decentralized Experienced Management with Strong Corporate Infrastructure. Our corporate group is responsible for maintaining a unified infrastructure to support our diversified operations through standardized financial and accounting, safety, environmental and maintenance processes and controls. Below our corporate level, we operate a decentralized operational organization in which our nine regional or division managers are responsible for their operations, including asset management, cost control, policy compliance and training and other aspects of quality control. With the majority having over 30 years of industry experience, each regional manager has extensive knowledge of the customer base, job requirements and working conditions in each local market. Below our nine regional or division managers, our area managers are directly responsible for customer relationships, personnel management, accident prevention and equipment maintenance, the key drivers of our operating profitability. This management structure allows us to monitor operating performance on a daily basis, maintain financial, accounting and asset management controls, integrate acquisitions, prepare timely financial reports and manage contractual risk. Our Business Strategy The key components of our business strategy include: Establishing and Maintaining Leadership Positions in Core Operating Areas. We strive to establish and maintain market leadership positions within our core operating areas. To achieve this goal, we maintain close customer relationships, seek to expand the breadth of our services and offer high quality services and equipment that meet the scope of customer specifications and requirements. In addition, our significant presence in our core operating areas facilitates employee retention and attraction, a key factor for success in our business. Our significant presence in our core operating areas also provides us with brand recognition that we intend to utilize in creating leading positions in new operating areas. Selectively Expanding Within Our Regional Markets. We intend to continue strengthening our presence within our existing geographic footprint through internal growth and acquisitions of businesses with strong customer relationships, well-maintained equipment and experienced and skilled personnel. We typically enter into new markets through the acquisition of businesses with strong management teams that will allow us to expand within these markets. Management of acquired companies often remain with us and retain key positions within our organization, which enhances our attractiveness as an acquisition partner. We have a record of successfully implementing this strategy. By concentrating on targeted expansion in areas in which we already have a meaningful presence, we believe we maximize the returns on expansion capital while reducing downside risk. Developing Additional Service Offerings Within the Well Servicing Market. We intend to continue broadening the portfolio of services we provide to our clients by utilizing our well servicing infrastructure. A customer typically begins a new maintenance or workover project by securing access to a well servicing rig, which stays on site for the duration of the project. As a result, our rigs are often the first equipment to arrive at the well site and typically the last to leave, providing us the opportunity to offer our customers other complementary services. We believe the fragmented nature of the well servicing market creates an opportunity to sell more services to our core customers and to expand our total service offering within each of our markets. We have expanded our suite of services available to our customers and increased our opportunities to cross-sell new services to our core well servicing customers through acquisitions and internal growth. We expect to continue to develop or selectively acquire capabilities to provide additional services to expand and further strengthen our customer relationships. Pursuing Growth Through Selective Capital Deployment. We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and regional operations management and are reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and natural gas commodity price cycle. Based on these factors, we make 4


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    capital investment decisions that we believe will support our long-term growth strategy and these decisions may involve a combination of asset acquisitions and the purchase of new equipment. General Industry Overview Our business is influenced substantially by both operating and capital expenditures by oil and gas companies.Exploration and production spending is categorized as either an operating expenditure or a capital expenditure. Activities designed to add hydrocarbon reserves are classified as capital expenditures, while those associated with maintaining or accelerating production are categorized as operating expenditures. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by oil and gas companies for the maintenance of existing wells historically have been relatively stable and predictable. In contrast, capital expenditures by oil and gas companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices. We believe our focus on production and workover activity partially insulates our financial results from the volatility of the active drilling rig count. However, significantly lower commodity prices have impacted production and workover activities due to both customer cash liquidity limitations and well economics for these service activities. Capital expenditures by oil and gas companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for even a short period of time, capital expenditure projects are routinely deferred until prices return to an acceptable level. In contrast, both mandatory and discretionary operating expenditures are substantially more stable than exploration and drilling expenditures. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and projects to maintain the well and related infrastructure in operating condition (for example, repairs to a central tank battery, downhole pump, saltwater disposal system or gathering system). Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field, but these projects are relatively insensitive to commodity price volatility. Discretionary operating expenditure work is evaluated according to a simple short-term payout criterion that is far less dependent on commodity price forecasts. Demand for services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States. Our customers’ expenditures are affected by both current and expected levels of oil and natural gas prices. Natural gas prices have remained at lower levels in the 2011-2015 periods, which resulted in decreased activity in our natural gas-driven markets. Oil prices increased during the first half of 2011 primarily due to political and economic instability in several oil producing countries and remained relatively stable until the fourth quarter of 2014, when oil prices declined due to oversupply concerns worldwide and continued to decline significantly throughout 2015. Despite natural gas prices remaining at lower levels, several markets that produce significant natural gas liquids, such as the Eagle Ford shale, and/or that have other advantages like proximity to key consuming markets, such as the Marcellus shale, continued to see relatively stable activity during 2015. The table below sets forth average closing prices for the Cushing WTI Spot Oil Price and the Henry Hub Natural Gas Spot Price since2013: Cushing WTI Spot Henry Hub Gas Period Oil Price ($/Bbl.) Spot Price ($/Mcf.) 1/1/13 - 12/31/13 $ 97.91 $ 3.73 1/1/14 - 12/31/14 93.26 4.39 1/1/15 - 12/31/15 48.69 2.63 Closing Price at 12/31/15 37.13 2.28 Source: U.S. Department of Energy. Increased expenditures for exploration and production activities generally drive the increased demand for our services. In 2013, oil prices remained stable and natural gas prices increased, and the average oil-based drilling rig count also remained stable. In the first three quarters of 2014, oil prices and natural gas prices increased incrementallycausing the land-based drilling rig count to increase approximately 10%. In the fourth quarter of 2014, oil prices began to decline resulting in a decrease in the land based rig count of approximately 5%. Average natural gas-focuse d drilling rig count decreased 40% from 2013 to 2014. In 2015, oil prices declined significantly and the average oil-based drilling rig count decreased approximately 64% throughout the year. Gas prices also declined leading to a 52% decrease in natural gas-focused drilling rig count. Data for each of the foregoing rig counts are based on information from the Baker Hughes rig count. 5


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    Overview of Our Segments and Services Completion and Remedial Services Segment Our completion and remedial services segment provides oil and natural gas operators with a package of services that include the following: • pumping services, such as cementing, acidizing, fracturing, nitrogen and pressure testing; • rental and fishing tools; • coiled tubing; • snubbing services; • thru-tubing; • cased-hole wireline services; and • underbalanced drilling in low pressure and fluid sensitive reservoirs. This segment operates 291 pumping units, with approximately 444,000 horsepower of capacity, to conduct a variety of services designed to stimulate oil and natural gas production or to enable cement slurry to be placed in or circulated within a well. We also operate 42 air compressor packages, including foam circulation units, for underbalanced drilling, 36 snubbing units, 15 coiled tubing units and 8 wireline units for cased-hole measurement and pipe recovery services. Just as a well servicing rig is required to perform various operations over the life cycle of a well, there is a similar need for equipment capable of pumping fluids into the well under varying degrees of pressure. During the drilling and completion phase, the well bore is lined with large diameter steel pipe called casing. Casing is cemented into place by circulating slurry into the annulus created between the pipe and the rock wall of the well bore. The cement slurry is forced into the well by pumping equipment located on the surface. Cementing services are also utilized over the life of a well to repair leaks in the casing, to close perforations that are no longer productive and ultimately to “plug” the well at the end of its productive life. A hydrocarbon reservoir is essentially an interval of rock that is saturated with oil and/or natural gas, usually in combination with water. Three primary factors determine the productivity of a well that intersects a hydrocarbon reservoir: porosity (the percentage of the reservoir volume represented by pore space in which the hydrocarbons reside), permeability (the natural propensity for the flow of hydrocarbons toward the well bore), and “skin” (the degree to which the portion of the reservoir in close proximity to the well bore has experienced reduced permeability as a result of exposure to drilling fluids or other contaminants). Well productivity can be increased by artificially improving either permeability or skin through stimulation methods described below. Permeability can be increased through the use of fracturing methods by which a reservoir is subjected to fluids pumped into it under high pressure. This pressure creates stress in the reservoir and causes the rock to fracture, thereby creating additional channels through which hydrocarbons can flow. In most cases, sand or another form of proppant is pumped with the fluid as a means of holding open the newly created fractures. The most common means of reducing near-well bore damage, or skin, is the injection of a highly reactive solvent (such as hydrochloric acid) solution into the area where the hydrocarbons enter the well. This solution has the effect of dissolving contaminants that have accumulated and are restricting the flow of hydrocarbons. This process is generically known as acidizing. After a well is drilled and completed, the casing may develop leaks as a result of abrasions from production tubing, exposure to corrosive elements or inadequate support from the original attempt to cement the casing in place. When a leak develops, it is necessary to place specialized equipment into the well and to pump cement in such a way as to seal the leak, a process known as “squeeze” cementing. The following table sets forth the type, number and location of the completion and remedial services equipment that we operated at December 31,2015: Market Area Rocky Permian Ark-La-Tex Mid-Continent Gulf Coast Mountain Basin Appalachia Total Pumping Units 12 167 - 53 59 - 291 Air/Foam Packages - 10 - 25 7 - 42 Snubbing Units 18 8 - - - 10 36 Rental and Fishing Tool Stores - 8 - 4 8 - 20 Coiled Tubing Units 2 - 1 11 1 - 15 Wireline Units - - - - 8 - 8 6


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    Our pumping services business focuses primarily on lower horsepower cementing, acidizing and fracturing services markets. Currently, there are several pumping companies that provide their services on a national basis. For the most part, these companies have concentrated their assets in markets characterized by complex work with higher horsepower requirements. This has created an opportunity in the markets for pumping services in mature areas with less complex characteristics and lower horsepower requirements. We, along with a number of smaller, regional companies, have concentrated our efforts on these markets. The level of activity of our pumping services business is tied to drilling and workoveractivity. The bulk of pumping work is associated with cementing casing in place as the well is drilled or pumping fluid that stimulates production from the well during the completion phase. Pumping service work is awarded based on a combination of price and expertise. Our rental and fishing tool business provides a range of specialized services and equipment that is utilized on a non-routine basis for both drilling and well servicing operations. Drilling and well servicing rigs are equipped with an array of tools to complete routine operations under normal conditions for most projects in the geographic area in which they are employed. When downhole problems develop with drilling or servicing operations or conditions require non-routine equipment, our customers will usually rely on a provider of rental and fishing tools to augment equipment that is provided with a typical drilling or well servicing rig package. The term “fishing” applies to a wide variety of downhole operations designed to correct a problem that has developed during the drilling or servicing of a well. The problem most commonly involves equipment that has become lodged in the well and cannot be removed without special equipment. Our technicians utilize tools that are specifically suited to retrieve, or “fish,” and remove the trapped equipment, allowing our customers to resume operations. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well interventions, including wellbore maintenance, nitrogen services, thru-tubing services, and formation stimulation using acid and other chemicals. Our snubbing service business utilizes specialized equipment to run or remove pipe and other associated downhole tools into a wellbore. This process is accomplished with a wellbore having surface pressure or with the anticipation of surface pressure. Our snubbing services are utilized for both routine and non-routine workover, completion and remedial activities. Cased-hole wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of a cased wellbore. These tools can be used to measure pressures and temperature as well as the condition of the casing and the cement that holds the casing in place. Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, or perforating the casing and cutting off pipe that is stuck in the well so that the free section can be recovered. Wireline trucks are utilized throughout the life of a well. Fluid Services Segment Our fluid services segment provides oilfield fluid supply, transportation, storage and construction services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations. These services include: • the transportation of fluids used in drilling and workover operations and of salt water produced as a by-product of oil and natural gas production; • the sale and transportation of fresh and brine water used in drilling and workover activities; • the rental of portable fracturing tanks and test tanks used to store fluids on well sites; • the recycling and treatment of wastewater, including produced water and flowback, to be reused in the completion and production process; • the operation of company-owned fresh water and brine source wells and of non-hazardous wastewater disposal wells; and • the preparation, construction and maintenance of access roads, drilling locations, and production facilities. 7


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    This segment utilizes our fleet of fluid service trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at December 31, 2015: Market Area Rocky Permian Mountain Ark-La-Tex Basin Mid-Continent Gulf Coast Total Fluid Service Trucks 125 149 508 57 146 985 Salt Water Disposal Wells 5 25 32 11 12 85 Fresh/Brine Water Stations 2 - 47 - 5 54 Fluid Storage Tanks 627 751 1,272 282 389 3,321 Requirements for minor or incidental fluid services are usually purchased on a “call out” basis and charged according to a published schedule of rates. Larger projects, such as servicing the requirements of a multi-well drilling program or fracturing program, generally involve a bidding process. We compete for both services on a call out basis and for multi-well contract projects. We provide a full array of fluid sales, transportation, storage, treatment and disposal services required on most workover, completion and remedial projects. Our breadth of capabilities in this segment allows us to serve as a one-stop source of equipment and services for our customers. Many of our smaller competitors in this segment can provide some, but not all, of the equipment and services required by oil and gas operators, requiring them to use several companies to meet their requirements and increasing their administrative burden. Our fluid services segment has a base level of business volume related to the regular maintenance of oil and natural gas wells. Most oil and natural gas fields produce residual salt water in conjunction with oil or natural gas. Fluid service trucks pick up this fluid from tank batteries at the well site and transport it to a salt water disposal well for injection. This type of regular maintenance work must be performed if a well is to remain active. Transportation and disposal of produced water is considered a low value service by most operators, and it is difficult for us to command a premium over rates charged by our competition. Our ability to outperform competitors in this segment depends on our ability to achieve significant economies relating to logistics, specifically the proximity between the areas where salt water is produced and the areas where our company-owned disposal wells are located. We operate salt water disposal wells in most of our markets, and our ownership of these disposal wells eliminates the need to pay third parties a fee for disposal. Workover, completion and remedial activities also provide the opportunity for higher operating margins from tank rentals and fluid sales. Drilling and workover jobs typically require fresh or brine water for drilling mud or circulating fluid used during the job. Completion and workover procedures often also require large volumes of water for fracturing operations, which involves stimulating a well hydraulically to increase production. Spent mud and flowback fluids from drilling and completion activities are required to be transported from the well site to an approved disposal facility. Water treatment solutions are also utilized by customers to treat produced water and flowback, in order to be reused during the production and completion process. Our competitors in the fluid services industry are mostly small, regionally focused companies. There are currently no companies that have a dominant position on a nationwide basis. The level of activity in the fluid services industry is comprised of a relatively stable demand for services related to the maintenance of producing wells and a highly variable demand for services used in the drilling and completion of new wells. As a result, the level of onshore drilling activity significantly affects the level of activity in the fluid services industry. While there are no industry-wide statistics, the Baker Hughes Land Drilling Rig Count is an indirect indication of demand for fluid services because it directly reflects the level of onshore drilling activity. Fluid Services. At December 31, 2015, we owned and operated 985 fluid service trucks equipped with an average fluid hauling capacity of up to 150 barrels apiece. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid service trucks are also used to transport water to fill fracturing tanks on well locations, including fracturing tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of our fracturing tanks, we mainly use our fluid service trucks to transport water for use in fracturing operations. Following completion of fracturing operations, our fluid service trucks are used to transport the flowback produced as a result of the fracturing operations from the well site to disposal wells. Fluid service trucks are usually provided to oilfield operators within a 50-mile radius of our nearest yard. Salt Water Disposal Well Services. At December 31, 2015, we owned 85 salt water disposal facilities. Disposal wells are permitted to dispose of salt water and incidental non-hazardous oil and natural gas wastes. Our fluid service trucks frequently transport the fluids that are disposed of in these salt water disposal wells. Our disposal wells have an average permitted injection capacity of over 6,000 barrels per day per well and are strategically located in close proximity to our customers’ producing wells. Most oil and 8


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    natural gas wells produce varying amounts of salt water throughout their productive lives. In the states in which we operate, oil and natural gas wastes and salt water produced from oil and natural gas wells are required by law to be disposed of in authorized facilities, including permitted salt water disposal wells. Injection wells are licensed by state authorities and are completed in permeable formations below the fresh water table. We maintain separators at most of our disposal wells, allowing us to salvage residual crude oil that we later sell for our account. Fresh and Brine Water Stations. Our network of fresh and brine water stations, particularly in the Permian Basin where surface water is normally not available, is used to supply water necessary for the drilling and completion of oil and natural gas wells. Our strategic locations, in combination with our other fluid handling services, give us a competitive advantage over other service providers in those areas in which these other companies cannot provide these services. Fluid Storage Tanks. Our fluid storage tanks can store up to 500 barrels of fluid and are used by oilfield operators to store various fluids at the well site, including fresh water, brine and acid for fracturing jobs, flowback, temporary production and mud storage. We transport the tanks on our trucks to well locations that are usually within a 50-mile radius of our nearest yard. Frac turing tanks are used during all phases of the life of a producing well. We typically rent fluid services tanks at daily rates for a minimum of three days. A typical fracturing operation can be completed within four days using 5 to 50 fracturing tanks. Water Treatment Services. We utilize a number of water treatment methods in order to treat produced water and flowback that is transported to one of several treatment locations throughout our geographic footprint. Treated water is then sold to customers to be reused for fracturing or other oil and gas-related uses on wells. We typically charge for these services on a per-barrel basis. Construction Services. We utilize a fleet of power units, including dozers, trenchers, motor graders, backhoes and other heavy equipment used in road construction. In addition, we own rock pits in some markets in our Rocky Mountain operations to ensure a reliable source of rock to support our construction activities. Contracts for well site construction services are normally awarded by our customers on the basis of competitive bidding and may range in scope from several days to several months in duration. Well Servicing Segment Our well servicing segment encompasses a full range of services performed with a mobile well servicing rig, also commonly referred to as a workover rig, and ancillary equipment. Our rigs and personnel provide the means for hoisting equipment and tools into and out of the well bore, and our well servicing equipment and capabilities also facilitate most other services performed on a well. Our well servicing segment services, which are performed to maintain and improve production throughout the productive life of an oil and natural gas well, include: • maintenance work involving removal, repair and replacement of down-hole equipment and returning the well to production after these operations are completed; • hoisting tools and equipment required by the operation into and out of the well, or removing equipment from the well bore, to facilitate specialized production enhancement and well repair operations performed by other oilfield service companies; and • plugging and abandonment services when a well has reached the end of its productive life. Our well servicing segment also includes the manufacturing and sale of new workover rigs through our wholly-owned subsidiary, Taylor Industries, LLC, which we formed in connection with the acquisition of a rig manufacturing business in 2010. Regardless of the type of work being performed on the well, our personnel and rigs are often the first to arrive at the well site and the last to leave. Wetypically charge our customers an hourly rate for these services, which rate varies based on a number of considerations including market conditions in each region, the type of rig and ancillary equipment required, and the necessary personnel. Our fleet included 421 well servicing rigs as of December 31, 2015, including 221 newbuilds since October 2004 and 76 rebuilds since the beginning of 2009. Our well servicing rigs operate from facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado, California, Arkansas, Utah, Montana, Kansas, Kentucky, Pennsylvania and West Virginia. Ou r well servicing rigs are mobile units thatnormally operate within a radius of approximately 75 to 100 miles from their respective bases. 9


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    The following table sets forth the location, characteristics and number of the well servicing rigs that we operated at December 31,2015. We categorize our rig fleet by the rated capacity of the mast, which indicates the maximum weight that the rig is capable of lifting. The maximum weight our rigs are capable of lifting is the limiting factor in our ability to provide these services. Market Area Rated Permian Mid - Rocky Rig Type Capacity Basin Gulf Coast Ark-La-Tex Continent Mountain California Appalachia Inactive Total Swab N/A - - 3 3 2 - - 3 11 Light Duty < 90 tons - - - - - 1 - 10 11 Medium Duty > 90 <125 tons 67 19 21 26 40 10 - 77 260 Heavy Duty > 125 tons 76 17 5 4 12 - 6 15 135 24-Hour > 125 tons - - - - - - - 4 4 Total 143 36 29 33 54 11 6 109 421 We operate a total of 421 well servicing rigs, one of the largest fleets in the United States. Based on the most recent publicly available information, five of our competitors operate more than 100 well servicing rigs: Key Energy Services, Inc., C&J Energy Services, Ltd., Superior Energy Services, Inc., Forbes Energy Services Ltd., and Pioneer Energy Services Corp. Maintenance. Regular maintenance is required throughout the life of a well to sustain optimal levels of oil and natural gas production. Regular maintenance currently comprises the largest portion of our work in this segment, and because ongoing maintenance spending is required to sustain production, we generally experience relatively stable demand for these services. We provide well service rigs, equipment and crews to our customers for these maintenance services. Maintenance services are often performed on a series of wells in proximity to each other and consist of routine mechanical repairs necessary to maintain production, such as repairing inoperable pumping equipment in an oil well or replacing defective tubing in a natural gas well, and removing debris such as sand and paraffin from the well. Other services include pulling the rods, tubing, pumps and other downhole equipment out of the well bore to identify and repair a production problem. These downhole equipment failures are typically caused by the repetitive pumping action of an oil well. Corrosion, water cut, grade of oil, sand production and other factors can also result in frequent failures of downhole equipment. The need for maintenance activity does not directly depend on the level of drilling activity, although it is somewhat impacted by short-term fluctuations in oil and natural gas prices. Demand for our maintenance services is driven primarily by the production requirements of local oil or natural gas fields and is therefore affected by changes in the total number of producing oil and natural gas wells in our geographic service areas. Our regular well maintenance services involve relatively low-cost, short-duration jobs which are part of normal well operating costs. Well operators cannot delay all maintenance work without a significant impact on production. Operators may, however, choose to shut in producing wells temporarily when oil or natural gas prices are too low to justify additional expenditures, including maintenance. Workover. In addition to periodic maintenance, producing oil and natural gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our workover rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive workover operations are normally performed by a workover rig with additional specialized auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular type of workover operation. Most of our well servicing rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and additional auxiliary equipment. The demand for workover services is sensitive to oil and natural gas producers’ intermediate and long-term expectations for oil and natural gas prices. As oil and natural gas prices increase, the level of workover activity tends to increase as oil and natural gas producers seek to increase output by enhancing the efficiency of their wells. New Well Completion. New well completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or natural gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well servicing rigs to minimize the use of higher cost drilling rigs in the completion process. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and require additional auxiliary equipment. Accordingly, completion services require less well-to-well mobilization of equipment and normally provide higher operating margins than regular maintenance work. 10


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    The demand for completion services is directly related to drilling activity levels, which are sensitive to expectations relating to and changes in oil and natural gas prices. Plugging and Abandonment. Well servicing rigs are also used in the process of permanently closing oil and natural gas wells no longer capable of producing in economic quantities. Plugging and abandonment work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging and abandonment work. Many well operators bid this work on a “turnkey” basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and comply with state regulatory requirements. Plugging and abandonment work can provide favorable operating margins and is less sensitive to oil and natural gas prices than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies. Contract Drilling Segment Our contract drilling segment employs drilling rigs and related equipment to penetrate the earth to a desired depth and initiate production. We own and operate 12 land drilling rigs, which are currently deployed in the Permian Basin of Texas and New Mexico. A land drilling rig consists of engines, a drawworks, a mast, pumps to circulate the drilling fluid (mud) under various pressures, blowout preventers, drill string and related equipment. The engines power the different pieces of equipment, including a rotary table or top drive that turns the drill string, causing the drill bit to bore through the subsurface rock layers. These jobs are typically bid by “daywork” contracts, in which an agreed upon rate per day is charged to the customer, or “footage” contracts, in which an agreed upon rate per the number of feet drilled is charged to the customer. The demand for drilling services is highly dependent on the availability of new drilling locations available to well operators, as well as sensitivity to expectations relating to and changes in oil and natural gas prices. Properties Our principal executive offices are located at 801 Cherry Street, Suite 2100, Fort Worth, Texas 76102. We currently conduct our business from 146 area offices, 87 of which we own and 59 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 146 area offices, 88 are located in Texas, twelve are in New Mexico, Oklahoma and Colorado each have nine, five are in North Dakota, six are in Wyoming, Louisiana and Kansas each have four, Utah, California, Montana, and Pennsylvania each have two, and Arkansas has one. Customers We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2015, no single customer comprised over10% of our total revenues. The majority of our business is with independent oil and gas companies. In the current market conditions, the loss of any current material customers could have an adverse effect on our business until the equipment is redeployed. Operating Risks and Insurance Our operations are subject to hazards inherent in the oil and natural gas industry, such as accidents, blowouts, explosions, craters, fires and oil spills that can cause: • personal injury or loss of life; • damage to or destruction of property, equipment and the environment; and • suspension of operations. In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in our being named as a defendant in lawsuits asserting large claims. Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury. Despite our efforts to maintain high safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of damage awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations. 11


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    Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. We do maintain employer’s liability, pollution, cargo, umbrella, comprehensive commercial general liability, workers’ compensation and limited physical damage insurance. There can be no assurance, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us. Competition Our competition includes small regional contractors as well as larger companies with international operations. We believe ourfive largest competitors, Key Energy Services, Inc., Superior Energy Services Inc., C&J Energy Services Ltd., Forbes Energy Services Ltd., and Pioneer Energy Services Corp., each own a significant number of the U.S. marketable well servicing rigs according to the most recent publicly available data, including the Guiberson-AESC well service rig count. All five are public companies that operate in most of the large oil and natural gas producing regions in the United States. They each have centralized management teams that direct their operations and decision-making primarily from corporate and regional headquarters. In addition, because of their size, they market a large portion of their work to the major oil and gas companies. We differentiate ourselves from our major competition by our operating philosophy. We operate a decentralized organization, where local, experienced management teams are largely responsible for sales and operations and developing stronger relationships with our customers at the field level. We target areas that are attractive to independent oil and gas operators who in our opinion tend to be more aggressive in spending, less focused on price and more likely to award work based on performance. We concentrate on providing services to a diverse group of large and small independent oil and gas companies. These independents typically are relationship driven, make decisions at the local level and are willing to pay higher rates for services. We have been successful using this business model and believe it will enable us to continue to grow our business. Safety Program Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property. We have comprehensive safety and training programs designed to minimize accidents in the workplace and improve the efficiency of our operations. In addition, many of our larger customers now place greater emphasis on safety and quality management programs of their contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee safety and quality management training programs as well as our employee review process. While our efforts in these areas are not unique, we believe many competitors, and particularly smaller contractors, have not undertaken similar training programs for their employees. We believe our approach to safety management is consistent with our decentralized management structure. Company-mandated policies and procedures provide the overall framework to ensure our operations minimize the hazards inherent in our work and are intended to meet regulatory requirements, while allowing our operations to satisfy customer-mandated policies and local needs and practices. Environmental Regulation and Climate Change Environment, Health and Safety Regulation, Including Climate Change Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, commonly referred to as the “EPA,” and analogous state agencies issue regulations to implement and enforce these laws, which often require stringent and costly compliance measures. These laws and regulations may, among other things, require the acquisition of permits; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling; restrict the way we handle or dispose of our materials and wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; or require investigatory and remedial actions to mitigate pollution conditions. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the possible issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose liability for environmental damages and cleanup costs without regard to negligence or fault. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental, health and safety laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or our competitive position. Below is a discussion of the principal environmental laws and regulations that relate to our business. The Comprehensive Environmental Response, Compensation and Liability Act, referred to as “CERCLA” or the Superfund law, and comparable state laws impose liability, potentially without regard to fault or legality of the activity at the time, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons include 12


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    the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances that have been released at the site. Under CERCLA, these persons may be subject to joint and several liabilities for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as “RCRA,” regulates the management and disposal of solid and hazardous waste. Some wastes associated with the exploration and production of oil and natural gas are exempted from the most stringent regulation in certain circumstances, such as drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas. However, these wastes and other wastes may be otherwise regulated by the EPA or state agencies. Moreover, in the ordinary course of our operations, industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA. We currently own or lease, and have in the past owned or leased, a number of properties that have been used as service yards in support of oil and natural gas exploration and production activities. Although we have utilized operating and disposal practices that we considered standard in the industry at the time, there is the possibility that repair and maintenance activities on rigs and equipment stored in these service yards, as well as fluids stored at these yards, may have resulted in the disposal or release of hydrocarbons or other wastes on or under these yards or other locations where these wastes have been taken for disposal. In addition, we own or lease properties that in the past were operated by third parties whose operations were not under our control. These properties and the hydrocarbons or wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination. In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials, or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated or occupied by us have been used for oil and natural gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM. Our operations are also subject to the federal Clean Water Act and analogous state laws. Under these laws, permits must be obtained to discharge pollutants into regulated surface or subsurface waters. Spill prevention, control and countermeasure requirements under federal law require appropriate operating protocols, including containment berms and similar structures, to help prevent the contamination of regulated waters in the event of a petroleum hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities or during construction activities. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Additionally, permits for discharges of storm water runoff may be required for certain of our properties. The federal Clean Water Act and the federal Oil Pollution Act of 1990 contain numerous requirements relating to the prevention of and response to oil spills into regulated waters, and require some owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” relating to the possible discharge of oil into regulated waters. Our underground injection operations are subject to the federal Safe Drinking Water Act, referred to as the “SDWA,” as well as analogous state and local laws and regulations including the Underground Injection Control (“UIC”) program, which program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities. The federal Energy Policy Act of 2005 amended the UIC provisions to exclude certain hydraulic fracturing activities from the definition of “underground injection” under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Similar legislation could be introduced in the current session of Congress, which commenced in January 2016, or at the state level. For example at the state level, several states in which we operate, including Wyoming, Texas, Colorado and Oklahoma, have adopted regulations requiring operators to disclose certain information regarding hydraulic fracturing fluids. In addition, public concerns have recently been raised regarding the disposal of hydraulic fluid in injection wells. Partly in response to public concerns, the Texas Railroad Commission, referred to as (“RRC”), amended its existing oil and gas disposal well regulations to require seismic activity data in permit applications and provisions to authorize the imposition of certain limitations on existing wells if seismic activity increases in the area of an injection well, including a temporary injection ban.Our operations employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. Our hydraulic fracturing activities are principally in Texas, Oklahoma, Kansas and Colorado. Our operations also involve the 13


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    disposal of produced salt water by underground injection. The substantial majority of our saltwater disposal wells are located in Texas and are regulated by the RRC. We also operate salt water disposal wells in New Mexico, Oklahoma, Arkansas, Louisiana and North Dakota and are subject to similar regulatory controls in those states. Regulations in these states require us to obtain a permit from the applicable regulatory agencies to operate each of our underground salt water disposal wells. We believe that we have obtained the necessary permits from these agencies for each of our underground injection wells and that we are in substantial compliance with permit conditions and commission rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment or other conditions such as earthquakes. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries. In addition, our sales of residual crude oil collected as part of the saltwater injection process could impose liability on us in the event that the entity to which the oil was transferred fails to manage the residual crude oil in accordance with applicable environmental health and safety laws. We maintain insurance against some risks associated with environmental liabilities that may occur as a result of well service activities. However, there can be no assurance that this insurance will cover all potential losses, that insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a material adverse effect on our financial condition and operations. We are also subject to the requirements of the federal Occupational Safety and Health Act, known as (“OSHA,”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We are also subject to the requirements of the Federal Motor Carrier Safety Regulations (“DOT – FMCSA”) of the U.S. Department of Transportation (“DOT”) and comparable state statutes that regulate commercial motor vehicle operations. In addition, we are also subject to the Pipeline and Hazardous Materials Safety Administration “DOT-PHMSA” and comparable state statutes that regulate hazardous materials shipments. The federal Clean Air Act, as amended, known as the “Clean Air Act” or (“CAA)” and state air pollution permitting laws, restrict the emission of air pollutants from many sources, including drilling operations and related equipment, and as a result affect oil and natural gas operations. In addition, more stringent regulations governing emissions of air pollutants, including greenhouse gases such as methane (a component of natural gas) and carbon dioxide (“CO2”), are being developed by the federal government and may increase the costs of compliance for our drilling services or our customers’ operations. For example, on January 14, 2015, the Obama administration announced a new emission reduction target for methane emissions associated with the oil and gas sector. Responding to scientific studies that have suggested that emissions of gases, commonly referred to as “greenhouse gases,” including gases associated with the oil and gas sector such as carbon dioxide, methane, and nitrous oxide among others, may be contributing to global warming and other environmental effects, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. In the recent Congress, numerous legislative measures were introduced that would have imposed restrictions or costs on greenhouse gas emissions, including from the oil and gas industry. It is uncertain whether similar measures will be introduced in, or passed by, the new Congress which co nvened in January 2016. However, any such legislation may have the potential to affect our business, customers or the energy sector generally. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change (“UNFCCC”). The U.S. was among 195 nations that signed an international accord in December 2015, the so-called Paris Agreement, with the objective of limiting greenhouse gas emissions. The EPA has also taken action under the CAA to regulate greenhouse gas emissions. In addition, some states have taken or proposed legal measures to reduce emissions of greenhouse gases. Following the U.S. Supreme Court’s decision in Massachusetts, et al. v. EPA , 549 U.S. 497 (2007), finding that greenhouse gases fall within the CAA definition of “air pollutant,” the EPA determined that greenhouse gases from certain sources “endanger” public health or welfare. As a result, the EPA took the position that existing CAA provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under the EPA’s Prevention of Significant Deterioration (“PSD”) and Title V permit programs beginning in 2011. In 2014, the Supreme Court’s decision in Utility Air Regulatory Group v. EPA limited the EPA to include greenhouse gasses in the permitting process only if PSD was already triggered by another listed pollutant. If deemed cost-effective, facilities that trigger permit requirements may be required to reduce greenhouse gas emissions consistent with the “best available control technology” standards. Such changes will also affect state air permitting programs in states that administer the CAA under a delegation of authority, including states in which we have operations. Additionally, in November 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and natural gas industry. The expansion requires annual, on-site monitoring and additional inventory and reporting of greenhouse gas emissions and affects many of our existing operations and must be considered when planning for future operations. Although subject to legal challenge, the EPA rules promulgated thus far are currently 14


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    final and effective, and will remain so unless the regulations are overturned by a court ruling, or Congress adopts legislation altering the EPA’s regulatory authority. In January 2015, the White House announced plans to regulate methane emissions attributable to the upstream oil and gas industry, including activities related to gathering and compression, as a greenhouse gas. In August 2015, the EPA proposed new regulations that set methane emission standards for new and modified natural gas production and natural gas processing and transmission facilities. The EPA has announced plans to finalize these rules this spring. The rules are a result of the Obama administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45% from 2012 levels by 2025. Until such proposed rules are finalized, the impact on our operations is not known; however, it is believed that the only facilities impacted by this proposed rule would be those placed into service after the rules are finalized. A number of states, individually or in regional cooperation, have also imposed restrictions on greenhouse gas emissions under various policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy, or use of fuels with lower carbon content. These federal, regional and state measures generally apply to industrial sources, including facilities in the oil and gas sector, and could increase the operating and compliance costs of our services and facilities.International accords such as the Paris Agreement may result in additional regulations to control greenhouse gas emis sions. These regulations could also adversely affect market demand or pricing for our services, by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources. The potential increase in the costs of our operations could include costs to operate and maintain our equipment or facilities install new emission controls on our equipment or facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged for our services, such recovery of costs is uncertain and may depend on events beyond our control, including the provisions of any final regulations. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce demand for our services. There is considerable debate as to global warming and the environmental effects of greenhouse gas emissions and associated consequences affecting global climate, oceans, and ecosystems. As a commercial enterprise, we are not in a position to validate or repudiate the existence of global warming or various aspects of the scientific debate. However, if global warming is occurring, it could have an impact on our operations. For example, our operations in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels or disruption of operations from more frequent and severe weather events. Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe. Changes in climate or weather may hinder exploration and production activities or increase or decrease the cost of production of oil and natural gas resources and consequently affect demand for our field services. Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix. However, we are not in a position to predict the precise effects of global warming on energy markets or the physical effects of global warming. We are providing this disclosure based on publicly available information on the matter. Employees As of December 31, 2015, we employed approximately 3,900 people, with approximately 80% employed on an hourly basis. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory. Executive Officers of the Registrant Our executive officers as of February 23, 2016 and their respective ages and positions are as follows: Name Age Position T. M. “Roe” Patterson 41 President, Chief Executive Officer and Director Alan Krenek 60 Senior Vice President, Chief Financial Officer, Treasurer and Secretary James F. Newman 51 Senior Vice President — Region Operations William T. Dame 55 Vice President — Pumping Services Douglas B. Rogers 52 Vice President — Marketing Eric Lannen 50 Vice President — Human Resources Lanny T. Poldrack 48 Vice President — Central Region and Tubular Division John Cody Bissett 41 Vice President, Controller and Chief Accounting Officer Brett J. Taylor 43 Vice President — Equipment and Manufacturing 15


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    Set forth below is the description of the backgrounds of our executive officers. T. M. “Roe” Patterson (President, Chief Executive Officer and Director) has 21 years of related industry experience. He was named our President and Chief Executive Officer and appointed as a Director in September 2013. Since joining Basic in 2006, he served in positions of increasing responsibility: as our Senior Vice President and Chief Operating Officer from April 2011 until September 2013, as a Senior Vice President from September 2008 until April 2011 and as a Vice President of various groups within Basic from February 2006 until September 2008. Prior to joining Basic, he was president of his own manufacturing and oilfield service company, TMP Companies, Inc., from 2000 to 2006. He was a Contracts/Sales Manager for the Permian Division of Patterson Drilling Company from 1996 to 2000. He was an Engine Sales Manager for West Texas Caterpillar from 1995 to 1996. Mr. Patterson graduated with a B.S. degree in Biology from Texas Tech University. Alan Krenek (Senior Vice President, Chief Financial Officer, Treasurer and Secretary) has 28 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. He became Senior Vice President and Secretary in May 2006. Prior to joining Basic, he held various financial management positions at Landmark Graphics Corp., Noble Corporation and Pool Energy Services Company. Mr. Krenek graduated with a B.B.A. degree in Accounting from Texas A&M University and is a Certified Public Accountant. James F. Newman (Senior Vice President — Regional Operations) has 31 years of related industry experience and has been our Senior Vice President, Region Operations since November 2013. He previously served as our Group Vice President — Permian Business Unit from April 2011 until September 2013 and has been a Group Vice President since September 2008. Prior to joining Basic, he co-founded Triple N Services in 1986 and served as its President through May 2008. He initially served Basic as an Area Manager in the plugging and abandonment operations. Mr. Newman is a registered Professional Engineer and is active in the Society of Petroleum Engineers. Mr. Newman graduated with a B.S. in Petroleum Engineering from Colorado School of Mines. William T. Dame (Vice President — Pumping Services) has 35 years of related industry experience. Mr. Dame joined Basic in 2003 and has served as our Vice President — Pumping Services since 2006. He previously served as our Vice President — PPW and RAFT Divisions from 2005 to 2006 and as a regional vice president from 2004 through 2005. Mr. Dame began his career in 1981 with Halliburton. From1987 to 1997, he served as a vice president of Fleet Cementers, Inc., and from 1997 to 2003, he worked in various operational management positions at Plains Energy, Precision Drilling and New Force Energy Services. Mr. Dame attended Tarleton State University. Douglas B. Rogers (Vice President — Marketing) has 33 years of related industry experience. He joined Basic in 2007 and serves as Vice President — Marketing after serving as Vice President-Contracts for the Drilling Division. Mr. Rogers was Vice President- Rocky Mountain Division for Patterson - UTI Drilling Company from March 2003 to June 2007. He also served as Western Division Sales Manager for Ambar Lonestar Fluid Services, a division of Patterson - UTI Drilling Company, from 1998 to 2003. He began his career in 1983 with Permian Servicing Company, where he managed well servicing operations. He continued in that capacity through Permian Servicing Company’s mergers with Xpert Well Service and Pride Petroleum Service until joining Zia Drill/Nova Mud in March 1997. Mr. Rogers graduated with a B.A. degree from Eastern New Mexico University. Eric Lannen (Vice President — Human Resources) has been a Vice President since August 2015. Eric Lannen has more than 24 years of Human Resources experience in the oil & gas, engineering & construction, defense & government services and the technology industries, as well as more than 15 years of experience in HR leadership roles. Prior to joining Basic, Mr. Lannen served as Senior Vice President, Human Resources for Dyncorp International and Vice President of Human Resources at McDermott International. Mr. Lannen’s prior experience includes: talent acquisition leader for IBM growth markets across five continents; leading Human Resources for the Government Services Division of Kellogg Brown & Root (KBR); and several HR positions at Halliburton Company. Mr. Lannen graduated from Texas A&M University with a Bachelor of Science degree. Lanny T. Poldrack (Vice President — Central Region and Tubular Division) has 29 years of related industry experience. He has served as our Vice President — Safety and Operations Support since April 2011. From April 2009 to April 2011, he served as a Corporate Marketing Representative based in Houston, Texas. Prior to joining Basic, he spent 13 years at Cudd Energy Services where he held various technical sales and sales management positions forboth well intervention and live well service divisions, the last 4 years of which he served as Business Development Manager for Cudd Well Control for both domestic and international operations in U.S., Canadian, Latin America, European, Middle Eastern and South East Asian markets. He began his oilfield career in West Texas as a technical field representative for Weatherford International, specializing in fishing and rental tools and hydraulic BOPsystems. Mr. Poldrack graduated with an applied science degree from Odessa Junior College. John Cody Bissett (Vice President, Controller and Chief Accounting Officer) has 17 years of related industry experience. He was appointed Basic’s Vice President, Controller and Chief Accounting Officer in March 2012. Mr. Bissett previously served as Basic’s Corporate Controller from July 2008 to March 2012 and as the Director of Financial Reporting from December 2007 to July 2008. Prior to joining Basic, Mr. Bissett was the Controller of Cap Rock Energy from November 2006 through December 2007, and previously held various roles in the accounting and finance function of Sirius Computer Solutions and the audit practice of KPMG LLP. Mr. Bissett graduated with an M.B.A. and a B.B.A. in Accounting from Angelo State University and is a Certified Public Accountant. 16


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    Brett J. Taylor (Vice President — Manufacturing and Equipment) has 23 years of related industry experience. He has been our Vice President of Manufacturing and Equipment since June 2013. Prior to joining Basic, he was President of Taylor Industries, LLC in Tulsa , Oklahoma from 2010 to 2013. From 2009 to 2010, he served as Executive Vice President of Sales and Marketing at Serva Group Manufacturing. Before that, Mr. Taylor held positions of increasing responsibilities at Taylor Industries over an 11-year span. His tenure at Taylor included the role of Consultant, President of Sales from 2008 to 2009, President of Taylor from 2003 to 2008, General Manager & Vice President of Business Development from 2001 to 2003, and Sales and Marketing Manager from 1997 to 1999. Mr. Taylor graduated with a Bachelor of Business Degree from the University of Oklahoma. Additional Information We make available free of charge on our website, www.basicenergyservices.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to the Exchange Act, as soon as reasonably practicable after we electronically file such information with, or furnish it to, the SEC. These documents are also available on the SEC’s website at www.sec.gov, or you may read and copy any materials that we file with or furnish to the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The information on our website is not, and shall not be deemed to be, a part of this annual report on Form 10-K or incorporated into any of our other filings with the SEC. We have a Code of Conduct that applies to all of our directors, officers and employees. The Code of Conduct is available publicly on our website atwww.basicenergyservices.com. Any waivers granted to directors or executive officers and any material amendments to our Code of Conduct will be posted promptly on our website and/or disclosed in a Current Report on Form 8-K. The certifications by our Chief Executive Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits to this Annual Report on Form 10-K. We have also filed with the New York Stock Exchange the most recent Annual CEO Certification as required by Section 303A.12(a) of the New York Stock Exchange Listed Company Manual. ITEM 1A. RISK FACTORS The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition and prospects. Risks Relating to Our Business Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business has been in the past, and may in the future be, adversely affected by industry and financial market 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 the United States. Customers’ expectations for lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing demand for our services and equipment. Industry conditions are influenced by numerous factors over which we have no control, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, political instability in oil and natural gas producing countries and merger and divestiture activity among oil and gas producers. The volatility of the oil and natural gas industry and the consequent impact on exploration and production activity could adversely impact the level of drilling and workover activity by some of our customers. This reduction may cause a decline in the demand for our services or adversely affect the price of our services. In addition, reduced discovery rates of new oil and natural gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines. Deterioration in the global economic environment commencing in the latter part of 2008 and continuing throughout 2009 caused the oilfield services industry to cycle into a downturn due to weakened demand. The industry returned to higher activity levels in 2011 and remained higher during the first half of 2012, before another downturn in the second half of 2012, affecting natural gas prices in particular. The industry pricing remained relatively stable through the middle of 2014. However, beginning in the second half of 2014, oil prices declined substantially from historical highs and have continued to decline. Oil and gas prices may remain depressed for the foreseeable future. In light of thecurrent depressed oil prices, many oil producers, including many of our customers, have announced significant reductions in capital budgets for 2016. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause oil and natural gas producers to make further reductions to capital budgets in the future even if oil or natural gas prices increase from current levels. Any such cuts in spending will curtail drilling programs as well as discretionary spending on well services, which may result in a reduction in the demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events could adversely affect our operating results. 17


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    If oil and natural gas prices remain volatile, or if oil or natural gas prices remain low or decline further, the demand for our services could be adversely affected. The demand for our services is primarily determined by current and anticipated oil and natural gas prices and the related general production spending and level of drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and may cause lower rates and lower utilization of our well service equipment. If oil prices or natural gas prices continue to remain low or decline further, or if there is a reduction in drilling activities, the demand for our services and our results of operations could be materially and adversely affected. Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. The Cushing WTI Spot Oil Price averaged $97.91, $93.26 and $48.69 per barrel in 2013, 2014 and 2015, respectively. The Cushing WTI oil prices have declined from over $107 per barrel in June 2014 to $37 per barrel on December 31, 2015 and $26.55 per barrel during January 2016. The Henry Hub Natural Gas Spot Price averaged $3.73, $4.39 and $2.63 per Mcf for 2013, 2014 and 2015, respectively. Competition within the well services industry may adversely affect our ability to market our services. The well services industry is highly competitive and fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. The amount of equipment available may exceed demand, which could result in active price competition. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. In addition, adverse market conditions lower demand for well servicing equipment, which results in excess equipment and lower utilization rates. If adverse oil and natural gas market conditions persist or deteriorate further, our utilization rates may decline. We may require additional capital in the future. We cannot assure you that we will be able to generate sufficient cash internally or obtain alternative sources of capital on favorable terms, if at all. If we are unable to fund capital expenditures, our business may be adversely affected. While reducing capital expenditures based on current industry conditions, we anticipate that we will continue to make substantial capital investments in the future to purchase additional equipment to expand our services, refurbish our well servicing rigs and replace existing equipment. For the year ended December 31, 2014, we invested approximately $236.3 million in cash for capital expenditures, excluding acquisitions. For the year ended December 31, 2015, we invested approximately $53.9 million in cash for capital expenditures, excluding acquisitions. For 2016, we have currently budgeted $40.0 million for capital expenditures, excluding acquisitions. Historically, we have financed these investments through internally generated funds, debt and equity offerings, our capital lease program and borrowing under a senior credit facility. Please read “Liquidity and Capital Resources” for more information. Our significant capital investments require cash that we could otherwise apply to other business needs. However, if we do not incur these expenditures while our competitors make substantial fleet investments, our market share may decline and our business may be adversely affected. In addition, if we are unable to generate sufficient cash internally or obtain alternative sources of capital to fund our proposed capital expenditures and acquisitions, take advantage of business opportunities or respond to competitive pressures, it could materially adversely affect our results of operations, financial condition and growth. If we raise additional funds by issuing equity securities, dilution to existing stockholders may result. Adverse changes in the capital markets could make it difficult to obtain additional capital or obtain it at attractive rates. Our future financial results could be adversely impacted by asset impairments or other charges. We have recorded goodwill impairment charges and asset impairment charges in the past. We periodically evaluate our long-lived assets, including our property and equipment, indefinite-lived intangible assets, and goodwill for impairment. In performing these assessments, we project future cash flows on a discounted basis for goodwill, and on an undiscounted basis for other long-lived assets, and compare these cash flows to the carrying amount of the related assets. These cash flow projections are based on our current operating plans, estimates and judgmental assumptions. We perform the assessment of potential impairment on our goodwill and indefinite-lived intangible assets at least annually in the fourth quarter, or more often if events and circumstances warrant. We perform the assessment of potential impairment for our property and equipment whenever facts and circumstances indicate that the carrying value of those assets may not be recoverable due to various external or internal factors. 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 additional impairment charges in future periods, which could have a material adverse effect on our financial position and results of operations. We have operated at a loss in the past, and there is no assurance of our profitability in the future. Historically, we have experienced periods of low demand for our services and have incurred operating losses. In the future, we may not be able to reduce our costs, increase our revenues, or reduce our debt service obligations sufficient to achieve or maintain 18


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    profitability and generate positive operating income. Under such circumstances, we may incur further operating losses and experience negative operating cash flow. Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions. We now have, and will continue to have, a significant amount of indebtedness. As of December 31, 2015, our total debt was $887.0 million, including $960,000 of premium, comprisedof $475.0 million aggregate principal amount due under our 7.75% Senior Notes due 2019, $300.0 million aggregate principal amount due under our 7.75% Senior Notes due 2022 and capital lease obligations in the aggregate amount of $111.1 million. As of December 31, 2015, we had no borrowings and $50.3 million of letters of credit outstanding under our $250.0 million revolving credit facility, giving us $93.4 million of available borrowing capacity. We intend to amend our revolving credit facility to reduce aggregate commitments thereunder to $100.0 million. On February 17, 2016, we entered into a term loan credit agreement that provides for borrowings ofan aggregate principal amount of $165.0 million on the closing date and delayed draw term loan borrowings in an aggregate principal amount not to exceed $15.0 million. The making of such term loans is subject to the satisfaction of certain conditions precedent, including, with respect to the delayed draw term loan borrowing, the consent of the lenders providing such term loan. For the year ended December 31, 2015, we made cash interest payments totaling $61.6 million. Our current and future indebtedness could have important consequences. For example, it could: • impair our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes; • limit our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness; • make us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow will be required to make principal and interest payments on our indebtedness, making it more difficult to react to changes in our business and in industry and market conditions; • limit our ability to obtain additional financing that may be necessary to operate or expand our business; • put us at a competitive disadvantage to competitors that have less debt; and • increase our vulnerability to interest rate increases to the extent that we incur variable rate indebtedness. If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in instruments governing any existing or future indebtedness, we could be in default under the terms of such instruments. In the event of a default, the holders of our indebtedness could elect to declare all the funds borrowed under those instruments to be due and payable together with accrued and unpaid interest, secured lenders could foreclose on any of our assets securing their loans and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. If our indebtedness is accelerated, or we enter into bankruptcy, we may be unable to pay all of our indebtedness in full. Any of the foregoing consequences could restrict our ability to grow our business and cause the value of our common stock to decline. Our Revolving Credit Facility and the indentures governing our 7.75% Senior Notes due 2019 and our 7.75% Senior Notes due 2022 impose restrictions on us that may affect our ability to successfully operate our business. Our Revolving Credit Facility and the indentures governing our 7.75% Senior Notes due 2019 and our 7.75% Senior Notes due 2022 each impose limitations on our ability to take various actions, such as: • limitations on the incurrence of additional indebtedness; • restrictions on mergers, sales or transfers of assets without the lenders’ consent; and • limitations on dividends and distributions. In addition, our Revolving Credit Facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, some of which become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. The failure to comply with any of these financial conditions, including the financial ratios or covenants, would 19


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    cause a default under our Revolving Credit Facility. A default under any of our indebtedness, if not waived, could result in the acceleration of such indebtedness or other indebtedness, in which case the debt would become immediately due and payable. In addition, a default or acceleration of any of our indebtedness under our 7.75% Senior Notes due 2019, our 7.75% Senior Notes due 2022 or our Revolving Credit Facility could result in a default under or acceleration of other indebtedness with cross-default or cross-acceleration provisions. In the event of any acceleration of our indebtedness, we may not be able to pay our debt or borrow sufficient funds to refinance it, and any holders of secured indebtedness may seek to foreclose on the assets securing such indebtedness. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our Revolving Credit Facility or existing limitations on the incurrence of additional indebtedness, including in connection with acquisitions. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Revolving Credit Facility” for a discussion of our Revolving Credit Facility. Our operations are subject to inherent risks, including operational hazard and cyber attacks. These risks may be self-insured, or may not be fully covered under our insurance policies. Our operations are subject to hazards inherent in the oil and natural gas industry, such as, but not limited to, accidents, blowouts, explosions, craters, fires and oil spills. These conditions can cause: • personal injury or loss of life; • damage to or destruction of property, equipment and the environment; and • suspension of operations. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations. In addition, claims for loss of oil and natural gas production and damage to formations can occur in the well services industry. Litigation arising from a catastrophic occurrence at a location where our equipment and services are being used may result in our being named as a defendant in lawsuits asserting large claims. As is customary in our industry, our service contracts generally provide that we will indemnify and hold harmless our customers from any claims arising from personal injury or death of our employees, damage to or loss of our equipment, and pollution emanating from our equipment and services. Similarly, our customers agree to indemnify and hold us harmless from any claims arising from personal injury or death of their employees, damage to or loss of their equipment, and pollution caused from their equipment or the well reservoir (including uncontained oil flow from a reservoir). Our indemnification arrangements may not protect us in every case. For example, from time to time we may enter into contracts with less favorable indemnities or perform work without a contract that protects us. In addition, our indemnification rights may not fully protect us if the customer is insolvent or becomes bankrupt, does not maintain adequate insurance or otherwise does not possess sufficient resources to indemnify us. In addition, our indemnification rights may be held unenforceable in some jurisdictions. Our inability to fully realize the benefits of our contractual indemnification protections could result in significant liabilities and could adversely affect our financial condition, results of operations and cash flows. Our operations are also subject to the risk of cyber-attacks. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data, having our business operations interrupted, and increased costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. We maintain insurance coverage that we believe to be customary in the industry against these hazards. However, we do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. As such, not all of our property is insured. We are also self-insured up to retention limits with regard to workers’ compensation, general liability, and medical and dental coverage. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. It is likely that, in our insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or considerably more expensive than it has been in the recent past. In addition, our insurance is subject to coverage limits, and some policies exclude coverage for damages resulting from environmental contamination. 20


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    We are subject to environmental, health and safety laws and regulations that may expose us to significant liabilities for penalties, damages or costs of remediation or compliance. Our operations are subject to federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities, the imposition of substantial liabilities for pollution resulting from our operations and the application of specific health and safety criteria addressing worker protection. Regulations concerning equipment certification also create an ongoing need for regular maintenance. Failure to comply with these laws and regulations could result in investigations, restrictions or orders suspending well operations, the assessment of administrative, civil and criminal penalties, the revocation of permits and the issuance of corrective action orders, any of which could have a material adverse effect on our business, results of operations and financial condition. There is inherent risk of environmental costs and liabilities in our business as a result of our handling of petroleum hydrocarbons and oilfield and industrial wastes, air emissions and wastewater discharges related to our operations, and historical industry operations and waste disposal practices. Our fluid services segment includes disposal operations into injection wells that pose risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, which means that in some situations, we could be exposed to liability as a result of our conduct that was without fault or lawful at the time it occurred or as a result of the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition and results of operations. We operate as a motor carrier and therefore are subject to regulation by the DOT and by other various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. In addition, the trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, require on board black box recorder devices or limits on vehicle weight and size. 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 costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas and could limit well servicing opportunities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance. Please read “Business and Properties — Environmental Regulation and Climate Change” for more information on the environmental laws and government regulations that are applicable to us. We may not be able to grow successfully through future acquisitions or successfully manage future growth, and we may not be able to effectively integrate the businesses we do acquire. Our business strategy includes growth through the acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating our current or future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making further acquisitions or causing us to refrain from making additional acquisitions. We may also be limited in our ability to incur additional indebtedness in connection with or to fund future acquisitions under the Revolving Credit Facility and under the indentures governing our 7.75% Senior Notes due 2019 and 7.75% Senior Notes due 2022. Whether we realize the anticipated benefits from an acquisition depends, in part, upon our ability to integrate the operations of the acquired business, the performance of the underlying product and service portfolio, and the performance of the management team and other personnel of the acquired operations. Accordingly, our financial results could be adversely affected from unanticipated performance issues, legacy liabilities, transaction-related charges, amortization of expenses related to intangibles, charges for impairment of long-term assets, credit guarantees, partner performance and indemnifications. While we believe that we have established appropriate and adequate procedures and processes to mitigate these risks, there is no assurance that these transactions will be successful. 21


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    We depend on several significant customers, and a loss of one or more significant customers could adversely affect our results of operations. Our customers consist primarily of major and independent oil and gas companies. During 2015 and 2014, our top five customers accounted for 24% of our revenues. However, no individual customer composed greater than 10% of our revenues. The loss of any one of our largest customers or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations. If our customers delay paying or fail to pay a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. In most cases, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience increased delays and failures due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition. Our industry has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could adversely affect our business. We may not be able to find enough skilled labor to meet our needs, which could limit our growth. Our business activity historically decreases or increases with the prices of oil and natural gas. We may have problems finding enough skilled and unskilled laborers in the future if the demand for our services increases. If we are not able to increase our service rates sufficiently to compensate for wage rate increases, our operating results may be adversely affected. Other factors may also inhibit our ability to find enough workers to meet our employment needs. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility 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 with ours. We believe that our success is dependent upon our ability to continue to employ and retain skilled technical personnel. Our inability to employ or retain skilled technical personnel generally could have a material adverse effect on our operations. Our success depends on key members of our management, the loss of any of whom could disrupt our business operations. We depend to a large extent on the services of some of our executive officers. The loss of the services of T. M. “Roe” Patterson, our President and Chief Executive Officer, or other key personnel could disrupt our operations. Although we have entered into employment agreements with Mr. Patterson and our other executive officers that contain, among other provisions, non-compete agreements, we may not be able to enforce the non-compete provisions in the employment agreements. Adverse weather conditions may affect our operations. Our operations may be materially affected by severe weather conditions in areas where we operate. Severe weather, such as blizzards, extreme temperatures and hurricanes may cause evacuation of personnel, curtailment of services and suspension of operations, and loss of or damage to equipment and facilities. Damage from any adverse weather conditions could adversely affect our financial condition, results of operations and cash flows. Weather conditions may also affect the price of crude oil and natural gas, and related demand for our services. Please read the risk factor above, “If oil andnatural gas prices remain volatile, or if oil prices decline or natural gas prices remain low or decline further, the demand for our services could be adversely affected.” Climate change legislation or regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for our field services. In response to findings that emissions of carbon dioxide, methane and other greenhouse gases from industrial and energy sources contribute to increases of carbon dioxide levels in the earth’s atmosphere and oceans and contribute to global warming and other environmental effects, the EPA has adopted various regulations under the federal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and gas industry. On August 16, 2012 the EPA published rules that include standards to reduce methane emissions associated with oil and gas production. EPA has announced plans to finalize additional rules to reduce methane emissions from new oil and gas facilities this spring. Federal changes will affect state air permitting programs in states that administer the federal Clean Air Act under a delegation of authority, including states in which we have operations. Numerous legislative measures have been introduced in the past that would have imposed restrictions or costs on greenhouse gas emissions, including from the oil and gas industry. It is uncertain whether similar measures will be introduced in, or passed by, the new Congress which convened in January 201 6. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change which led to the signing of the Paris Agreement in December 2015. Additionally, certain U.S. states or regional coalitions of states have adopted measures regulating or limiting 22


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    greenhouse gases from certain sources or have adopted policies seeking to reduce overall emissions of greenhouse gases. The adoption and implementation of any international treaty or of any federal or state legislation or regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with our operations and other sources within the industrial or energy sectors. Such legislation or regulations could adversely affect demand for the production of oil and natural gas and thus reduce demand for the services we provide to oil and natural gas producers as well as increase our operating costs by requiring additional costs to operate and maintain equipment and facilities, install emissions controls, acquire allowances or pay taxes and fees relating to emissions, which could adversely affect our results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases may produce changes in climate or weather, such as increased frequency and severity of storms, floods and other climatic events, which if any such effects were to occur, could have adverse physical effects on our operations, physical assets and field services to exploration and production operators. Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our well servicing activities and could adversely affect our financial position, results of operations and cash flows. We provide hydraulic fracturing and fluid handling services to our customers. Hydraulic fracturing is a commonly used process that involves injection of water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the federal Safe Drinking Water Act (“SDWA”) to exclude certain hydraulic fracturing practices from the definition of “underground injection.” The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and published proposed guidance relating to such practices in May 2012. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. Congress has considered bills to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and would require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the internet. At the state level, several states in which we operate have adopted regulations requiring the disclosure of certain information regarding hydraulic fracturing fluids. Scrutiny of hydraulic fracturing activities continues in other ways, as the EPA commenced a study of the potential environmental impacts of hydraulic fracturing and issued adraft final report in June 2015 for public comment and review. The U.S. Department of the Interior issued regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents in March 2015. On April 13, 2012, the Department of Interior, the Department of Energy and the EPA issued a memorandum outlining a multi-agency collaboration on unconventional oil and gas research in response to the White House “Blueprint for a Secure Energy Future” and the recommendations of the Secretary of Energy Advisory Board Subcommittee on Natural Gas. Moreover, the EPA has announced that it will develop effluent limitations for the treatment of discharge of wastewater resulting from hydraulic fracturing activities. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Recently, public concerns have been raised regarding the disposal of hydraulic fluid in injection wells. Partly in response to public concerns, the Texas Railroad Commission amended its existing oil and gas disposal well regulations to require seismic activity data in permit applications and provisions to authorize the imposition of certain limitations on existing wells if seismic activity increases in the area of an injection well, including a temporary injection ban. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas. In 2010, a committee of the U.S. House of Representatives undertook investigations into hydraulic fracturing practices involving the use of diesel fuel in hydraulic fracturing fluids, including requesting information from various field services companies including us. We responded to that request and have received no further communication from the committee with regard to that investigation. However, on January 31, 2011, Representative Henry Waxman and other members of Congress wrote to the EPA asserting that various companies, including us, had engaged in hydraulic fracturing operations requiring a permit without obtaining such a permit. We have no knowledge as to whether or how the EPA will respond to that letter. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our customers or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could potentially increase our costs of operations and cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash flows. 23


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    Potential listing of species as “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions or delays on our oil and natural gas exploration and production customers, which could adversely reduce the amount of contract drilling services that we provide to such customers. The federal Endangered Species Act, referred to as the “ESA,” and analogous state laws regulate a variety of activities, including oil and gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species could cause oil and natural gas exploration and production operators to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce the amount of drilling activities in affected areas, including support services that we provide to such operators under our contract drilling services segment. Numerous species have been listed or proposed for protected status in areas in which we provide or could in the future provide field services. For instance, in March 2014 the U.S. Fish & Wildlife Service, also referred to as the (“FWS.”) listed the lesser prairie chicken as a threatened species under the Endangered Species Act. Concurrently, the FWS finalized a special rule under Section 4(d) of the Endangered Species Act that authorizes Kansas, Oklahoma, Texas, New Mexico and Colorado to continue managing conservation efforts related to oil and gas activities under the Western Association of Fish and Wildlife Agencies’ range-wide conservation plan. However in September 2015, a federal district court vacated the listing. The Department of Justice has appealed the vacation on behalf of FWS. Certain wildflower species, among others, are also species that have been or are being considered for protected status under the ESA and whose range can coincide with oil and natural gas production activities. The presence of protected species in areas where operators whom we provide contract drilling services conduct exploration and production operations could impair such operators’ ability to timely complete well drilling and development and, consequently, adversely affect the amount of contract drilling or other field services that we provided to such operators, which reduction of services could have a significant adverse effect on our results of operations and financial position. One of our directors may have a conflict of interest because he is also currently a managing partner of a private equity firm that makes investments in the energy sector. The resolution of any conflict of interest may not be in our or our stockholders’ best interests. Steven A. Webster, the Chairman of our Board of Directors, is the Co-Managing Partner of Avista Capital Holdings, L.P., a private equity firm that makes investments in the energy sector. This relationship may create a conflict of interest because of his responsibilities to Avista and its owners. His duties as a partner in, or director or officer of, Avista or its affiliates may conflict with his duties as a director of our company regarding corporate opportunities and other matters. The resolution of any such conflict may not always be in our or our stockholders’ best interest. Risks Relating to Ownership of Our Common Stock Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock. Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including: • a classified board of directors, so that only approximately one third of our directors are elected each year; • limitations on the removal of directors; • the prohibition of stockholder action by written consent; • limitations on the ability of our stockholders to call special meetings; and • advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders. Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors. Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us. We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock. 24


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    ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 3. LEGAL PROCEEDINGS From time to time, Basic is a party to litigation or other legal proceedings that Basic considers to be a part of the ordinary course of business. Basic is not currently involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity. The information regarding litigation and environmental matters described in Note 7 of the notes to our audited consolidated financial statements included in this Annual Report on Form 10-K is incorporated herein by reference. 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 Market Price for Registrant’s Common Equity Our common stock is traded on the New York Stock Exchange under the symbol “BAS.” The table below presents the high and low daily closing sales prices of the common stock, as reported by the New York Stock Exchange, for each of the quarters in the years ended December 31, 2014 and 2015, respectively: High Low 2014: First Quarter $ 27.41 $ 14.63 Second Quarter $ 29.22 $ 25.14 Third Quarter $ 29.46 $ 21.69 Fourth Quarter $ 20.59 $ 5.17 2015: First Quarter $ 8.04 $ 5.44 Second Quarter $ 10.19 $ 7.16 Third Quarter $ 6.92 $ 3.30 Fourth Quarter $ 5.10 $ 2.40 As February 23, 2016, we had 42,195,405 shares of common stock outstanding held by approximately 194 record holders. We have not declared or paid any cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. Securities Authorized for Issuance under Equity Compensation Plans The following table provides information regarding options or warrants authorized for issuance under our equity compensation plans as of December 31,2015: Number of Securities to be Issued upon Weighted Average Exercise Price of Number of Securities Remaining Available for Future Plan Category Exercise of Outstanding Options Outstanding Options Issuance Under Equity Compensation Plans (1) Equity compensation plans approved by security holders 175,000 $ 26.29 2,095,334 Equity compensation plans not approved by security holders — — — Total 175,000 $ 26.29 2,095,334 (1) Consists of the Sixth Amended and Restated Basic Energy Services, Inc. 2003 Incentive Plan (as amended effective May21, 2015). 25


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    Issuer Purchases of Equity Securities The following table provides information relating to our repurchase of shares of common stock during the three months ended December 31,2015 (dollars in thousands, except average price paid per share): Issuer Purchases of Equity Securities Total Number of Approximate Dollar Shares Purchased Value of Shares as Part of Publicly that May Yet be Total Number of Average Price Paid Announced Purchased Under Period Shares Purchased Per Share Program (1) the Program (1) October 1 — October 31 1,818 $ 3.68 — $ — November 1 — November 30 (2) 9,261 $ 3.96 — $ — December 1 — December 31 402,099 $ 2.63 400,000 $ — Total 413,178 $ 2.66 400,000 $ 9,451 (1) On May 24, 2012, we announced that our Board of Directors had reauthorized the repurchase of up to approximately $35.2 million of shares of our common stock from time to time in open market or private transactions, at our discretion, as a continuation of our prior $50.0 million stock repurchase program announced in 2008 (of which $14.8 million had been previously purchased). The stock repurchase program may be suspended or discontinued at any time. (2) These amounts include shares that were repurchased from various employees to provide such employees the cash amounts necessary to pay certain tax liabilities associated with the vesting of restricted shares owned by them. The shares were repurchased on various dates based on the closing price per share on the date of repurchase. 26


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    Performance Graph The following is a line graph comparing cumulative, total shareholder return for the five years ended December 31,2015 with (i) a general market index (the Russell 2000 Index) and (ii) a group of peers selected by the Company in the same line of business or industry as the Company. The peer group is comprised of the following companies: Key Energy Services, Inc., Nabors Industries Ltd. and Pioneer Energy Services Corp. The graph assumes investments of $100 on December 31, 2010 at the closing sale price, and the reinvestment of all dividends, if any. The graph shall not be deemed incorporated by reference by any general statement incorporating by reference this report into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates this information by reference, and shall not otherwise be deemed filed under such Acts. Comparison of Five Year Cumulative Total Return Value of $100 Invested at December 31, 2010, December 31, 2011, December 31, 2012, December 31, 2013 December 31, 2014 and December 31, 2015 T Basic Energy Services Russell 2000 Index Peer Group December 31, 2010 $ 100.00 $ 100.00 $ 100.00 December 31, 2011 $ 119.54 $ 94.55 $ 83.85 December 31, 2012 $ 69.24 $ 108.38 $ 60.44 December 31, 2013 $ 95.75 $ 148.49 $ 70.93 December 31, 2014 $ 42.54 $ 153.73 $ 47.34 December 31, 2015 $ 16.26 $ 144.95 $ 29.06 The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to the Regulations 14A or 14C under the Securities Exchange Act of 1934, as amended, or to the liabilities of Section 18 under such Act. 27


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    ITEM 6. SELECTED FINANCIAL DATA The following table sets forth our selected historical financial information for the periods shown. The following information should be read in conjunction with Item 7,Management’s Discussion and Analysis of Financial Condition and Results of Operations and our financial statements included elsewhere in this report. The amounts for each historical annual period presented below were derived from our audited financial statements. Year Ended December 31, 2015 2014 2013 2012 2011 (Dollars in thousands, except per share data) Statement of Operations Data: Revenues: Completion and remedial services $ 307,550 $ 698,917 $ 501,137 $ 586,070 $ 537,134 Fluid services 258,597 369,774 343,863 352,246 332,010 Well servicing 217,245 361,683 363,386 376,268 333,057 Contract drilling 22,207 60,910 54,518 60,300 41,054 Total revenues 805,599 1,491,284 1,262,904 1,374,884 1,243,255 Expenses: Completion and remedial services 245,069 434,457 327,540 357,960 297,276 Fluid services 196,155 265,105 239,154 236,588 211,959 Well servicing 184,952 270,344 265,058 268,219 228,723 Contract drilling 16,680 41,513 36,336 39,817 28,154 General and administrative (a) 143,458 167,301 171,439 183,274 144,485 Depreciation and amortization 241,471 217,480 209,747 187,083 154,341 Loss on disposal of assets 1,602 1,974 2,873 3,334 447 Goodwill impairment 81,877 34,703 - - - Total expenses 1,111,264 1,432,877 1,252,147 1,276,275 1,065,385 Operating income (loss) (305,665) 58,407 10,757 98,609 177,870 Net interest expense (67,938) (67,002) (67,154) (62,355) (52,299) Loss on early extinguishment of debt - - - (7,942) (49,366) Bargain purchase gain - - - 910 - Other income 528 775 743 627 525 Income (loss) before income taxes (373,075) (7,820) (55,654) 29,849 76,730 Income tax (expense) benefit 131,330 (521) 19,725 (10,263) (30,894) Net income (loss) $ (241,745) $ (8,341) $ (35,929) 19,586 $ 45,836 Basic earnings (loss) per share of common stock: $ (5.97) $ (0.20) $ (0.89) $ 0.48 $ 1.14 Diluted earnings (loss) per share of common stock: $ (5.97) $ (0.20) $ (0.89) $ 0.47 $ 1.10 Other Financial Data: Cash flows from operating activities $ 95,539 $ 224,536 $ 165,588 $ 303,681 $ 279,455 Cash flows from investing activities (53,673) (213,429) (139,686) (250,762) (419,967) Cash flows from financing activities (75,049) (42,724) (48,935) 3,188 171,052 Capital expenditures: Acquisitions, net of cash acquired 7,914 16,090 21,467 84,939 218,347 Property and equipment, excluding capital leases 53,868 236,295 136,950 171,440 221,839 (a) Includes approximately $13,728, $14,714, $11,830, $12,855 and $9,487 of non-cash stock compensation expense for the years ended December 31, 2015, 2014, 2013, 2012 and 2011, respectively. As of December 31, 2015 2014 2013 2012 2011 (Dollars in thousands) Balance Sheet Data: Cash and cash equivalents $ 46,732 $ 79,915 $ 111,532 $ 134,565 $ 78,458 Property and equipment, net 846,290 1,007,969 928,037 943,766 856,412 Total assets 1,161,369 1,597,177 1,543,339 1,599,006 1,462,352 Long-term debt 838,368 882,572 846,691 844,906 748,976 Stockholders' equity 106,338 342,653 345,287 372,410 357,668 28


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    ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Management’s Overview We provide a wide range of well site services to oil and natural gas drilling and producing companies, including completion and remedial services, fluid services, well servicing and contract drilling services. Our results of operations reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in seven separate acquisitions from January 1, 2013 to December 31, 2015 for total consideration of $54.3 million. Our hydraulic horsepower capacity for pumping services increased from 291,000 at January 1, 2013 to 444,000 at December 31, 2015. Our weighted average number of fluid service trucks increased from 963 in the first quarter of 2013 to 1,002 in the fourth quarter of 2015. Our weighted average number of well servicing rigs decreased from 425 in the first quarter of 2013 to 421 in the fourth quarter of 2015. Our weighted average number of drilling rigs remained constant at 12 from thefirst quarter of 2013 to the fourth quarter of 2015. As a result of these acquisitions, changes in revenues, expenses and income may not be directly comparable between periods. Our operating revenues from each of our segments, and their relative percentages of our total revenues, consisted of the following (dollars in millions): Year Ended December 31, 2015 2014 2013 Revenues: Completion and remedial services $ 307.6 38% $ 698.9 47% $ 501.1 40% Fluid services 258.6 32% 369.8 25% 343.9 27% Well servicing 217.2 27% 361.7 24% 363.4 29% Contract drilling 22.2 3% 60.9 4% 54.5 4% Total revenues $ 805.6 100% $ 1,491.3 100% $ 1,262.9 100% Our core businesses depend on our customers’ willingness to make expenditures to produce, develop and explore for oil and natural gas in the United States. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, political instability in oil producing countries and merger and divestiture activity among oil and natural gas producers. The volatility of the oil and natural gas industry, and the consequent impact on exploration and production activity, has adversely impacted the level of drilling and workover activity by some of our customers. This volatility also affects the demand for our services and the price of our services in 2015. In addition, the discovery rate of new oil and natural gas reserves in our market areas also may have an impact on our business, even in an environment of stronger oil and natural gas prices. For a more comprehensive discussion of our industry trends, see “General Industry Overview” included in Items 1 and 2, Business and Properties, of this Annual Report on Form 10-K. We derive a majority of our revenues from services supporting production from existing oil and natural gas operations. Demand for these production-related services, including well servicing and fluid services, tends to remain relatively stable, even in moderate oil and natural gas price environments, as ongoing maintenance spending is required to sustain production. As oil and natural gas prices reach higher levels, demand for all of our services generally increases as our customers engage in more well servicing activities relating to existing wells to maintain or increase oil and natural gas production from those wells. Because our services are required to support drilling and workover activities, our revenues will vary based on changes in capital spending by our customers as oil and natural gas prices increase or decrease. Oil prices have remained relatively stable until the fourth quarter of 2014 when an extended period of significant decline began. The downward trend in oil and natural gas prices during 2015 has caused utilization and pricing for our services in our operating areas to decline throughout 2015. An extended period of lower pricing may cause overcapacity and continued pricing pressure on all service lines in 2016. Our revenues generally increased in 2014 due to an increase in activity during the first nine months the year. This increase was most notable in our completion and remedial services segment , due to significant amount of capital expansion during the first half of the year. These increases were somewhat offset by the drop in oil prices in the fourth quarter of 2014 and continued to decline throughout 2015. We anticipate our customer base to decrease their 2016 capital programs and, as a result, expect lower activity levels and pricing in 2016. We will continue to evaluate opportunities to expand our business through selective acquisitions and internal growth initiatives. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives, which is substantially driven by the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and natural gas commodity price cycle. Based on these factors, we make capital investment 29


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    decisions that we believe will support our long-term growth strategy. While we believe our costs of integration for prior acquisitions have been reflected in our historical results of operations, integration of acquisitions may result in unforeseen operational difficulties or require a disproportionate amount of our management’s attention. We believe the most important performance measures for our business segments are as follows: • Completion and Remedial Services — segment profits as a percent of revenues; • Fluid Services — trucking hours, revenue per truck, segment profits per truck and segment profits as a percent of revenues; • Well Servicing — rig hours, rig utilization rate, revenue per rig hour, profits per rig hour and segment profits as a percent of revenues; and • Contract Drilling — rig operating days, revenue per drilling day, profits per drilling day and segment profits as a percent of revenues. Segment profits are computed as segment operating revenues less direct operating costs. These measurements provide important information to us about the activity and profitability of our lines of business. For a detailed analysis of these indicators for our company, see “Segment Overview” below. Recent Strategic Acquisitions and Expansions During the period from 2013 through 2015, we grew through acquisitions and capital expenditures. We completed three acquisitions in 2013, one acquisition in 2014 and three acquisitions in 2015 none of which were considered significant. Selected 2013 Acquisitions During 2013, we made three acquisitions that complemented our existing business segments. These included: Atlas Environmental Consulting, Inc. and Atlas Oilfield Construction Company, LLC On February 16, 2013, we acquired all of the assets of Atlas Environmental Consulting, Inc. and Atlas Oilfield Construction Company, LLC for total cash consideration of $13.0 million. This acquisition is included in our fluid services segment. Selected 2014 Acquisitions During 2014, we made one acquisition that complemented our existing completion and remedial services business segment: Pioneer Fishing and Rental, Inc. On September 17, 2014, we acquired all of the assets of Pioneer Fishing and Rental, Inc. for total cash consideration of $16.1 million. This acquisition is included in our completion and remedial services segment. Selected 2015 Acquisitions During 2015, we made three acquisitions that complemented our existing business segments. These included: GreyRock Pressure Pumping, LLC. On August 31, 2015, we acquired all of the assets of GreyRock Pressure Pumping, LLC. for total cash consideration of $10.2 million. This acquisition is included in our completion and remedial services segment. Segment Overview Completion and Remedial Services In 2015, our completion and remedial services segment represented 38% of our revenues. Revenues from our completion and remedial services segment are derived from a variety of services designed to stimulate oil and natural gas production or place cement slurry within the wellbores. Our completion and remedial services segment includes pumping services, rental and fishing tool operations, coiled tubing services, nitrogen services, cased-hole wireline services, snubbing and underbalanced drilling. Our pumping services concentrate on providing single truck, lower-horsepower cementing and acidizing services, as well as various fracturing services in selected markets. Our total hydraulic horsepower capacity for our pumping services was approximately 444,000 horsepower at December 31, 2015, compared to 443,000 horsepower and 297,000 horsepower at December 31, 2014 and December 31, 2013, respectively. Our rental and fishing tool business operates 20 rental and fishing tool stores in selected markets as of December 31, 2015. Our snubbing services operate 36 units throughout our geographic footprint as of December 31, 2015. We have operations in the wireline, coiled tubing services, nitrogen services, water treatment and the underbalanced drilling services businesses. For a description of our wireline, coiled tubing services, nitrogen services, water treatment, and snubbing 30


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    operations, please read “Overview of Our Segments and Services — Completion and Remedial Services Segment” included in Items 1 and 2,Business and Properties, of this Annual Report on Form 10-K. In this segment, we derive our revenues on a project-by-project basis in a competitive bidding process. Our bids are based on the amount and type of equipment and personnel required, with the materials consumed billed separately. During periods of decreased spending by oil and gas companies, we may be required to discount our rates to remain competitive, which would cause lower segment profits. The following is an analysis of our completion and remedial services segment for each of the quarters and years in the years ended December 31, 2015, 2014 and 2013 (dollars in thousands): Segment Completion & Remedial Revenues Profits % 2013: First Quarter $ 118,361 33% Second Quarter $ 132,216 35% Third Quarter $ 127,119 35% Fourth Quarter $ 123,441 35% Full Year $ 501,137 35% 2014: First Quarter $ 137,485 37% Second Quarter $ 164,366 38% Third Quarter $ 193,699 39% Fourth Quarter $ 203,367 38% Full Year $ 698,917 38% 2015: First Quarter $ 112,775 28% Second Quarter $ 69,055 17% Third Quarter $ 67,240 16% Fourth Quarter $ 58,479 15% Full Year $ 307,550 20% We gauge the performance of our completion and remedial services segment based on the segment’s operating revenues and segment profits as a percent of revenues. Fluid Services In 2015, our fluid services segment represented 32% of our revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage and disposal of fluids used in the drilling, production and maintenance of oil and natural gas wells. Revenues also include water treatment, well site construction and maintenance services. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and natural gas. These services are necessary for our customers and have a stable demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or fracturing fluids used during a job, and all of these fluids require storage tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking, storage and disposal required on most drilling and workover projects, the add-on services associated with drilling and workover activity enable us to generate higher segment profits. The higher segment profits are due to the relatively small incremental labor costs associated with providing these services in addition to our base fluid services operations. Revenues from our well site construction services are derived primarily from preparing and maintaining access roads and well locations, installing small diameter gathering lines and pipelines, constructing foundations to support drilling rigs and providing maintenance services for oil and natural gas facilities. Revenue from water treatment services results from the treatment and reselling of produced water and flowback to customers for the purposes of reusing as fracturing water. We typically price fluid services by the job, by the hour or by the quantities sold, disposed of or hauled. 31


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    The following is an analysis of our fluid services segment for each of the quarters and years in the years ended December 31, 2015, 2014 and 2013 (dollars in thousands): Weighted Average Revenue Per Segment Profits Number of Fluid Fluid Service Per Fluid Segment Fluid Services Service Trucks Truck Hours Truck Service Truck Profits % 2013: First Quarter 963 555,600 $ 88 $ 27 31% Second Quarter 972 568,500 $ 88 $ 27 31% Third Quarter 970 578,900 $ 89 $ 27 31% Fourth Quarter 986 579,400 $ 89 $ 26 29% Full Year 973 2,282,400 $ 353 $ 107 30% 2014: First Quarter 1,006 607,200 $ 92 $ 26 28% Second Quarter 1,015 630,900 $ 89 $ 25 28% Third Quarter 1,025 645,800 $ 91 $ 26 29% Fourth Quarter 1,043 661,900 $ 90 $ 26 28% Full Year 1,022 2,545,800 $ 362 $ 102 28% 2015: First Quarter 1,046 595,100 $ 71 $ 19 27% Second Quarter 1,011 573,700 $ 63 $ 15 24% Third Quarter 1,012 565,400 $ 62 $ 15 24% Fourth Quarter 1,002 557,000 $ 58 $ 12 21% Full Year 1,018 2,291,200 $ 254 $ 61 24% We gauge activity levels in our fluid services segment based on trucking hours, revenue per fluid service truck, segment profits per fluid service truck and segment profits as a percent of revenues. Well Servicing In 2015, our well servicing segment represented 27% of our revenues. Revenue in our well servicing segment is derived from maintenance, workover, completion and plugging and abandonment services, as well as rig manufacturing operations. We provide maintenance-related services as part of the normal, periodic upkeep of producing oil and natural gas wells. Maintenance-related services represent a relatively consistent component of our business. Workover and completion services generate more revenue per hour than maintenance work due to the use of auxiliary equipment, but demand for workover and completion services fluctuates more with the overall activity level in the industry. We typically charge our well servicing rig customers for services on an hourly basis at rates that are determined by the type of service and equipment required, market conditions in the region in which the rig operates, the ancillary equipment provided on the rig and the necessary personnel. We measure the activity level of our well servicing rigs on a weekly basis by calculating a rig utilization rate based on a 55-hour work week per rig. We acquired our rig manufacturing business in May 2010. We manufacture workover rigs for internal purposes as well as to sell to outside companies. Our rig manufacturing operation also performs large scale refurbishments and maintenance services to used workover rigs. 32


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    The following is an analysis of our well servicing segment for each of the quarters and years in the years ended December 31, 2015, 2014 and 2013. The revenues do not include revenues associated with rig manufacturing operations: Weighted Average Rig Revenue Profits Number of Rig Utilization Per Rig Per Rig Segment Well Service Rigs Hours Rate Hour Hour Profits % 2013: First Quarter 425 210,800 69% $ 399 $ 108 26% Second Quarter 425 223,900 74% $ 408 $ 111 28% Third Quarter 425 227,100 75% $ 404 $ 118 27% Fourth Quarter 425 199,400 66% $ 404 $ 113 27% Full Year 425 861,200 71% $ 404 $ 114 27% 2014: First Quarter 425 217,400 73% $ 417 $ 106 25% Second Quarter 421 214,200 71% $ 410 $ 116 28% Third Quarter 421 217,500 71% $ 405 $ 108 26% Fourth Quarter 421 204,400 67% $ 416 $ 97 23% Full Year 422 853,500 71% $ 412 $ 107 25% 2015: First Quarter 421 163,900 55% $ 377 $ 69 18% Second Quarter 421 154,700 51% $ 351 $ 61 17% Third Quarter 421 154,100 50% $ 334 $ 50 14% Fourth Quarter 421 120,000 39% $ 324 $ 33 9% Full Year 421 592,700 49% $ 348 $ 54 15% We gauge activity levels in our well servicing rig operations based on rig hours, rig utilization rate, revenue per rig hour, profits per rig hour and segment profits as a percent of revenues. Contract Drilling In 2015, our contract drilling segment represented 3% of our revenues. Revenues from our contract drilling segment are derived primarily from the drilling of new wells. Within this segment, we typically charge our drilling rig customers a daily rate or a rate based on footage at an established rate per number of feet drilled. Depending on the type of job, we may also charge by the project. We measure the activity level of our drilling rigs on a weekly basis by calculating a rig utilization rate based on a seven-day work week per rig. 33


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    The following is an analysis of our contract drilling segment for each of the quarters and years in the years ended December 31, 2015, 2014 and 2013: Weighted Average Rig Profits Number Operating Revenue (Loss) Segment Contract Drilling of Rigs Days Per Day Per Day Profits % 2013: First Quarter 12 850 $ 16,500 $ 5,700 35% Second Quarter 12 846 $ 16,500 $ 5,000 30% Third Quarter 12 833 $ 16,500 $ 5,500 34% Fourth Quarter 12 781 $ 16,400 $ 5,800 35% Full Year 12 3,310 $ 16,500 $ 5,500 33% 2014: First Quarter 12 821 $ 16,500 $ 5,300 32% Second Quarter 12 942 $ 16,300 $ 5,100 32% Third Quarter 12 968 $ 16,800 $ 5,200 31% Fourth Quarter 12 948 $ 16,600 $ 5,400 33% Full Year 12 3,679 $ 16,600 $ 5,300 32% 2015: First Quarter 12 674 $ 17,000 $ 5,900 34% Second Quarter 12 280 $ 15,500 $ 3,000 20% Third Quarter 12 252 $ 15,300 $ 2,600 17% Fourth Quarter 12 155 $ 16,500 $ 400 3% Full Year 12 1,361 $ 16,300 $ 4,000 25% We gauge activity levels in our drilling operations based on rig operating days, revenue per drilling day, profits per drilling day and segment profits as a percent of revenues. Operating Cost Overview Our operating costs are comprised primarily of labor costs, including workers’ compensation and health insurance, repair and maintenance, fuel and insurance. A majority of our employees are paid on an hourly basis. We also employ personnel to supervise our activities, sell our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Repair and maintenance is performed by our crews, company maintenance personnel and outside service providers. Insurance is generally a fixed cost regardless of utilization and can vary depending on the number of rigs, trucks and other equipment in our fleet, as well as employee payroll, and our safety record. Compensation for administrative personnel in local operating yards and our corporate office is accounted for as general and administrative expenses. Critical Accounting Policies and Estimates Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. We have identified below accounting policies that are of particular importance in the presentation of our financial position, results of operations and cash flows and which require the application of significant judgment by management. A complete summary of these policies is included in Note 2 of the notes to our consolidated financial statements. Critical Accounting Policies Property and Equipment. Property and equipment are stated at cost, or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as incurred. We also review the capitalization of refurbishment of workover rigs as described in Note 2 of the notes to our consolidated financial statements. Impairments. We review our assets including tangible assets, intangible assets and goodwill, for impairment at a minimum annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recovered over its remaining service life. Impairment is indicated when the sum of the estimated future cash flows, on an undiscounted basis, is less than the asset’s carrying amount. When impairment is identified and fair value is less than carrying value, an impairment charge is recorded to income based on an estimate of future cash flows on a discounted basis. Self-Insured Risk Accruals. We are self-insured up to retention limits with regard to workers’ compensation, general liability claims, and medical and dental coverage of our employees. We generally maintain no physical property damage coverage on our rig fleet, with the exception of certain rigs, newly manufactured rigs and pumping services equipment. We have deductibles per occurrence for workers’ compensation, auto & general liability claims, and medical and dental coverage of $2.5 million, $1 million, 34


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    and $400,000, respectively. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party actuarial data and claims history. Revenue Recognition. We recognize revenues when the services are performed, collection of the relevant receivables is probable, persuasive evidence of the arrangement exists and the price is fixed and determinable. Rig manufacturing revenue is recognized by individual rig based on the completed contract method. Income Taxes. We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized. We record net deferred tax assets to the extent we believe these assets will more likely than not be realized. In making such determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax planning strategies and recent financial operations. Although realization is not assured, management believes it is more likely than not that we will generate sufficient future U.S. taxable income to realize our U.S. deferred tax assets as of December 31, 2015 based on the weight of all available evidence including the future reversal of existing U.S. taxable temporary differences as of December 31, 2015. We believe that it is more likely than not that the benefit from certain state net operating loss carryforwards and other deductible temporary differences in certain state jurisdictions will not be realized. In recognition of this risk, we have provided a valuation allowance of $0.9 million on the net deferred tax asset relating to these state jurisdictions as a result of the company being in a cumulative three year pre-tax book loss position and absence of other objectively verifiable positive evidence including reversal of existing taxable temporary differences in these certain state tax jurisdictions. If estimates of future taxable income in the carryforward periods are reduced and we feel that there is not a more-likely-than-not basis that the Company will be able to realize the U.S deferred tax assets and state deferred tax assets that do not have a valuation allowance as of December 31, 2015, we may record a valuation allowance at that time. Critical Accounting Estimates The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. We analyze our estimates based on experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The following is a discussion of our critical accounting estimates. Depreciation and Amortization. In order to depreciate and amortize our property and equipment and our intangible assets with finite lives, we estimate the useful lives and salvage values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry. Impairment of Property and Equipment. We analyze the potential impairment of property and equipment annually as of December 31 or on an interim basis if events or circumstances indicate that the fair values of the assets have decreased below the carrying value. Our analysis for potential impairment of property and equipment requires us to estimate undiscounted future cash flows. Actual impairment charges are recorded using an estimate of discounted future cash flows. The determination of future cash flows requires us to estimate rates and utilization in future periods and such estimates can change based on market conditions, technological advances in industry or changes in regulations governing the industry. Impairment of Goodwill. Goodwill is not amortized. We assess impairment of goodwill annually as of December 31, or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. A qualitative assessment of whether it is more likely than not that the fair value of a reporting unit is less than its carrying value is allowed but not required. If it is more likely than not that the fair value of the reporting unit is less than its carrying amount, then the two-step impairment test is performed. In the two-step test, first, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value. We performed our assessment of goodwill related to the completion and remedial services segment as of September 30, 2015. For step one of the impairment testing, we tested the only reporting unit with goodwill for goodwill impairment: completion and remedial services. Our contract drilling, well servicing and fluid services reporting units did not carry any goodwill, and were not subject to the test. This assessment indicated that $81.9 million was considered impaired as of September 30, 35


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    2015. This non-cash charge eliminated all of our existing goodwill as of September 30, 2015.Please see Note 19. Fair Value in the notes to our consolidated financial statements for further information about our goodwill impairment. Allowance for Doubtful Accounts. We estimate our allowance for doubtful accounts based on an analysis of past collection activity and specific identification of overdue accounts. Factors that may affect this estimate include (1) changes in the financial positions of significant customers and (2) a decline in commodity prices that could affect the entire customer base. Litigation and Self-Insured Risk Reserves. We estimate our reserves related to litigation and self-insured risk based on the facts and circumstances specific to the litigation and self-insured risk claims and our past experience with similar claims. The actual outcome of litigation and insured claims could differ significantly from estimated amounts. As discussed in “Self-Insured Risk Accruals” above with respect to our critical accounting policies, we maintain accruals on our balance sheet to cover self-insured retentions. These accruals are based on a third-party analysis developed using historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon reported claims and actual claim settlements. Fair Value of Assets Acquired and Liabilities Assumed. We estimate the fair value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property and equipment, intangible assets and the resulting amount of goodwill, if any. Cash Flow Estimates. Our estimates of future cash flows are based on the most recent available market and operating data for the applicable asset or reporting unit at the time the estimate is made. Our cash flow estimates are used for asset impairment analyses. Stock-Based Compensation. We have historically compensated our directors, executives and employees through the awarding of stock options and restricted stock. We accounted for stock option and restricted stock awards in 2015 , 2014 and 2013 using a grant date fair-value based method, resulting in compensation expense for stock-based awards being recorded in our consolidated statements of operations. For performance-based restricted stock awards, compensation expense is recognized in our financial statements based on their grant date fair value. We utilize (i) the closing stock price on the date of the grant to determine the fair value of vesting restricted stock awards and (ii) a Monte Carlo simulation to determine the fair value of restricted stock awards with a combination of market and service vesting criteria. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The expected volatility utilized in the model was estimated using our historical volatility and the historical volatilities of our peer companies. The risk free interest rate was based on the U.S. treasury rate for a term commensurate with the expected life of the grant. Stock options have not been issued since 2007 but were valued on the grant date using Black-Scholes-Merton option pricing model and restricted stock issued is valued based on the fair value of our common stock at the grant date. In addition, judgment is required in estimating the amount of stock-based awards that are expected to be forfeited. Because the determination of these various assumptions is subject to significant management judgment and different assumptions could result in material differences in amounts recorded in our consolidated financial statements, management believes that accounting estimates related to the valuation of stock options are critical. Income Taxes. The amount and availability of our loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests. The utilization of such carryforwards could be limited or lost upon certain changes in ownership and the passage of time. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future. Results of Operations The results of operations between periods may not be comparable, primarily due to fluctuations in the oil and natural gas industry throughout 2015 , 2014 and 2013, as well as the Company’s growth in asset base during 2014 and 2013. The asset base decreased in 2015 from 2014. Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 Revenues. Revenues decreased by 46% to $805.6 million in 2015 from $1.5 billion in 2014. This decrease was primarily due to a significant decrease in crude oil prices resulting in lower demand for our services by our customers, particularly from our completion and remedial services and contract drilling segments. Completion and remedial services revenue decreased by 56% to $307.6 million in 2015 as compared to $698.9 million in 2014. The decrease in revenue between these periods was primarily due to lower pumping and fracturing revenues driven by the overall decrease in new well completion activity, as well as pricing concessions given to customers. Total hydraulic horsepower was 444,000 and 443,000 at December 31, 2015 and December 31, 2014, respectively. Fluid services revenue decreased by 30% to $258.6 million in 2015 compared to $369.8 million in 2014. This decrease was mainly due to a decrease in trucking hours and lower pricing for our services.Revenue per fluid service truck decreased 30% to 36


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    $254,000 in 2015 compared to $362,000 in 2014, due to decreased disposal activities and lower pricing.Our weighted average number of fluid service trucks decreased to 1,018 in 2015 from 1,022 in 2014. Well servicing revenues decreased by 40% to $217.2 million in 2015 compared to $361.7 million in 2014. Rig utilization decreased to 49% in 2015 from 71% during 2014, reflecting lower activity levels and the competitive market in oil- dominated areas. Our weighted average number of well servicing rigs decreased to 421 during 2015 compared to 422 in 2014 due to the sale of four barge rigs in the first quarter of 2014. We experienced a decrease of 16% in revenue per rig hour to $348 during 2015 from $412 during 2014, due to pricing competition, especially from smaller service companies. Contract drilling revenues decreased by 64% to $22.2 million in 2015 compared to $60.9 million in 2014. The decrease was driven mainly by a decrease in drilling activity, which caused a decline in rig operating days.The number of rig operating days decreased to 1,361 in 2015 compared to 3,679 in 2014. The average revenue per rig day decreased to $16,300 in 2015 from $16,600 in 2014, due to pricing competition. Direct Operating Expenses. Direct operating expenses, which primarily consist of labor costs, including workers’ compensation and health insurance, and maintenance and repair costs, decreased by 36% to $642.9 million in 2015 from $1.0 billion in 2014. This decrease was due to the lower activity levels in all our segments. Direct operating expenses for the completion and remedial services segment decreased by 44% to $245.1 million in 2015 as compared to $434.5 million in 2014, due primarily to decreased activity levels and reduction in headcount. Segment profits decreased to 20% of revenues in 2015 compared to 38% in 2014, due to decremental margins on a lower revenue base in all operating areas as well as significant pricing discounts for our pumping services. Direct operating expenses for the fluid services segment decreased by 26% to $196.2 million in 2015 as compared to $265.1 million in 2014. Segment profits were 24% of revenues in 2015 and 28% of revenues in 2014, due to high levels of competition for trucking services and lower skim oil sales and disposal activity. Direct operating expenses for the well servicing segment decreased by 32% to $185.0 million in 2015 as compared to $270.3 million in 2014, due primarily to decreased personnel costs and reduced demand for our services. Segment profits decreased to 15% of revenues in 2015 compared to 25% in 2014, due to competitive pricing pressures and the impact of decremental margins on a lower revenue base. Direct operating expenses for the contract drilling segment decreasedby 60% to $16.7 million in 2015 as compared to $41.5 million in 2014, due to a significant decrease in the North American on-shore drilling rig count. Segment profits were 25% of revenues in 2015 compared to 32% in 2014, due to decline in drilling activity. General and Administrative Expenses. General and administrative expenses decreased by 14% to $143.5 million in 2015 from $167.3 million in 2014. The decrease was primarily due to lower payroll and incentive compensation costs due to a reduction in workforce in 2015, plus additional cost saving initiatives implemented in late 2014 and 2015. G&A expense included $13.7 million and $14.7 million of stock-based compensation expense in 2015 and 2014, respectively. Depreciation and Amortization Expenses. Depreciation and amortization expenses were $241.5 million in 2015, as compared to $217.5 million in 2014, reflecting the increase in the size of and investment in our asset base during 2014. During 2015, we invested $56.9 million for cash capital expenditures, $16.0 million for capital leases and an additional $16.7 million for acquisitions. Goodwill Impairment. In the third quarter of 2015, we recorded a non-cash charge totaling $81.9 million for impairment of all of the goodwill associated with our completion and remedial services segment. Interest Expense. Interest expense remained relatively flat at $68.0 million in 2015 compared to $67.0 million in 2014. Income Tax Expense. Income tax benefit was $131.3 million in 2015, as compared to tax expense of $521,000 in 2014. Our effective tax benefit rate was approximately 35% in 2015 compared to an effective tax expense rate of 7% in 2014. The change in the effective tax rate is due to the tax impact associated with the impairment of goodwill in 2015 and 2014 and the impact of permanent items on a higher pre-tax loss amount in 2015. Our effective tax benefit in 2015 approximates the federal statutory rate of 35%. The 2014 effective tax rate of 7% differed from the statutory tax rate due to state taxes and goodwill impairment. Year Ended December 31, 2014 Compared to Year Ended December 31, 2013 Revenues. Revenues increased by 18% to $1.5 billion in 2014 from $1.3 billion in 2013. This increase was primarily due to relatively high demand by our customers, particularly from our completion and remedial services segment. Completion and remedial services revenue increased by 39% to $698.9 million in 2014 as compared to $501.1 million in 2013. The increase in revenue between these periods was primarily due to higher pumping revenues driven by an increase in pumping capacity. Total hydraulic horsepower was 443,000 and 297,000 at December 31, 2014 and December 31, 2013, respectively. 37


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    Fluid services revenue increased by 8% to $369.8 million in 2014 compared to $343.9 million in 2013.This increase was mainly due to an increase in our truck fleet and disposal wells in 2014. In 2014, we added four salt water disposal wells. Revenue per fluid service truck increased 2% to $362,000 in 2014 compared to $353,000 in 2013, due to increased disposal activities and improved pricing. Our weighted average number of fluid service trucks increased 5% to 1,022 in 2014 from 973 in 2013, which reflects the expansion of our truck fleet. Well servicing revenues decreased by 1% to $361.7 million in 2014 compared to $363.4 million in 2013. Rig utilization remained constant at 71% during 2014 and 2013, reflecting the competitive market in oil-dominated areas. Our weighted average number of well servicing rigs decreased to 422 during 2014 compared to 425 in 2013 due to the sale of four barge rigs in the first quarter of 2014. We experienced an increase of 2% in revenue per rig hour to $412 during 2014 from $404 during 2013, due to increased revenues from plugging and abandonment units, which work for higher rates than workover rigs. Contract drilling revenues increased by 12% to $60.9 million in 2014 compared to $54.5 million in 2013.The increase was driven mainly by an increase in rig operating days.The number of rig operating days increased to 3,679 in 2014 compared to 3,310 in 2013. The average revenue per rig day increased to $16,600 in 2014 from $16,500 in 2013. Direct Operating Expenses. Direct operating expenses, which primarily consist of labor costs, including workers’ compensation and health insurance, and maintenance and repair costs, increased by 17% to $1,011.4 million in 2014 from $868.1 million in 2013. This increase was due to the higher activity levels in three of our segments. Direct operating expenses for the completion and remedial services segment increased by 33% to $434.5 million in 2014 as compared to $327.5 million in 2013, due primarily to increased activity levels. Segment profits increased to 38% of revenues in 2014 compared to 35% in 2013, due to increased activity in all operating areas as well as pricing improvement for our pumping services. Direct operating expenses for the fluid services segment increased by 11% to $265.1 million in 2014 as compared to $239.2 million in 2013. Segment profits were 28% of revenues in 2014 and 30% of revenues in 2013, due to high levels of competition offset by increased fuel and propane prices in 2014. Direct operating expenses for the well servicing segment increased by 2% to $270.3 million in 2014 as compared to $265.1 million in 2013, due primarily to higher personnel costs which could not be offset by rate increases for our services. Additionally, we incurred approximately $3.0 million of expense for downhole issues. Segment profits decreased to 25% of revenues in 2014 compared to 27% in 2013, due to competitive pricing pressures and the costs discussed above. Direct operating expenses for the contract drilling segment increased by 14% to $41.5 million in 2014 as compared to $36.3 million in 2014, due to increase in activity levels. Segment profits were 32% of revenues in 2014 compared to 33% in 2013. General and Administrative Expenses. General and administrative expenses decreased by 2% to $167.3 million in 2014 from $171.4 million in 2013. The decrease was primarily due to decreased litigation costs of $8.0 million that were expensed in 2013, related to a settlement of an accident that occurred in 2008, plus cost saving initiatives implemented in late 2013. G&A expense included $14.7 million and $11.8 million of stock-based compensation expense in 2014 and 2013, respectively. Depreciation and Amortization Expenses. Depreciation and amortization expenses were $217.5 million in 2014, as compared to $209.7 million in 2013, reflecting the increase in the size of and investment in our asset base. We invested $236.3 million for cash capital expenditures, $75.2 million for capital leases and an additional $16.1 million for acquisitions in 2014. Goodwill Impairment. In the fourth quarter of 2014, we recorded a non-cash charge totaling $34.7 million for impairment of all of the goodwill associated with our well servicing and fluid services segments. Interest Expense. Interest expense remained relatively flat at $67.0 million in 2014 compared to $67.2 million in 2013. Income Tax Expense. Income tax expense was $521,000 in 2014, as compared to tax benefit of $19.7 million in 2013. Our effective tax expense rate was approximately 7% in 2014 compared to an effective tax benefit rate of 35% in 2013. The change in the effective tax rate is due to the tax impact associated with the impairment of goodwill in 2014. Liquidity and Capital Resources Currently, our primary capital resources are net cash flows from our operations and utilization of capital leases and our $250.0 million revolving credit facility. On February 17, 2016, we entered into a term loan agreement that provides for borrowings of an aggregate principal amount of $165.0 million on the closing date and delayed draw term loan borrowings in an aggregate principal amount not to exceed $15.0 million. As of December 31, 2015, we had cash and cash equivalents of $46.7 million compared to $79.9 million as of December 31, 2014. We have utilized, and expect to utilize in the future, bank and capital lease financing and sales of equity to obtain capital resources. When appropriate, we will consider public or private debt and equity offerings and non-recourse transactions to meet our liquidity needs. 38


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    On April 21, 2015, we entered into Amendment No. 2 to our Amended and Restated Credit Agreement (as amended, the “Credit Agreement”) that, among other things: (A) reduces the maximum aggregate commitments thereunder from $300 million to $250 million; (B) permits credit extensions under the Credit Agreement based on availability under a borrowing base comprised of our eligible billed accounts receivable, eligible unbilled accounts receivable and eligible equipment; and (C) provides for the replacement of the existing financial covenants with new financial covenants, which apply only if availability under the Credit Agreement is less than the greater of (i) 25% of the aggregate commitments outstanding, or (ii) $62.5 million. If that circumstance exists, we will be required to maintain (a) a consolidated senior secured leverage ratio not to exceed 2.50 to 1.00 and (b) a consolidated fixed charge coverage ratio not less than 1.00 to 1.00. As of December 31, 2015, we had no borrowings and $50.3 million of letters of credit outstanding under our Credit Agreement giving us $93.4 million of available borrowing capacity based on its borrowing base (comprised of eligible billed accounts receivable, eligible unbilled accounts receivable and eligible equipment) determined as of such date. If borrowing capacity under our Credit Agreement decreases in the future (i.e., based on eligible billed accounts receivable, eligible unbilled accounts receivable and eligible equipment), we may pursue alternative debt financing arrangements (subject to limitations under our senior note indentures) or other sources depending on market conditions to meet future liquidity needs. Net Cash Provided by Operating Activities Cash flow from operating activities was $95.5 million for the year ended December 31, 2015 as compared to $224.5 million in 2014 and $165.6 million in 2013. The decrease in 2015 was due primarily to a decrease in operating income offset by an increase in working capital. The increase in 2014 was primarily due to an increase in operating income and a decrease in accounts receivable. Capital Expenditures Capital expenditures are the main component of our investing activities. Cash capital expenditures (including acquisitions) for 2015 were $70.6 million as compared to $252.4 million in 2014, and $158.4 million in 2013. Cash capital expenditures decreased in 2015 from 2014 due to a decrease in expansionary capital expenditures, primarily related to our completion and remedial segment of $9.6 million in 2015 from $119.5 million in 2014. Through our capital lease program, we also added assets of approximately $16.0 million, $75.2 million and $50.6 million in 2015, 2014 and 2013, respectively. In 2016, we have currently planned capital expenditures of approximately $40.0 million including capital leases of $15.0 million. We do not budget acquisitions in the normal course of business, and we regularly engage in discussions related to potential acquisitions related to the well services industry. Capital Resources and Financing Our current primary capital resources are cash flow from our operations, our $250.0 million revolving credit facility, and the ability to enter into capital leases, the ability to incur additional secured indebtedness, and a cash balance of $46.7 million at December 31, 2015. We had no borrowings and $50.3 million in letters of credit outstanding under the Amended and Restated Credit Agreement as of December 31, 2015, giving us $93.4 million of available borrowing capacity. In 2015, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. On February 17, 2016, we entered into a term loan agreement that provides for borrowings of an aggregate principal amount of $165.0 million on the closing date and delayed draw term loan borrowings in an aggregate principal amount not to exceed $15.0 million. We expect the initial closing date of the Term Loan Agreement will occur on or about February 26, 2016, at which time we will also enter into an amendment to our revolving credit facility to reduce aggregate commitments thereunder to $100.0 million. See “--Term Loan Agreement” below. We have significant contractual obligations in the future that will require capital resources. Our primary contractual obligations are (1) our long-term debt, (2) interest on long-term debt, (3) our capital leases, (4) our operating leases, (5) our asset retirement obligations and (6) our other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2015 (in thousands): Obligations Due in Periods Ended December 31, Contractual Obligations Total 2016 2017-2018 2019-2020 Thereafter Long-term debt (excluding capital leases) $ 775,000 $ - $ - $ 475,000 $ 300,000 Capital leases 111,063 48,651 56,164 6,155 93 Operating leases 15,884 4,162 5,049 3,241 3,432 Asset retirement obligation 2,301 577 217 569 938 Total $ 904,248 $ 53,390 $ 61,430 $ 484,965 $ 304,463 39


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    Our long-term debt as of December 31, 2015, excluding capital leases, consisted of our $300.0 million 7.75% Senior Notes due 2022 and our $475.0 million 7.75% Senior Notes due 2019. Interest on long-term debt relates to our future contractual interest obligations on our Senior Notes. Our capital leases relate primarily to light-duty and heavy-duty vehicles and trailers. Our operating leases relate primarily to real estate. Our asset retirement obligation relates to disposal wells. Our ability to access additional sources of financing will be dependent on our operating cash flows and demand for our services, which could be negatively impacted due to the extreme volatility of commodity prices. 7.75% Senior Notes due 2019 On February 15, 2011, we issued $275.0 million aggregate principal amount of 7.75% Senior Notes due 2019 (the “2019 Notes”). On June 13, 2011, we issued an additional $200.0 million aggregate principal amount of 2019 Notes, resulting in outstanding 2019 Notes with an aggregate principal amount of $475.0 million. The 2019 Notes are jointly and severally, and unconditionally, guaranteed on a senior unsecured basis by all of our current subsidiaries, other than three immaterial subsidiaries. The 2019 Notes and the guarantees rank (1) equally in right of payment with any of our and the subsidiary guarantors’ existing and future senior indebtedness, including our existing 7.75% Senior Notes due 2022 and the related guarantees, and (2) effectively junior to all existing or future liabilities of our subsidiaries that do not guarantee the 2019 Notes and to our and the subsidiary guarantors’ existing or future secured indebtedness to the extent of the value of the collateral therefor. The 2019 Notes and guarantees were offered and sold in private transactions in accordance with Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). The purchase price for the $275.0 million of 2019 Notes issued on February 15, 2011 was 100.000% of their principal amount, and the purchase price for the $200.0 million of 2019 Notes issued on June 13, 2011 was 101.000%, plus accrued interest from February 15, 2011. We received net proceeds from the issuance of the 2019 Notes of approximately $464.6 million after premiums and offering expenses. We used a portion of the net proceeds from the February 2011 offering to fund our tender offer and consent solicitation for our 11.625% Senior Secured Notes and to redeem any of the Senior Secured Notes not purchased in the tender offer. We used the net proceeds from the June 2011 offering to fund the $186.3 million purchase price for the Maverick Companies acquisition completed in July 2011 and for general corporate purposes. The 2019 Notes and guarantees were issued pursuant to an indenture dated as of February 15, 2011 (the “2019 Notes Indenture”), by and among Basic, the guarantors party thereto and Wells Fargo Bank, N.A., as trustee. Interest on the 2019 Notes accrues from and including February 15, 2011 at a rate of 7.75% per year. Interest on the 2019 Notes is payable semi-annually in arrears on February 15 and August 15 of each year. The 2019 Notes mature on February 15, 2019. The 2019 Notes Indenture contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: • incur additional indebtedness; • pay dividends or repurchase or redeem capital stock; • make certain investments; • incur liens; • enter into certain types of transactions with affiliates; • limit dividends or other payments by our restricted subsidiaries to us; and • sell assets or consolidate or merge with or into other companies. These and other covenants that are contained in the 2019 Notes Indenture are subject to important exceptions and qualifications set forth in the 2019 Notes Indenture. At December 31, 2015, we were in compliance with the restrictive covenants under the 2019 Notes Indenture. We may, at our option, redeem all or part of the 2019 Notes, at any time on or after February 15, 2015, at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest to the date of redemption. Following a change of control, as defined in the 2019 Notes Indenture, we will be required to make an offer to repurchase all or a portion of the 2019 Notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase. 7.75% Senior Notes due 2022 On October 16, 2012, we issued $300.0 million aggregate principal amount of 7.75% Senior Notes due 2022 (the “2022 Notes”). The 2022 Notes are jointly and severally, and unconditionally, guaranteed on a senior unsecured basis initially by all of our current subsidiaries other than three immaterial subsidiaries. The 2022 Notes and the guarantees rank (1) equally in right of payment 40


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    with any of our and the subsidiary guarantors’ existing and future senior indebtedness, including our existing 2019 Notes and the related guarantees, and (2) effectively junior to all existing or future liabilities of our subsidiaries that do not guarantee the 2022 Notes and to our and the subsidiary guarantors’ existing or future secured indebtedness to the extent of the value of the collateral therefor. The 2022 Notes and the guarantees were offered and sold in private transactions in accordance with Rule 144A and Regulation S under the Securities Act. We received net proceeds from the issuance of the 2022 Notes of approximately $293.3 million after discounts and offering expenses. We used a portion of the net proceeds from the offering to fund our pending tender offer and consent solicitation for our 7.125% Senior Notes due 2016 (The “2016 Notes”) and to redeem any of the 2016 Notes not purchased in the tender offer. The remainder of the net proceeds was used for general corporate purposes. The 2022 Notes and the guarantees were issued pursuant to an indenture dated as of October 16, 2012 (the “2022 Notes Indenture”), by and among us, the guarantor’s party thereto and Wells Fargo Bank, National Association, as trustee. Interest on the 2022 Notes accrues from and including October 16, 2012 at a rate of 7.75% per year. Interest on the 2022 Notes is payable semi-annually in arrears on April 15 and October 15 of each year, commencing on April 15, 2013. The 2022 Notes mature on October 15, 2022. The 2022 Notes Indenture contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: • incur additional indebtedness; • pay dividends or repurchase or redeem capital stock; • make certain investments; • incur liens; • enter into certain types of transactions with affiliates; • limit dividends or other payments by our restricted subsidiaries to us; and • sell assets or consolidate or merge with or into other companies. These and other covenants that are contained in the 2022 Notes Indenture are subject to important exceptions and qualifications set forth in the 2022 Indenture. At December 31, 2015, we were in compliance with the restrictive covenants under the 2022 Notes Indenture. We may, at our option, redeem all or part of the 2022 Notes, at any time on or after October 15, 2017, at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest to the date of redemption. At any time before October 15, 2017, we may redeem some or all of the 2022 Notes at a redemption price equal to 100% of the principal amount of the 2022 Notes, plus an applicable premium and accrued and unpaid interest to the date of redemption. Following a change of control, as defined in the 2022 Notes Indenture, we will be required to make an offer to repurchase all or a portion of the 2022 Notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase. 41


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    Previous Revolving Credit Facility On February 15, 2011, in connection with the initial offering of 2019 Notes, we terminated our previous $30.0 million secured revolving credit facility with Capital One, National Association, and entered into a credit agreement (the “Previous Credit Agreement”) providing for a $165.0 million Revolving Credit Facility. On November 26, 2014, we amended and restated the Previous Credit Agreement in order to increase the aggregate commitments and extend the maturity date (each defined in the Previous Credit Agreement), among other modifications. Amended and Restated Revolving Credit Facility On November 26, 2014, we entered into an amended and restated $300.0 million revolving credit facility (the “Amended and Restated Credit Agreement”) with a syndicate of lenders and Bank of America, N.A., as administrative agent for the lenders. The Amended and Restated Credit Agreement includes an accordion feature whereby the total credit available to us can be increased by up to $150.0 million, subject to receiving additional lender commitments and the satisfaction of customary conditions. The obligations under the Amended and Restated Credit Agreement are guaranteed on a joint and several basis by each of our current subsidiaries, other than three immaterial subsidiaries, and are secured by substantially all of our and our guarantors’ assets as collateral under a Security Agreement dated as of February 15, 2011, as ratified by a Ratification and Amendment of Security Agreement dated as of November 26, 2014 (as so ratified, the “Security Agreement”). Borrowings under the Amended and Restated Credit Agreement will mature on November 26, 2019 unless we have not refinanced our 2019 Notes by August 15, 2018, in which event borrowings under the Amended and Restated Credit Agreement will mature on January 2, 2019. We have the ability at any time to prepay the Amended and Restated Credit Agreement without premium or penalty. At our option, advances under the Amended and Restated Credit Agreement may be comprised of (i) alternate base rate loans, at a variable base interest rate plus a margin ranging from 1.25% to 2.25% based on our consolidated leverage ratio or (ii) Eurodollar loans, at a variable base interest rate plus a margin ranging from 2.25% to 3.25% based on our consolidated leverage ratio. We will pay a commitment fee equal to 0.50% on the daily unused amount of the commitments under the Amended and Restated Credit Agreement. The Amended and Restated Credit Agreement contains various covenants that, subject to agreed upon exceptions, limit our ability and the ability of certain of our subsidiaries to: • incur indebtedness; • grant liens; • enter into sale and leaseback transactions; • make loans, capital expenditures, acquisitions and investments; • change the nature of business; • acquire or sell assets or consolidate or merge with or into other companies; • declare or pay dividends; • enter into transactions with affiliates; • enter into burdensome agreements; • prepay, redeem or modify or terminate other indebtedness; • change accounting policies and reporting practices; • amend organizational documents; and • use proceeds to fund any activities of or business with any person that is the subject of governmental sanctions. The Amended and Restated Credit Agreement also contains covenants that require us to maintain specified ratios or conditions as follows: · a minimum consolidated interest coverage ratio of not less than 2.50 to 1.00; · a maximum consolidated leverage ratio not to exceed 4.00 to 1.00; · a maximum consolidated senior secured leverage ratio of 2.00 to 1.00. If an event of default occurs under the Amended and Restated Credit Agreement, then the lenders may (i) terminate their commitments under the Amended and Restated Credit Agreement, (ii) declare any outstanding loans under the Amended and Restated Credit Agreement to be immediately due and payable, (iii) require that we cash collateralize our letter of credit obligations and (iv) foreclose on the collateral secured by the Security Agreement. 42


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    On December 15, 2014, we entered into an amendment to the Amended and Restated Credit Agreement that, among other things, (i) permits the prepayment, purchase or other satisfaction of senior notes by the borrower in an aggregate principal amount not to exceed $100 million, provided that certain requirements are met, (ii) permits the disposition of those senior notes prepaid, purchased or otherwise satisfied by the borrower or any other loan party (the “Permitted Purchased Notes”), provided that certain requirements are met, (iii) permits the cancellation or other satisfaction of any Permitted Purchased Notes and (iv) removes Permitted Purchased Notes and any interest or gain therefrom from the calculations of consolidated interest coverage ratio, consolidated EBITDA, consolidated leverage ratio and consolidated net income under the Amended and Restated Credit Agreement. On April 21, 2015, Basic entered into an amendment to the Amended and Restated Credit Agreement that, among other things: (A) reduces the maximum aggregate commitments thereunder from $300 million to $250 million; (B) permits credit extensions under the Credit Agreement based on availability under a borrowing base comprised of eligible billed accounts receivable, eligible unbilled accounts receivable and eligible equipment of Basic; and (C) provides for the replacement of the existing financial covenants with new financial covenants, which apply only if availability under the Credit Agreement is less than the greater of (i) 25% of the aggregate commitments outstanding, or (ii) $62.5 million. If availability is less than these amounts, Basic will be required to maintain (a) a consolidated senior secured leverage ratio not to exceed 2.50 to 1.00 and (b) a consolidated fixed charge coverage ratio not less than 1.00 to 1.00. We had no borrowings and $50.3 million in letters of credit outstanding under the Amended and Restated Credit Agreement as of December 31, 2015, giving us $93.4 million of available borrowing capacity. At December 31, 2015, we were in compliance with our covenants under the Amended and Restated Credit Agreement. Term Loan Agreement On February 17, 2016, we entered into a Term Loan Credit Agreement (the “Term Loan Agreement”) with a syndicate of lenders and U.S. Bank National Association, as administrative agent for the lenders. The Term Loan Agreement includes two categories of borrowings: (a) the closing date term loan borrowings in an aggregate amount of $ 165.0 million, and (b) the delayed draw term loan borrowings in an aggregate principal amount not to exceed $ 15.0 million. The making of the term loans is subject to the satisfaction of certain conditions precedent, including, with respect to thedelayed draw term loans, the consent of the lenders providing the delayed draw term loans. The conditions precedent to the making of the closing date term loans include, among other things, (i) the execution and delivery of (a) a guarantee agreement, pursuant to which the obligations under the Term Loan Agreement will be guaranteed on a joint and several basis by each of Basic’s current subsidiaries (subject to certain exceptions), (b) a security agreement, pursuant to which the obligations under the Term Loan Agreement will be secured by substantially all assets of Basic and the assets of the guarantors and (c) an intercreditor agreement, which will govern, among other things, priority of distribution of collateral that is pledged as collateral under each of the Term Loan Agreement and our Revolving Credit Facility and (ii) our causing more than 49.1% of the Term Loan Priority Collateral to become subject to a perfected lien in favor of the term loan administrative agent. The proceeds of the term loans will be deposited into an escrow account, from which they will be released only upon the satisfaction of the following conditions: (i) 49.1% of the proceeds of theclosing date term loans may be released upon our causing not less than 49.1% of the Term Loan Priority Collateral to become subject to a perfected lien in favor of the term loan administrative agent; (ii) upon our causing not less than 75% of the Term Loan Priority Collateral to become subject to a perfected lien in favor of the term loan administrative agent, the term loans in the escrow account may be released to the extent that the aggregate amount ofterm loans released to the borrower on or prior to such date equals 75% of the term loans funded into the escrow account and (iii) the remaining proceeds of theterm loans deposited in the escrow account may be released upon our causing not less than 95% of the Term Loan Priority Collateral to become subject to a perfected lien in favor of the term loan administrative agent. Borrowings under the Term Loan Agreement will mature on February 26, 2021 unless , such date is not a business day, in which case the borrowings under the Term Loan Agreement will mature on the first preceding business day. However, if Basic has not completed an acceptable 2019 Senior Notes Refinancing by November 17, 2018, then the borrowings under the Term Loan Agreement will mature on November 17, 2018. We are required to prepay the Term Loan Agreement under circumstances without premium or penalty unless such prepayment is the result of a “springing” maturity date of November 17, 2018 described above, a change of control or the incurrence of indebtedness not permitted under the Term Loan Agreement and under certain other circumstances, in which case such prepayment will be subject to an applicable premium. Each loan shall bear interest on the outstanding principal amount thereof from the applicable borrowing date at a rate per annum equal to 13.50%. In addition,we will be responsible for the applicable lenders’ fees, including a closing payment equal to 7.00% of the aggregate principal amount of commitments of each lender under the Term Loan Agreement as of the effective date, and administrative agent fees. The Term Loan Agreement contains various covenants that, subject to agreed upon exceptions, limit Basic’s ability and the ability of certain of our subsidiaries to: · incur indebtedness; · grant liens; · enter into sale and leaseback transactions; 43


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    · make loans, capital expenditures, acquisitions and investments; · change the nature of business; · acquire or sell assets or consolidate or merge with or into other companies; · declare or pay dividends; · enter into transactions with affiliates; · enter into burdensome agreements; · prepay, redeem or modify or terminate other indebtedness; · change accounting policies and reporting practices; · amend organizational documents; and · use proceeds to fund any activities of or business with any person that is the subject of governmental sanctions. If an event of default occurs under the Term Loan Agreement, then theterm loan administrative agent may, with the consent of the required lenders , or shall, at the direction of, the required lenders, (i) terminate lenders’ commitments under the Term Loan Agreement, (ii) declare any outstanding loans under the Term Loan Agreement to be immediately due and payable, and (iii) exercise on behalf of itself and the lenders all rights and remedies available to it and the lenders under the applicable loan documents or applicable law or equity. We expect the initial closing date of the Term Loan Agreement will occur on or about February 26, 2016, at which time we will also enter into an amendment to our revolving credit facility to reduce aggregate commitments thereunder to $100.0 million, the term loan security agreement with the term loan administrative agent and an intercreditor agreement. Other Debt We have a variety of other capital leases and notes payable outstanding that are customary in our business. None of these debt instrumentsare individually material. Our leases with Bank of America Leasing & Capital, LLC require us to maintain a minimum debt service coverage ratio of 1.05 to 1.00. As of December 31, 2015, we had total capital leases of approximately $111.1 million. Preferred Stock At December 31, 2015 and December 31, 2014, we had 5,000,000 shares of $.01 par value preferred stock authorized, of which none was designated, issued or outstanding. Other Matters Off-Balance Sheet Arrangements We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. Net Operating Losses As of December 31, 2015, we had approximately $352.5 million of net operating loss carryforwards. Although realization is not assured, management believes it is more likely than not that we will generate sufficient future U.S. taxable income to realize our U.S. deferred tax assets as of December 31, 2015 based on the weight of all available evidence including the future reversal of existing U.S. taxable temporary differences as of December 31, 2015. We believe that it is more likely than not that the benefit from certain state net operating loss carryforwards and other deductible temporary differences in certain state jurisdictions will not be realized. In recognition of this risk, we have provided a valuation allowance of approximately $898,000 on the net deferred tax asset relating to these state jurisdictions as a result of the company being in a cumulative three year pre-tax book loss position and absence of other objectively verifiable positive evidence including reversal of existing taxable temporary differences in these certain state tax jurisdictions. Recent Accounting Pronouncements In January 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items.”The Update eliminates the concept of an extraordinary item. The Update is effective for annual periods beginning after December 15, 2015, and interim periods within those annual periods.Basic does not believe this pronouncement will have a material impact on its consolidated financial statements and related disclosures. 44


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    In April 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Update is effective for annual periods beginning after December 15, 2015, and interim periods within those annual periods.Basic does not believe this pronouncement will have a material impact on its consolidated financial statements and related disclosures. In July 2015 the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory.” ASU 2015-11, changes the measurement principle for entities that do not measure inventory using the last-in, first-out (LIFO) or retail inventory method from the lower of cost or market to lower of cost and net realizable value. The Update also eliminates the requirement for these entities to consider replacement cost or net realizable value less an approximately normal profit margin when measuring inventory. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Basic is in the process of determining if this pronouncement will have a material impact on its consolidated financial statements and related disclosures. In August 2015 the FASB issued ASU 2015-14, “Revenue from Contracts with Customers—Deferral of the Effective Date”, that defers by one year the effective date of ASU 2014-09, “Revenue from Contracts with Customers”. The Update is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Basic is in the process of determining if this pronouncement will have a material impact on its consolidated financial statements and related disclosures. In September 2015 the FASB issued ASU 2015-16, “Business Combinations: Simplifying the Accounting for Measurement-Period Adjustment”. ASU 2015-16 eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement –period adjustments that occur in periods after a business combination is consummated. The Update is effective for annual periods beginning after December 15, 2015, and interim periods within those annual periods. Basic has early adopted this pronouncement and it did not have a material impact on its consolidated financial statements and related disclosures. In November 2015, the FASB issued ASU No 2015-17,Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes. The main provision of this Update is to simplify the presentation of deferred income taxes by requiring that deferred tax assets and liabilities be classified as noncurrent in the statement of financial position. This Update is effective for Basic in annual and interim periods beginning after December 15, 2016. The adoption of this Update will not have a material impact on the Company's consolidated financial statements and related disclosures. Impact of Inflation on Operations Management is of the opinion that inflation has not had a significant impact on our business. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK As of December 31, 2015, we had no borrowings outstanding under agreements with market risk sensitive instruments, and were not party to any other material market risk sensitive instruments. 45


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    ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Basic Energy Services, Inc. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Management’s Report on Internal Control Over Financial Reporting 47 Reports of Independent Registered Public Accounting Firm 48 Consolidated Balance Sheets as of December 31, 2015 and 2014 50 Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013 51 Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2015, 2014 and 2013 52 Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013 53 Notes to Consolidated Financial Statements 54 46


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    MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management of Basic Energy Services, Inc. (“Basic” or the “Company”) is responsible for establishing and maintaining adequate internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting for the Company. As defined by the Securities and Exchange Commission (Rule 13a-15(f) under the Exchange Act of 1934, as amended), internal control over financial reporting is a process designed by, or under the supervision of Basic’s principal executive and principal financial officers and effected by its Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles. The Company’s internal control over financial reporting is supported by written policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the Company’s transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorization 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 consolidated 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. In connection with the preparation of the Company’s annual consolidated financial statements, management has undertaken an assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO Framework). Management’s assessment included an evaluation of the design of the Company’s internal control over financial reporting and testing of the operational effectiveness of those controls. Based on this assessment, management has concluded that as of December 31, 2015, the Company’s internal control over financial reporting was effective to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. The Company acquired Harbor Resources, LLC, Aerion Rental, LLC and GreyRock Pressure Pumping, LLC, during 2015, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015, Harbor Resources, LLC, Aerion Rental, LLC and GreyRock Pressure Pumping, LLC’s internal control over financial reporting associated with total assets of $16.7 million and total revenues of $3.0 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2015. KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this report, has issued an attestation report on the effectiveness of internal control over financial reporting. /s/ T. M. “Roe” Patterson /s/ Alan Krenek T. M. “Roe” Patterson Alan Krenek Chief Executive Officer Chief Financial Officer 47


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    Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders Basic Energy Services, Inc.: We have audited Basic Energy Services, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Basic Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed 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. A 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 assets of the company; (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 management and directors of the company; 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. In our opinion, Basic Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Basic Energy Services, Inc. acquired Harbor Resources, LLC, Aerion Rental, LLC and GreyRock Pressure Pumping, LLC (collectively, the “Acquisitions”) during 2015, and management excluded from its assessment of the effectiveness of Basic Energy Services, Inc.’s internal control over financial reporting as of December 31, 201 5, the Acquisitions’ internal control over financial reporting associated with total assets of $16.7 million and total revenues of $3.0 million included in the consolidated financial statements of Basic Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2015. Our audit of internal control over financial reporting of Basic Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of the Acquisitions. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 23, 2016 expressed an unqualified opinion on those consolidated financial statements. KPMG LLP Dallas, Texas February 23, 2016 48


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    Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders Basic Energy Services, Inc.: We have audited the accompanying consolidated balance sheets of Basic Energy Services, Inc. and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2015. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule 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 Basic Energy Services, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three‑year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Basic Energy Services, Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report datedFebruary 23, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting. KPMG LLP Dallas, Texas February 23, 2016 49

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