UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Form 10-K

 

 

Commission file number 001-32693

 

 

 

 

Basic Energy Services, Inc.

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:

(432) 620-5500

 

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

 

 

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

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     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 o     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 o

 

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

 

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.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

(Do not check if a smaller reporting company)

 

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

 

The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was approximately $121,143,061 as of June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter (based on a closing price of $7.70 per share and 15,732,865 shares held by non-affiliates).

 

There were 41,598,958 shares of the registrant’s common stock outstanding as of February 18, 2011.

 

Documents incorporated by reference:  Portions of the definitive 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

 

CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

 

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends affecting the financial condition of our business. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including, among other things, the risk factors discussed in Item 1A of this annual report and other factors, most of which are beyond our control.

 

The words “believe,” “estimate,” “expect,” “anticipate,” “project,” “intend,” “plan,” “seek,” “could,” “should,” “may,” “potential” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this annual report are forward looking-statements. Although we believe that the forward-looking statements contained in this annual report are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this annual report may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.

 

Important factors that may affect our expectations, estimates or projections include:

 

 

Our forward-looking statements speak only as of the date of this annual report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

This annual report includes market share data, industry data and forecasts that we obtained from internal company surveys (including estimates based on our knowledge and experience in the industry in which we operate), market research, consultant surveys, publicly available information, industry publications and surveys. These sources include Baker Hughes Incorporated, the Association of Energy Service Companies (“AESC”), and the Energy Information Administration of the U.S. Department of Energy (“EIA”). Industry surveys and publications, consultant surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable. Although we believe such information is accurate and reliable, we have not independently verified any of the data from third party sources cited or used for our management’s industry estimates, nor have we ascertained the underlying economic assumptions relied upon therein. For example, the number of onshore well servicing rigs in the U.S. could be lower than our estimate to the extent our two larger competitors have continued to report as stacked rigs equipment that is not actually complete or subject to refurbishment. Statements as to our position relative to our competitors or as to market share refer to the most recent available data.

 

General

 

We provide a wide range of well site services to oil and natural gas drilling and producing companies, including completion and remedial services, fluid services, well servicing and contract drilling. 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. Our operations are managed regionally and are concentrated in major United States onshore oil and natural gas producing regions located in Texas, New Mexico, Oklahoma, Arkansas, Kansas, Louisiana, Wyoming, North Dakota, Colorado, Utah, Montana, West Virginia and Pennsylvania. Our operations are focused on liquid rich basins that currently exhibit strong drilling and production economics as well as natural gas-focused shale plays characterized by prolific reserves and attractive economics. Specifically, we have a significant presence in the Permian Basin and the Bakken, Eagle Ford, Haynesville and Marcellus shales. We provide our services to a diverse group of over 2,000 oil and gas companies.

 

We revised our business segments beginning in the first quarter of 2008, and in connection therewith restated the corresponding items of segment information for earlier periods. Our current operating segments are Completion and Remedial Services, Fluid Services, Well Servicing, and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services has been consolidated with our Fluid Services segment. The following is a description of our current business segments:

 

 

Financial information about our segments is included in Note 15 of the notes to our historical consolidated financial statements.

Our Competitive Strengths

 

We believe that the following competitive strengths currently position us well within our industry:

 

Significant Market Position.  We maintain a significant market share for our well servicing operations in our core operating areas throughout Texas and a growing market share in the other markets that we serve. Our fleet of 412 well servicing rigs as of December 31, 2010 represents the third largest fleet in the United States, and our goal is to be one of the top two providers of well site services in each of our core operating areas. Our market position allows us to expand the range of services performed on a well throughout its life, such as drilling, maintenance, workover, completion and plugging and abandonment services.

 

Modern and Active Well Servicing Fleet.  We operate a modern and active fleet of well servicing rigs. We believe over 75% of the active U.S. well servicing rig fleet was built prior to 1985. Greater than 50% of our rigs at December 31, 2010 were either 2000 model year or newer, or have undergone major refurbishments during the last five years. Driven by our desire to maintain one of the most efficient, reliable and safest fleets in the industry, we took delivery of our final two newbuild well service rigs during 2009 as part of a 134-rig newbuild commitment which started in October 2004. In addition to our regular maintenance program, we have an established program to routinely monitor and evaluate the condition of our fleet. We selectively refurbish rigs and other assets to maintain the quality of our service and to provide a safe work environment for our personnel and have made major refurbishments on 68 of our rigs since the beginning of 2006. Since 2003, we have obtained annual independent reviews and evaluations of substantially all of our assets, which confirmed the location and condition of these assets. We believe that by maintaining a modern and active fleet, we are better able to earn our customers’ business while reducing risk of unplanned downtime.

 

Extensive Domestic Footprint in the Most Prolific Basins.  Our operations are focused on liquids rich basins that currently exhibit strong drilling and production economics as well as natural gas-focused shale plays characterized by prolific reserves and attractive economics. Specifically, we have a significant presence in the Permian Basin and the Bakken, Eagle Ford, Haynesville and Marcellus shales. Based on the most recent publicly available information, we operate in states that accounted for approximately 78% of the approximately 800,000 existing onshore oil and natural gas wells in the 48 contiguous states and approximately 79% of onshore oil production and 91% of onshore natural gas production. We believe that our operations are located in the most active U.S. well services markets, as we currently focus our operations on onshore domestic oil and natural gas production areas that include both the highest concentration of existing oil and natural gas production activities and the largest prospective acreage for new drilling activity. We believe our extensive footprint allows us to offer our suite of services to more than 2,000 customers who are active in those areas and allows us to redeploy equipment between markets as activity shifts, reducing the risk that a basin-specific slowdown will have a disproportionate impact on our cash flows and operational results.

 

Diversified Service Offering for Further Revenue Growth and Reduced Volatility.  We believe our range of well site services provides us a competitive advantage over smaller companies that typically offer fewer services. Our experience, equipment and network of 119 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.

 

Decentralized Experienced Management with Strong Corporate Infrastructure.  Our corporate group is responsible for maintaining a unified infrastructure to support our diversified operations through standardized financial and accounting, safety, environmental and maintenance processes and controls. Below our corporate level, we operate a decentralized operational organization in which our ten regional or division managers are responsible for their operations, including asset management, cost control, policy compliance and training and other aspects of quality control. With an average of over 30 years of industry experience, each regional manager has extensive knowledge of the customer base, job requirements and working conditions in each local market. Below our ten regional or division managers, our area managers are directly responsible for customer relationships, personnel management, accident prevention and equipment maintenance, the key drivers of our operating profitability. This

management structure allows us to monitor operating performance on a daily basis, maintain financial, accounting and asset management controls, integrate acquisitions, prepare timely financial reports and manage contractual risk.

 

Our Business Strategy

 

The key components of our business strategy include:

 

Establishing and Maintaining Leadership Positions in Core Operating Areas.  We strive to establish and maintain market leadership positions within our core operating areas. To achieve this goal, we maintain close customer relationships, seek to expand the breadth of our services and offer high quality services and equipment that meet the scope of customer specifications and requirements. In addition, our significant presence in our core operating areas facilitates employee retention and attraction, a key factor for success in our business. Our significant presence in our core operating areas also provides us with brand recognition that we intend to utilize in creating leading positions in new operating areas.

 

Selectively Expanding Within Our Regional Markets.  We intend to continue strengthening our presence within our existing geographic footprint through internal growth and acquisitions of businesses with strong customer relationships, well-maintained equipment and experienced and skilled personnel. We typically enter into new markets through the acquisition of businesses with strong management teams that will allow us to expand within these markets. Management of acquired companies often remain with us and retain key positions within our organization, which enhances our attractiveness as an acquisition partner. We have a record of successfully implementing this strategy. By concentrating on targeted expansion in areas in which we already have a meaningful presence, we believe we maximize the returns on expansion capital while reducing downside risk.

 

Developing Additional Service Offerings Within the Well Servicing Market.  We intend to continue broadening the portfolio of services we provide to our clients by utilizing our well servicing infrastructure. A customer typically begins a new maintenance or workover project by securing access to a well servicing rig, which generally stays on site for the duration of the project. As a result, our rigs are often the first equipment to arrive at the well site and typically the last to leave, providing us the opportunity to offer our customers other complementary services. We believe the fragmented nature of the well servicing market creates an opportunity to sell more services to our core customers and to expand our total service offering within each of our markets. We have expanded our suite of services available to our customers and increased our opportunities to cross-sell new services to our core well servicing customers through acquisitions and internal growth. In connection with the acquisition of Taylor Rig, LLC, a rig manufacturing business operating in our well servicing segment, in the second quarter of 2010, we added a rig manufacturing and service facility that builds new workover rigs, performs large-scale refurbishments of used workover rigs and provides maintenance services on previously manufactured rigs. We expect to continue to develop or selectively acquire capabilities to provide additional services to expand and further strengthen our customer relationships.

 

Pursuing Growth Through Selective Capital Deployment.  We intend to continue growing our business through selective acquisitions, continuing a newbuild program and/or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed of each of those alternatives. Acquisitions are evaluated for “fit” with our area and regional operations management and are thoroughly reviewed by corporate level financial, equipment, safety and environmental specialists to ensure consideration is given to identified risks. We also evaluate the cost to acquire existing assets from a third party, the capital required to build new equipment and the point in the oil and natural gas commodity price cycle. Based on these factors, we make 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

 

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, which in turn is affected by current and expected levels of oil and natural gas prices. As oil and natural gas prices increased from 2006 through most of 2008, oil and gas companies increased their drilling and workover activities. In the last part of 2008, oil and natural gas prices declined rapidly, resulting in decreased drilling and workover activities. During the second

half of 2009, oil prices began to increase and remained relatively stable through the latter half of 2010, which resulted in increases in drilling, maintenance and workover activities in the oil-driven markets during this period. However, natural gas prices continued to decline significantly through most of 2009 and remained depressed throughout 2010, which resulted in decreased activity in the natural gas-driven markets. Despite natural gas prices remaining below the levels seen in recent years, several markets that produce significant natural gas liquids, such as the Eagle Ford shale, and/or that have other advantages like proximity to key consuming markets, such as the Marcellus shale, have continued to see increased activity.

 

The table below sets forth average closing prices for the Cushing WTI Spot Oil Price and the EIA average wellhead price for natural gas since 2006. The December 2010 average wellhead price for natural gas was not available at the time this report was filed; therefore the average price through November 2010 was used:

 

 

 

 

Source: U.S. Department of Energy.

 

Increased expenditures for exploration and production activities generally drives the increased demand for our services. Rising oil and natural gas prices from 2006 through the first half of 2008 and the corresponding increase in onshore oil exploration and production spending led to expanded drilling and well service activity, as the U.S. land-based drilling rig count increased approximately 4% during 2007. With the rapid decline in oil and natural gas prices in the second half of 2008 there was a decrease in the land-based drilling rig count of approximately 3% during 2008 and 31% during 2009. In 2010 the land based drilling rig count increased approximately 45%, according to Baker Hughes. The increase in oil prices in the past year resulted in both higher utilization of those rigs and increases in the rates being charged.

 

Exploration and production spending is generally 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.

 

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.

 

Our business is influenced substantially by both operating and capital expenditures by oil and gas companies. 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 are 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.

 

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:

 

 

This segment currently operates 147 pressure pumping units, with approximately 142,000 of horsepower 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. As of December 31, 2010, we also operated 40 air compressor packages, including foam circulation units, for underbalanced drilling, 12 wireline units for cased-hole measurement and pipe recovery services and 25 snubbing units.

 

Just as a well servicing rig is required to perform various operations over the life cycle of a well, there is a similar need for equipment capable of pumping fluids into the well under varying degrees of pressure. During the drilling and completion phase, the well bore is lined with large diameter steel pipe called casing. Casing is cemented into place by circulating slurry into the annulus created between the pipe and the rock wall of the well bore. The cement slurry is forced into the well by pressure pumping equipment located on the surface. Cementing services are also utilized over the life of a well to repair leaks in the casing, to close perforations that are no longer productive and ultimately to “plug” the well at the end of its productive life.

 

A hydrocarbon reservoir is essentially an interval of rock that is saturated with oil and/or natural gas, usually in combination with water. Three primary factors determine the productivity of a well that intersects a hydrocarbon reservoir: porosity (the percentage of the reservoir volume represented by pore space in which the hydrocarbons reside), permeability (the natural propensity for the flow of hydrocarbons toward the well bore), and “skin” (the degree to which the portion of the reservoir in close proximity to the well bore has experienced reduced permeability as a result of exposure to drilling fluids or other contaminants). Well productivity can be increased by artificially improving either permeability or skin through stimulation methods described below.

 

Permeability can be increased through the use of fracturing methods by which a reservoir is subjected to fluids pumped into it under high pressure. This pressure creates stress in the reservoir and causes the rock to fracture, thereby creating additional channels through which hydrocarbons can flow. In most cases, sand or another form of proppant is pumped with the fluid as a means of holding open the newly created fractures.

 

The most common means of reducing near-well bore damage, or skin, is the injection of a highly reactive solvent (such as hydrochloric acid) solution into the area where the hydrocarbons enter the well. This solution has the effect of dissolving contaminants that have accumulated and are restricting the flow of hydrocarbons. This process is generically known as acidizing.

 

After a well is drilled and completed, the casing may develop leaks as a result of abrasions from production tubing, exposure to corrosive elements or inadequate support from the original attempt to cement the casing in place. When a leak develops, it is necessary to place specialized equipment into the well and to pump cement in such a way as to seal the leak, a process known as “squeeze” cementing.

The following table sets forth the type, number and location of the completion and remedial services equipment that we operated at December 31, 2010:

 

 

Our pumping services business focuses primarily on lower horsepower cementing, acidizing and fracturing services markets. Currently, there are several pressure 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 pressure 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. One of our major well servicing competitors also participates in the pressure pumping business, but primarily outside our core areas of operations for pumping services.

 

The level of activity of our pumping services business is tied to drilling and workover activity. The bulk of pressure 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. Pressure pumping 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.

 

Snubbing is the act of putting drill pipe into the wellbore when the blowout preventors are closed and pressure is contained in the well. Due to the large rigup, it is only used for the most demanding of operations when lighter intervention techniques do not offer the strength and durability. Unlike conventional drilling and completions operations, snubbing can be performed with the well still under pressure.

 

Cased-hole wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of a cased wellbore. These tools can be used to measure pressures and temperature as well as the condition of the casing and the cement that holds the casing in place. Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, or perforating the casing and cutting off pipe that is stuck in the well so that the free section can be recovered. Electric wireline contains a conduit that allows signals to be transmitted to or from tools located in the well. A simpler form of wireline, slickline, lacks an electrical conduit and is used only to perform mechanical tasks such as setting or retrieving various tools. Wireline trucks are often used in place of a well servicing rig when there is no

requirement to remove tubulars from the well in order to make repairs. Wireline trucks, like well servicing rigs, are utilized throughout the life of a well.

 

Unlike pressure pumping and wireline services, underbalanced drilling services are not utilized universally throughout oil and natural gas operations. Underbalanced drilling is a technique that involves maintaining the pressure in a well at or slightly below that of the surrounding formation using air, nitrogen, mist, foam or lightweight drilling fluids instead of conventional drilling fluid. The most common method of reducing the weight of drilling fluid is to mix it with air as the fluid is pumped into the well. By varying the volume of air pumped with the fluid, the net hydrostatic pressure can be adjusted to the desired level. In extreme cases, air alone can be used to circulate rock cuttings from the well.

 

Fluid Services Segment

 

Our fluid services segment provides oilfield fluid supply, transportation, storage and construction services. These services are required in most workover, completion and remedial projects and are routinely used in daily producing well operations. These services include:

 

 

This segment utilizes our fleet of fluid service trucks and related assets, including specialized tank trucks, portable storage tanks, water wells, disposal facilities and related equipment. The following table sets forth the type, number and location of the fluid services equipment that we operated at December 31, 2010:

 

 

Requirements for minor or incidental fluid services are usually purchased on a “call out” basis and charged according to a published schedule of rates. Larger projects, such as servicing the requirements of a multi-well drilling program or frac 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 and disposal services required on most workover, completion and remedial projects. Our breadth of capabilities in this segment allows us to serve as a one-stop source of equipment and services for our customers. Many of our smaller competitors in this segment can provide some, but not all, of the equipment and services required by oil and gas operators, requiring them to use several companies to meet their requirements and increasing their administrative burden.

 

Our fluid services segment has a base level of business volume related to the regular maintenance of oil and natural gas wells. Most oil and natural gas fields produce residual salt water in conjunction with oil or natural gas. Fluid service trucks pick up this fluid from tank batteries at the well site and transport it to a salt water disposal well for injection. This type of regular maintenance work must be performed if a well is to remain active. Transportation and disposal of produced water is considered a low value service by most operators, and it is difficult for us to command a premium over rates charged by our competition. Our ability to outperform competitors in this segment depends on our ability to achieve significant economies relating to logistics, specifically the proximity between the

areas where salt water is produced and the areas where our company-owned disposal wells are located. We operate salt water disposal wells in most of our markets, and our ownership of these disposal wells eliminates the need to pay third parties a fee for disposal.

 

Workover, completion and remedial activities also provide the opportunity for higher operating margins from tank rentals and fluid sales. Drilling and workover jobs typically require fresh or brine water for drilling mud or circulating fluid used during the job. Completion and workover procedures often also require large volumes of water for fracturing operations, which involves stimulating a well hydraulically to increase production. Spent mud and flowback fluids from drilling and completion activities are required to be transported from the well site to an approved disposal facility.

 

Our competitors in the fluid services industry are mostly small, regionally focused companies. There are currently no companies that have a dominant position on a nationwide basis. The level of activity in the fluid services industry is comprised of a relatively stable demand for services related to the maintenance of producing wells and a highly variable demand for services used in the drilling and completion of new wells. As a result, the level of onshore drilling activity significantly affects the level of activity in the fluid services industry. While there are no industry-wide statistics, the Baker Hughes Land Drilling Rig Count is an indirect indication of demand for fluid services because it directly reflects the level of onshore drilling activity.

 

Fluid Services.  We currently own and operate 800 fluid service trucks equipped with a fluid hauling capacity of up to 150 barrels. 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 is also used to transport water to fill frac tanks on well locations, including frac tanks provided by us and others, to transport produced salt water to disposal wells, including injection wells owned and operated by us, and to transport drilling and completion fluids to and from well locations. In conjunction with the rental of our frac tanks, we generally 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 generally provided to oilfield operators within a 50-mile radius of our nearest yard.

 

Salt Water Disposal Well Services.  We own disposal wells that are permitted to dispose of salt water and incidental non-hazardous oil and natural gas wastes. Our fluid service trucks frequently transport the fluids that are disposed of in these salt water disposal wells. Our disposal wells have an average permitted injection capacity of over 6,000 barrels per day per well and are strategically located in close proximity to our customers’ producing wells. Most oil and natural gas wells produce varying amounts of salt water throughout their productive lives. In the states in which we operate, oil and natural gas wastes and salt water produced from oil and natural gas wells are required by law to be disposed of in authorized facilities, including permitted salt water disposal wells. Injection wells are licensed by state authorities and are completed in permeable formations below the fresh water table. We maintain separators at most of our disposal wells, allowing us to salvage residual crude oil that we later sell for our account.

 

Fresh and Brine Water Stations.  Our network of fresh and brine water stations, particularly in the Permian Basin where surface water is generally not available, is used to supply water necessary for the drilling and completion of oil and natural gas wells. Our strategic locations, in combination with our other fluid handling services, give us a competitive advantage over other service providers in those areas in which these other companies cannot provide these services.

 

Fluid Storage Tanks.  Our fluid storage tanks can store up to 500 barrels of fluid and are used by oilfield operators to store various fluids at the well site, including fresh water, brine and acid for frac jobs, flowback, temporary production and mud storage. We transport the tanks on our trucks to well locations that are usually within a 50-mile radius of our nearest yard. Frac tanks are used during all phases of the life of a producing well. We generally rent fluid services tanks at daily rates for a minimum of three days. A typical fracturing operation can be completed within four days using 5 to 50 frac tanks.

 

Construction Services.  We utilize a fleet of power units, including dozers, trenchers, motor graders, backhoes and other heavy equipment used in road construction. In addition, we own rock pits in some markets in our Rocky Mountain operations to ensure a reliable source of rock to support our construction activities.

Contracts for well site construction services are normally awarded by our customers on the basis of competitive bidding and may range in scope from several days to several months in duration.

 

Well Servicing Segment

 

Our well servicing segment encompasses a full range of services performed with a mobile well servicing rig, also commonly referred to as a workover rig, and ancillary equipment. Our rigs and personnel provide the means for hoisting equipment and tools into and out of the well bore, and our well servicing equipment and capabilities also facilitate most other services performed on a well. Our well servicing segment services, which are performed to maintain and improve production throughout the productive life of an oil and natural gas well, include:

 

 

Our well servicing segment also includes the manufacturing and sale of new workover rigs through our wholly-owned subsidiary, Taylor Industries, LLC, which we formed in connection with the acquisition of a rig manufacturing business in the second quarter of 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 generally charge our customers an hourly rate for these services, which rate varies based on a number of considerations including market conditions in each region, the type of rig and ancillary equipment required, and the necessary personnel.

 

Our fleet included 412 well servicing rigs as of December 31, 2010, including 135 newbuilds since October 2004 and 68 rebuilds since the beginning of 2006. Our well servicing rigs operate from facilities in Texas, Wyoming, Oklahoma, North Dakota, New Mexico, Louisiana, Colorado, Arkansas, Utah, Montana, Pennsylvania and West Virginia. Our well servicing rigs are mobile units that generally operate within a radius of approximately 75 to 100 miles from their respective bases. The majority of our well servicing segment consists of land-based equipment. We also own four inland well servicing barges. Inland barges are used to service wells in shallow water marine environments, such as coastal marshes and bays.

 

The following table sets forth the location, characteristics and number of the well servicing rigs that we operated at December 31, 2010. 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.

 

 

We operate a total of 412 well servicing rigs, the third largest fleet in the United States. Based on the most recent publicly available information, Key Energy Services is our largest competitor, with an estimated total of 787 domestic rigs and Nabors is our second largest competitor, with an estimated 556 domestic rigs. Our only other competitors operating more than 100 rigs are Complete Production Services, with an estimated 272 domestic rigs

and Forbes Energy Services with an estimated 173 domestic rigs. Excluding the rigs operated by Nabors in California where we do not compete, we believe we have the second largest rig fleet in the United States.

 

The total number of rigs owned by us and the four other companies referenced above is approximately 2,200, or 70% of the available fleet owned by member companies of the AESC, the major trade association of well site service providers. The remaining 30% of the well servicing rigs are owned by more than 100 local and regional companies. The December 2010 monthly activity survey conducted by the AESC indicated that 63% of the rigs owned were active.

 

Maintenance.  Regular maintenance is generally required throughout the life of a well to sustain optimal levels of oil and natural gas production. Regular maintenance currently comprises the largest portion of our work in this segment and because ongoing maintenance spending is required to sustain production, we generally experience relatively stable demand for these services. We provide well service rigs, equipment and crews to our customers for these maintenance services. Maintenance services are often performed on a series of wells in proximity to each other and consist of routine mechanical repairs necessary to maintain production, such as repairing inoperable pumping equipment in an oil well or replacing defective tubing in a natural gas well, and removing debris such as sand and paraffin from the well. Other services include pulling the rods, tubing, pumps and other downhole equipment out of the well bore to identify and repair a production problem. These downhole equipment failures are typically caused by the repetitive pumping action of an oil well. Corrosion, water cut, grade of oil, sand production and other factors can also result in frequent failures of downhole equipment.

 

The need for maintenance activity does not directly depend on the level of drilling activity, although it is somewhat impacted by short-term fluctuations in oil and natural gas prices. Demand for our maintenance services is driven primarily by the production requirements of local oil or natural gas fields and is therefore affected by changes in the total number of producing oil and natural gas wells in our geographic service areas.

 

Our regular well maintenance services involve relatively low-cost, short-duration jobs which are part of normal well operating costs. Well operators cannot delay all maintenance work without a significant impact on production. Operators may, however, choose to shut in producing wells temporarily when oil or natural gas prices are too low to justify additional expenditures, including maintenance.

 

Workover.  In addition to periodic maintenance, producing oil and natural gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our workover rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive workover operations are normally performed by a workover rig with additional specialized auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular type of workover operation. Most of our well servicing rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and generally require additional auxiliary equipment. The demand for workover services is sensitive to oil and natural gas producers’ intermediate and long-term expectations for oil and natural gas prices. As oil and natural gas prices increase, the level of workover activity tends to increase as oil and natural gas producers seek to increase output by enhancing the efficiency of their wells.

 

New Well Completion.  New well completion services involve the preparation of newly drilled wells for production. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or natural gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. We provide well service rigs to assist in this completion process. Newly drilled wells are frequently completed by well servicing rigs to minimize the use of higher cost drilling rigs in the completion process. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services require less well-to-well mobilization of equipment and generally 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.

 

Plugging and Abandonment.  Well servicing rigs are also used in the process of permanently closing oil and natural gas wells no longer capable of producing in economic quantities. Plugging and abandonment work can be performed with a well servicing rig along with wireline and cementing equipment; however, this service is typically provided by companies that specialize in plugging and abandonment work. Many well operators bid this work on a “turnkey” basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and comply with state regulatory requirements. Plugging and abandonment work can provide favorable operating margins and is less sensitive to oil and natural gas prices than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies.

 

Contract Drilling Segment

 

Our contract drilling segment employs drilling rigs and related equipment to penetrate the earth to a desired depth and initiate production.

 

We own and operate six land drilling rigs, which are currently deployed in the Permian Basin of Texas and New Mexico. A land drilling rig generally 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.

 

Our drilling rig fleet was acquired in April 2007 with the acquisition of Sledge Drilling Corp.

 

Properties

 

Our principal executive offices are located at 500 W. Illinois, Suite 100, Midland, Texas 79701. We currently conduct our business from 119 area offices, 58 of which we own and 61 of which we lease. Each office typically includes a yard, administrative office and maintenance facility. Of our 119 area offices, 70 are located in Texas, 12 are in Oklahoma, eight are in New Mexico, seven are in Wyoming, five are in Louisiana, four are in Colorado, four are in Arkansas, three are in North Dakota, two are in Montana, two are in Kansas, one is in Pennsylvania and one is in Utah.

 

Customers

 

We serve numerous major and independent oil and gas companies that are active in our core areas of operations. During 2010, no single customer comprised over 10% of our total revenues. The majority of our business is with independent oil and gas companies. While we believe we could redeploy equipment in the current market environment if we lost any material customers, such loss could have an adverse effect on our business until the equipment is redeployed.

 

Operating Risks and Insurance

 

Our operations are subject to hazards inherent in the oil and natural gas industry, such as accidents, blowouts, explosions, craterings, fires and oil spills that can cause:

 

 

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 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 two largest competitors, Key Energy Services, Inc. and Nabors Well Services Co., combined own approximately 43% of the U.S. marketable well servicing rigs according to the most recent publicly available data including the Guiberson-AESC well service rig count. Both Key and Nabors 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, Key and Nabors market a large portion of their work to the major oil and gas companies.

 

We differentiate ourselves from our major competition by our operating philosophy. We operate a decentralized organization, where local, experienced management teams are largely responsible for sales and operations and developing stronger relationships with our customers at the field level. We target areas that are attractive to independent oil and gas operators who in our opinion tend to be more aggressive in spending, less focused on price and more likely to award work based on performance. We concentrate on providing services to a diverse group of large and small independent oil and gas companies. These independents typically are relationship driven, make decisions at the local level and are willing to pay higher rates for services. We have been successful using this business model and believe it will enable us to continue to grow our business.

 

Safety Program

 

Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property. We have comprehensive safety and training programs designed to minimize accidents in the workplace and improve the efficiency of our operations. In addition, many of our larger customers now place greater emphasis on safety and quality management programs of their contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee safety and quality management training programs as well as our employee review process. While our efforts in these areas are not unique, we believe many competitors, and particularly smaller contractors, have not undertaken similar training programs for their employees.

 

We believe our approach to safety management is consistent with our decentralized management structure. Company-mandated policies and procedures provide the overall framework to ensure our operations minimize the

hazards inherent in our work and are intended to meet regulatory requirements, while allowing our operations to satisfy customer-mandated policies and local needs and practices.

 

Environmental Regulation and Climate Change

 

Environment, Health and Safety Regulation, Including Climate Change

 

Our operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, commonly referred to as the “EPA,” and analogous state agencies issue regulations to implement and enforce these laws, which often require stringent and costly compliance measures. These laws and regulations may, among other things, require the acquisition of permits; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling; restrict the way we handle or dispose of our materials and wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; or require investigatory and remedial actions to mitigate pollution conditions. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the possible issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose liability for environmental damages and cleanup costs without regard to negligence or fault. Strict adherence with these regulatory requirements increases our cost of doing business and consequently affects our profitability. We believe that we are in substantial compliance with current applicable environmental, health and safety laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or our competitive position. Below is a discussion of the principal environmental laws and regulations that relate to our business.

 

The Comprehensive Environmental Response, Compensation and Liability Act, referred to as “CERCLA” or the Superfund law, and comparable state laws impose liability, potentially without regard to fault or legality of the activity at the time, on certain classes of persons that are considered to be responsible for the release of a hazardous substance into the environment. These persons include 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 liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of some health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

 

The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, referred to as “RCRA,” regulates the management and disposal of solid and hazardous waste. Some wastes associated with the exploration and production of oil and natural gas are exempted from the most stringent regulation in certain circumstances, such as drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas. However, these wastes and other wastes may be otherwise regulated by the EPA or state agencies. Moreover, in the ordinary course of our operations, industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA.

 

We currently own or lease, and have in the past owned or leased, a number of properties that have been used as service yards in support of oil and natural gas exploration and production activities. Although we have utilized operating and disposal practices that we considered standard in the industry at the time, there is the possibility that repair and maintenance activities on rigs and equipment stored in these service yards, as well as fluids stored at these yards, may have resulted in the disposal or release of hydrocarbons or other wastes on or under these yards or other locations where these wastes have been taken for disposal. In addition, we own or lease properties that in the past were operated by third parties whose operations were not under our control. These properties and the hydrocarbons

or wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination.

 

In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials, or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated or occupied by us have been used for oil and natural gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.

 

Our operations are also subject to the federal Clean Water Act and analogous state laws. Under these laws, permits must be obtained to discharge pollutants into regulated surface or subsurface waters. Spill prevention, control and countermeasure requirements under federal law require appropriate operating protocols, including containment berms and similar structures, to help prevent the contamination of regulated waters in the event of a petroleum hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities or during construction activities. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Additionally, permits for discharges of storm water runoff may be required for certain of our properties.

 

The federal Clean Water Act and the federal Oil Pollution Act of 1990 contain numerous requirements relating to the prevention of and response to oil spills into regulated waters, and require some owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” relating to the possible discharge of oil into regulated waters.

 

Our underground injection operations are subject to the federal Safe Drinking Water Act, referred to as the “SDWA,” as well as analogous state and local laws and regulations including the Underground Injection Control (“UIC”) program, which program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities. The federal Energy Policy Act of 2005 amended the UIC provisions to exclude certain hydraulic fracturing activities from the definition of “underground injection” under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Similar legislation could be introduced in the current session of Congress, which commenced in January 2011, or at the state level. 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 and Kansas. Our operations also involve the disposal of produced salt water by underground injection. The substantial majority of our saltwater disposal wells are located in Texas and are regulated by the Texas Railroad Commission, also known as the “RRC.” We also operate salt water disposal wells in New Mexico, Oklahoma, Arkansas and Louisiana and are subject to similar regulatory controls in those states. Regulations in these states require us to obtain a permit from the applicable regulatory agencies to operate each of our underground salt water disposal wells. We believe that we have obtained the necessary permits from these agencies for each of our underground injection wells and that we are in substantial compliance with permit conditions and commission rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries. In addition, our sales of residual crude oil collected as part of the

saltwater injection process could impose liability on us in the event that the entity to which the oil was transferred fails to manage the residual crude oil in accordance with applicable environmental health and safety laws.

 

We maintain insurance against some risks associated with environmental liabilities that may occur as a result of well service activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will cover all potential losses, that insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.

 

We are also subject to the requirements of the federal Occupational Safety and Health Act, known as “OSHA,” and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public.

 

The federal Clean Air Act, as amended, known as the “Clean Air Act,” and state air pollution permitting laws, restrict the emission of air pollutants from many sources, including drilling operations and related equipment, and as a result affect oil and natural gas operations. In addition, more stringent regulations governing emissions of air pollutants, including greenhouse gases such as methane (a component of natural gas) and carbon dioxide (“CO₂”), are being developed by the federal government and may increase the costs of compliance for our drilling services or our customers’ operations.

 

Responding to scientific studies that have suggested that emissions of gases, commonly referred to as “greenhouse gases,” including gases associated with the oil and gas sector such as carbon dioxide, methane, and nitrous oxide among others, may be contributing to global warming and other environmental effects, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. In the recent Congress, numerous legislative measures were introduced that would have imposed restrictions or costs on greenhouse gas emissions, including from the oil and gas industry. It is uncertain whether similar measures will be introduced in, or passed by, the new Congress which convened in January 2011. However, any such legislation may have the potential to affect our business, customers or the energy sector generally. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change (“UNFCCC”). Other nations have already agreed to regulate emissions of greenhouse gases, pursuant to the UNFCCC and a subsidiary agreement known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. The United States is a party to the UNFCCC but did not ratify the Kyoto Protocol. Such negotiations have thus far not resulted in substantive changes that would affect domestic industrial sources in the United States, and it is uncertain whether an international agreement will be reached or what the terms of any such agreement would be. The EPA has also taken action under the CAA to regulate greenhouse gas emissions. In addition, some states have taken or proposed legal measures to reduce emissions of greenhouse gases.

 

Following the U.S. Supreme Court’s decision in Massachusetts, et al. v. EPA, 549 U.S. 497 (2007), finding that greenhouse gases fall within the CAA definition of “air pollutant,” the EPA determined that greenhouse gases from certain sources “endanger” public health or welfare. The EPA subsequently promulgated certain regulations and interpretations that will require new and modified stationary sources of greenhouse gases above certain thresholds to report, limit or control such emissions. On November 8, 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and gas industry, which may affect certain of our existing or future operations and require the inventory and reporting of emissions. In addition, the EPA has taken the position that existing Clean Air Act provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under the EPA’s Prevention of Significant Deterioration and Title V permit programs beginning in 2011. Facilities triggering permit requirements may be required to reduce greenhouse gas emissions consistent with “best available control technology” standards if deemed to be cost effective. Such changes will also affect state air permitting programs in states that administer the federal CAA under a delegation of authority, including states in which we have operations. Although subject to legal challenge, the EPA rules promulgated thus far are currently final and

effective and will remain so unless overturned by a court, or unless Congress adopts legislation altering the EPA’s regulatory authority. The EPA has also announced its intention to promulgate additional regulations restricting greenhouse gas emissions, including rules applicable to the power generation sector and oil refining sector.

 

There is considerable debate as to global warming and the environmental effects of greenhouse gas emissions and associated consequences affecting global climate, oceans, and ecosystems. As a commercial enterprise, we are not in a position to validate or repudiate the existence of global warming or various aspects of the scientific debate. However, if global warming is occurring, it could have an impact on our operations. For example, our operations in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels or disruption of operations from more frequent and severe weather events. Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe. Changes in climate or weather may hinder exploration and production activities or increase or decrease the cost of production of oil and natural gas resources and consequently affect demand for our field services. Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix. However, we are not in a position to predict the precise effects of global warming on energy markets or the physical effects of global warming. We are providing this disclosure based on publicly available information on the matter.

 

Employees

 

As of December 31, 2010, we employed approximately 4,500 people, with approximately 82% 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 Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such information with, or furnish it to, the SEC.

 

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.

 

 

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition and prospects.

 

Risks Relating to Our Business

 

Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business has been in the past, and may in the future be, adversely affected by industry and financial market conditions that are beyond our control.

 

We depend on our customers’ willingness to make operating and capital expenditures to explore, develop and produce oil and natural gas in the United States. Customers’ expectations for lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing demand for our services and equipment.

 

Industry conditions are influenced by numerous factors over which we have no control, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, political instability in oil and

natural gas producing countries and merger and divestiture activity among oil and gas producers. The volatility of the oil and natural gas industry and the consequent impact on exploration and production activity could adversely impact the level of drilling and workover activity by some of our customers. This reduction may cause a decline in the demand for our services or adversely affect the price of our services. In addition, reduced discovery rates of new oil and natural gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced and the number of producing wells for us to service declines.

 

Deterioration in the global economic environment commencing in the latter part of 2008 and continuing throughout 2009 caused the oilfield services industry to cycle into a downturn, and the possibility of its return to former levels is uncertain. Adverse changes in capital markets and declines in prices for oil and natural gas experienced during this period caused many oil and natural gas producers to announce reductions in capital budgets for future periods. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause these and other oil and natural gas producers to make additional reductions to capital budgets in the future even if oil prices remain at current levels 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 prices decline or natural gas prices remain low or decline further, the demand for our services could be adversely affected.

 

The demand for our services is primarily determined by current and anticipated oil and natural gas prices and the related general production spending and level of drilling activity in the areas in which we have operations. Volatility or weakness in oil prices or natural gas prices (or the perception that oil prices or natural gas prices will decrease) affects the spending patterns of our customers and may result in the drilling of fewer new wells or lower production spending on existing wells. This, in turn, could result in lower demand for our services and may cause lower rates and lower utilization of our well service equipment. If oil prices decline or natural gas prices continue to remain low or decline further, or if there is a reduction in drilling activities, the demand for our services and our results of operations could be materially and adversely affected.

 

Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. The Cushing WTI Spot Oil Price averaged $99.67, $61.65 and $79.39 per barrel in 2008, 2009 and 2010, respectively, and the average wellhead price for natural gas, as recorded by the EIA, was $8.07, $3.66 and $4.18 per Mcf for 2008, 2009 and 2010, respectively. The full 2010 average wellhead price for natural gas was not available at the time this report was filed; therefore the average price through November 2010 was used.

 

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 that we will continue to make substantial capital investments to purchase additional equipment to expand our services, refurbish our well servicing rigs and replace existing equipment. For the year ended December 31, 2009, we invested approximately $43.4 million in cash for capital expenditures, excluding acquisitions. For the year ended December 31, 2010, we invested approximately $63.6 million in cash for capital expenditures, excluding acquisitions. Historically, we have financed these investments through internally generated funds, debt and equity offerings, our capital lease program and borrowing under a senior credit facility. Please read “Liquidity and Capital Resources” for more information.

 

Our significant capital investments require cash that we could otherwise apply to other business needs. However, if we do not incur these expenditures while our competitors make substantial fleet investments, our market share may decline and our business may be adversely affected. In addition, if we are unable to generate sufficient cash internally or obtain alternative sources of capital to fund our proposed capital expenditures and acquisitions, take advantage of business opportunities or respond to competitive pressures, it could materially

adversely affect our results of operations, financial condition and growth. If we raise additional funds by issuing equity securities, dilution to existing stockholders may result. Adverse changes in the capital markets could make it difficult to obtain additional capital or obtain it at attractive rates.

 

Competition within the well services industry may adversely affect our ability to market our services.

 

The well services industry is highly competitive and fragmented and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial and other resources than we do. Our larger competitors’ greater resources could allow those competitors to compete more effectively than we can. The amount of equipment available may exceed demand, which could result in active price competition. Many contracts are awarded on a bid basis, which may further increase competition based primarily on price. In addition, adverse market conditions experienced in the latter part of 2008 and in 2009 lowered demand for well servicing equipment, which resulted in excess equipment and lower utilization rates during 2009 and 2010. If market conditions in our oil-oriented operating areas were to deteriorate or if adverse market conditions in our natural gas-oriented operating areas persist, utilization rates may decline.

 

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 2009 and 2010, our top five customers accounted for 23% and 24%, respectively, of our revenues. The loss of any one of our largest customers or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations.

 

We may not be able to grow successfully through future acquisitions or successfully manage future growth, and we may not be able to effectively integrate the businesses we do acquire.

 

Our business strategy includes growth through the acquisitions of other businesses. We may not be able to continue to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating our current or future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating our current or future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making further acquisitions or causing us to refrain from making additional acquisitions. We may also be limited in our ability to incur additional indebtedness in connection with or to fund future acquisitions under the New Revolving Credit Facility and under the indentures governing our 7.125% Senior Notes due 2016 and 7.75% Senior Notes due 2019.

 

Our industry has experienced a high rate of employee turnover. Any difficulty we experience replacing or adding personnel could adversely affect our business.

 

We may not be able to find enough skilled labor to meet our needs, which could limit our growth. Our business activity historically decreases or increases with the prices of oil and natural gas. We may have problems finding enough skilled and unskilled laborers in the future if the demand for our services increases. If we are not able to increase our service rates sufficiently to compensate for wage rate increases, our operating results may be adversely affected.

 

Other factors may also inhibit our ability to find enough workers to meet our employment needs. Our services require skilled workers who can perform physically demanding work. As a result of our industry volatility and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. We believe that our success is dependent upon our ability

to continue to employ and retain skilled technical personnel. Our inability to employ or retain skilled technical personnel generally could have a material adverse effect on our operations.

 

Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.

 

We depend to a large extent on the services of some of our executive officers. The loss of the services of Kenneth V. Huseman, our President and Chief Executive Officer, or other key personnel could disrupt our operations. Although we have entered into employment agreements with Mr. Huseman 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 operations are subject to inherent risks, some of which are beyond our control. 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, craterings, fires and oil spills. These conditions can cause:

 

 

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.

 

We maintain insurance coverage that we believe to be customary in the industry against these hazards. However, we do not have insurance against all foreseeable risks, either because insurance is not available or because of the high premium costs. As such, not all of our property is insured. We are also self-insured up to retention limits with regard to workers’ compensation, general liability, and medical and dental coverage. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party data and historical claims history. The occurrence of an event not fully insured against, or the failure of an insurer to meet its insurance obligations, could result in substantial losses. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. Insurance may not be available to cover any or all of the risks to which we are subject, or, even if available, it may be inadequate, or insurance premiums or other costs could rise significantly in the future so as to make such insurance prohibitively expensive. It is likely that, in our insurance renewals, our premiums and deductibles will be higher, and certain insurance coverage either will be unavailable or considerably more expensive than it has been in the recent past. In addition, our insurance is subject to coverage limits, and some policies exclude coverage for damages resulting from environmental contamination.

 

We are subject to environmental, health and safety laws and regulations that may expose us to significant liabilities for penalties, damages or costs of remediation or compliance.

 

Our operations are subject to federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities, the imposition of substantial liabilities for pollution resulting from our operations and the application of specific health and safety criteria addressing worker protection. Failure to comply with these laws and regulations could result in restrictions or orders suspending well operations, the assessment of administrative, civil and criminal penalties, the revocation of permits and the issuance of corrective action orders.

There is inherent risk of environmental costs and liabilities in our business as a result of our handling of petroleum hydrocarbons and oilfield and industrial wastes, air emissions and wastewater discharges related to our operations, and historical industry operations and waste disposal practices. Our fluid services segment includes disposal operations into injection wells that pose risks of environmental liability, including leakage from the wells to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, which means that in some situations, we could be exposed to liability as a result of our conduct that was without fault or lawful at the time it occurred or as a result of the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition and results of operations.

 

Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas and could limit well servicing opportunities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance.

 

Please read “Business — Environmental Regulation and Climate Change” for more information on the environmental laws and government regulations that are applicable to us.

 

Climate change legislation or regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for our field services.

 

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases from industrial and energy sources contribute to increases of carbon dioxide levels in the earth’s atmosphere and oceans and contribute to global warming and other environmental effects, the EPA has adopted various regulations under the federal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and gas industry. On November 8, 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and gas industry, including certain onshore oil and natural gas production activities, which may affect certain of our or our customers’ existing or future operations and require the inventory and reporting of emissions. In addition, the EPA has taken the position that existing Clean Air Act provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under the EPA’s Prevention of Significant Deterioration and Title V permit programs beginning in 2011. Facilities triggering permit requirements may be required to reduce greenhouse gas emissions consistent with “best available control technology” standards if deemed to be cost effective. Such 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. In the recent Congress, numerous legislative measures were introduced that would have imposed restrictions or costs on greenhouse gas emissions, including from the oil and gas industry. It is uncertain whether similar measures will be introduced in, or passed by, the new Congress which convened in January 2011. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change. 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 reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with our operations and other sources within the industrial or energy sectors. Such legislation or regulations could adversely affect demand for the production of oil and natural gas and thus reduce demand for the services we provide to oil and natural gas producers as well as increase our operating costs by requiring additional costs to operate and maintain equipment and facilities, install emissions controls, acquire allowances or pay taxes and fees relating to emissions, which could adversely affect our results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases may produce changes in climate or weather, such as increased frequency and severity of storms, floods and other climatic events, which if any such effects were to occur, could have adverse physical effects on our operations, physical assets and field services to exploration and production operators.

Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our well servicing activities and could adversely affect our financial position, results of operations and cash flows.

 

We provide hydraulic fracturing services to our customers. Hydraulic fracturing is a commonly used process that involves using 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 provisions of the federal Safe Drinking Water Act to exclude hydraulic fracturing from the definition of “underground injection” and associated permitting requirements under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Similar legislation could be introduced in the current session of Congress, which commenced in January 2011, or at the state level. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available by late 2012. Last year, a committee of the U.S. House of Representatives undertook investigations into hydraulic fracturing practices, including requesting information from various field services companies including us. We responded to that request and have received no further communication from the committee with regard to that investigation. However, on January 31, 2011, Representative Henry Waxman and other members of Congress wrote to the EPA asserting that various companies, including us, had engaged in hydraulic fracturing operations requiring a permit without obtaining such a permit. We have no knowledge as to whether or how the EPA will respond to that letter. The U.S. Department of the Interior has announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing 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 natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our customers or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations or ordinances regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our well servicing activities, which could adversely affect our financial position, results of operations and cash flows.

 

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

 

We now have, and will continue to have, a significant amount of indebtedness. As of December 31, 2010, our total debt was $508.3 million, including the aggregate principal amount due under our 7.125% Senior Notes due 2016 of $225.0 million, the aggregate principal amount due under our 11.625% Senior Secured Notes due 2014 of $225.0 million and capital lease obligations in the aggregate amount of $58.3 million. There were no amounts outstanding under our $30.0 million secured revolving credit facility as of December 31, 2010. For the year ended December 31, 2010, we made cash interest payments totaling $43.8 million.

 

On February 15, 2011, we issued $275.0 million of 7.75% Senior Notes due 2019 and used a portion of the net proceeds from the offering to retire our outstanding 11.625% Senior Secured Notes. Also on February 15, 2011, we terminated our $30.0 million secured revolving credit facility and entered into a $165.0 million new revolving credit facility (the “New Revolving Credit Facility”).

Our current and future indebtedness could have important consequences. For example, it could:

 

 

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.

 

The indentures governing our 7.125% Senior Notes due 2016 and our 7.75% Senior Notes due 2019 and our New Revolving Credit Facility impose restrictions on us that may affect our ability to successfully operate our business.

 

The indentures governing our 7.125% Senior Notes due 2016 and our 7.75% Senior Notes due 2019 and our New Revolving Credit Facility include limitations on our ability to take various actions, such as:

 

 

In addition, our New Revolving Credit Facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, some of which become more restrictive over time and may require us to reduce our debt or take some other action in order to comply with them. The failure to comply with any of these financial conditions, including the financial ratios or covenants, would cause a default under our New Revolving Credit Facility. A default under any of our indebtedness, if not waived, could result in the acceleration of such indebtedness or other indebtedness, in which case the debt would become immediately due and payable. In addition, a default or acceleration of any of our indebtedness under our 7.125% Senior Notes, our 7.75% Senior Notes or our New Revolving Credit Facility could result in a default under or acceleration of other indebtedness with cross-default or cross-acceleration provisions. In the event of any acceleration of our indebtedness, we may not be able to pay our debt or borrow sufficient funds to refinance it, and any holders of secured indebtedness may seek to foreclose on the assets securing such indebtedness. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financings, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our New Revolving Credit Facility or existing limitations on the incurrence of additional indebtedness, including in connection with acquisitions. Please read

“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Revolving Credit Facility” for a discussion of our New Revolving Credit Facility.

 

One of our directors may have a conflict of interest because he is also currently a managing partner of a private equity firm that makes investments in the energy sector. The resolution of any conflict of interest may not be in our or our stockholders’ best interests.

 

Steven A. Webster, the Chairman of our Board of Directors, is the Co-Managing Partner of Avista Capital Holdings, L.P., a private equity firm that makes investments in the energy sector. This relationship may create a conflict of interest because of his responsibilities to Avista and its owners. His duties as a partner in, or director or officer of, Avista or its affiliates may conflict with his duties as a director of our company regarding corporate opportunities and other matters. The resolution of any such conflict may not always be in our or our stockholders’ best interest.

 

Risks Relating to Our Relationship with DLJ Merchant Banking

 

Affiliates of DLJ Merchant Banking will have a substantial influence on the outcome of stockholder voting and may exercise this voting power in a manner that may not be in the best interest of our other stockholders.

 

As of February 18, 2011, DLJ Merchant Banking Partners III, L.P. and affiliated funds (“DLJ Merchant Banking”), which are managed by affiliates of Credit Suisse, a Swiss Bank, and Credit Suisse Securities (USA) LLC, beneficially owned approximately 43.5% of our outstanding common stock. Accordingly, DLJ Merchant Banking is in a position to have a substantial influence on the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of DLJ Merchant Banking may differ from those of our other stockholders, and DLJ Merchant Banking may vote its common stock in a manner that may adversely affect our other stockholders.

 

Risks Relating to Ownership of Our Common Stock

 

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

 

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

 

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.

 

 

None.

 

 

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.

 

 

Executive Officers of the Registrant

 

Our executive officers as of December 31, 2010 and their respective ages and positions are as follows:

 

 

Set forth below is the description of the backgrounds of our executive officers.

 

Kenneth V. Huseman (President — Chief Executive Officer and Director) has 32 years of well servicing experience. He has been our President and Chief Executive Officer and a Director since 1999. Prior to joining Basic, he was Chief Operating Officer at Key Energy Services from 1996 to 1999. He was a Divisional Vice President at WellTech, Inc., from 1993 to 1996. From 1978 to 1993, he was employed at Pool Energy Services Co., where he managed operations throughout the United States, including drilling operations in Alaska. Mr. Huseman graduated with a B.B.A. degree in Accounting from Texas Tech University.

 

Alan Krenek (Senior Vice President, Chief Financial Officer, Treasurer and Secretary) has 23 years of related industry experience. He has been our Vice President, Chief Financial Officer and Treasurer since January 2005. He became Senior Vice President and Secretary in May 2006. From October 2002 to January 2005, he served as Vice President and Controller of Fleetwood Retail Corp., a subsidiary in the manufactured housing division of Fleetwood Enterprises, Inc. He worked in various financial management positions at Pool Energy Services Co. from 1980 to 1993 and at Noble Corporation from 1993 to 1995. Mr. Krenek graduated with a B.B.A. degree in Accounting from Texas A&M University and is a certified public accountant.

T. M. “Roe” Patterson (Senior Vice President — Rig and Truck Operations) has 16 years of related industry experience. He has been our Senior Vice President of Rig and Truck operations since September 2008, and has been the Vice President of various different groups within Basic since February 2006. Prior to joining us, he was president of his own manufacturing and oilfield service company, TMP Companies, Inc., from 2000 to 2006. He was a Contracts/Sales Manager for the Permian Division of Patterson Drilling Company from 1996 to 2000. He was an Engine Sales Manager for West Texas Caterpillar from 1995 to 1996. Mr. Patterson graduated with a B.S. degree in Biology from Texas Tech University.

 

James F. Newman (Group Vice President — Completion and Remedial Services) has 26 years of related industry experience and has been our Group Vice President of Completion and Remedial Services since September 2008. Prior to joining Basic, he co-founded Triple N Services in 1986 and served as its President through May 2008. He initially served Basic as an Area Manager in the plugging and abandonment operations. Mr. Newman is a registered Professional Engineer and is active in the Society of Professional Engineers. Mr. Newman graduated with a B.S. in Petroleum Engineering from Colorado School of Mines.

 

Stephen J. McCoy (Vice President — Contract Drilling) has 35 years of related industry experience. Mr. McCoy has served as our Vice President — Contract Drilling since February 2009 after serving as our Vice President — Contracts since joining the company in June 2008. Prior to joining us, he was the Chief Operating Officer of H&M Resources from August 2007 to June 2008 and handled various operating duties in drilling and operating wells in the Permian Basin. He served as Vice President of Marketing for Patterson-UTI over their Permian Basin Division and in other various capacities from November 1996 until July of 2007 after Patterson Drilling purchased Gene Sledge Drilling Company. Mr. McCoy started with the Western Company in January 1978 before joining Cactus Drilling Corporation as a Contract Representative in October 1978 until May 1991. He joined Ranchland Rental Tools as Vice President of Marketing in 1991 and worked there through the mergers of Triumph Tools and Total Energy and then as District Manager for Enterra’s drilling tool division until joining Nabors Drilling as a Contracts Manager in January 1996. Mr. McCoy graduated with a B.B.A. degree in Business Management from Texas Tech University.

 

Douglas B. Rogers (Vice President — Marketing) has 28 years of related industry experience. He joined Basic in 2007 and serves as Vice President Marketing after serving as Vice President Contracts for the Drilling Division. Mr. Rogers was Vice President Rocky Mountain Division for Patterson-UTI Drilling Company from March 2003 to June 2007. He also served as Western Division Sales Manager for Ambar Lonestar Fluid Services, a division of Patterson-UTI Drilling Company, from 1998 to 2003. He began his career in 1983 with Permian Servicing Company, where he managed well servicing operations. He continued in that capacity through Permian Servicing Company’s mergers with Xpert Well Service and Pride Petroleum Service until joining Zia Drill/Nova Mud in March 1997. Mr. Rogers graduated with a B.A. degree from Eastern New Mexico University.

 

James E. Tyner (Vice President — Human Resources) has been a Vice President since January 2004. From 1999 to June 2003, he was the General Manager of Human Resources at CMS Panhandle Companies, where he directed delivery of HR Services. Mr. Tyner was the Director of Human Resources Administration and Payroll Services at Duke Energy’s Gas Transmission Group from 1998 to 1999. From 1981 to 1998, Mr. Tyner held various positions at Panhandle Eastern Corporation. At Panhandle, he managed all Human Resources functions and developed corporate policies and as a Certified Safety Professional, he designed and implemented programs to control workplace hazards. Mr. Tyner received a B.S. in General Science and M.S. in Microbiology from Mississippi State University.

 

 

Market Price for Registrant’s Common Equity

 

Our common stock is traded on the New York Stock Exchange under the symbol “BAS.” The table below presents the high and low daily closing sales prices of the common stock, as reported by the New York Stock Exchange, for each of the quarters in the years ended December 31, 2009 and 2010, respectively:

 

 

As of February 18, 2011, we had 41,598,958 shares of common stock outstanding held by approximately 286 record holders.

 

We have not declared or paid any cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board.

 

Securities Authorized for Issuance under Equity Compensation Plans

 

The following table provides information regarding options or warrants authorized for issuance under our equity compensation plans as of December 31, 2010:

 

 

 

 

Issuer Purchases of Equity Securities

 

On October 13, 2008, Basic announced that its Board of Directors had authorized the repurchase of up to $50.0 million of Basic’s shares of common stock from time to time in open market or private transactions, at Basic’s

discretion. The stock repurchase program was suspended by the Board of Directors during the first quarter of 2009. As of December 31, 2010, approximately $35.2 million remained authorized for purchase under this program.

 

The following table provides information relating to our repurchase of shares of common stock during the three months ended December 31, 2010 (dollars in thousands, except average price paid per share):

 

 

 

Performance Graph

 

The following is a line graph comparing cumulative, total shareholder return from December 30, 2005 through December 31, 2010 with (i) a general market index (the Russell 2000 Index) and (ii) a group of peers selected by the Company in the same line of business or industry as the Company. The peer group is comprised of the following companies: Key Energy Services, Inc., Complete Production Services, Inc., Tetra Technologies, Inc. and Pioneer Drilling Company.

 

The graph assumes investments of $100 on December 30, 2005 at the closing sale price, and the reinvestment of all dividends, if any.

 

The graph shall not be deemed incorporated by reference by any general statement incorporating by reference this report into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that the Company specifically incorporates this information by reference, and shall not otherwise be deemed filed under such Acts.

 

December 30, 2005 to December 31, 2010

 

 

Value of $100 Invested at December 30, 2005, December 29, 2006, December 31, 2007,
December 31, 2008, December 31, 2009 and December 31, 2010

 

 

The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to the Regulations 14A or 14C under the Securities Exchange Act of 1934 or to the liabilities of Section 18 under such act.

 

The following table sets forth our selected historical financial information for the periods shown. The following information should be read in conjunction with Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and our financial statements included elsewhere in this report. The amounts for each historical annual period presented below were derived from our audited financial statements.

 

 

 

 

 

Management’s Overview

 

We provide a wide range of well site services to oil and natural gas drilling and producing companies, including completion and remedial services, fluid services, well servicing and contract drilling services. Our results of operations reflect the impact of our acquisition strategy as a leading consolidator in the domestic land-based well services industry. Our acquisitions have increased our breadth of service offerings at the well site and expanded our market presence. In implementing this strategy, we have purchased businesses and assets in 28 separate acquisitions from January 1, 2006 to December 31, 2010. Our weighted average number of fluid service trucks increased from 529 in the first quarter of 2006 to 782 in the fourth quarter of 2010. We added 98 trucks through the acquisition of Azurite Services Company, Inc., Azurite Leasing Company, LLC, and Freestone Disposal, LP (collectively “Azurite”) in the third quarter of 2008. Our weighted average number of well servicing rigs increased from 325 in the first quarter of 2006 to 407 in the fourth quarter of 2010. Our weighted average number of drilling rigs increased from two in the first quarter of 2006 to six in the fourth quarter of 2010. These acquisitions make changes in revenues, expenses and income not directly comparable between periods.

 

We revised our business segments beginning in the first quarter of 2008, and in connection therewith, restated the corresponding items of segment information for earlier periods. Our current operating segments are Completion and Remedial Services, Fluid Services, Well Servicing and Contract Drilling. These segments were selected based on changes in management’s resource allocation and performance assessment in making decisions regarding the Company. Contract Drilling was previously included in our Well Servicing segment. Well Site Construction Services has been consolidated with our Fluid Services segment.

 

Our operating revenues from each of our segments, and their relative percentages of our total revenues, consisted of the following (dollars in millions):

 

 

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, could adversely impact the level of drilling and workover activity by some of our customers. This volatility also affects the demand for our services and the price of our services. In addition, the discovery rate of new oil and natural gas reserves in our market areas also may have an impact on our business, even in an environment of stronger oil and natural gas prices. For a more comprehensive discussion of our industry trends, see “General Industry Overview” included in Items 1 and 2, Business and Properties, of this Annual Report on Form 10-K.

 

We derive a majority of our revenues from services supporting production from existing oil and natural gas operations. Demand for these production-related services, including well servicing and fluid services, tends to remain relatively stable, even in moderate oil and natural gas price environments, as ongoing maintenance spending is required to sustain production. As oil and natural gas prices reach higher levels, demand for all of our services generally increases as our customers engage in more well servicing activities relating to existing wells to maintain or increase oil and natural gas production from those wells. Because our services are required to support drilling and

workover activities, our revenues will vary based on changes in capital spending by our customers as oil and natural gas prices increase or decrease.

 

Through the middle of 2008, oil and natural gas prices reached historic highs, which increased utilization and pricing for our services. However, in the latter part of 2008 there were significant decreases in oil and natural gas prices, which caused significantly lower utilization of our services in the fourth quarter of 2008. In 2009, natural gas prices continued to decline from prices experienced in the fourth quarter of 2008 while oil prices increased over the same period. This decrease in natural gas prices, coupled with adverse changes in the capital markets, resulted in lower demand for our services and increased price competition during 2009, as a number of oil and gas producers reduced their budgets for 2009. During 2010, oil prices remained relatively stable following the increase in prices experienced during 2009. This trend in oil prices has caused utilization and pricing for our services to increase in our oil-based operating areas, while utilization and pricing for our services in our natural gas-based operating areas throughout 2010 have remained depressed due to low natural gas prices. We expect oil prices in 2011 to remain above levels necessary to support increased capital spending programs for workover and drilling programs as well as routine maintenance. We believe that the outlook for natural gas prices in 2011 will continue to be uncertain, which will cause our customers to remain cautious in their spending until natural gas prices gain strength and stability. We expect that the supply of available equipment combined with higher demand from our customers will result in utilization levels across all of our business segments showing further improvements throughout 2011 as we continue to reactivate and relocate equipment to meet demand, particularly in our established oil-oriented market areas.

 

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.

 

We believe that the most important performance measures for our business segments are as follows:

 

 

Segment profits are computed as segment operating revenues less direct operating costs. These measurements provide important information to us about the activity and profitability of our lines of business. For a detailed analysis of these indicators for our company, see “Segment Overview” below.

 

Recent Strategic Acquisitions and Expansions

 

During the period from 2008 through 2010, we grew through acquisitions and capital expenditures. During 2008, we completed five acquisitions, of which Azurite was considered significant. During 2009, we completed one acquisition, which was not considered significant. During 2010, we completed four acquisitions that complemented our existing business segments, none of which were considered significant.

 

We discuss the aggregate purchase prices and related financing issues below in “Liquidity and Capital Resources” and present the pro forma effects of the acquisition of Azurite in Note 3 of the notes to our historical consolidated financial statements included in this report.

Selected 2008 Acquisitions

 

During 2008, we made several acquisitions that complemented our existing business segments. These included, among others:

 

Xterra Fishing and Rental Tools Co.

 

On January 28, 2008, we acquired all of the outstanding capital stock of Xterra Fishing and Rental Tools Co. (“Xterra”) for total consideration of $21.5 million cash. This acquisition operates in our completion and remedial services segment.

 

Azurite Services Company, Inc.

 

On September 26, 2008, we acquired substantially all of the operating assets of Azurite for $61.0 million in cash. This acquisition operates in our fluid services segment.

 

Selected 2009 Acquisitions

 

Team Snubbing Services, Inc.

 

On December 28, 2009, we acquired substantially all of the assets of Team Snubbing Services, Inc. for total consideration of $7.0 million in cash. This acquisition operates in our completion and remedial services segment.

 

Selected 2010 Acquisitions

 

During 2010, we made four acquisitions that complemented our existing business segments. These included, among others:

 

Taylor Rig, LLC

 

On May 3, 2010, we acquired all the assets of Taylor Rig, LLC for total consideration of $8.7 million in cash. This acquisition has been included in our well servicing segment.

 

Platinum Pressure Services, Inc.

 

On December 16, 2010, we acquired all of the outstanding stock of Platinum Pressure Services, Inc. (“Platinum”) and Admiral Well Service, Inc., a wholly owned subsidiary of Platinum, for total cash consideration of $39.9 million. This acquisition operates in our completion and remedial services and well servicing segments.

 

Segment Overview

 

Completion and Remedial Services

 

In 2010, our completion and remedial services segment represented 36% of our revenues. Revenues from our completion and remedial services segment are generally 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, cased-hole wireline services, snubbing and underbalanced drilling.

 

Our pumping services concentrate on providing single truck, lower-horsepower cementing, acidizing and fracturing services in selected markets. Our total hydraulic horsepower capacity for our pumping services was approximately 142,000 horsepower at December 31, 2010 compared to 139,000 horsepower at both December 31, 2009 and December 31, 2008.

 

Our rental and fishing tool business operates 20 rental and fishing tool stores in selected markets as of December 31, 2010.

Our snubbing services operate 25 units throughout our geographic footprint as of December 31, 2010. We entered the snubbing business in 2009 with the acquisition of Team Snubbing Services, which operated in Arkansas. We further expanded our snubbing business in 2010 through the acquisition of Platinum Pressure Services, Inc., which operated in Texas, Oklahoma, Arkansas, Louisiana and Pennsylvania.

 

We have operations in the wireline business and in the underbalanced drilling services business, which we entered into in 2004. For a description of our wireline, underbalanced drilling services, and snubbing, 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 generally derive our revenues on a project-by-project basis in a competitive bidding process. Our bids are generally 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, 2008, 2009 and 2010 (dollars in thousands):

 

 

We gauge the performance of our completion and remedial services segment based on the segment’s operating revenues and segment profits as a percent of revenues.

 

Fluid Services

 

In 2010, our fluid services segment represented 33% of our revenues. Revenues in our fluid services segment are earned from the sale, transportation, storage and disposal of fluids used in the drilling, production and maintenance of oil and natural gas wells. Revenues also include well site construction and maintenance services. The fluid services segment has a base level of business consisting of transporting and disposing of salt water produced as a by-product of the production of oil and natural gas. These services are necessary for our customers and generally have a stable demand but typically produce lower relative segment profits than other parts of our fluid services segment. Fluid services for completion and workover projects typically require fresh or brine water for making drilling mud, circulating fluids or frac fluids used during a job, and all of these fluids require storage tanks and hauling and disposal. Because we can provide a full complement of fluid sales, trucking, storage and disposal

required on most drilling and workover projects, the add-on services associated with drilling and workover activity enable us to generate higher segment profits. The higher segment profits are due to the relatively small incremental labor costs associated with providing these services in addition to our base fluid services operations. Revenues from our well site constructions 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. 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 fluid services segment for each of the quarters and years in the years ended December 31, 2008, 2009 and 2010 (dollars in thousands):

 

 

We gauge activity levels in our fluid services segment based on trucking hours, revenue per fluid service truck, segment profits per fluid service truck and segment profits as a percent of revenues.

 

Well Servicing

 

In 2010, our well servicing segment represented 28% 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.

Our well servicing rig fleet increased from a weighted average number of 392 rigs in the first quarter of 2008 to 407 in the fourth quarter of 2010 through a combination of newbuild purchases, acquisitions, and other individual equipment purchases.

 

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. We acquired our rig manufacturing business in May 2010.

 

The following is an analysis of our well servicing segment for each of the quarters and years in the years ended December 31, 2008, 2009 and 2010. The revenues do not include revenues associated with rig manufacturing operations:

 

 

We gauge activity levels in our well servicing rig operations based on rig hours, rig utilization rate, revenue per rig hour, profits per rig hour and segment profits as a percent of revenues.

 

Contract Drilling

 

In 2010, our contract drilling segment represented 3% of our revenues. Revenues from our contract drilling segment are derived primarily from the drilling of new wells.

 

Within this segment, we typically charge our drilling rig customers at a daywork daily rate, or 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. In the fourth quarter of 2010, we converted three of our drilling rigs to well service rigs.

The following is an analysis of our contract drilling segment for each of the quarters and years in the years ended December 31, 2008, 2009 and 2010 (dollars in thousands):

 

 

We gauge activity levels in our drilling operations based on rig operating days, revenue per drilling day, profits per drilling day and segment profits as a percent of revenues.

 

Operating Cost Overview

 

Our operating costs are comprised primarily of labor costs, including workers’ compensation and health insurance, repair and maintenance, fuel and insurance. A majority of our employees are paid on an hourly basis. We also incur costs to employ personnel to sell and supervise our services and perform maintenance on our fleet. These costs are not directly tied to our level of business activity. Compensation for our administrative personnel in local operating yards and in our corporate office is accounted for as general and administrative expenses. 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 relates to the number of rigs, trucks and other equipment in our fleet, employee payroll and our safety record.

 

Critical Accounting Policies and Estimates

 

Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. A complete summary of these policies is included in Note 2 of the notes to our historical consolidated financial statements. The following is a discussion of our critical accounting policies and estimates.

 

Critical Accounting Policies

 

We have identified below accounting policies that are of particular importance in the presentation of our financial position, results of operations and cash flows and which require the application of significant judgment by management.

 

Property and Equipment.  Property and equipment are stated at cost, or at estimated fair value at acquisition date if acquired in a business combination. Expenditures for repairs and maintenance are charged to expense as

incurred. We also review the capitalization of refurbishment of workover rigs as described in Note 2 of the notes to our historical consolidated financial statements.

 

Impairments.  We review our assets for impairment at a minimum annually, or whenever, in management’s judgment, events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recovered over its remaining service life. Provisions for asset impairment are charged to income when the sum of the estimated future cash flows, on an undiscounted basis, is less than the asset’s carrying amount. When impairment is indicated, an impairment charge is recorded based on an estimate of future cash flows on a discounted basis.

 

Self-Insured Risk Accruals.  We are self-insured up to retention limits with regard to workers’ compensation and medical and dental coverage of our employees. We generally maintain no physical property damage coverage on our workover rig fleet, with the exception of certain of our 24-hour workover rigs and newly manufactured rigs. We have deductibles per occurrence for workers’ compensation and general liability and medical and dental coverage of $500,000, $500,000, and $250,000, respectively. We have lower deductibles per occurrence for automobile liability. We maintain accruals in our consolidated balance sheets related to self-insurance retentions by using third-party actuarial data and historical claims history.

 

Revenue Recognition.  We recognize revenues when the services are performed, collection of the relevant receivables is probable, persuasive evidence of the arrangement exists and the price is fixed and determinable. Rig manufacturing revenue is recognized by individual rig based on the completed contract method.

 

Income Taxes.  We recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using statutory tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in the period that includes the statutory enactment date. A valuation allowance for deferred tax assets is recognized when it is more likely than not that the benefit of deferred tax assets will not be realized.

 

Critical Accounting Estimates

 

The preparation of our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable under the circumstances. However, actual results could differ from such estimates. The following is a discussion of our critical accounting estimates.

 

Depreciation and Amortization.  In order to depreciate and amortize our property and equipment and our intangible assets with finite lives, we estimate the useful lives and salvage values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry.

 

Impairment of Property and Equipment.  Our analysis for potential impairment of property and equipment requires us to estimate undiscounted future cash flows. Actual impairment charges are recorded using an estimate of discounted future cash flows. The determination of future cash flows requires us to estimate rates and utilization in future periods and such estimates can change based on market conditions, technological advances in industry or changes in regulations governing the industry. We analyze the potential impairment of property and equipment annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the assets have decreased below the carrying value.

 

Impairment of Goodwill.  Our goodwill is considered to have an indefinite useful economic life and is not amortized. We assess impairment of goodwill annually as of December 31 or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. A two-step process is required for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. If impairment is indicated, then the fair value of the reporting

unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value.

 

We performed an assessment of goodwill as of March 31, 2009. A “triggering event” requiring this assessment was deemed to have occurred because the oil and natural gas services industry continued to decline in the first quarter of 2009 and our common stock price declined by 50% from December 31, 2008 to March 31, 2009. For Step One of the impairment testing, we tested three reporting units for goodwill impairment: well servicing, fluid services, and completion and remedial services. Our contract drilling reporting unit does not carry any goodwill and was not subject to the test.

 

To estimate the fair value of the reporting units, we used a weighting of the discounted cash flow method and the public company guideline method of determining fair value of a business unit. We weighted the discounted cash flow method 85% and public company guideline method 15%, due to differences between our reporting units and the peer companies’ size, profitability and diversity of operations. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a stand-alone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with our capitalization. The measurement date for our common stock price and market capitalization was the closing price on March 31, 2009.

 

Based on the results of Step One of the impairment test, impairment was indicated in all three of the assessed reporting units. As such, we were required to perform Step Two assessment on all three of the reporting units. Step Two requires the allocation of the estimated fair value to the tangible and intangible assets and liabilities of the respective unit. This assessment indicated that $204.1 million was considered impaired as of March 31, 2009. This non-cash charge eliminated all of our existing goodwill as of March 31, 2009.

 

Allowance for Doubtful Accounts.  We estimate our allowance for doubtful accounts based on an analysis of historical collection activity and specific identification of overdue accounts. Factors that may affect this estimate include (1) changes in the financial positions of significant customers and (2) a decline in commodity prices that could affect the entire customer base.

 

Litigation and Self-Insured Risk Reserves.  We estimate our reserves related to litigation and self-insured risk based on the facts and circumstances specific to the litigation and self-insured risk claims and our past experience with similar claims. The actual outcome of litigation and insured claims could differ significantly from estimated amounts. As discussed in “— Self-Insured Risk Accruals” above with respect to our critical accounting policies, we maintain accruals on our balance sheet to cover self-insured retentions. These accruals are based on certain assumptions developed using third-party data and historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and reported claims.

 

Fair Value of Assets Acquired and Liabilities Assumed.  We estimate the fair value of assets acquired and liabilities assumed in business combinations, which involves the use of various assumptions. These estimates may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair value of property and equipment, intangible assets and the resulting amount of goodwill, if any. We test annually for impairment of the goodwill and intangible assets with indefinite useful lives recorded in business combinations. This requires us to estimate the fair values of our own assets and liabilities at the reporting unit level. Therefore, considerable judgment, similar to that described above in connection with our estimation of the fair value of an acquired company, is required to assess goodwill and certain intangible assets for impairment.

 

Cash Flow Estimates.  Our estimates of future cash flows are based on the most recent available market and operating data for the applicable asset or reporting unit at the time the estimate is made. Our cash flow estimates are used for asset impairment analyses.

 

Stock-Based Compensation.  We have historically compensated our directors, executives and employees through the awarding of stock options and restricted stock. We accounted for stock option and restricted stock awards in 2007, 2008 and 2009 using a grant date fair-value based method, resulting in compensation expense for stock-based awards being recorded in our consolidated statements of income. Stock options issued are valued on the

grant date using Black-Scholes-Merton option pricing model and restricted stock issued is valued based on the fair value of our common stock at the grant date. In addition, judgment is required in estimating the amount of stock-based awards that are expected to be forfeited. Because the determination of these various assumptions is subject to significant management judgment and different assumptions could result in material differences in amounts recorded in our consolidated financial statements, management believes that accounting estimates related to the valuation of stock options are critical.

 

Income Taxes.  The amount and availability of our loss carryforwards (and certain other tax attributes) are subject to a variety of interpretations and restrictive tests. The utilization of such carryforwards could be limited or lost upon certain changes in ownership and the passage of time. Accordingly, although we believe substantial loss carryforwards are available to us, no assurance can be given concerning the realization of such loss carryforwards, or whether or not such loss carryforwards will be available in the future.

 

Asset Retirement Obligations.  We record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset, depreciating it over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation is adjusted at the end of each quarter to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, acquisition or construction of assets, and settlement of obligations.

 

Results of Operations

 

The results of operations between periods will not be comparable, primarily due to the significant decline in the oil and natural gas industry throughout 2009 and recovery throughout 2010.

 

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

 

Revenues.  Revenues increased by 38% to $728.2 million in 2010 from $526.6 million in 2009. This increase was primarily due to increased expenditures by our customers for our services, especially in oil-producing areas that had significant increases in exploration, completion of new wells and workovers performed on existing wells.

 

Completion and remedial services revenues increased by 94% to $261.4 million in 2010 as compared to $134.8 million in 2009. The increase in revenue between these periods was due to increased utilization of our pressure pumping equipment, resulting from higher drilling and completion activity as well as improved pricing for our services. Total hydraulic horsepower was 142,000 and 139,000 at December 31, 2010 and December 31, 2009, respectively.

 

Fluid services revenues increased by 12% to $241.1 million in 2010 compared to $214.8 million in 2009. Our weighted average number of fluid service trucks decreased 2% to 790 in 2010 from 805 in 2009, and our revenue per fluid service truck increased to $305,000 in 2010 compared to $267,000 in 2009, which reflects an increase in utilization and improved pricing for our services.

 

Well servicing revenues increased by 28% to $204.9 million in 2010 compared to $160.6 million in 2009. This increase was due to the increase in rig utilization to 53% during 2010 from 41% during 2009. This increase in rig utilization was offset by a decrease of 4% in revenue per rig hour to $319 during 2010 from $331 during 2009, due to increased price competition. Pricing per hour increased steadily throughout the second half of 2010. Our average number of well servicing rigs decreased to 405 during 2010 compared to 413 in 2009, due to the retirement of older, less efficient rigs.

 

Contract drilling revenues increased by 27% to $20.8 million in 2010 compared to $16.4 million in 2009. The number of rig operating days increased to 2,006 in 2010 compared to 1,370 in 2009. This increase in revenues was due to an increase in new well starts in the Permian Basin, the region in which all of our drilling rigs operate, and was offset by lower dayrates.

 

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 30% to $506.9 million

in 2010 from $389.6 million in 2009. This increase was due to the higher activity levels in all of our segments and was offset by cost-cutting measures implemented as a result of the decline in revenues in 2009.

 

Direct operating expenses for the completion and remedial services segment increased by 64% to $156.6 million in 2010 as compared to $95.3 million in 2009 due primarily to increased activity levels. Segment profits increased to 40% of revenues in 2010 compared to 29% in 2009, due to higher levels of completion and pumping services and improved pricing for our services.

 

Direct operating expenses for the fluid services segment increased by 12% to $178.2 million in 2010 as compared to $159.1 million in 2009, due to higher activity levels. Segment profits were 26% of revenues in both 2010 and 2009.

 

Direct operating expenses for the well servicing segment increased by 29% to $156.9 million in 2010 as compared to $121.6 million in 2009, due primarily to the 26% increase in rig hours to 613,400 in 2010 from 485,200 in 2009. Segment profits decreased slightly to 23% of revenues in 2010 compared to 24% in 2009.

 

Direct operating expenses for the contract drilling segment increased by 12% to $15.3 million in 2010 as compared to $13.6 million in 2009 due primarily to a 46% increase in rig operating days in 2010, which was offset by the mix of day rate work and footage work between 2010 and 2009. Segment profits for this segment were 27% of revenues in 2010 compared to 17% in 2009, due primarily to increased dayrates.

 

General and Administrative Expenses.  General and administrative expenses increased by 3% to $107.8 million in 2010 from $104.3 million in 2009, which included $5.7 million and $5.2 million of stock-based compensation expense in 2010 and 2009, respectively. The increase from 2009 primarily reflects higher salary expenses related to the increase in the number of employees along with the reversal of pay reductions enacted at the end of the first quarter of 2009 and higher incentive compensation.

 

Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $135.0 million in 2010, as compared to $132.5 million in 2009, reflecting the increase in the size of and investment in our asset base. We invested $50.3 million for acquisitions, $23.4 million for capital leases and an additional $63.6 million for cash capital expenditures in 2010.

 

Goodwill Impairment.  In the first half of 2009, we recorded a non-cash charge totaling $204.0 million for impairment of all of the goodwill associated with our well servicing, fluid services, and completion and remedial services segments as of March 31, 2009. There was no impairment of goodwill in 2010.

 

Interest Expense.  Interest expense increased by 41% to $46.5 million in 2010 from $32.9 million in 2009. The increase was primarily due to the effect in 2010 of the issuance of $225.0 million of 11.625% Senior Secured Notes in July 2009, the proceeds of which were used to retire our previous $225.0 million revolving credit facility.

 

Income Tax Expense.  Income tax benefit was $24.8 million in 2010, as compared to an expense of $87.5 million in 2009. Our effective benefit rate was approximately 36% in 2010 and our effective benefit rate was approximately 26% in 2009. The lower effective benefit rate in 2009 relates to the goodwill write-down in the first quarter of 2009 and is due to differences in the taxable nature of the impaired goodwill. A portion of the goodwill came from stock acquisitions, which have zero tax bases.

 

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

 

Revenues.  Revenues decreased by 48% to $526.6 million in 2009 from $1.0 billion in 2008. This decrease was primarily due to lower expenditures by our customers for our services and increased price competition from our competitors due to the decline in oil and natural gas prices.

 

Completion and remedial services revenues decreased by 56% to $134.8 million in 2009 as compared to $304.3 million in 2008. The decrease in revenue between these periods was due to decreased utilization of equipment due to the decline in oil and natural gas prices. Increased market competition also caused significant rate declines. Total hydraulic horsepower was 139,000 at both December 31, 2009 and December 31, 2008.

 

Fluid services revenues decreased by 32% to $214.8 million in 2009 compared to $315.8 million in 2008. This decrease was primarily due to decreased rates that we charged to our customers for our services caused by increased

price competition from our competitors. These decreases were partially offset by the Azurite acquisition in September 2008 which added 98 fluid service trucks and 632 frac tanks. Our weighted average number of fluid service trucks increased to 805 in 2009 from 699 in 2008, although our revenue per fluid service truck decreased to $267,000 in 2009 compared to $452,000 in 2008.

 

Well servicing revenues decreased by 53% to $160.6 million in 2009 compared to $343.1 million in 2008. This decrease was due to the decrease in rig utilization to 41% during 2009 from 73% during 2008, along with a decrease in revenue per rig hour to $331 during 2009 from $408 during 2008. These declines were due to decreased expenditures by our customers for our services along with decreased pricing for our services as a result of price competition with our competitors. Our average number of well servicing rigs increased to 413 during 2009 compared to 405 in 2008, due to internal expansion from our newbuild rig program and the Lackey Construction, LLC and the Triple N Services, Inc. acquisitions.

 

Contract drilling revenues decreased by 61% to $16.4 million in 2009 compared to $41.7 million in 2008. The number of rig operating days decreased to 1,370 in 2009 compared to 2,777 in 2008. This decrease was due to fewer new well starts in the geographic market in which we operate.

 

Direct Operating Expenses.  Direct operating expenses, which primarily consist of labor, including workers’ compensation and health insurance, and maintenance and repair costs, decreased by 36% to $389.6 million in 2009 from $612.6 million in 2008. This decrease was due to the lower activity levels in all of our segments and cost-cutting measures implemented as a result of the decline in revenues.

 

Direct operating expenses for the completion and remedial services segment decreased by 42% to $95.3 million in 2009 as compared to $165.6 million in 2008 due primarily to decreased activity levels. Segment profits decreased to 29% of revenues in 2009 compared to 46% in 2008, due to activity levels and rates declining faster than costs.

 

Direct operating expenses for the fluid services segment decreased by 22% to $159.1 million in 2009 as compared to $203.2 million in 2008, which is due to lower activity levels. Segment profits were 26% of revenues in 2009 compared to 36% in 2008.

 

Direct operating expenses for the well servicing segment decreased by 43% to $121.6 million in 2009 as compared to $215.2 million in 2008, due primarily to the 42% decrease in rig hours to 485,200 in 2009 from 840,200 in 2008. Segment profits decreased to 24% of revenues in 2009 compared to 37% in 2008, which reflects the faster decline in activity levels and rates than in costs during 2009.

 

Direct operating expenses for the contract drilling segment decreased by 52% to $13.6 million in 2009 as compared to $28.6 million in 2008 due primarily to a 51% decrease in operating days in 2009. Segment profits for this segment were 17% of revenues in 2009 compared to 31% in 2008.

 

General and Administrative Expenses.  General and administrative expenses decreased by 10% to $104.3 million in 2009 from $115.3 million in 2008, which included $5.2 million and $4.1 million of stock-based compensation expense in 2009 and 2008, respectively. The decrease from 2008 primarily reflects lower salary and office expenses related to the reduction in the number of employees along with pay reductions enacted at the end of the first quarter of 2009.

 

Depreciation and Amortization Expenses.  Depreciation and amortization expenses were $132.5 million in 2009, as compared to $118.6 million in 2008, reflecting the increase in the size of and investment in our asset base. We invested $7.8 million for acquisitions, $18.6 million for capital leases and an additional $43.4 million for cash capital expenditures in 2009.

 

Goodwill Impairment.  In the first half of 2009, we recorded a non-cash charge totaling $204.0 million for impairment of all of the goodwill associated with our well servicing, fluid services, and completion and remedial services segments as of March 31, 2009. In 2008, we recorded a $22.5 million non-cash charge for all of the goodwill associated with our contract drilling division.

 

Interest Expense.  Interest expense increased by 23% to $32.9 million in 2009 from $26.8 million in 2008. The increase was primarily due to the issuance of the $225.0 million of 11.625% Senior Secured Notes in July 2009, the proceeds of which were used to retire our $225.0 million revolving credit facility.

Income Tax Expense.  Income tax benefit was $87.5 million in 2009, as compared to an expense of $55.1 million in 2008. Our effective benefit rate was approximately 26% in 2009 and our effective tax rate was approximately 45% in 2008. The lower effective benefit rate in 2009 relates to the goodwill write-down in the first quarter of 2009 and is due to differences in the taxable nature of the impaired goodwill. A portion of the goodwill came from stock acquisitions, which have zero tax bases.

 

Liquidity and Capital Resources

 

Currently, our primary capital resources are net cash flows from our operations and utilization of capital leases. As of December 31, 2010, we had cash and cash equivalents of $47.9 million compared to $125.4 million as of December 31, 2009. 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.

 

Net Cash Provided by Operating Activities

 

Cash flow from operating activities was $49.4 million for the year ended December 31, 2010 as compared to $89.2 million in 2009 and $212.8 million in 2008. The decrease in 2010 was due primarily to the increase in accounts receivable generated during the year. The decrease in operating cash flows in 2009 compared to 2008 was primarily due to lower profitability being partially offset by the collection of accounts receivable generated in prior periods. .

 

Capital Expenditures

 

Capital expenditures are the main component of our investing activities. Cash capital expenditures (including for acquisitions) for 2010 were $113.9 million as compared to $51.2 million in 2009, and $202.8 million in 2008. In 2008, the majority of our capital expenditures were for business acquisitions. Through our capital lease program, we also added assets of approximately $23.4 million, $18.6 million and $50.7 million in 2010, 2009 and 2008, respectively.

 

In 2011, we have currently planned capital expenditures of approximately $136 million. We do not budget acquisitions in the normal course of business, and we regularly engage in discussions related to potential acquisitions related to the well services industry.

 

Capital Resources and Financing

 

Our current primary capital resources are cash flow from our operations, the ability to enter into capital leases and a cash balance of $47.9 million at December 31, 2010. In 2010, we financed activities in excess of cash flow from operations primarily through the use of bank debt and capital leases.

 

We have significant contractual obligations in the future that will require capital resources. Our primary contractual obligations are (1) our long-term debt, (2) interest on long-term debt, (3) our capital leases, (4) our operating leases, (5) our asset retirement obligations and (6) our other long-term liabilities. The following table outlines our contractual obligations as of December 31, 2010 (in thousands):

 

Our long-term debt as of December 31, 2010, excluding capital leases, consisted of our $225.0 million 7.125% Senior Notes and our $225.0 million 11.625% Senior Secured Notes. Interest on long-term debt relates to our future contractual interest obligations on our Senior Notes and our Senior Secured Notes. Please read “11.625% Senior Secured Notes due 2014” below for a discussion of recent events regarding the redemption and satisfaction and discharge of our Senior Secured Notes. Our capital leases relate primarily to light-duty and heavy-duty vehicles and trailers. Our operating leases relate primarily to real estate.

 

The table above does not reflect any additional payments that we may be required to make pursuant to contingent earn-out agreements that are associated with certain acquisitions. At December 31, 2010, we had a maximum potential obligation of $21.0 million related to the contingent earn-out agreements. See Note 3 of the notes to our historical consolidated financial statements for additional detail.

 

Our ability to access additional sources of financing will be dependent on our operating cash flows and demand for our services, which could be negatively impacted due to the extreme volatility of commodity prices.

 

7.125% Senior Notes due 2016

 

In April 2006, we completed the issuance and sale of $225 million aggregate principal amount of 7.125% Senior Notes due April 15, 2016 in a private placement. The Senior Notes are jointly and severally guaranteed by each of our restricted subsidiaries (currently all of our subsidiaries other than three immaterial subsidiaries). The net proceeds from the offering were used to retire the outstanding balance of our Term B Loan and to pay down the outstanding balance under our then-existing senior credit facility. Remaining proceeds were used for general corporate purposes, including acquisitions.