Company Quick10K Filing
Quick10K
Basic Energy Services
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$3.28 27 $88
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
10-Q 2017-09-30 Quarter: 2017-09-30
10-Q 2017-06-30 Quarter: 2017-06-30
10-Q 2017-03-31 Quarter: 2017-03-31
10-K 2016-12-31 Annual: 2016-12-31
10-Q 2016-09-30 Quarter: 2016-09-30
10-Q 2016-06-30 Quarter: 2016-06-30
10-Q 2016-03-31 Quarter: 2016-03-31
10-K 2015-12-31 Annual: 2015-12-31
10-Q 2015-09-30 Quarter: 2015-09-30
10-Q 2015-06-30 Quarter: 2015-06-30
10-Q 2015-03-31 Quarter: 2015-03-31
10-K 2014-12-31 Annual: 2014-12-31
10-Q 2014-09-30 Quarter: 2014-09-30
10-Q 2014-06-30 Quarter: 2014-06-30
10-Q 2014-03-31 Quarter: 2014-03-31
10-K 2013-12-31 Annual: 2013-12-31
8-K 2018-12-12 Officers, Exhibits
8-K 2018-11-01 Earnings, Exhibits
8-K 2018-10-03 Regulation FD, Exhibits
8-K 2018-10-02 Enter Agreement, Leave Agreement, Off-BS Arrangement, Other Events, Exhibits
8-K 2018-09-25 Enter Agreement, Off-BS Arrangement, Other Events, Exhibits
8-K 2018-09-14 Enter Agreement, Regulation FD, Other Events, Exhibits
8-K 2018-08-14 Officers, Regulation FD, Exhibits
8-K 2018-07-31 Earnings, Exhibits
8-K 2018-05-21 Shareholder Vote
8-K 2018-05-03 Earnings, Exhibits
8-K 2018-04-17 Enter Agreement, Off-BS Arrangement, Regulation FD, Exhibits
8-K 2018-04-10 Officers
8-K 2018-04-03 Officers, Exhibits
8-K 2018-03-19 Officers
8-K 2018-03-07 Regulation FD, Exhibits
8-K 2018-03-05 Other Events, Exhibits
8-K 2018-02-28 Regulation FD, Other Events, Exhibits
8-K 2018-02-26 Earnings, Exhibits
8-K 2018-02-08 Officers, Exhibits
AAPL Apple 939,520
CDAY Ceridian HCM Holding 6,980
VSM Versum Materials 5,670
PRSC Providence Service 857
CVCY Central Valley Community Bancorp 269
GRWG Growgeneration 0
NVOS Novo Integrated Sciences 0
ICLD Intercloud Systems 0
ECOM Channeladvisor 0
PGTK Pacific Green Technologies 0
BAS 2018-12-31
Part I
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Part IV
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
EX-21.1 bas-20181231xex211.htm
EX-23.1 bas-20181231xex231.htm
EX-31.1 bas-20181231xex311.htm
EX-31.2 bas-20181231xex312.htm
EX-32.1 bas-20181231xex321.htm
EX-32.2 bas-20181231xex322.htm

Basic Energy Services Earnings 2018-12-31

BAS 10K Annual Report

Balance SheetIncome StatementCash Flow

Document
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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, 2018 
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)
Delaware54-2091194
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
  
801 Cherry Street, Suite 2100 
Fort Worth, Texas76102 
(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 ClassName of each exchange on which registered
Common Stock, $0.01 par value per shareNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: Warrants, exercisable for one share of Common Stock, $0.01 par value per share
________________________________________________________________________________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  ☐    No    þ  
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    þ  
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   þ   No  ☐ 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).    Yes   þ    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.     þ 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
 Large Accelerated Filer ☐
         Accelerated Filer  þ
Non-Accelerated filer  ☐
       Smaller reporting company  þ
       Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act  ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No    þ 
The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was approximately $206,658,513 as of June 30, 2018, the last business day of the registrant’s most recently completed second fiscal quarter (based on a closing price of $11.11 per share and 18,598,426 shares held by non-affiliates).
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes  þ No ¨☐
There were 26,906,690 shares of the registrant’s common stock outstanding as of March 1, 2019.  
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.



BASIC ENERGY SERVICES, INC.
Index to Form 10-K 

ii


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. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flows, pending legal or regulatory proceedings and claims, future economic performance, operating income, costs savings and management's plans, strategies, goals and objectives for future operations and goals. 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;
uncertainties about our ability to successfully execute our business and financial plans and strategies;
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. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.
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.
iii


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, water logistics, 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. References to “Basic,” the “Company,” “we,” “us” or “our” in this report refer to Basic Energy Services, Inc., and, unless the context otherwise suggests, its wholly owned subsidiaries and its controlled subsidiaries.
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, California and Colorado. 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, Denver-Julesburg 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, Well Servicing, Water Logistics, 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 (49% of our revenues in 2018) 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 and nitrogen units. The largest portion of this business segment consists of pumping services focused on cementing, acidizing and fracturing services in niche markets.
Well Servicing.    Our well servicing segment (26% of our revenues in 2018) operates our fleet of 310 active 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 the completion of the well bore to initiate production 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.
Water Logistics.    Our water logistics segment (24% of our revenues in 2018) utilizes our fleet of 823 fluid service trucks and related assets, including specialized tank trucks, storage tanks, pipelines, 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.
Contract Drilling.    Our contract drilling segment (1% of our revenues in 2018) operates our fleet of 11 drilling rigs and related equipment. We use these assets to penetrate the earth to a desired depth and initiate production from a well.
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 Eagle Ford, and Haynesville shale plays. We operate in states that accounted for approximately 98% of U.S. onshore oil and natural gas production. We believe 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
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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 132 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 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 leading 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 Central region of North Texas, Oklahoma, Arkansas, Louisiana and Kansas; California; and Colorado. 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. 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, accounting, safety, environmental and maintenance processes and controls. We operate a decentralized operational organization in which our regional or division managers are responsible for their operations, including asset management, cost control, policy compliance, training and other aspects of quality control. With the majority of our regional managers having over 30 years of industry experience, each have extensive knowledge of the customer base, job requirements and working conditions in each local market. Reporting to our 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 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 leading presence in our core operating areas facilitates employee retention, a key factor for success in our business, and provides us with brand recognition that we 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, 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 completion, 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
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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 and 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 oil and natural gas commodity price. Based on these factors, we make 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 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 since 2009, which has resulted in low levels of activity in our natural gas-driven markets. In the fourth quarter of 2014, oil prices declined due to oversupply concerns worldwide and have remained at relatively lower levels since that time.   
The table below sets forth average closing prices for the Cushing WTI Spot Oil Price and the Henry Hub Natural Gas Spot Price and the corresponding rig count for oil and natural gas drilling rigs since 2015:
 Cushing WTI SpotHenry Hub GasAverage Rig Count 
Period:Oil Price ($/Bbl.)Spot Price ($/Mcf.)Oil Natural Gas 
1/1/2015$48.69 $2.63 754 228 
1/1/201643.14 2.52 408 100 
1/1/201750.88 2.99 703 172 
1/1/201864.94 3.17 841 190 
12/31/201845.15 3.69 885 198 
Source: U.S. Department of Energy. Data for each of the foregoing rig counts are based on information from the Baker Hughes rig count.
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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; and
underbalanced drilling in low pressure and fluid sensitive reservoirs.
This segment operates 302 pumping units, with approximately 513,000 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 29 air compressor packages, including foam circulation units, for underbalanced drilling, 32 snubbing units and 17 coiled tubing units for cased-hole measurement and pipe recovery services. 
Because 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. 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 high pressure fluids pumped into it. 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, 2018:   
 Market Area
Asset Type:Ark-La-TexMid-ContinentGulf CoastRocky MountainPermian BasinTotal
Pumping Units26 180 67 21 302 
Air/Foam Packages— 11 — 13 29 
Snubbing Units21 11 — — — 32 
Rental and Fishing Tool Stores— — 15 
Coiled Tubing Units— — 14 — 17 
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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. This philosophy allows for better operating efficiency and longer lives for our equipment.
The level of activity of our pumping services business is tied to drilling and workover activity. 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.
For further discussion of financial results for the Completion and Remedial Services segment, see Note 16, Business Segment Information of the notes to our consolidated financial statements included in this Annual Report on Form 10-K.
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 an 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. We typically 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 actively marketed fleet included 310 well servicing rigs as of December 31, 2018. Our well servicing equipment operates from facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado, California, Arkansas, Utah, Montana and Kansas. Our well servicing rigs are mobile units that normally operate within a radius of approximately 75 to 100 miles from their respective bases.
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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, 2018. 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
Rig Type:Rated CapacityPermian BasinGulf CoastArk-La-TexMid-ContinentRocky MountainCaliforniaInactiveTotal
SwabN/A— — — — 
Light Duty< 90 tons— — — — — — 
Medium Duty
> 90 <125 tons
70 11 32 32 13 23 189 
Heavy Duty
> 125 tons
76 18 11 — 115 
Total 146 29 11 40 44 15 25 310 
We operate a total of 310 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., Ranger Energy Services Inc., 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.
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.
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.
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
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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.  
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.
For further discussion of financial results for the Well Servicing segment, see Note 16, Business Segment Information of the notes to our consolidated financial statements included in this Annual Report on Form 10-K.
Water Logistics Segment
Our water logistics 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, completion, workover, and flowback operations and of saltwater produced as a by-product of oil and natural gas production either by truck or pipeline;
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.
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 water logistics equipment that we operated at December 31, 2018:  
 Market Area
 Asset Type:Rocky MountainArk-La-TexPermian BasinMid-ContinentGulf CoastTotal
Fluid Service Trucks93 106 437 56 131 823 
Saltwater Disposal Wells24 30 13 11 83 
Fresh/Brine Water Stations— 40 — 50 
Fluid Storage Tanks237 751 1,117 296 363 2,764 
Requirements for minor or incidental water logistics 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.
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Our water logistics 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 saltwater in conjunction with oil or natural gas. This residual water remains the legal property of the producer throughout the disposal process. We transport and dispose of this water using several different methods. Fluid service trucks pick up this fluid from tank batteries at the well site and transport it to a saltwater disposal well for injection. Water can also be transported from the tank battery to the saltwater disposal well by pipeline. Pipelining of water increased throughout the year, and represented approximately 33% of total disposal volumes in the fourth quarter of 2018. This type of regular maintenance work must be performed if a well is to remain active. 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 saltwater is produced and the areas where our company-owned disposal wells are located. We operate saltwater 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.
Completion, remedial, and workover 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. Flowback fluids, spent mud, and 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 water logistics industry are mostly small, regionally focused companies. There are currently no companies that have a dominant position on a nationwide basis. Activity in the water logistics 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, onshore drilling activity significantly affects the level of activity in the water logistics industry. While there are no industry-wide statistics, the Baker Hughes Land Drilling Rig Count is an indirect indication of demand for water logistics because it directly reflects onshore drilling activity.
Water Logistics.    At December 31, 2018, we owned and operated 823 fluid service trucks, each equipped with an average fluid hauling capacity of up to 150 bbls. 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 saltwater 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.
Saltwater Disposal Well Services.    At December 31, 2018, we owned 83 saltwater disposal facilities. Disposal wells are permitted to dispose of saltwater and incidental non-hazardous oil and natural gas wastes. Our fluid service trucks frequently transport the fluids that are disposed of in these saltwater disposal wells. Our disposal wells have an average permitted injection capacity of over 7,500 bbls per day per well and are strategically located in close proximity to our customers’ producing wells. Most oil and natural gas wells produce varying amounts of saltwater throughout their productive lives. In the states in which we operate, oil and natural gas wastes and saltwater produced from oil and natural gas wells are required by law to be disposed of in authorized facilities, including permitted saltwater 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 bbls 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. Fracturing 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.
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
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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-bbl basis.
For further discussion of financial results for the Water Logistics segment, see Note 16, Business Segment Information of the notes to our consolidated financial statements included in this Annual Report on Form 10-K.
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 11 land drilling rigs, which are currently stationed 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.
For further discussion of financial results for the Contract Drilling segment, see Note 16, Business Segment Information of the notes to our consolidated financial statements included in this Annual Report on Form 10-K.
Properties
Our principal executive offices are located at 801 Cherry Street, Suite 2100, Fort Worth, Texas 76102. We currently conduct our business from 132 area offices, 80 of which we own and 52 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 132 area offices, 83 are located in Texas and ten are in New Mexico. Additionally, we have eight area offices in each of North Dakota and Oklahoma, seven area offices in Colorado, six area offices in Wyoming, two area offices in each of Louisiana, Kansas, Utah and California and one area office in each of Montana, and Arkansas.
Customers 
We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2018, no single customer comprised over 10% 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 operations 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.
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
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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 our largest well servicing competitors are Key Energy Services, Inc., Superior Energy Services Inc., C&J Energy Services, Ltd., Ranger Energy Services Inc., and Pioneer Energy Services Corp. 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, tribal, 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 (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. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results. Moreover, 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, as amended from time to time that relate to our business.
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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 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, this exemption for such drilling fluids, produced waters and other oil and gas wastes is subject to being limited or lost. For example, the EPA and certain non-governmental environmental groups that were contesting the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes entered into an agreement that was finalized in a consent decree issued by the U.S. District Court for the District of Columbia in December 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. A loss of the RCRA hazardous waste exemption for drilling fluids, produced waters and related wastes could result in an increase in customers’ drilling programs’ costs to manage and dispose of wastes they generate, which development could have a material adverse effect on the drilling program’s operations and reduce the demand for our services. Moreover, these wastes and other wastes may be otherwise regulated by the EPA or state agencies. 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 or our customers 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 some owners or operators of facilities that store or otherwise handle oil to prepare plans and implement 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. and, permits for discharges of storm water runoff may be required for certain of our properties. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. In June 2015, the EPA and the U.S. Army Corps of Engineers (“Corps”) released a final rule that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, ("WOTUS") including wetlands, but legal challenges to this rule followed. The 2015 rule was stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. On January 22, 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides
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with the federal district courts In addition, the EPA and Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a final rule on February 6, 2018 specifying that the contested June 2015 rule would not take effect until February 6, 2020. In July 2018, the EPA issued a supplemental notice of proposed rulemaking, offering support and clarification regarding the Agency’s June 2017 proposed repeal of the 2015 WOTUS rule. Later in 2018, the EPA’s decision was challenged in court, which resulted in a decision by the U.S. District Court for the District of South Carolina to enjoin the EPA’s February 2018 delay rule. Several states then acted to halt reinstatement of the 2015 WOTUS rule, the effect of all of which is that the 2015 WOTUS definition is currently in effect in 22 states. Meanwhile, in December 2018, the EPA and the Corps issued a proposed rule to revise the definition of “Waters of the United States.” The proposed rule would narrow the definition, excluding, for example, streams that do not flow year-round and wetlands without a direct surface connection to other jurisdictional waters. Litigation by parties opposing the rule quickly followed. Due to the administrative procedures required to establish the rule and pending litigation, the new definition of “Waters of the United States” may not be implemented, if at all, for several years. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations may be triggered during development and operation of our or our customers’ properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of those properties.
Our underground injection operations are subject to the Safe Drinking Water Act ("SDWA") as well as analogous state and local laws and regulations including the Underground Injection Control ('UIC") UIC program, which 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 regulating underground injection has been introduced 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 disposal of produced saltwater by underground injection. The substantial majority of our saltwater disposal wells are located in Texas and are regulated by the RRC. We also operate saltwater disposal wells in New Mexico, Oklahoma, Arkansas, Louisiana and North Dakota and are subject to similar regulatory controls in those states. In addition, in response to reports tying the increase in seismic activity in Oklahoma to the injection of produced water, the Oklahoma Corporation Commission ("OCC") has implemented a variety of measures, including the adoption of the National Academy of Science’s “traffic light system”, pursuant to which the agency reviews new disposal well applications and may restrict operations at existing wells. The OCC and the Oklahoma Geologic Survey continue to release well completion seismicity guidance, which most recently directs operators to adopt a seismicity response plan and take certain prescriptive actions, including mitigation, following anomalous seismic activity within a certain radius of hydraulic fracturing operations. Beginning in 2013, the OCC has ordered the reduction of disposal volumes into the Arbuckle formation. More recently, the OCC directed the shut in of a number of disposal wells due to increased earthquake activity in the Arbuckle formation and imposed further disposal well volume reductions in the Edmond area. In addition, since 2015, the OCC’s Oil and Gas Conservation Division has issued a number of directives restricting the future volume of wastewater disposed of via subsurface injection and directing the shut in of certain injection wells. To date, none of our wells have been restricted. Regulations in the states in which we operate require us to obtain a permit from the applicable regulatory agencies to operate each of our underground saltwater 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, 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.
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In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Clean Water Act if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, and those petitions were granted in February 2019. The EPA has also brought attention to the reach of the Clean Water Act’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the Clean Water Act permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. To date, no further action has been taken by the EPA with respect to the issue, but should Clean Water Act permitting be required for saltwater injections wells, the costs of permitting and compliance for our operations could increase.
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 this insurance will cover all potential losses, or that insurance will continue to be commercially available or 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 U.S. Occupational Safety and Health Administration’s hazard communication standard the EPA’s community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, the general duty clause and Risk Management Planning regulations promulgated under Section 112(r) of the Clean Air Act, and comparable state statues require 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, and plans for response to a release be developed for certain facilities.
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 (“CAA”) and comparable state laws and regulations restrict the emission of various air pollutants from many sources through air emissions standards, construction and operating permitting programs, and the imposition of other monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Obtaining required permits has the potential to delay the development of oil and natural gas projects.
Over the next several years, we and our customers may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” and completed the remaining area of designations not addressed under the November 2017 final rule in April and July of 2018. Additionally, state implementation of these revised standards could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Compliance with this final rule or any other new legal requirements could, among other things, require us or our customers to install new emission controls on some equipment and to incur longer permitting timelines or significantly increased capital expenditures and operating costs. Additionally, if such compliance reduces demand for the oil and natural gas that our customers produce, we could also incur reduced demand for our services, which one or more developments could adversely impact our business.
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 EPA has begun to adopt regulations to report and reduce emissions of greenhouse gases. Any such regulations 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 approximately 195 nations that signed an international accord in December 2015, the so-called Paris Agreement, which became effective in 2016, with the objective of limiting greenhouse gas emissions. However, in August 2017, the U.S. State Department
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informed the United Nations of its intent to withdraw from the Paris Agreement. Notably, the earliest date of withdrawal under the terms of the agreement is November 4, 2020.
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 emissions. 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. 
Finally, it should be noted that, recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for our customers to secure funding for exploration and production activities, which could reduce demand for our services. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time.
Employees
As of December 31, 2018, we employed approximately 4,100 people, with approximately 83% 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.
 
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 at www.basicenergyservices.com. Any waivers granted to directors or executive officers and any material amendments to our Code of Ethics will be posted promptly on our website and/or disclosed in a current report on Form 8-K.
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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 operations, 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, acquisition and divestiture activity among oil and gas producers. Activities by non-governmental organizations to limit certain sources of funding for the energy sector or to restrict the exploration, development and production of oil and natural gas may adversely affect the ability of certain of our customers to conduct operations. The volatility of the oil and natural gas industry, environmental and other governmental regulations regarding the exploration for and production and development of oil and natural gas reserves, 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.
Oil and gas industry pricing remained relatively stable through the middle of 2014. From the second half of 2014 through 2016, oil and natural gas prices declined significantly, due in large part to increasing supplies and weakening demand growth. Although oil prices increased from 2017 into 2018, they have since declined towards the end of 2018 and into 2019. Natural gas prices have been depressed for a prolonged period and utilization and pricing for our services in our natural gas-based operating areas have remained challenged. Oil and gas prices may remain lower for the foreseeable future.
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. 
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 or natural gas prices (or the perception that oil 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 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 $50.88 and $64.94 per bbl in 2017 and 2018, respectively. The Cushing WTI oil prices
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have declined from over $107 per bbl in June 2014 to $45.15 per bbl on December 28, 2018.  The Henry Hub Natural Gas Spot Price averaged $2.99 and $3.17 per Mcf for 2017 and 2018, 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 have longer operating histories, possess substantially greater financial, technological and other resources and have greater name recognition in certain operating areas 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.
Fuel conservation measures could reduce demand for oil and natural gas, which would in turn reduce the demand for our services.
Fuel conservation measures, alternative fuel requirements, technological advances in fuel economy and energy generation, and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, prospects, results of operations and cash flows. Additionally, the increased competitiveness of alternative energy sources (such as wind, solar geothermal, tidal and biofuels) could reduce demand for hydrocarbons and therefore for our services, which would lead to a reduction in our revenues.
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.
We anticipate we will need 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 including idled equipment brought back into service as activity levels improved. For the year ended December 31, 2017, we invested approximately $63.4 million in cash for capital expenditures and $67.5 million of capital leases. For the year ended December 31, 2018, we invested approximately $68.7 million in cash for capital expenditures and $20.2 million of capital leases. For 2019, we have currently budgeted $94.1 million for capital expenditures, excluding acquisitions, including $15.6 million for capital leases. Historically, we have financed these investments through internally generated funds, debt and equity offerings, our capital lease program and borrowings under our credit facilities. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operation - 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 and 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. If we are unable to maintain or obtain access to capital, we could experience a reduction of liquidity and may result in difficulty funding our operations, repayment of short-term borrowings, payments of interest and other obligations.
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, and intangible assets. If any indication of impairment for our long lived assets exists, we project future cash flows 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 for our long-lived assets 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.
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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 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.
As of December 31, 2018, we had total outstanding debt of $349.7 million, net of discount and deferred financing costs, including $300.0 million of aggregate principal amount due under the Senior Notes, capital lease obligations in the aggregate amount of $60.9 million. As of December 31, 2018, Basic had $39.6 million of letters of credit outstanding under the Credit Facility, giving Basic $69.6 million of available borrowing capacity under the Credit Facility. For the years ended December 31, 2017 and 2018, we made cash interest payments totaling $25.6 million and $35.1 million, respectively.

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;
limit management's flexibility in operating our business;
limit our flexibility in planning for, and reacting to, changes in our business or industry;
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 New ABL Credit Agreement and the indenture governing our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.
Our New ABL Credit Agreement and the indenture governing our Senior Notes 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 New ABL Credit Agreement, our indenture and our current and future indebtedness may require 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 cause a default under our New ABL Credit Agreement, our indenture or future indebtedness. 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 any of our indebtedness 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
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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 New ABL Credit Agreement, our indenture or future indebtedness or existing limitations on the incurrence of additional indebtedness, including in connection with acquisitions. Please read Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility” for a discussion of our New ABL Credit Agreement.
Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our New ABL Facility bear interest at variable rates, exposing us to interest rate risk. If the interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed would remain the same, and our results of operations and cash flows for servicing our indebtedness would decrease.
Our operations are subject to inherent risks, including operational hazards 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.
We maintain insurance coverage that we believe to be customary in the industry against many of 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.
We may not be successful in implementing and maintaining technology development and enhancements. New technology may cause us to become less competitive. 
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The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. Our competitors may develop or acquire the right to use new technologies not available to us, which may place us at a competitive disadvantage. In addition, we may face competitive pressure to implement or acquire new technologies at a substantial cost. Some of our competitors have greater resources that may allow them to implement new technologies before we can. Our inability to develop and implement new technologies or products on a timely basis and at competitive cost could have a material adverse effect on our financial position and results of operations.
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, local and tribal 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 or other substantial 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 and public health and safety. 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 or other service 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 water logistics segment includes disposal operations into injection wells that pose risks of seismic activity and 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 past operations or 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 U.S. Department of Transportation and by various state agencies and other regulatory authorities. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety and hazardous materials manifesting, 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, requirements for recording devices or electronic logging devices or limits on vehicle weight and size.
Laws protecting the environment generally have become more stringent over time and could 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 production of 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 Items 1 and 2. “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
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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 our credit agreements.
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.
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 each of 2018 and 2017, our top five customers accounted for 24% and 25% of our revenues, respectively. However, no individual customer composed greater than 10% of our revenues in either year. 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. In addition, customers who are more highly leveraged or otherwise unable to pay their creditors in the ordinary course of business may become insolvent or be unable to operate as a going concern. We may be unable to collect amounts due or damages we are awarded from these customers, and our efforts to collect such amounts may damage our customer relationships. 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. In addition, we compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the requisite technical skills and experience. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions, which can increase our labor costs or subject us to liabilities to our employees. We may have problems finding enough skilled and unskilled laborers in the future if the demand for our services increases. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. 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. these individuals possess extensive expertise, talent and leadership. The loss of the services of T. M. “Roe” Patterson, our President and Chief Executive Officer, or
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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.
Our business could be negatively affected by cybersecurity threats and other disruptions.
We rely heavily on information systems to conduct and protect our business. These information systems are increasingly subject to sophisticated cybersecurity threats such as unauthorized access to data and systems, loss or destruction of data (including confidential customer information), computer viruses, or other malicious code, phishing and cyber attacks, and other similar events. These threats arise from numerous sources, not all of which are within our control, including fraud or malice on the part of third parties, accidental technological failure, electrical or telecommunication outages, failures of computer servers or other damage to our property or assets, or outbreaks of hostilities or terrorist acts. While we attempt to mitigate these risks, we remain vulnerable to additional known or unknown threats.
Given the rapidly evolving nature of cyber threats, there can be no assurance that the systems we have designed and implemented to prevent or limit the effects of cyber incidents or attacks will be sufficient in preventing all such incidents or attacks, or avoiding a material impact to our systems when such incidents or attacks do occur. A cyber incident or attack could result in the disclosure of confidential or proprietary customer information, theft or loss of intellectual property, damage to our reputation with our customers and the market, temporary disruptions of service, failure to meet customer requirements or customer dissatisfaction, theft or exposure to litigation, damage to equipment (which could cause environmental or safety issues) and other financial costs and losses. In addition, as cybersecurity threats continue to evolve, we may be required to devote additional resources to continue to enhance our protective measures or to investigate or remediate any cybersecurity vulnerabilities. We do not presently maintain insurance coverage to protect against cybersecurity risks. If we procure such coverage in the future, we cannot ensure that it will be sufficient to cover any particular losses we may experience as a result of such cyberattacks. A cyber-related attack could adversely impact our operating results and result in other negative consequences, including damage to our reputation or competitiveness, remediation or increased protection costs, litigation or regulatory action.  
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, tornadoes, droughts, flooding, 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 delay our operations and 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 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.”
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 studies finding 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. In 2012 the EPA published a final rule that includes standards to reduce volatile organic compound (“VOC”) emissions associated with oil and natural gas production.. In June 2016, the EPA also published a final rule to reduce methane and additional VOC emissions from oil and natural gas facilities that were constructed, reconstructed or modified after September 18, 2015. The rules and the EPA's subsequent actions to reconsider and propose stays of the rules have been heavily litigated, and in October 2018, the EPA released proposed revisions to some of the 2016 requirements, including reducing the required frequency of fugitive emissions monitoring at well sites and compressor stations. These proposed revisions have not yet been finalized and, as a result the EPA’s 2016 standards are currently in effect. According, future implementation and the ultimate scope of the 2016 standards is uncertain at this time. 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 (“GHGs”), including from the oil and gas industry. Additionally, in 2010, EPA promulgated final rules for mandatory annual reporting of GHGs from certain onshore oil and natural gas production, processing, transmission, storage, and distribution facilities, as well as from facilities in other industries. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate
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Change which led to the signing of the Paris Agreement in December 2015, which became effective in November 2016. However, in August 2017, the U.S. State Department informed the United Nations of its intent to withdraw from the Paris Agreement. Notably, the earliest date of withdrawal under the terms of the Agreement is November 4, 2020. Additionally, certain U.S. states or regional coalitions of states have adopted measures regulating or limiting 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 new or additional 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. 
Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for our customers to secure funding for exploration and production activities, which could reduce demand for our services. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time. 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, state and local 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 expressly 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. 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 released its report on environmental impacts of hydraulic fracturing in December 2016, concluding that hydraulic fracturing could impact drinking water resources. The federal Bureau of Land Management (“BLM”), an agency of the U.S. Department of the Interior published a final rule in March 2015 relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. However, in January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court. These BLM hydraulic fracturing rules are in various stages of suspension, implementation, delay, rescission, and court challenges; accordingly, the future and ultimate scope of these rules is uncertain. The EPA also issued a final rule prohibiting the discharge of wastewater resulting from hydraulic fracturing activities into publicly owned wastewater treatment plants in June 2016.
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. Recent research has linked disposal of produced water into disposal wells to an increase in earthquakes across the South and Midwest. Certain state agencies, including those in Texas and Oklahoma, have implemented regulations authorizing the imposition of certain limitations on existing wells if seismic activity increases in the area of an injection well, including a temporary injection ban. For example, in Oklahoma, the OCC has implemented a variety of measures, including the adoption of the National Academy of Science’s “traffic light system”, pursuant to which the agency reviews new disposal well applications and may restrict
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operations at existing wells. Beginning in 2013, the OCC has ordered the reduction of disposal volumes into the Arbuckle formation. More recently, the OCC directed the shut in of a number of disposal wells due to increased earthquake activity in the Arbuckle formation and imposed further disposal well volume reductions in the Edmond area. Moreover, vigorous public debate over hydraulic fracturing and shale gas production continues, and has resulted in delays of well permits in some areas.
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 at the federal, state or local level 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.
Potential listing of species as "threatened" or “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 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. 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. 
Limitations or restrictions on our ability to obtain, dispose of or treat water may impact the services that we can provide to our customers.
Our water logistics operations involve the supply of significant amounts of water for drilling and hydraulic fracturing, treatment of produced and flowback water, and disposal of a variety of fluids. Limitations or restrictions on our ability to obtain water from local sources, such as restrictions that could be imposed during extreme drought conditions, may require us to find remote sources of water and transport that water to our service locations. In addition, treatment and disposal of such water after use is becoming more highly regulated and restricted. Thus, costs for obtaining, treating, and disposing of water could increase significantly, potentially limiting the services that we can provide to our customers. This could have an adverse effect on our business, financial condition, results of operations and cash flow.
Our ability to use net operating losses and credit carry-forwards to offset future taxable income for U.S. federal income tax purposes may be limited as a result of issuances of equity or other transactions.
In general, under Sections 382 and 383 of the Internal Revenue Code of 1986, as amended (the “Code”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to utilize its pre-change net operating losses (“NOLs”) and certain tax credits, to offset future taxable income and tax. In general, an ownership change occurs if the aggregate stock ownership of certain stockholders changes by more than 50 percentage points over such stockholders’ lowest percentage ownership during the testing period (generally three years). 
In connection with our emergence from our Chapter 11 Cases, we experienced an ownership change for the purposes of Section 382 of the Code.  The ownership changes have not resulted in the expiration or limitation of any NOLs generated prior to the emergence date.  However, any subsequent ownership changes under the provisions of Section 382 could adversely affect the use of NOLs in future periods.  The amount of consolidated Federal NOLs available as of December 31, 2018 is approximately $783.3 million.
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Recently enacted U.S. tax legislation, as well as future U.S. tax legislation, may adversely affect our business, results of operations, financial condition and cash flow.
The Tax Cuts and Jobs Act (the “Tax Act”) was enacted on December 22, 2017, which made significant changes to U.S. federal income tax laws. The Tax Act made broad and complex changes to the U.S. tax code which impact 2017 and 2018 and includes, among other things, reducing the U.S. corporate income tax rate to 21%, partially limits the deductibility of business interest expense and net operating losses, limits the deductibility for certain types of executive compensation, and allows the immediate deduction of certain new investments instead of deductions for depreciation expense over time.  Although we have estimated the impact of the Tax Act by incorporating assumptions based upon our current interpretation and analysis to date, the Tax Act is complex, far-reaching and is in a state of being clarified by regulation. Consequently, our analysis of the actual impact of its enactment on us is ongoing and subject to change as provisions of the Tax Act are clarified by regulation. Further analysis of the Tax Act could have an adverse effect on our business, results of operations, financial condition and cash flow.
Risks Relating to Ownership of Our Common Stock or Warrants
Our Second Amended and Restated Certificate of Incorporation and Second Amended and Restated 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 Second Amended and Restated 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 in our Second Amended and Restated Certificate of Incorporation and Second Amended and Restated 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. 
Our outstanding warrants are exercisable for shares of our common stock. The exercise of such equity instruments could have a dilutive effect to stockholders of the Company.
We currently have outstanding warrants that are exercisable into 2,066,576 shares of our common stock at an initial exercise price of $55.25 per warrant. The exercise of these warrants into our common stock could have a dilutive effect to the holdings of our existing stockholders. The warrants will not expire until December 23, 2023 and may create an overhang on the market for, and have a negative effect on the market price of, our common stock.
There is no guarantee that our outstanding warrants will become in the money, and unexercised warrants may expire worthless. Further, the terms of such warrants may be amended.
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As long as our stock price is below $55.25 per share, the warrants will have limited economic value, and they may expire worthless. In addition, the warrant agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least a certain percentage of the then-outstanding warrants originally issued to make any change that adversely affects the interests of the holders. Accordingly, we may amend the terms of the warrants in a manner adverse to a holder if holders of at least a certain percentage of the then outstanding warrants approve of such amendment.
Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, or the issuance of stock as consideration for a future acquisition, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.
Our Second Amended and Restated Certificate of Incorporation authorizes us to issue 80,000,000 shares of common stock, of which an estimated 26,906,690 shares of common stock were outstanding as of March 1, 2019. This number includes shares issued in connection with our emergence from bankruptcy, almost all of which are freely transferable without restriction or further registration pursuant to Section 1145 of the Bankruptcy Code. We also have 2,428,255 shares of common stock authorized for issuance as equity awards under the Basic Energy Services, Inc. Management Incentive Plan and Non-Employee Director Incentive Plan, respectively. As of March 1, 2019, 595,736 shares are issuable pursuant to outstanding options and 628,381 shares are issuable pursuant to outstanding restricted stock and restricted stock unit awards.
A large percentage of our shares of common stock are held by a relatively small number of investors. We entered into a registration rights agreement, (the “Registration Rights Agreement”) with certain of those investors pursuant to which we filed a registration statement with the SEC to facilitate potential future sales of such shares by them. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur, could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities and may adversely affect the trading price of our common stock.
We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.
We cannot predict the effect that future sales of our common stock will have on the price at which our common stock trades or the size of future issuances of our common stock or the effect, if any, that future issuances will have on the market price of our common stock. Sales of substantial amounts of our common stock, or the perception that such sales could occur, or the issuance of stock as consideration for a future acquisition may adversely affect the trading price of our common stock.
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 8. Commitments and Contingencies, 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.

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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

Market Information  
Our common stock trades on the New York Stock Exchange (the “NYSE”) under the symbol “BAS.” The stock began trading on the NYSE on December 27, 2016, in conjunction with our emergence from Chapter 11 proceedings. As of March 1, 2019, we had 26,906,690 shares of common stock outstanding held by approximately 120 record holders.
Dividend Policy
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 and rights authorized for issuance under our equity compensation plans as of December 31, 2018:  
Plan Category:Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (a) (2)
Weighted Average Exercise Price of Outstanding Options Warrants and Rights
(b)(3)
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding Securities Reflected in Column (a))
(c)(4)
Equity compensation plans approved by security holders (1) 2,475,579 $39.23 677,015 
Equity compensation plans not approved by security holders— — — 
Total2,475,579 $39.23 677,015 
  
(1) Represent shares of common stock issuable under the Basic Energy Services, Inc. Management Incentive Plan (the “MIP”), effective as of December 23, 2016.
(2) Includes 595,736 shares of common stock that may be issued upon the vesting of stock options and 1,879,843 shares that may be issued upon vesting of restricted stock units (“RSUs”).
(3) RSUs do not have an exercise price; accordingly, RSUs are excluded from the weighted average exercise price of outstanding awards.
(4) Represents the number of shares of common stock remaining available for grant under the MIP as of December 31, 2018. If any common stock underlying an unvested award is canceled, forfeited or is otherwise terminated without delivery of shares, then such shares will again be available for issuance under the MIP.
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Unregistered Sales of Equity Securities
None
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, 2018 and 2017(dollars in thousands, except average price paid per share):

 Issuer Purchases of Equity Securities
 Total Number ofAverage Price Paid
Period:Shares Purchased (1)Per Share
2017
October 1 - October 31— $— 
November 1 - November 30— — 
December 1 - December 31 (1)
84,222 23.71 
Total84,222 $23.71 
2018
October 1 - October 31— $— 
November 1 - November 30— — 
December 1 - December 31 (1)
30,949 4.16 
Total30,949 $4.16 

(1) “Total Number of Shares Purchased” 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 and RSUs owned by them. The shares were repurchased on various dates based on the closing price per share on the date of repurchase. The repurchased shares were issued under the MIP.

ITEM 6. SELECTED FINANCIAL DATA 

Not applicable.
 


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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, well servicing, water logistics and contract drilling. Our emergence from bankruptcy, and various market fluctuations, may make our revenues, expenses and income not directly comparable between periods. Our hydraulic horsepower capacity for pumping services increased from 443,600 at January 1, 2016 to 513,000 at December 31, 2018. Our weighted average number of fluid service trucks decreased from 985 in the first quarter of 2016 to 837 in the fourth quarter of 2018. Our weighted average number of well servicing rigs decreased from 421 in the first quarter of 2016 to 310 as of December 31, 2018, as we retired 111 rigs in the fourth quarter of 2017. Our weighted average number of drilling rigs decreased from 12 in the first quarter of 2016 to 11 in the fourth quarter of 2018.
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,
Revenues:20182017
    
Completion and remedial services$469.4 49%  $433.5 50%  
Well servicing251.0 26%  210.8 24%  
Water logistics231.3 24%  208.8 24%  
Contract drilling13.0 1%  11.0 2%  
Total revenues$964.7 100%  $864.1 100%  

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, and in turn, the market for our services. 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 water logistics, 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 dropped in the fourth quarter of 2014 and continued to decline throughout 2015 and stayed low all throughout 2016. Oil prices increased gradually in the fourth quarter of 2016 and throughout 2017, and have stayed relatively stable throughout most of 2018. Although oil prices declined towards the end of 2018 into 2019, we expect our customers capital programs to remain relatively steady during 2019.
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 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.


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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;
Well Servicing — rig hours, rig utilization rate, revenue per rig hour, profits per rig hour and segment profits as a percent of revenues;
Water Logistics — trucking hours, segment revenue, pipeline volumes 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.
Segment Overview
Completion and Remedial Services
In 2018, our completion and remedial services segment represented 49% 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, 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 513,000 horsepower at December 31, 2018 and 523,000 horsepower at December 31, 2017.
Our rental and fishing tool business operates 15 rental and fishing tool stores in selected markets as of December 31, 2018.  
Our snubbing services operate 32 units throughout our geographic footprint as of December 31, 2018.  
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 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, 2018 and 2017 (dollars in thousands):  
Completion & RemedialTotal HHPFrac HHPRevenuesSegment Profits %
2017
First Quarter443,320 356,900 $80,431 16%  
Second Quarter518,365 381,850 $107,386 24%  
Third Quarter522,565 413,300 $123,650 32%  
Fourth Quarter522,565 413,300 $121,983 30%  
Full Year522,565 413,300 $433,450 27%  
2018
First Quarter522,565 413,300 $117,597 24%  
Second Quarter516,465 407,800 $126,948 21%  
Third Quarter516,465 386,050 $115,978 21%  
Fourth Quarter513,000 386,050 $108,933 21%  
Full Year513,000 386,050 $469,456 22%  
We gauge the performance of our completion and remedial services segment based on the segment’s total horsepower, frac horsepower, operating revenues and segment profits as a percent of revenues.
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Well Servicing
In 2018, our well servicing segment represented 26% 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 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.

The following is an analysis of our well servicing segment for each of the quarters and years in the years ended December 31, 2018 and 2017. The revenue per rig hour does not include revenues associated with rig manufacturing operations:  
 Weighted Average RigRevenueProfits 
 Number ofRigUtilizationPer RigPer RigSegment
Well ServiceRigsHoursRateHourHourProfits %
2017 
First Quarter421 157,600 52%  $307 $49 16%  
Second Quarter421 162,300 54%  $321 $69 21%  
Third Quarter421 165,200 55%  $329 $69 21%  
Fourth Quarter421 159,500 53%  $339 $63 19%  
Full Year421 644,600 54%  $324 $63 19%  
2018         
First Quarter310 168,500 76%  $338 $55 16%  
Second Quarter310 181,600 82%  $348 $81 23%  
Third Quarter310 180,300 82%  $357 $67 18%  
Fourth Quarter310 159,600 72%  $368 $65 17%  
Full Year310 690,000 78%  $353 $68 19%  
On December 31, 2017, we classified 111 rigs from our current fleet as "cold-stacked", reducing our total active rig fleet to 310 rigs, and removed these rigs from the active rig count. These cold-stacked rigs will ultimately be retired and disposed of in an orderly fashion.
We gauge activity levels and profitability 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.
Water Logistics
In 2018, our water logistics segment represented 24% of our revenues. Revenues in our water logistics segment are earned from the sale, transportation, pipelining, 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 water logistics segment has a base level of business consisting of transporting and disposing of saltwater 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 water logistics segment. Water logistics 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 water logistics 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
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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.
The following is an analysis of our water logistics segment for each of the quarters and years in the years ended December 31, 2018 and 2017 (dollars in thousands):
 
 Weighted Average TruckingPipeline 
 Number of FluidTruckVolumesVolumesSegment
Water LogisticsService TrucksHours(in bbls)(in bbls)RevenueProfits %
2017 
First Quarter935 484,300 6,489,700 1,609,000 $50,206 17%  
Second Quarter943 473,500 7,233,100 1,191,000 $50,740 18%  
Third Quarter947 483,300 7,067,900 1,560,000 $52,333 21%  
Fourth Quarter967 492,800 7,348,400 1,921,000 $55,505 20%  
Full Year948 1,933,900 28,139,100 6,281,000 $208,784 19%  
2018        
First Quarter960 479,600 6,414,800 1,551,000 $56,509 28%  
Second Quarter903 486,800 6,912,900 2,064,000 $59,679 26%  
Third Quarter870 448,200 6,898,200 2,526,000 $59,539 28%  
Fourth Quarter837 438,500 6,659,000 3,221,000 $55,556 29%  
Full Year891 1,853,100 26,884,900 9,362,000 $231,283 28%  
We gauge activity levels and profitability in our water logistics segment based on trucking hours, revenue per fluid service truck, segment profits per fluid service truck and segment profits as a percent of revenues.
Contract Drilling
In 2018, our contract drilling segment represented 1% 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.
The following is an analysis of our contract drilling segment for each of the quarters and years in the years ended December 31, 2018 and 2017:  
 Weighted AverageRig Profits 
 NumberOperatingRevenue(Loss)Segment
Contract Drillingof RigsDaysPer DayPer DayProfits %
2017 
First Quarter12 135 $20,500 $2,600 12%  
Second Quarter11 91 $23,300 $2,800 12%  
Third Quarter11 92 $31,000 $3,300 11%  
Fourth Quarter11 139 $23,500 $2,500 11%  
Full Year11 457 $24,100 $2,800 11%  
2018        
First Quarter11 175 $17,300 $2,700 16%  
Second Quarter11 91 $25,700 $6,500 25%  
Third Quarter11 129 $27,700 $6,500 24%  
Fourth Quarter11 184 $22,100 $4,800 23%  
Full Year11 579 $22,400 $4,900 22%  
We gauge activity levels and profitability 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.

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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.
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 2018 and 2017.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Revenues.    Revenues increased by 12% to $964.7 million in 2018 from $864.0 million in 2017. This increase was primarily due to an increase in crude oil prices resulting in higher demand for our services by our customers, particularly from our well servicing and completion and remedial services segment.
Completion and remedial services revenue increased by 8% to $469.5 million in 2018 as compared to $433.5 million in 2017. The increase in revenue between these periods was primarily due to improved rental tool and fracturing revenues driven by the overall increase in new well completion activity, as well as pricing improvements. Total hydraulic horsepower was approximately 513,000 at December 31, 2018 and 523,000 at December 31, 2017.
Well servicing revenues increased by 19% to $251.0 million in 2018 compared to $210.8 million in 2017. Rig utilization increased to 78% in 2018 from 54% during 2017 (73% based on our current fleet), reflecting pricing improvements in oil-dominated operating areas. Our weighted average number of well servicing rigs decreased to 310 in 2018 down from 421 during 2017, as we classified 111 rigs from our current fleet as "cold-stacked" on December 31, 2017. We experienced an increase of 9% in revenue per rig hour to $353 during 2018 from $324 during 2017, due to pricing improvements driven by increased activity levels particularly in our 24-hour rig work.
Water logistics revenue increased by 11% to $231.3 million in 2018 compared to $208.8 million in 2017.  This increase was mainly due to an increases in pipeline disposal volumes and pricing for our services. Pipeline disposal volumes increased 49% to 9.4 million in 2018 compared to 6.3 million in 2017, due to increased disposal activities and improved pricing. Our weighted average number of fluid service trucks decreased to 891 in 2018 from 948 in 2017.
Contract drilling revenues increased by 18% to $13.0 million in 2018 compared to $11.0 million in 2017. The increase was driven by an increase rig operating days. The number of rig operating days increased to 579 in 2018 compared to 457 in 2017.  The average revenue per rig day decreased to $22,400 in 2018 from $24,100 in 2017, due to continued competitive pricing pressures in 2018.
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 12% to $746.4 million in 2018 from $666.5 million in 2017. This increase was due to the improved activity levels in all our segments.
Direct operating expenses for the completion and remedial services segment increased by 15% to $365.8 million in 2018 as compared to $318.2 million in 2017, due primarily to increased activity levels and headcount. Segment profits decreased to 22% of revenues in 2018 compared to 27% in 2017, due to pricing pressures and increased input costs.
Direct operating expenses for the well servicing segment increased by 20% to $203.6 million in 2018 as compared to $169.9 million in 2017, due primarily to increased personnel costs and improved demand for our services. Segment profits remained constant at 19% of revenues in 2018  and 2017.
Direct operating expenses for the water logistics segment decreased by 1% to $166.9 million in 2018 as compared to $168.6 million in 2017. Segment profits increased to 28% of revenues in 2018 from 19% of revenues in 2017, due to incremental margins from an increase in higher margin pipeline disposal revenue.
Direct operating expenses for the contract drilling segment increased by 4% to $10.1 million in 2018 as compared to $9.7 million in 2017, driven by an increase in activity driven by an increase in the North American on-shore drilling rig count. Segment profits were 22% of revenues in 2018 compared to 11% in 2017, due to an increase in working days.
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General and Administrative Expenses.    General and administrative expenses increased by 14% to $167.5 million in 2018 from $146.5 million in 2017. The increase was due to $9.7 million of higher payroll-related costs due to an increase in workforce in 2018, and an increase of $4.3 million in stock-based compensation expense, which increased to $27.3 million in 2018 compared to $23.0 million in 2017. In addition, we incurred costs related our Texas Sales and Use Tax audit liability totaling $6.0 million, bad debt related to a single customer of $3.1 million, and consulting fees related to our strategic realignment of approximately $4.1 million. General and administrative expense in 2017 also included legal and professional fees related to due diligence on corporate development activities of $4.2 million.
Depreciation and Amortization Expenses.    Depreciation and amortization expenses were $126.4 million in 2018, as compared to $112.2 million in 2017. The increase in depreciation and amortization expense is due to capital additions. During 2018, we invested $67.3 million for cash capital expenditures and $20.2 million for capital leases.
Interest Expense.    Interest expense increased to $45.9 million in 2018 compared to $37.5 million in 2017.  The increase in interest expense in 2018 was primarily due to the waiver fees paid during the year and interest on a higher outstanding balance under our credit facility.
Extinguishment of Debt.    Extinguishment of debt expense related to the pay-down of our Term Loan facility and revolving debt totaled $26.4 million in 2018. Expenses included $17.6 million of make whole premium, $7.4 million of accelerated amortization of discount related to our Term Loan and $1.4 million accelerated amortization of debt costs related to our revolving debt.
Income Tax Benefit (Expense).    Income tax expense was $0.2 million in 2018 compared to an income tax benefit of $1.7 million in  2017. Our effective tax expense rate was approximately 0.15% in 2018 compared to an effective tax benefit rate of 1.7% in 2017.
Liquidity and Capital Resources
As of December 31, 2018, our primary capital resources were cash on hand, cash flows from operations, utilization of capital leases and the ability to borrow under our $150 million Credit Facility (the “New ABL Facility”). As of December 31, 2018, we had no borrowings under the New ABL Facility. Including the $ 69.6 million of availability under the New ABL Facility, we currently have $159.9 million in total liquidity. At December 31, 2018, we had unrestricted cash and cash equivalents of $90.3 million compared to $38.5 million as of December 31, 2017. An additional amount of $47.7 million was classified as restricted cash at December 31, 2017.  
On October 2, 2018, the Company issued $300 million aggregate principal amount of 10.75% senior secured notes due 2023 and replaced the Prior ABL Facility by entering into a $150.0 million ABL Credit Agreement among the Company, as borrower, Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer, UBS Securities LLC, as syndication agent, PNC Bank National Association, as documentation agent and letter of credit issuer, and the other lenders from time to time party thereto.
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. The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. This assumes the Company will be able to realize its assets and discharge its liabilities in the normal course of business.
Net Cash Provided by Operating Activities
Cash flow provided by operating activities was $74.3 million for the year ended December 31, 2018, as compared to cash provided by operations of $25.9 million in 2017.  The increase in 2018 was due primarily to stronger operating results and working capital levels.   
Capital Expenditures
Capital expenditures are the main component of our investing activities. Cash capital expenditures for 2018 were $68.7 million, of which $6.5 million was accrued capital expenditures as compared to $63.4 million in 2017.  Cash capital expenditures increased in 2018 from 2017 due to an increase in maintenance capital expenditures arising from increased utilization. Through our capital lease program, we also added assets of approximately $20.2 million and $67.5 million  in 2018 and 2017, respectively.
In 2019, we have planned capital expenditures of approximately $94.1 million including capital leases of $15.6 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.
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Capital Resources and Financing
Our current primary capital resources are cash flow from our operations, availability under our $150.0 million New ABL Facility, the ability to enter into capital leases, the ability to incur additional secured indebtedness, and a cash balance of $90.3 million at December 31, 2018. We had no borrowings under our New ABL Facility. We had $69.6 million of available borrowing capacity at December 31, 2018. We financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases. See “New ABL Facility” and “Amended Restated Term Loan Agreement” below.
On October 2, 2018, the Company issued $300.0 million aggregate principal amount of 10.75% senior secured notes due October 2023 (the “Senior Notes”) in an offering exempt from registration under the Securities Act. The Senior Notes were issued at a price of 99.042% of par to yield 11.0%. The Senior Notes are secured by a first-priority lien on substantially all of the assets of the Company and the subsidiary guarantors other than accounts receivable, inventory and certain related assets. Net proceeds from the offering of approximately $290.0 million were used to repay the Company’s existing indebtedness under the Amended and Restated Term Loan Agreement, to repay the Company’s outstanding borrowings under the Prior ABL Facility, and for general corporate purposes.
Indenture
The Company’s Senior Notes were issued under and are governed by an indenture, dated as of October 2, 2018 (the “Indenture”), by and among the Company, the guarantors named therein (the “Guarantors”), and UMB Bank, N.A. as Trustee and Collateral Agent (the “Trustee”). The Senior Notes are jointly and severally, fully and unconditionally guaranteed (the “Guarantees”) on a senior secured basis by the Guarantors and are secured by first priority liens on substantially all of the Company’s and the Guarantors’ assets, other than accounts receivable, inventory and certain related assets.
The Indenture contains covenants that limit the ability of the Company and certain subsidiaries to:
incur additional indebtedness or issue preferred stock;
pay dividends or make other distributions to our stockholders;
repurchase or redeem capital stock or subordinated indebtedness and certain refinancings thereof;
make certain investments;
incur liens;
enter into certain types of transactions with affiliates;
limit dividends or other payments by restricted subsidiaries to the Company; and
sell assets or consolidate or merge with or into other companies.
These limitations are subject to a number of important qualifications and exceptions.
Upon an Event of Default (as defined in the Indenture), the Trustee or the holders of at least 25% in aggregate principal amount of the outstanding Senior Notes may declare the entire principal of, premium, if any, and accrued and unpaid interest, if any, on all the Senior Notes to be due and payable immediately.
At any time on or prior to October 15, 2020, the Company may redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 110.750% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, with an amount of cash not greater than the net proceeds from certain equity offerings. At any time prior to October 15, 2020, the Company may redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Notes plus a “make-whole” premium plus accrued and unpaid interest, if any, to the redemption date. The Company may also redeem all or a part of the Senior Notes at any time on or after October 15, 2020, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest, if any, to the redemption date.
The Company may redeem all, but not less than all, of the Senior Notes in connection with a company sale transaction, at a redemption price of 105.375% of principal for a company sale that occurs on or after April 15, 2019 and on or before October 15, 2019, or 108.063% of principal amount for a company sale that occurs after October 15, 2019 and before October 15, 2020, in each case plus accrued and unpaid interest, if any, to the redemption date. If the Company experiences a change of control, the Company may be required to offer to purchase the Senior Notes at a purchase price equal to 101% of the principal amount, plus accrued and unpaid interest, if any, to the purchase date.
The Senior Notes and the Guarantees rank equally in right of payment with all of the Company’s and the Guarantors’ existing and future unsubordinated indebtedness, effectively senior to all of the Company’s and the Guarantors’ existing and future indebtedness to the extent of the value of the collateral securing the Senior Notes but junior to other indebtedness that is secured by liens on assets other than collateral for the Senior Notes to the extent of the value of such assets, and senior to