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

 

 

 

 

Form 10-K

 

 

Commission File Number 0-22664

 

 

 

 

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:

(281) 765-7100

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 þ     or No o

 

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     or 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 þ     or 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.  þ

 

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 Act).  Yes o     No þ

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010, the last business day of the registrant’s most recently completed second fiscal quarter, was $1,948,746,558, calculated by reference to the closing price of $12.87 for the common stock on the Nasdaq Global Select Market on that date.

 

As of February 11, 2011, the registrant had outstanding 154,203,597 shares of common stock, $.01 par value, its only class of common stock.

 

Documents incorporated by reference:

 

Portions of the registrant’s definitive proxy statement for the 2011 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

 

 

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

 

This Annual Report on Form 10-K (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional acquisitions (if further opportunities arise); impact of inflation; demand for our services; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts and often use words such as “believes,” “budgeted,” “continue,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act.

 

Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, deterioration of global economic conditions, declines in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates, utilization, margins and planned capital expenditures, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating acquisitions, shortages of equipment and materials, governmental regulation and ability to retain management and field personnel. Refer to “Risk Factors” contained in Part 1 of this Report for a more complete discussion of these and other factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise.

 

PART I

 

 

Available Information

 

This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our Internet website (www.patenergy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Overview

 

We own and operate one of the largest fleets of land-based drilling rigs in the United States. The Company was formed in 1978 and reincorporated in 1993 as a Delaware corporation. Our contract drilling business operates primarily in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada.

 

As of December 31, 2010, we had a drilling fleet that consisted of 356 marketable land-based drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. A drilling rig is considered marketable at a point in time if it is operating or can be made ready to operate without significant capital expenditures. We also have a substantial inventory of drill pipe and drilling rig components.

 

We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We also own and invest in oil and natural gas assets as a working interest owner. Our oil and natural gas working interests are located primarily in Texas and New Mexico.

 

Prior to January 20, 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. We sold our drilling and completion fluids services business on January 20, 2010.

 

On October 1, 2010 we acquired the assets and operations of a pressure pumping business and an electric wireline business. The electric wireline business that we acquired was classified as held for sale at December 31, 2010 and sold on January 27, 2011. The results of our drilling and completion fluids services business and our electric wireline business are presented as discontinued operations in this Report.

 

Industry Segments

 

Our revenues, operating profits and identifiable assets are primarily attributable to three industry segments:

 

 

All of our industry segments had operating profits in 2010 and 2008. In 2009, our pressure pumping services and oil and natural gas exploration and production segments had operating profits and our contract drilling services segment had an operating loss.

 

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 15 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments.

 

Contract Drilling Operations

 

General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2010, we had 356 marketable land-based drilling rigs based in the following regions:

 

 

Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,000 feet to 25,000 feet. Of these drilling rigs, 124 are electric rigs and 232 are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the diesel power (the sole energy source for a mechanical rig) into electricity to power the rig. We also have a substantial inventory of drill pipe and drilling rig components, which may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs.

 

Drilling rigs are typically equipped with engines, drawworks, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year as part of a program to modify, upgrade and maintain our drilling rigs to ensure that our drilling equipment is competitive. We have spent $1.4 billion during the last three years on capital expenditures to (1) build new land drilling rigs, and (2) modify, upgrade and maintain our drilling fleet. During fiscal years 2010, 2009 and 2008, we spent approximately $656 million, $395 million and $361 million, respectively, on these capital expenditures.

 

Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job.

 

Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts and other related rig equipment, fuel and qualified personnel. Some of these have been in short supply from time to time.

 

Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our drilling contracts are either on a well-to-well basis or a term basis. Well-to-well contracts are generally short-term in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently one to three years) and provide for the use of the drilling rig to drill multiple wells. During 2010, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 21 days.

 

Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of drilling personnel and necessary maintenance expenses. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for the payment of an early termination fee to us in the event that the contract is terminated by the customer. Generally, we indemnify our customers against claims by our employees and claims that might arise from surface pollution caused by spills of fuel, lubricants and other solvents within our control. Generally, the customers indemnify us against claims that might arise from other surface and subsurface pollution. Each drilling contract contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to industry conditions or other factors.

 

Our drilling contracts provide for payment on a daywork, footage or turnkey basis, or a combination thereof. In each case, we provide the rig and crews. Our bid for each job depends upon location, depth and anticipated complexity of the well, on-site drilling conditions, equipment to be used, estimated risks involved, estimated duration of the job, availability of drilling rigs and other factors particular to each proposed well.

 

Under daywork contracts, we provide the drilling rig and crew to the customer. The customer supervises the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are interrupted or restricted by adverse weather conditions or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. Except for two wells drilled under footage contracts in 2009, all of the wells we drilled in 2010, 2009 and 2008 were under daywork contracts.

 

Under footage contracts, we contract to drill a well to a certain depth under specified conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the agreed-upon depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling contractor typically assumes

certain risks associated with loss of the well from fire, blowouts and other risks. We drilled two wells under footage contracts in 2009, and we did not drill any wells under footage contracts in 2010 or 2008.

 

Under turnkey contracts, we contract to drill a well to a certain depth under specified conditions for a fixed fee. In a turnkey arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, casing, cementing, and the technical well design and engineering services during the drilling process. We also typically assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. Compensation occurs only when the agreed- upon scope of the work has been completed, which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. Given the increased exposure we have under a turnkey contract, however, profits can be significantly reduced and losses can be incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of drilling contracts. Although we have entered into turnkey contracts in the past, we did not enter into any turnkey contracts in the past three years.

 

Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows:

 

 

 

 

Drilling Rigs and Related Equipment — We estimate the depth capacity with respect to our marketable rigs as of December 31, 2010 to be as follows:

 

 

At December 31, 2010, we owned and operated 317 trucks and 402 trailers used to rig down, transport and rig up our drilling rigs. Our ownership of trucks and trailers reduces our dependency upon third parties for these services and generally enhances the efficiency of our contract drilling operations, particularly in periods of high drilling rig utilization.

 

Most repair and overhaul work to our drilling rig equipment is performed at our yard facilities located in Texas, Oklahoma, Wyoming, Utah, Pennsylvania and western Canada.

 

Pressure Pumping Operations

 

General — We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services consist of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require

well stimulation through fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well stimulation services. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing.

 

Equipment — Our pressure pumping equipment at December 31, 2010 includes equipment used in providing hydraulic and nitrogen fracturing services as well as nitrogen, cementing and acid pumping services as follows:

 

 

Our pressure pumping operations are supported by a fleet of equipment including blenders, tractors, manifold trailers and numerous trailers for transportation of materials to and from the worksite as well as bins for storage of materials at the worksite.

 

Oil and Natural Gas Interests

 

We own and invest in oil and natural gas assets as a working interest owner. Our oil and natural gas working interests are located primarily in producing regions of Texas and New Mexico.

 

Customers

 

The customers of each of our contract drilling and pressure pumping business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2010, no single customer accounted for 10% or more of our consolidated operating revenues.

 

Competition

 

Our contract drilling and pressure pumping businesses are highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand in our markets. The price for our services is a key competitive factor in our markets, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability and condition of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job in the markets in which we operate. We expect that the market for land drilling and pressure pumping services will continue to be highly competitive.

 

Government and Environmental Regulation

 

All of our operations and facilities are subject to numerous Federal, state, foreign, and local laws, rules and regulations related to various aspects of our business, including:

 

 

To date, applicable environmental laws and regulations in the United States and Canada have not required the expenditure of significant resources outside the ordinary course of business. We do not anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with

environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any new requirements could become material, and we could incur liability in any instance of noncompliance.

 

Our business is generally affected by political developments and by Federal, state, foreign, and local laws and regulations that relate to the oil and natural gas industry. The adoption of laws and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling and production, and otherwise have an adverse effect on our operations. Federal, state, foreign and local environmental laws and regulations currently apply to our operations and may become more stringent in the future. Any suspension or moratorium of the services we provide, whether or not short-term in nature, by a Federal, state, foreign or local governmental authority, could have a material adverse effect on our business, financial condition and results of operation.

 

We believe we use operating and disposal practices that are standard in the industry. However, hydrocarbons and other materials may have been disposed of, or released in or under properties currently or formerly owned or operated by us or our predecessors, which may have resulted, or may result, in soil and groundwater contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to remediation requirements under Federal, state, foreign and local laws and regulations. In addition, some of these properties have been operated by third parties over whom we have no control of their treatment of hydrocarbon and other materials or the manner in which they may have disposed of or released such materials. We could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, it is possible we could be held responsible for oil and natural gas properties in which we own an interest but are not the operator.

 

Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations.

 

In the United States, the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, commonly known as CERCLA, and comparable state statutes impose strict liability on:

 

 

The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.

 

The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern:

 

 

The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Penalties may also be imposed for violation of Federal safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.

 

The Oil Pollution Act also expands the authority and capability of the Federal government to direct and manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or into navigable waters. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same

under the Federal Water Pollution Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.

 

Our activities include the performance of hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shales. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the Federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production customers.

 

In Canada, a variety of Canadian federal, provincial and municipal laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws and regulations also require that facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment.

 

Our operations are also subject to Federal, state, foreign and local laws, rules and regulations for the control of air emissions, including the Federal Clean Air Act and the Canadian Environmental Protection Act. We are aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (GHG) emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the U.S. Environmental Protection Agency and the Canadian provinces of Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

 

Risks and Insurance

 

Our operations are subject to the many hazards inherent in the drilling business, including:

 

 

These and other hazards could cause:

 

 

Damage to the environment, including property contamination in the form of either soil or ground water contamination, could also result from our operations, including through:

 

 

We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. Such risks include personal injury, well disasters, extensive fire damage, damage to the environment, and other hazards. The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our rigs and other assets, employer’s liability, automobile liability, commercial general liability insurance, and workers compensation insurance. We cannot assure, 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 that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and other assets, such insurance does not cover the full replacement cost of the rigs or other assets, and we do not carry insurance against loss of earnings resulting from such damage. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our financial condition and results of operations.

 

In addition to insurance coverage, we also attempt to obtain indemnification from our customers for certain risks. These indemnity agreements typically require our customers to hold us harmless in the event of loss of production or reservoir damage. There is no assurance that we will obtain such contractual indemnity, and if obtained, whether such indemnity will be enforceable, whether the customer will be able to satisfy such indemnity or whether such indemnity will be supported by adequate insurance maintained by the customer.

 

Employees

 

We had approximately 7,000 full-time employees at December 31, 2010. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be satisfactory. None of our employees are represented by a union.

 

Seasonality

 

Seasonality does not significantly affect our overall operations. However, our drilling operations in Canada and, to a lesser extent, our pressure pumping operations in the Appalachian Basin, are subject to slow periods of activity during the annual Spring thaw.

 

Raw Materials and Subcontractors

 

We use many suppliers of raw materials and services. Although, these materials and services have historically been available, there is no assurance that such materials and services will continue to be available on favorable terms or at all. We also utilize numerous independent subcontractors from various trades.

 

 

You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks and uncertainties not presently known to us or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business and financial results could be harmed. You should also refer to the other information set forth in this Report, including our financial statements and the related notes.

 

Global Economic Conditions May Adversely Affect Our Operating Results.

 

Beginning in late 2008 and continuing through 2009, there was a substantial deterioration in the global economic environment. As part of this deterioration, there was substantial uncertainty in the capital markets and access to financing was reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services. Furthermore, these factors resulted in certain of our customers experiencing an inability to pay suppliers, including us. Although the significant deterioration in the global economic environment appeared to stabilize to some degree during 2010, there is no assurance that the global economic environment could not quickly deteriorate again due to one or more factors. A return of the conditions causing a deterioration in the global economic environment could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Oil and Natural Gas Prices Have Adversely Affected Our Operating Results.

 

Our revenue, profitability and cash flows are highly dependent upon prevailing prices for natural gas and oil. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by:

 

 

All of these factors are beyond our control. During 2008, the monthly average market price of natural gas (monthly average Henry Hub price as reported by the Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly declining to an average of $5.99 per Mcf in December. In 2009, the monthly average market price of natural gas declined further to a low of $3.06 per Mcf in September. The monthly average market price of natural gas has not recovered to levels experienced during early 2008 and was $4.38 per Mcf in December 2010. This volatility and the extended declines in the market price of natural gas resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low through 2009 before increasing somewhat in 2010. The increase in 2010 can be attributed partially to increased activity in oil rich basins as a result of the growing development of unconventional oil reservoirs and an improvement in the price of oil compared to 2009. Although our average number of rigs operating increased during 2010, it remains well below the number of our available rigs. Construction of new land drilling rigs in the United States during the last ten years has significantly contributed to excess capacity. As a result of decreased drilling activity and excess capacity, our average number of rigs operating has declined significantly from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for natural gas and oil would likely result in low demand for our drilling rigs and pressure pumping services and would adversely affect our operating results, financial condition and cash flows.

 

A General Excess of Operable Land Drilling Rigs, Increasing Rig Specialization and Excess Pressure Pumping Equipment May Adversely Affect Our Utilization and Profit Margins.

 

The North American land drilling industry has experienced periods of downturn in demand over the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins and, at times, have sustained losses during the downturn periods.

 

In addition, unconventional resource plays have substantially increased recently and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack of capability to successfully compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

 

 

Construction of new drilling rigs increased significantly during the last ten years. The addition of new drilling rigs to the market and the recent decrease in demand has resulted in excess capacity. Similarly, the substantial recent increase in unconventional resource plays has led to higher demand for pressure pumping services. As a result, we believe there has been, and we expect there to continue to be, a significant increase in the construction of new pressure pumping equipment. The addition of new pressure pumping equipment, as well as any general decline in demand for pressure pumping services, could result in there being substantially more pressure pumping equipment available than necessary to meet demand. If this were to occur, providers of pressure pumping services will have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict either the

future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses.

 

Shortages of Drill Pipe, Replacement Parts, Other Equipment and Materials Adversely Affect Our Operating Results.

 

During periods of increased demand for drilling and pressure pumping services, the industry has experienced shortages of drill pipe, replacement parts, other equipment and materials, including proppants and gels for our pressure pumping operations. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply due to vendor or other issues could result in significant delays in delivery of equipment and materials or prevent operations. These price increases and delays in delivery may require us to increase capital and repair expenditures and incur higher operating costs. Severe shortages or delays in delivery could limit our ability to operate our drilling rigs and pressure pumping equipment.

 

The Oil Service Business Segments in Which We Operate Are Highly Competitive with Excess Capacity, which Adversely Affects Our Operating Results.

 

Our land drilling and pressure pumping businesses are highly competitive. At times, available land drilling rigs and pressure pumping equipment exceed the demand for such equipment. This excess capacity has resulted in substantial competition for drilling and pressure pumping contracts. The fact that drilling rigs and pressure pumping equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

 

We believe that price competition for drilling and pressure pumping contracts will continue due to the existence of available rigs and pressure pumping equipment.

 

In recent years, many drilling and pressure pumping companies have consolidated or merged with other companies. Although this consolidation has decreased the total number of competitors, we believe the competition for drilling and pressure pumping services will continue to be intense.

 

Labor Shortages and Rising Labor Costs Adversely Affect Our Operating Results.

 

During periods of increasing demand for contract drilling and pressure pumping services, the industry experiences shortages of qualified personnel. During these periods, our ability to attract and retain sufficient qualified personnel to market and operate our drilling rigs and pressure pumping equipment is adversely affected, which negatively impacts both our operations and profitability. Operationally, it is more difficult to hire qualified personnel, which adversely affects our ability to mobilize inactive rigs and pressure pumping equipment in response to the increased demand for such services. Additionally, wage rates for drilling and pressure pumping personnel are likely to increase during periods of increasing demand, resulting in higher operating costs.

 

Growth Through the Building of New Rigs and Pressure Pumping Equipment and Rig and Other Acquisitions are Not Assured.

 

We have increased our drilling rig fleet and pressure pumping horsepower in the past through mergers, acquisitions and new construction. The land drilling and pressure pumping industries have experienced significant consolidation, and there can be no assurance that acquisition opportunities will be available in the future. We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved technology has enhanced the ability to recover oil and natural gas, contract drillers may continue to build new, high technology rigs and providers of pressure pumping services may continue to build new, high horsepower equipment.

 

There can be no assurance that we will:

 

 

 

We may incur substantial indebtedness to finance future acquisitions, build new drilling rigs or build new pressure pumping equipment and also may issue equity, convertible or debt securities in connection with any such acquisitions or building program. Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity would be dilutive to existing stockholders. Also, continued growth could strain our management, operations, employees and other resources.

 

The Nature of our Business Operations Presents Inherent Risks of Loss that, if not Insured or Indemnified Against, Could Adversely Affect Our Operating Results.

 

Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, which in turn could cause personal injury or death, work stoppage, or serious damage to our equipment. Our operations could also cause environmental and reservoir damages. We maintain insurance coverage and have indemnification agreements with many of our customers. However, there is no assurance that such insurance or indemnification agreements would be enforceable or adequately protect us against liability or losses from all consequences of these hazards. Additionally, there can be no assurance that insurance would be available to cover any or all of these risks, or, even if available, that insurance premiums or other costs would not rise significantly in the future, so as to make the cost of such insurance prohibitive. It is possible that a customer or insurer could fail or be unable to meet its indemnification or insurance obligations, which could result in a material loss. Moreover, we could suffer a material loss if we were to become subject to an unexpected judgment against us for which we are uninsured, for which indemnification is unenforceable or otherwise not available or that is beyond the amounts we reserved or anticipated incurring. Incurring a liability for which we are not fully insured or indemnified could materially affect our business, financial condition and results of operations.

 

We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we generally maintain a $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverages and a $2.0 million per occurrence self insured retention on our general liability insurance coverage.

 

Difficulties Integrating Our Recently Acquired Pressure Pumping Assets Could Adversely Affect Our Operating Results.

 

We expect that our recently acquired pressure pumping assets will complement and expand our business. Successfully integrating the acquired business depends on our ability to integrate the acquired assets and personnel and to maintain and grow the acquired customer base. We may encounter challenges in integrating the acquired business with our existing operations and management. We may not be able to fully take advantage of expected business opportunities, including successfully developing new markets and retaining acquired customers. The integration of the new business may place additional strain on our management. In addition, the acquired business may not achieve anticipated results. If the acquired business is not successfully integrated, our operating results could be adversely affected.

 

We are Dependent Upon our Subsidiaries to Meet our Obligations Under our Long Term Debt

 

We have borrowings outstanding under a term loan and our senior notes. These obligations are guaranteed by each of our existing subsidiaries other than immaterial subsidiaries. Our ability to meet our interest and principal payment obligations depends in large part on dividends paid to us by our subsidiaries. If our subsidiaries do not

generate sufficient cash flows to pay us dividends, we may be unable to meet our interest and principal payment obligations.

 

Environmental Laws and Regulations, Including Violations Thereof Could Materially Adversely Affect Our Operating Results.

 

All of our operations and facilities are subject to numerous Federal, state, foreign and local environmental laws, rules and regulations, including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance with these laws and regulations could be substantial. A failure to comply with these requirements could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States and Canada impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs and pressure pumping equipment, we may be deemed to be a responsible party under these laws and regulations.

 

Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Result in Operational Delays.

 

Members of the U.S. Congress and the U.S. Environmental Protection Agency (the “EPA”) are reviewing more stringent regulation of hydraulic fracturing, a technology employed by our pressure pumping business, which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Both the EPA and the U.S. Congress are studying whether there is any link between hydraulic fracturing activities and soil or ground water contamination. As part of their respective studies, the House Subcommittee on Energy and Environment and the EPA each sent requests to a number of companies, including our company for information on their hydraulic fracturing practices. We have responded to each of the inquiries. In addition, legislation has been proposed in the U.S. Congress to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing ground water or causing other damage. These bills, if adopted, could establish an additional level of regulation at the federal or state level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Certain states have adopted or are considering similar disclosure legislation. Additional regulation could increase the costs of conducting our business and could materially reduce our business opportunities and revenues if our customers decrease their levels of activity in response to such regulation.

 

Legislation and Regulation of Greenhouse Gases Could Adversely Affect our Business

 

We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the Canadian provinces of Alberta and British Columbia. In 2007, the U.S. Supreme Court in Massachusetts, et al. v. Environmental Protection Agency held that carbon dioxide, a GHG, may be regulated as an “air pollutant” under the Clean Air Act, which could result in future regulations even if the U.S. Congress does not enact new legislation regarding such emissions. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

 

Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby Affect the Related Purchase Price.

 

We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law. We have also enacted certain anti-takeover measures, including a stockholders’ rights plan. In

addition, our Board of Directors has the authority to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. As a result of these measures and others, potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions.

 

 

None.

 

 

Our corporate headquarters comprises approximately 12,000 square feet of leased office space, and is located at 450 Gears Road, Suite 500, Houston, Texas. Our telephone number at that address is (281) 765-7100. Our primary administrative office is located in Snyder, Texas and includes approximately 37,000 square feet of office and storage space.

 

Contract Drilling Operations — Our drilling services are supported by several offices and yard facilities located throughout our areas of operations, including Texas, New Mexico, Oklahoma, Colorado, Utah, Wyoming, Pennsylvania and western Canada.

 

Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our areas of operations including Texas, Pennsylvania, Ohio, West Virginia, Kentucky, Tennessee and Colorado.

 

Oil and Natural Gas Working Interests — Our interests in oil and natural gas properties are primarily located in Texas and New Mexico.

 

We own our administrative offices in Snyder, Texas, as well as several of our other facilities. We also lease a number of facilities, and we do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to meet our needs.

 

 

We are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our results of operations, cash flows or financial condition.

 

 

PART II

 

 

 

Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol “PTEN.” Our common stock is included in the S&P MidCap 400 Index and several other market indices. The following table provides high and low sales prices of our common stock for the periods indicated:

 

 

 

As of February 11, 2011, there were approximately 1,500 holders of record of our common stock.

 

 

We paid cash dividends during the years ended December 31, 2009 and 2010 as follows:

 

 

On February 2, 2011, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on March 30, 2011 to holders of record as of March 15, 2011. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

 

Equity compensation plan information as of December 31, 2010 follows:

 

 

 

 

 

The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2005 through December 31, 2010, with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group determined by us. Our peer group consists of BJ Services Company, Bronco Drilling Company, Inc., Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Drilling Co., Precision Drilling Corp and Superior Well Services, Inc. All of the companies in our peer group are providers of land-based drilling or pressure pumping services. BJ Services Company and Superior Well Services, Inc. were acquired by Baker Hughes, Inc. and Nabors Industries, Ltd., respectively during 2010. The graph assumes investment of $100 on December 31, 2005 and reinvestment of all dividends.

 

 

 

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 Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act.

 

 

Our selected consolidated financial data as of December 31, 2010, 2009, 2008, 2007 and 2006, and for each of the five years in the period ended December 31, 2010 should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. Certain reclassifications have been made to the historical financial data to conform with the 2010 presentation. Due to the sale of our drilling and completion fluids business in January 2010 and the sale of our electric wireline business in January

2011, the results of operations for those businesses have been reclassified and are presented as discontinued operations in all periods presented below.

 

 

 

Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and, to a lesser extent, pressure pumping services. In addition to the aforementioned contract services, we also invest, on a working interest basis, in oil and natural gas properties. For the three years ended December 31, 2010, our operating revenues consisted of the following (dollars in thousands):

 

 

We provide our contract services to oil and natural gas operators in many of the oil and natural gas producing regions of North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada, while our pressure pumping services are focused primarily in Texas and the Appalachian Basin. The oil and natural gas properties in which we hold interests are primarily located in Texas and New Mexico.

 

Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During 2010, our average number of rigs operating was 168 compared to 91 in 2009 and 254 in 2008. Our average revenue per operating day was $17,670 in 2010 compared to $17,950 in 2009 and $19,380 in 2008. We had consolidated net income of $117 million for 2010 compared to a consolidated net loss of $38.3 million for 2009. The increase in consolidated net income was primarily due to our contract drilling segment experiencing an increase in the average number of rigs operating. Additionally, our pressure pumping segment experienced an increase in large multi-stage fracturing jobs in 2010 compared to 2009. This increase includes the fourth quarter contribution of a pressure pumping business we acquired on October 1, 2010, which significantly expanded our pressure pumping operations into new markets in the fourth quarter of 2010.

 

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for natural gas and oil. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our contract services. Conversely, in periods when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. After reaching a peak in June 2008, there was a significant decline in oil and natural gas prices and a substantial deterioration in the global economic environment. As part of this deterioration, there was substantial uncertainty in the capital markets and access to financing was reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average number of rigs operating from a high of 283 in October 2008 to a low of 60 in June 2009. Our monthly average number of rigs operating has subsequently increased from the mid-year low in 2009 to 196 in December 2010. The decline in commodity prices and deterioration in the global economy resulted in certain of our customers experiencing an inability to pay suppliers, including us. We are also highly impacted by competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” in Item 1A of this Report.

 

We believe that our liquidity as of December 31, 2010, which includes approximately $241 million in working capital and approximately $359 million available under our $400 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities borrowing capacity under our revolving

credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

 

Commitments and Contingencies — As of December 31, 2010, we maintained letters of credit in the aggregate amount of $41.2 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2010, no amounts had been drawn under the letters of credit.

 

As of December 31, 2010, we had commitments to purchase approximately $267 million of major equipment.

 

Trading and investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

 

Description of business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, Pennsylvania, West Virginia and western Canada. For the years ended December 31, 2010, 2009 and 2008, revenue earned in Canada was $65.7 million, $45.4 million and $88.5 million, respectively. Additionally, we had long-lived assets located in Canada of $70.7 million and $69.2 million as of December 31, 2010 and 2009, respectively. As of December 31, 2010, we had 356 marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for completion of new wells and remedial work on existing wells. We also invest, on a working interest basis, in oil and natural gas properties.

 

Critical Accounting Policies

 

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, oil and natural gas properties, goodwill, revenue recognition and the use of estimates.

 

Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances indicate that the carrying values of certain assets may not be recovered over their estimated remaining useful lives. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will continue to fluctuate. Based on management’s expectations of future trends, we estimate future cash flows over the life of the respective assets in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured based on discounted cash flows.

 

On a periodic basis, we evaluate our fleet of drilling rigs for marketability. In connection with our long term planning process, we evaluated our then-current fleet of marketable drilling rigs in 2010, 2009 and 2008 and identified four, 23 and 22 rigs, respectively, that we determined would no longer be marketed as rigs. The components comprising these rigs were evaluated, and those components with continuing utility to our other marketed rigs were transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs were impaired and the associated net book value of $4.2 million in 2010, $10.5 million in 2009 and $10.4 million in 2008 was expensed in our consolidated statements of operations as an impairment charge.

In late 2008, we experienced a significant decrease in the number of our rigs operating and oil and natural gas prices decreased significantly. These events were deemed by us to be triggering events that required us to perform an assessment with respect to impairment of long-lived assets, including property and equipment, in our contract drilling segment. With respect to these long-lived assets, we estimated future cash flows over the expected life of the long-lived assets, which were comprised primarily of property and equipment, and determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets. Based on this assessment, no impairment was indicated in 2008. Due to a continued decrease in the operating levels in our contract drilling segment through the first three quarters of 2009, we again deemed it necessary to perform an impairment assessment of long-lived assets in our contract drilling segment in 2009. Based on the estimated undiscounted cash flows associated with the assets, we determined that no impairment was indicated in 2009. In light of the recent favorable trends in rig utilization and revenue per operating day experienced by us and our peers, we concluded that no triggering event had occurred in 2010 with respect to our contract drilling segment. We also concluded that no triggering event had occurred with respect to our pressure pumping segment in 2010, 2009 or 2008. Impairment considerations related to our oil and natural gas segment are discussed below.

 

Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. Costs of exploratory wells are initially capitalized to wells-in-progress until the outcome of the drilling is known. We review wells-in-progress quarterly to determine whether sufficient progress is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, we consider the well costs to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized on the units-of-production method, based on engineering estimates of proved oil and natural gas reserves for each respective field.

 

We review our proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our expectation of future commodity prices over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and discounted cash flow. The discounted cash flow estimates used in measuring impairment are based on our expectations of future commodity prices over the life of the respective field. We review unproved oil and natural gas properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately $792,000, $3.7 million and $4.4 million for the years ended December 31, 2010, 2009 and 2008, respectively, and is included in depreciation, depletion and impairment in the accompanying consolidated statements of operations.

 

Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. We assess impairment of our goodwill annually as of December 31, or on an interim basis if events or circumstances indicate that the fair value of goodwill may have decreased below its carrying value. Goodwill impairment testing is performed at the level of our reporting units. Our reporting units have been determined to be the same as our operating segments.

 

In connection with our annual impairment assessment of goodwill, we compare the fair value of the reporting unit with its carrying value. If the fair value exceeds the carrying value, no impairment is indicated. If the carrying value exceeds the fair value, we measure any impairment of goodwill in that reporting unit by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on their respective fair values. Any excess

unallocated fair value would equal the implied fair value of goodwill, and if that amount is below the carrying value of goodwill, an impairment charge is recognized.

 

In connection with our annual goodwill impairment assessment performed as of December 31, 2008, we performed an impairment test of goodwill recorded in our contract drilling and drilling and completion fluids reporting units. In light of the adverse market conditions affecting our common stock price beginning in the fourth quarter of 2008 and continuing into 2009, including a significant decrease in the average number of our rigs operating and a significant decline in oil and natural gas commodity prices, we utilized a discounted cash flow methodology to estimate the fair values of our reporting units. In completing the first step of our analysis, we used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of our reporting units. In developing these fair value estimates, we applied key assumptions, including an assumed discount rate of 13.99% for all reporting units, an assumed long-term growth rate of 3.50% for the contract drilling reporting unit and an assumed long-term growth rate of 2.00% for the drilling and completion fluids reporting unit.

 

Based on the results of the first step of the impairment test in 2008, we concluded that no impairment was indicated in our contract drilling reporting unit as the estimated fair value of that reporting unit exceeded its carrying value. However, an impairment was indicated in our drilling and completion fluids reporting unit as the estimated fair value of that reporting unit was less than its carrying value. In validating this conclusion, we considered the results of our long-lived asset impairment tests and performed sensitivity analyses of the key assumptions used in deriving the respective fair values of our reporting units. We then performed the second step of the analysis of our drilling and completion fluids reporting unit, which included allocating the estimated fair value to the identifiable tangible and intangible assets and liabilities of this reporting unit based on their respective values. This allocation indicated no residual value for goodwill, and accordingly we recorded an impairment charge of approximately $10.0 million in our December 31, 2008 statement of operations. We exited the drilling and completion fluids business on January 20, 2010, and the 2008 impairment charge is included in our loss from discontinued operations in our statement of operations for the year ended December 31, 2008.

 

We performed our annual goodwill impairment assessment as of December 31, 2009 related to the $86.2 million in goodwill recorded in our contract drilling reporting unit. In completing the first step of our analysis, we used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of the reporting unit. In developing this fair value estimate, we applied key assumptions, including an assumed discount rate of 15.42% and an assumed long-term growth rate of 3.50%. Based on the results of the first step of the impairment test in 2009, we concluded that no impairment was indicated in our contract drilling reporting unit as the estimated fair value of that reporting unit exceeded its carrying value.

 

We performed our annual goodwill impairment assessment as of December 31, 2010. In completing the first step of our analysis, we estimated our enterprise value based on our market capitalization as determined by reference to the closing price of our common stock during the fifteen days before and after year end. We allocated the enterprise value to our reporting units and determined that the fair values of our reporting units were in excess of their carrying value. As a result, we concluded that no impairment of goodwill was indicated as of December 31, 2010.

 

During the fourth quarter of 2010, we recorded goodwill in our pressure pumping reporting unit in connection with our acquisition of a pressure pumping business. The goodwill associated with this acquisition was estimated to be $67.6 million.

 

In the event that market conditions weaken, we may be required to record an impairment of goodwill in our contract drilling or pressure pumping reporting units in the future, and such impairment could be material.

 

Revenue recognition — Revenues are recognized when services are performed, except for revenues earned under turnkey contract drilling arrangements which are recognized using the completed-contract method of accounting. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. Due to the nature of turnkey contract drilling arrangements and the risks therein, we follow the completed-contract method of accounting for such arrangements.

Under this method, revenues and expenses related to a well-in-progress are deferred and recognized in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total expenses are expected to exceed total revenues. We recognize as revenue reimbursements received from third parties for out-of-pocket expenses and account for those out-of-pocket expenses as direct costs. Except for two wells drilled under footage contacts in 2009, all of the wells we drilled in 2010, 2009 and 2008 were drilled under daywork contracts.

 

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

 

Key estimates used by management include:

 

 

For additional information on our accounting policies, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

 

Liquidity and Capital Resources

 

As of December 31, 2010, we had working capital of $241 million, including cash and cash equivalents of $27.6 million. During 2010, our sources of cash flow included:

 

 

During 2010, we used $238 million to acquire pressure pumping and electric wireline businesses, $30.8 million to pay dividends on our common stock, $10.8 million to pay debt issuance costs, $1.9 million to repurchase shares of our common stock and $738 million:

 

 

We paid cash dividends during the year ended December 31, 2010 as follows:

 

 

On February 2, 2011, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on March 30, 2011 to holders of record as of March 15, 2011. The amount and timing of all future dividend payments, if any, is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

 

On August 1, 2007, our Board of Directors approved a stock buyback program, authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. During the year ended December 31, 2010, we purchased 8,743 shares of our common stock under this program at a cost of approximately $123,000. As of December 31, 2010, we are authorized to purchase approximately $113 million of our outstanding common stock under this program.

 

On August 19, 2010, we entered into a Credit Agreement (the “2010 Credit Agreement”). The 2010 Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The 2010 Credit Agreement replaced a previous unsecured revolving credit facility.

 

The revolving credit facility permits aggregate borrowings of up to $400 million and contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million. Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility be increased by up to $100 million, not to exceed total commitments of $500 million. The maturity date for the revolving credit facility is August 19, 2013.

 

The term loan facility provided for a loan of $100 million which was funded on August 19, 2010. The term loan facility is payable in quarterly principal installments commencing November 19, 2010, and the installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the next subsequent three quarterly installments, and the remainder due at maturity. The maturity date for the term loan facility is August 19, 2014.

 

Loans under the 2010 Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate. The applicable margin on LIBOR rate loans varies from 2.75% to 3.75% and the applicable margin on base rate loans varies from 1.75% to 2.75%, in each case determined based upon our debt to capitalization ratio. As of December 31, 2010, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee payable to the lenders for the unused portion of the revolving credit facility varies from 0.50% to 0.75% based upon our debt to capitalization ratio and was 0.50% as of December 31, 2010.

 

The 2010 Credit Agreement contains customary representations, warranties, indemnities and affirmative and negative covenants. The 2010 Credit Agreement also requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45% at any time. The 2010 Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The 2010 Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these financial covenants as of December 31,

2010. We do not expect that the restrictions and covenants will impair our ability to operate or react to opportunities that might arise.

 

As of December 31, 2010, we had $98.8 million principal amount outstanding under the term loan facility at an interest rate of 3.125% and no borrowings outstanding under the revolving credit facility. We had $41.2 million in letters of credit outstanding at December 31, 2010, and as a result, we had available borrowing capacity of approximately $359 million at that date.

 

On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Notes”) in a private placement. A portion of the proceeds from the Notes was used to repay a $200 million borrowing on our revolving credit facility, which had been drawn to fund a portion of a business acquisition that closed on October 1, 2010.

 

The Notes bear interest at a rate of 4.97% per annum and were priced at 100% of the principal amount of the Notes. We will pay interest on the Notes on April 5 and October 5 of each year commencing on April 5, 2011. The Notes will mature on October 5, 2020. The Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the Notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreement. We must offer to prepay the Notes upon the occurrence of any change of control. In addition, we must offer to prepay the Notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid Note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

 

The note purchase agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreement generally defines the interest coverage ratio as the ratio for the four prior quarters of EBITDA to interest charges for the same period. We were in compliance with these financial covenants as of December 31, 2010. We do not expect that the restrictions and covenants will impair our ability to operate or react to opportunities that might arise.

 

Events of default under the note purchase agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then holders of a majority in principal amount of the Notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if we default in payments on any Note, then until such defaults are cured, the holder thereof may declare all the Notes held by it to be immediately due and payable.

 

We believe that our current level of cash, short-term investments and borrowing capacity available under our revolving credit facility, together with cash expected to be generated from our operating activities, should be sufficient to fund our current plans to build new equipment, make improvements to our existing equipment and pay cash dividends.

 

From time to time, opportunities to expand our business, including acquisitions and the building of new equipment, are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Contractual Obligations

 

The following table presents information with respect to our contractual obligations as of December 31, 2010 (dollars in thousands):

 

 

 

 

Off-Balance Sheet Arrangements

 

We had no off-balance sheet arrangements at December 31, 2010.

 

Results of Operations

 

Comparison of the years ended December 31, 2010 and 2009

 

The following tables summarize operations by business segment for the years ended December 31, 2010 and 2009:

 

The demand for our contract drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States in recent years has also contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas and oil for each of the fiscal quarters and full year in 2010 and 2009 follows:

 

 

 

 

Revenues and direct operating costs increased in 2010 compared to 2009 as a result of an increase in the number of operating days. The increase in operating days was due to increased demand largely caused by higher prices for natural gas and oil. Our average number of rigs operating during 2009 included an average of approximately six rigs operating under term contracts that earned standby revenues of $22.3 million. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. We had no significant standby revenue associated with rigs operating under term contracts in 2010. We recognized approximately $8.0 million of revenues during 2009 from the early termination of term contracts. We had no such revenue from the early termination of term contracts in 2010. Selling, general and administrative expenses increased in 2010 primarily as a result of increased personnel costs to support increased activity levels. Significant capital expenditures were incurred in 2010 and 2009 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of capital expenditures. Depreciation and impairment expense includes approximately $4.2 million in 2010 and approximately $10.5 million in 2009 of impairment charges related to drilling equipment on drilling rigs that were removed from our marketable fleet. We removed four rigs from our marketable fleet in 2010 and removed 23 rigs from our marketable fleet in 2009.

 

Revenues and direct operating costs increased primarily as a result of the increase in the number of larger multi-stage fracturing jobs, which was driven by higher demand for services associated with unconventional reservoirs. Also contributing to these increases was our acquisition of a pressure pumping business on October 1, 2010 which significantly expanded the size of our fleet of pressure pumping equipment and the markets in which we provide pressure pumping services. This acquisition was accounted for as a business combination and the results of operations of the acquired business are included in our pressure pumping segment results from the date of acquisition. The acquired business contributed revenue of $84.7 million and operating income of $22.8 million to our operating results during the year ended December 31, 2010.

 

Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. As a result, we have experienced an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Average revenue per other job increased as a result of increased pricing for the services provided and a change in job mix. Selling, general and administrative expenses in 2010 include $1.5 million associated with the acquired business. The remaining increase in selling, general and administrative expenses is due to additional costs necessary to support increased business activity in 2010. Significant capital expenditures have been incurred in recent years to add capacity in our pressure pumping segment. Depreciation and amortization expense in 2010 includes $1.0 million in amortization of intangible assets and $4.7 million in depreciation of property and equipment associated with the acquired business. The remaining increase in depreciation in 2010 compared to 2009 is a result of our recent capital expenditures.

 

 

Revenues increased due to higher average sales prices of oil and natural gas and increased oil production partially offset by a decline in natural gas production. Average net daily oil production increased primarily due to the addition of new wells. Average net daily natural gas production decreased primarily due to production declines on existing wells. Depreciation, depletion and impairment expense in 2010 includes approximately $792,000 of oil and natural gas property impairments compared to approximately $3.7 million of oil and natural gas property impairments in 2009. Depletion expense increased approximately $915,000 in 2010 compared to 2009. Capital expenditures increased in 2010 as a result of greater drilling activity and increased costs per well.

 

Selling, general and administrative expense increased in 2010 primarily as a result of increased personnel costs. The provision for bad debts in 2009 resulted from an increase in our reserve on specific account balances based on the deteriorating economic and credit environment at the time. The negative provision for bad debts in 2010 is the result of reductions in our reserve for specific accounts due to improved industry conditions. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on asset disposals in 2010 includes a gain of $20.1 million related to the sale of certain rights to explore and develop zones deeper than depths that we generally target for certain of the oil and natural gas properties in which we have working interests. Losses on asset disposals in 2009 were primarily related to the disposal of contract drilling equipment. Acquisition-related expenses in 2010 were incurred in connection with the acquisition of pressure pumping and electric wireline businesses during the fourth quarter of 2010. These expenses included certain legal and other professional fees directly related to the transaction, fees incurred in connection with the title transfers of the acquired equipment and transition costs related to information technology. Interest income increased due to the collection of interest on a customer account as well as interest received on prior overpayments of sales taxes in certain jurisdictions. Interest expense in 2010 includes $3.3 million due to the recognition of remaining deferred financing costs associated with a revolving credit facility that was replaced in August 2010, and $1.3 million due to the recognition of financing costs associated with a bridge facility that expired unused on September 30, 2010. The remainder of the 2010 increase relates to interest charges and the amortization of debt issuance costs associated with the $100 million term loan entered into in August 2010 and the $300 million Senior Notes issued in October 2010. Capital expenditures increased in 2010 due to the ongoing implementation of a new enterprise resource planning system.

 

 

On January 27, 2011, we sold our electric wireline business, which had been acquired by us on October 1, 2010. The results of operations of this business have been classified as a discontinued operation and the assets held for sale at December 31, 2010 are presented at net realizable value in the consolidated balance sheet. On January 20, 2010, we sold our drilling and completion fluids services business which had previously been presented as one of our reportable operating segments. Due to our exit from this business, we have classified our drilling and completion fluids operating segment as a discontinued operation. Impairment of assets held for sale in 2010 and 2009 reflects the transaction-related costs recorded to reduce the carrying value of the assets sold to their net realizable value at December 31, 2010, and 2009.

Comparison of the years ended December 31, 2009 and 2008

 

The following tables summarize operations by business segment for the years ended December 31, 2009 and 2008:

 

 

The demand for our contract drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States in recent years has also contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas and oil for each of the fiscal quarters and full year in 2009 and 2008 follow:

 

 

 

 

Revenues and direct operating costs decreased in 2009 compared to 2008 primarily as a result of a decrease in the number of operating days. The decrease in operating days was due to decreased demand largely caused by lower commodity prices for natural gas and oil. Our average number of rigs operating during 2009 included an average of approximately six rigs operating under term contracts that earned standby revenues of $22.3 million. This represented an increase from an average of approximately one rig operating under a term contract that earned standby revenues of $4.7 million in 2008. Rigs on standby earn a discounted dayrate as they do not have crews and have lower costs. We recognized approximately $8.0 million of revenues during 2009 from the early termination of drilling contracts compared to approximately $1.3 million in 2008. Average revenue per operating day decreased in 2009 primarily due to decreases in dayrates for rigs that were operating in the spot market and the expiration of term contracts that were entered into at higher rates. Average direct operating costs per operating day decreased in 2009 primarily due to decreases in labor and repair costs. Significant capital expenditures were incurred in 2009 and 2008 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation expense increased as a result of those capital expenditures. Depreciation and impairment

expense includes approximately $10.5 million in 2009 and approximately $10.4 million in 2008 of impairment charges related to drilling equipment on drilling rigs that were removed from our marketable fleet. We removed 23 rigs from our marketable fleet in 2009 and removed 22 rigs from our marketable fleet in 2008.

 

 

Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. As a result, we have experienced an increase in the number of these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. In 2009 we experienced a decrease in smaller traditional pressure pumping jobs due to depressed commodity prices, which contributed to the overall decrease in revenue and direct operating costs. In anticipation of increased activity associated with the unconventional reservoirs in the Appalachian Basin, we added facilities, equipment and personnel. Delays in the development of these reservoirs and lower commodity prices caused a slower increase in customer activity than we had expected, negatively impacting the profitability of this business. Significant capital expenditures have been incurred in recent years to add capacity. Depreciation expense increased as a result of our recent capital expenditures.

 

 

Revenues decreased due to lower average sales prices and lower average net daily production of oil and natural gas. Average net daily oil and natural gas production decreased primarily due to production declines on existing wells. Direct operating costs decreased primarily due to decreases in seismic expenses as well as decreased production taxes and other production costs. Depreciation, depletion and impairment expense in 2009 includes approximately $3.7 million of oil and natural gas property impairments compared to approximately $4.4 million of oil and natural gas property impairments in 2008. Depletion expense decreased approximately $2.3 million

primarily due to lower production and the impact of decreases in the carrying value of properties resulting from previous impairment charges. Capital expenditures decreased in 2009 as a result of declines in commodity prices.

 

 

Selling, general and administrative expense increased in 2009 primarily as a result of increased professional fees. The provision for bad debts resulted from an increase in our reserve on specific account balances based on the deteriorating economic and credit environment in 2008 and 2009. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. Losses on asset disposals in 2009 were primarily related to the disposal of contract drilling equipment. Gains on asset disposals in 2008 were primarily related to gains on the sale of contract drilling equipment and the sale of oil and natural gas properties. Interest expense increased in 2009 due to the amortization of debt issuance costs and increased fees associated with outstanding letters of credit and the unused portion of the revolving credit facility that was put into place in 2009. Capital expenditures increased in 2009 due to the purchase and ongoing implementation of a new enterprise resource planning system.

 

 

On January 20, 2010, we exited our drilling and completion fluids services business, which had previously been presented as one of our reportable operating segments. Due to our exit from this business, we have classified our drilling and completion fluids operating segment as a discontinued operation. Accordingly, the assets and liabilities of this business, along with its results of operations, were reclassified for all periods presented. Drilling and completion fluids revenue and direct operating costs decreased in 2009 due to decreased sales volume both on land and offshore in the Gulf of Mexico. Drilling and completion fluids selling, general and administrative expenses decreased in 2009 primarily due to a decrease in compensation costs for sales and support personnel due to headcount reductions. Goodwill impairment was recognized in the drilling and completion fluids reporting unit in 2008 as a result of our annual impairment testing which indicated that the fair value of goodwill in that reporting unit was zero. Impairment of assets held for sale in 2009 of $1.9 million represents the transaction-related costs recorded to reduce the carrying value of the assets sold to their net realizable value at December 31, 2009. In 2008,

income tax expense was recognized despite a pre-tax loss in the drilling and completion fluids business due to the fact that the goodwill impairment recorded in that year was not deductible for tax purposes.

 

Income Taxes

 

 

The effective tax rate is a result of a Federal rate of 35.0% adjusted as follows:

 

 

For 2008, the permanent difference indicated above was largely attributable to our Domestic Production Activities Deduction. The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008) and allows a deduction of 6% in both 2008 and 2009 and 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent differences for 2010 and 2009 reflect the recapture of a portion of this deduction due to the planned carryback of the 2010 net operating loss to prior years and the carryback of the 2009 net operating loss to prior years. This recapture resulted in a negative effective rate impact in 2009 due to the Company having a loss before income taxes in that year.

 

We record deferred Federal income taxes based primarily on the temporary differences between the book and tax bases of our assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as these benefits are utilized. We recognized deferred tax expense of approximately $147 million in 2010, $101 million in 2009 and $65.4 million in 2008.

 

On January 1, 2010, we converted our Canadian operations from a Canadian branch to a controlled foreign corporation for Federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets.

 

As a result of the above conversion, our Canadian assets are no longer subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted earnings in Canada, and intend to do so for the foreseeable future. As a result, no deferred United States Federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $6.3 million as of December 31, 2010.

 

Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition

 

Our revenue, profitability, financial condition and rate of growth are substantially dependent upon prevailing prices for natural gas and oil. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by market supply and demand factors as well as international military, political and economic conditions, and the ability of OPEC to set and maintain production and price targets. All of these factors are beyond our control. During 2008, the monthly average market price of natural gas (monthly average Henry Hub price as reported by the United States Energy Information Administration) peaked in June at $13.06 per Mcf before rapidly

declining to an average of $5.99 per Mcf in December. In 2009, the monthly average market price of natural gas declined further to a low of $3.06 per Mcf in September. This decline in the market price of natural gas resulted in our customers significantly reducing their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009 before recovering somewhat in 2010. Construction of new land drilling rigs in the United States during the last ten years has significantly contributed to excess capacity. As a result of these factors, our average number of rigs operating has declined significantly from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for natural gas and oil would likely result in lower demand for our drilling rigs and pressure pumping services and adversely affect our operating results, financial condition and cash flows.

 

The North American land drilling industry has experienced downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs available than necessary to meet demand. As a result, drilling contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

 

Impact of Inflation

 

Inflation has not had a significant impact on our operations during the three years in the period ended December 31, 2010. We believe that inflation will not have a significant near-term impact on our financial position.

 

Recently Issued Accounting Standards

 

In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Prior to this new standard, generally accepted accounting principles required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. This new standard is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. This new standard became effective for us on January 1, 2010. The adoption of this standard did not impact our consolidated financial statements.

 

In October 2009, the FASB issued a new accounting standard that addresses the accounting for multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately rather than as a combined unit. This new standard addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing accounting standards require a vendor to use objective and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a multiple-deliverable arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be separated in more circumstances than under current requirements. The new standard establishes a hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to multiple deliverables. The selling price used will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific objective evidence nor third-party evidence is available. The new standard must be prospectively applied to all revenue arrangements entered into in fiscal years beginning on or after June 15, 2010 and became effective for us on January 1, 2011. The adoption of this standard did not have a material impact on our consolidated financial position, results of operations or cash flows.

 

In December 2010, the FASB issued an accounting standard update that addresses the disclosure of supplementary pro forma information for business combinations. This update clarifies that when public entities are required to disclose pro forma information for business combinations that occurred in the current reporting period, the pro forma information should be presented as if the business combination occurred as of the beginning of the previous fiscal year when comparative financial statements are presented. This update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period

beginning on or after December 15, 2010. Early adoption is permitted. We elected to early adopt this update and this early adoption did not have an impact on our consolidated financial position, results of operations or cash flows.

 

 

We currently have exposure to interest rate market risk associated with any borrowings that we have under our term credit facility or our revolving credit facility. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.75% to 3.75% and the margin on base rate loans ranges from 1.75% to 2.75%, based on our debt to capitalization ratio. At December 31, 2010, the margin on LIBOR loans was 2.75% and the margin on base rate loans was 1.75%. As of December 31, 2010, we had no borrowings outstanding under our revolving credit facility and $98.8 million outstanding under our term credit facility at an interest rate of 3.125%. The interest rate on the borrowing outstanding under our term credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate. A one percent increase in the interest rate on the borrowing outstanding under our term credit facility as of December 31, 2010 would increase our annual cash interest expense by $987,500.

 

We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars.

 

The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items.

 

 

Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference.

 

 

None.

 

 

Disclosure Controls and Procedures:

 

Under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2010, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

 

Management’s Report on Internal Control over Financial Reporting:

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2010, based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting was effective as of December 31, 2010.

Our wholly-owned subsidiaries, Universal Pressure Pumping, Inc. (“UPP”) and Universal Wireline, Inc. (“UWL”), were excluded from our evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2010. UPP and UWL were formed in 2010 for the purpose of acquiring the assets of pressure pumping and wireline businesses in a business acquisition which closed on October 1, 2010. These subsidiaries were excluded from the scope of our review due to the fact that the acquisition closed in the fourth quarter of 2010, at which time we began integrating the acquired businesses into our existing internal controls over financial reporting. The acquired businesses represented approximately 6 percent of consolidated revenues for the year ended December 31, 2010 and approximately 9 percent of consolidated total assets as of December 31, 2010.

 

The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of this Report.

 

Changes in Internal Control over Financial Reporting:

 

There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. As discussed above, we began integrating the acquired pressure pumping and wireline businesses into our existing internal control over financial reporting during the most recently completed fiscal quarter.

 

 

None.

 

PART III

 

The information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive officer, principal financial officer and principal accounting officer. The text of this code is located on our website under “Governance.” Our Internet address is www.patenergy.com. We intend to disclose any amendments to or waivers from this code on our website.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

 

The information required by this Item is incorporated herein by reference to the Proxy Statement.

 

PART IV

 

 

(a)(1) Financial Statements

 

See Index to Consolidated Financial Statements on page F-1 of this Report.

 

(a)(2) Financial Statement Schedule

 

Schedule II — Valuation and qualifying accounts is filed herewith on page S-1.

 

All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto.

 

(a)(3) Exhibits

 

The following exhibits are filed herewith or incorporated by reference herein.

 

 

 

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS