PATTERSON UTI ENERGY INC - Annual Report: 2006 (Form 10-K)

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:

(325) 574-6300

 

 

Securities Registered Pursuant to 12(b) of the Act:

None

 

Securities Registered Pursuant to 12(g) of the Act:

(Title of class)

 

Common Stock, $.01 Par Value

 

 

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 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 the 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

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, 2006, the last business day of the registrant’s most recently completed second fiscal quarter, was $4,638,987,745, calculated by reference to the closing price of $28.31 for the common stock on the Nasdaq National Market on that date.

 

As of February 22, 2007, the registrant had outstanding 156,543,478 shares of common stock, $.01 par value, its only class of voting common stock.

 

Documents incorporated by reference:

 

Definitive Proxy Statement for the 2007 Annual Meeting of Stockholders (Part III).

 

 

FORWARD LOOKING STATEMENTS

 

This Annual Report on Form 10-K (including documents incorporated by reference herein) contains statements with respect to our expectations and beliefs as to future events. These types of statements are “forward-looking” and subject to uncertainties. Readers are cautioned that such forward-looking statements should be read in conjunction with our disclosures under the heading “Risk Factors,” in Part I of this Report.

 

PART I

 

 

Available Information

 

This Annual Report on Form 10-K, 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 Securities Exchange Act of 1934, 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 United States Securities and Exchange Commission (“SEC”).

 

Overview

 

Based on publicly available information, we believe we are the second largest operator of land-based drilling rigs in North America. The Company was formed in 1978 and reincorporated in 1993 as a Delaware corporation. Our contract drilling business operates primarily in:

 

 

As of December 31, 2006, we had a drilling fleet that consisted of 336 currently marketable land-based drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate earth to a depth desired by the customer. A drilling rig is considered currently 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 drilling rig components and equipment which may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs.

 

We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast

region of Louisiana. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We are also engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas operations are focused primarily in producing regions of West and South Texas, Southeastern New Mexico, Utah and Mississippi.

 

Industry Segments

 

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

 

 

All of our industry segments had operating profits in 2006, 2005 and 2004.

 

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, 2006, we had 336 currently marketable land-based drilling rigs which were based in the following regions:

 

 

Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,000 feet to 30,000 feet. Fifty-six of these drilling rigs are SCR electric rigs and 280 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 drilling rig components and equipment which may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs.

 

Drilling rigs are typically equipped with:

 

 

Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year on an ongoing program to modify and upgrade our drilling rigs to ensure that our drilling equipment is well maintained and competitive. We have spent $1 billion during the last three years on capital improvements to modify and upgrade our drilling rigs. During fiscal years 2006, 2005 and 2004, we spent approximately $531 million, $329 million and $141 million, respectively, on these capital improvements.

 

Depth and complexity of the well and drill site conditions are the principal factors in determining the size of drilling rig used for a particular job. We use our rigs for developmental and exploratory drilling, and they are capable of vertical or horizontal drilling.

 

Our contract drilling operations depend on the availability of:

 

 

some of which 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. Typically, the contracts are short-term to drill a single well or a series of wells. Customer demand for drilling contracts with a term of one or more years increased during 2005 due to the scarcity of available drilling rigs in the market place. In response to this demand, we entered into several long-term contracts in 2005 and 2006. These long-term contracts provide for the use of drilling rigs for fixed periods of time during which multiple wells are drilled. During 2006, our average number of days to drill a well was approximately 21 days. We may continue to enter into long-term contracts when considered beneficial to the Company.

 

The 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. We generally 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. The customers generally indemnify us against claims that might arise from other surface and subsurface pollution, except claims that might arise from our gross negligence.

 

The 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 contract depends upon:

 

 

Daywork Contracts

 

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 sometimes 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.

 

Footage 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 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 assumes certain risks associated with loss of the well from fire, blowouts and other risks. Due to current market conditions and improved rates received under daywork contracts, we are entering into fewer footage contracts than we did in the past.

 

Turnkey Contracts

 

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 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 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. However, given the increased exposure we have under a turnkey contract, 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: daywork, footage and turnkey. Due to current market conditions and improved rates received under daywork contracts, we are entering into fewer turnkey contracts than we did in the past.

 

Revenues by Contract Type — Information regarding our revenues by contract type for the last three years follows:

 

 

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

 

 

 

 

Drilling Rigs and Related Equipment — Certain drilling rig information with respect to rigs that were currently marketable as of December 31, 2006 follows:

 

 

At December 31, 2006, we owned and operated 336 trucks and 439 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 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, New Mexico, Oklahoma, Wyoming, Utah and Western Canada.

 

Pressure Pumping Operations

 

General — We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. Pressure pumping services are primarily well stimulation and cementing for the completion of new wells and remedial work on existing wells. Most wells drilled in the Appalachian Basin require some form of fracturing or other stimulation to enhance the flow of oil and natural gas by pumping fluids under pressure into the well bore. Generally, Appalachian Basin wells require cementing services before production commences. The cementing process inserts material between the wall of the well bore and the casing to center and stabilize the casing.

 

Equipment — Our pressure pumping equipment at December 31, 2006 follows:

 

 

Drilling and Completion Fluids Operations

 

General — We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. We serve our offshore customers through six stockpoint facilities located along the Gulf of

Mexico in Texas and Louisiana and our land-based customers through eleven stockpoint facilities in Texas, Louisiana, Oklahoma and New Mexico.

 

Drilling Fluids — Drilling fluid products and systems are used to cool and lubricate the bit during drilling operations, contain formation pressures (thereby minimizing blowout risk), suspend and remove rock cuttings from the hole and maintain the stability of the wellbore. Technical services are provided to ensure that the products and systems are applied effectively to optimize drilling operations.

 

Completion Fluids — After a well is drilled, the well casing is set and cemented into place. At that point, the drilling fluid services are complete and the drilling fluids are circulated out of the well and replaced with completion fluids. Completion fluids, also known as clear brine fluids, are solids-free, clear salt solutions that have high specific gravities. Combined with a range of specialty chemicals, these fluids are used to control bottom-hole pressures and to meet specific corrosion, inhibition, viscosity and fluid loss requirements.

 

Raw Materials — Our drilling and completion fluids operations depend on the availability of the following raw materials:

 

Drilling

barite and bentonite

Completion

calcium chloride, calcium bromide and zinc bromide

 

We obtain these raw materials through purchases made on the spot market and supply contracts with producers of these raw materials.

 

Barite Grinding Facility — We own and operate a barite grinding facility with two barite grinding mills in Houma, Louisiana. This facility allows us to grind raw barite into the powder additive used in drilling fluids.

 

Other Equipment — We operate 20 trucks and 83 trailers and lease another 33 trucks which are used to transport drilling and completion fluids and related equipment.

 

Oil and Natural Gas Operations

 

General — We are engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas business operates primarily in producing regions of West and South Texas, Southeastern New Mexico, Utah and Mississippi. We significantly expanded our oil and natural gas operations in 2004 through our acquisition of TMBR/Sharp Drilling, Inc. (“TMBR”). The oil and natural gas assets acquired in the acquisition of TMBR included both proved reserves and undeveloped properties.

 

Customers

 

The customers of each of our four business segments are oil and natural gas operators or purchasers of these commodities. Our customer base includes both major and independent oil and natural gas operators. During 2006, no single customer accounted for 10% or more of our consolidated operating revenues.

 

Competition

 

Contract Drilling and Pressure Pumping Businesses — 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. The equipment can also be moved from one market to another in response to market conditions.

 

Drilling and Completion Fluids Business — The drilling and completion fluids industry is highly competitive and price is generally the most important factor. Other competitive factors include the availability of chemicals and experienced personnel, the reputation of the fluids services provider in the drilling industry and relationships with customers. Some of our competitors have substantially more resources and longer operating histories than we have.

Oil and Natural Gas Business — There is substantial competition for the acquisition of oil and natural gas leases suitable for development and exploration and for experienced personnel. Our competitors in this business include:

 

 

Our ability to increase our oil and natural gas reserves in the future is directly dependent upon our ability to select, acquire and develop suitable prospects. Many of our competitors have facilities and financial and human resources greater than ours.

 

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 have not required the expenditure of significant resources. 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. They could have an adverse effect on our operations. Several state and Federal environmental laws and regulations currently apply to our operations and may become more stringent in the future.

 

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. 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.

 

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 is more comprehensive and stringent than previous oil pollution liability and prevention laws. It 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. We have spill prevention control and countermeasure plans in place for our oil and natural gas properties in each of the areas in which we operate and for each of the stockpoints operated by our drilling and completion fluids business. 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 operations are also subject to Federal, state and local regulations for the control of air emissions. The Federal Clean Air Act, as amended, and various state and local laws impose certain air quality requirements on us. Amendments to the Clean Air Act revised the definition of “major source” such that emissions from both wellhead and associated equipment involved in oil and natural gas production may be added to determine if a source is a “major source.” As a consequence, more facilities may become major sources and thus would be required to obtain operating permits. This permitting process may require capital expenditures in order to comply with permit limits.

 

Risks and Insurance

 

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

 

 

These 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, particularly through:

 

 

In addition, we could become subject to liability for reservoir damages. The occurrence of a significant event, including pollution or environmental damages, could materially affect our operations and financial condition.

 

As a protection against operating hazards, we maintain insurance coverage we believe to be adequate, including:

 

 

We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of:

 

 

We also carry insurance coverage for major physical damage to our drilling rigs. However, we do not carry insurance against loss of earnings resulting from such damage. In view of the difficulties that may be encountered in renewing such insurance at reasonable rates, no assurance can be given that:

 

 

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. These contractual indemnifications may not be supported by adequate insurance maintained by the customer.

 

Employees

 

We had approximately 9,000 full-time employees at December 31, 2006. 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 pressure pumping division in Appalachia and our drilling operations in Canada are subject to slow periods of activity during the Spring thaw. In addition, our drilling operations in Canada are subject to slow periods of activity during the Fall.

 

Raw Materials and Subcontractors

 

We use many suppliers of raw materials and services. These materials and services have historically been available, although 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.

 

 

From time to time, we make written or oral forward-looking statements, including statements contained in this Annual Report on Form 10-K, our other filings with the SEC, press releases and reports to stockholders. These forward-looking statements are made pursuant to the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995. These statements include, without limitation, statements relating to liquidity, financing of operations, sources and sufficiency of funds and impact of inflation. The words “believes,” “budgeted,” “expects,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” and similar expressions are used to identify our forward-looking statements. We do not undertake to update, revise, or correct any of our forward-looking information.

 

We include the following cautionary statement in accordance with the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statement made by us, or on our behalf. The factors identified in this cautionary statement are important factors (but not necessarily all of the important factors) that could cause actual results to differ materially from those expressed in any forward-looking statement made by us, or on our behalf. Where any such forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results. The differences between assumed facts or bases and actual results can be material, depending upon the circumstances.

 

Where, in any forward-looking statement, we express an expectation or belief as to the future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that the statement of expectation or belief will result, or be achieved or accomplished. Taking this into account, the following are identified as important risk factors currently applicable to, or which could readily be applicable to, us:

 

 

Our revenue, profitability and rate of growth are substantially dependent upon prevailing prices for oil and natural gas. For many years, oil and natural gas prices and, therefore, the level of drilling, exploration, development and production, have been extremely volatile. Prices are affected by:

 

 

All of these factors are beyond our control. The average market price of natural gas has improved from $3.36 in 2002 to $6.94 in 2006 resulting in an increase in demand for our drilling services. Our average number of rigs operating increased from 126 in 2002 to 296 in 2006. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition and operations and ability to access sources of capital. A significant decrease in market prices for natural gas would likely result in a material decrease in demand for drilling rigs and reduction in our operating results.

 

A General Excess of Operable Land Drilling Rigs Adversely Affects Our Profit Margins Particularly in Times of Weaker Demand.

 

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 during the downturn periods.

 

In addition to adverse effects that future declines in demand could have on us, ongoing factors which could adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

 

 

As a result of an increase in drilling activity and increased prices for drilling services, construction of new drilling rigs has increased significantly. We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.

 

Shortages of Drill Pipe, Replacement Parts and Other Related Rig Equipment Adversely Affects Our Operating Results.

 

During periods of increased demand for drilling services, the industry has experienced shortages of drill pipe, replacement parts and other related rig equipment. 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. These price increases and delays in delivery may require us to increase capital and repair expenditures in our contract drilling segment. Severe shortages could impair our ability to operate our drilling rigs.

 

The Various Business Segments in Which We Operate Are Highly Competitive with Excess Capacity which may Adversely Affect 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 for the foreseeable future 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.

 

The drilling and completion fluids services industry is highly competitive. Price is generally the most important factor. Other competitive factors include the availability of chemicals and experienced personnel, the reputation of the fluids services provider in the drilling industry and relationships with customers. Some of our competitors have substantially more resources and longer operating histories than we have.

 

Labor Shortages Adversely Affect Our Operating Results.

 

During periods of increasing demand for contract drilling services, the industry experiences shortages of qualified drilling rig personnel. During these periods, our ability to attract and retain sufficient qualified personnel to market and operate our drilling rigs 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 in response to the increased demand for our contract drilling services. Additionally, wage rates for drilling personnel are likely to increase, resulting in higher operating costs.

 

Continued Growth Through Rig Acquisition is Not Assured.

 

We have increased our drilling rig fleet in the past through mergers and acquisitions. The land drilling industry has experienced significant consolidation, and there can be no assurance that acquisition opportunities will be

available in the future. Additionally, we are likely to continue to face intense competition from other companies for available acquisition opportunities.

 

There can be no assurance that we will:

 

 

We may incur substantial indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with any such acquisitions. 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, pressure pumping, and drilling and completion fluids 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 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 such insurance prohibitive.

 

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

 

Violations of Environmental Laws and Regulations Could Materially Adversely Affect Our Operating Results.

 

The drilling of oil and natural gas wells is subject to various Federal, state, foreign, and local laws, rules and regulations. 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, Federal law imposes a variety of regulations 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, we may be deemed to be a responsible party under Federal law. Our operations and facilities are subject to numerous state and Federal 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.

 

Some of Our Contract Drilling Services are Provided Under Turnkey and Footage Contracts, Which are Financially Risky.

 

A portion of our contract drilling is performed under turnkey and footage contracts, which involve significant risks. Under turnkey drilling contracts, we contract to drill a well to a certain depth under specified conditions at a fixed price. Under footage contracts, we contract to drill a well to a certain depth under specified conditions at a

fixed price per foot. The risk to us under these types of drilling contracts are greater than on a well drilled on a daywork basis. Unlike daywork contracts, we must bear the cost of services until the target depth is reached. In addition, we must assume most of the risk associated with the drilling operations, generally assumed by the operator of the well on a daywork contract, including blowouts, loss of hole from fire, machinery breakdowns and abnormal drilling conditions. Accordingly, if severe drilling problems are encountered in drilling wells under such contracts, we could suffer substantial losses.

 

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 enacted in 1988. 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 are located in Snyder, Texas. We also have a number of offices, yards and stockpoint facilities located in our various operating areas.

 

Our corporate headquarters are located at 4510 Lamesa Highway, Snyder, Texas, and our telephone number at that address is (325) 574-6300. There are a number of improvements at our headquarters, including:

 

 

We have regional administrative offices, yards and stockpoint facilities in many of the areas in which we operate. The facilities are primarily used to support day-to-day operations, including the repair and maintenance of equipment as well as the storage of equipment, inventory and supplies and to facilitate administrative responsibilities and sales.

 

Contract Drilling Operations — Our drilling services are supported by several administrative offices and yard facilities located throughout our areas of operations including:

 

 

 

Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our areas of operations including:

 

 

Drilling and Completion Fluids — Our drilling and completion fluids services are supported by several administrative offices and stockpoint facilities located throughout our areas of operations including:

 

 

Oil and Natural Gas — Our oil and natural gas operations are supported by administrative and field offices in Texas.

 

We own our headquarters 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.

 

 

In December 2005, two purported derivative actions were filed in Texas state court in Scurry County, Texas and in May 2006, a derivative action was filed in federal court in Lubbock, Texas, in each case against our directors, alleging that the directors breached their fiduciary duties to us as a result of alleged failure to timely discover the embezzlement of approximately $77.5 million by our former CFO, Jonathan D. Nelson. The Board of Directors formed a special litigation committee to review and inquire about these allegations and recommend our response, if any. Further legal proceedings in these suits were stayed pending completion of the work of the special litigation committee. The lawsuits sought recovery on behalf of and for us and did not seek recovery from us. In November 2006, the parties to all three of the derivative actions reached an agreement to settle the actions. After a preliminary hearing and notice to our stockholders, the state court held a hearing, approved the settlement, which requires the implementation of certain corporate governance measures, and signed a final judgment on December 29, 2006. As contemplated by the settlement agreement, the federal court entered a final judgment on January 10, 2007. Pursuant to the terms of the settlement, we will pay a net amount of $230,000 to the attorneys for the plaintiffs in the suits.

 

We are party to various other 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 financial condition.

 

 

None.

 

PART II

 

 

 

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

 

 

 

As of February 21, 2007, there were approximately 2,200 holders of record and approximately 79,500 beneficial holders of our common stock.

 

 

On April 28, 2004, our Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 2004. At June 30, 2004, an adjustment was made to reclassify an amount from retained earnings to common stock to account for the par value of the common stock issued as a stock dividend. This adjustment had no overall effect on equity. All historical share and per-share information prior to June 30, 2004 has been restated to reflect the impact of the two-for-one stock split.

 

On April 28, 2004, our Board of Directors approved the initiation of a quarterly cash dividend of $0.02 on each share of our common stock which was paid on June 2, 2004, September 1, 2004 and December 1, 2004. Total dividends paid in 2004 were approximately $10 million. In February 2005, our Board of Directors approved an increase in the quarterly cash dividend on our common stock to $0.04 per share from $0.02 per share. Quarterly cash dividends in the amount of $0.04 per share were paid on March 4, 2005, June 1, 2005, September 1, 2005 and December 1, 2005. Total cash dividends in 2005 were approximately $27.3 million. On March 2, 2006, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share which was paid on March 30, 2006. On April 26, 2006, our Board of Directors approved an increase in our quarterly cash dividend from $0.04 to $0.08 on each outstanding share of our common stock. Cash dividends of $0.08 per share were paid on June 30, 2006, September 29, 2006 and December 29, 2006. Total cash dividends in 2006 were approximately $45.8 million. The amount and timing of all future dividend payments 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.

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2006.

 

 

 

 

 

Equity compensation to our employees, officers and directors as of December 31, 2006 follows:

 

 

 

 

Our selected consolidated financial data as of December 31, 2006, 2005, 2004, 2003 and 2002, and for each of the five years then ended 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 2006 presentation.

 

 

This Item 7 contains forward-looking statements, which are made pursuant to the “Safe Harbor” provisions of the Private Securities Litigation Reform Act of 1995.

 

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, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also engage in the development, exploration, acquisition and production of oil and natural gas. For the three years ended December 31, 2006, 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, South Dakota and Western Canada, while our pressure pumping services are focused primarily in the Appalachian Basin. Our drilling and completion fluids services are provided to operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Our oil and natural gas operations are primarily focused in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

 

The profitability of our business is most readily assessed by two primary indicators in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During 2006, our average number of rigs operating increased to 296 from 276 in 2005 and our average revenue per operating day increased to $20,050 from $14,770 in 2005. Primarily due to these improvements, we experienced an increase of approximately $301 million, or 81%, in consolidated net income in 2006.

 

Our revenues, profitability and cash flows are highly dependent upon the market prices of oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which results in increased demand for our contract services. Conversely, in periods of time when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services.

 

We believe that the liquidity shown on our balance sheet as of December 31, 2006, which includes approximately $335 million in working capital (including $13.4 million in cash) and $195 million available under a $375 million line of credit ($120 million in borrowings are outstanding at December 31, 2006 and availability of $60 million is reserved for outstanding letters of credit) provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets, pay cash dividends and survive downturns in our industry.

 

Commitments and Contingencies — We maintain letters of credit in the aggregate amount of approximately $60 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 at various times during each calendar year. No amounts have been drawn under the letters of credit.

 

As of December 31, 2006, we have remaining non-cancelable commitments to purchase approximately $297 million of equipment to be received throughout 2007.

 

In November 2005, we discovered that our former Chief Financial Officer, Jonathan D. Nelson (“Nelson”), had fraudulently diverted approximately $77.5 million of our funds for his own benefit. As a result, the Audit Committee of the Board of Directors commenced an investigation into Nelson’s activities and retained independent counsel and independent forensic accountants to assist with the investigation. Nelson has been sentenced and is

serving a term of imprisonment arising out of his embezzlement. A receiver has been appointed to take control of and liquidate the assets of Nelson in connection with his embezzlement of our funds. The receiver is in the process of seeking court approval for a plan of distribution of the assets recovered by the receiver and the proceeds thereof, which total approximately $40 million. While we believe we have a claim for at least the full amount of funds embezzled from us, other creditors have asserted or may assert claims with respect to the assets held by the receiver.

 

In December 2005, two purported derivative actions were filed in Texas state court in Scurry County, Texas and in May 2006, a derivative action was filed in federal court in Lubbock, Texas, in each case against our directors, alleging that the directors breached their fiduciary duties to us as a result of alleged failure to timely discover the embezzlement of approximately $77.5 million by our former CFO, Jonathan D. Nelson. The Board of Directors formed a special litigation committee to review and inquire about these allegations and recommend our response, if any. Further legal proceedings in these suits were stayed pending completion of the work of the special litigation committee. The lawsuits sought recovery on behalf of and for us and did not seek recovery from us. In November 2006, the parties to all three of the derivative actions reached an agreement to settle the actions. After a preliminary hearing and notice to our stockholders, the state court held a hearing, approved the settlement, which requires the implementation of certain corporate governance measures, and signed a final judgment on December 29, 2006. As contemplated by the settlement agreement, the federal court entered a final judgment on January 10, 2007. Pursuant to the terms of the settlement, we will pay a net amount of $230,000 to the attorneys for the plaintiffs in the suits.

 

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, money markets and highly rated municipal and commercial bonds.

 

Description of business — We conduct our contract drilling operations in Texas, New Mexico, Oklahoma, Arkansas, Louisiana, Mississippi, Colorado, Utah, Wyoming, Montana, North Dakota, South Dakota and Western Canada. As of December 31, 2006, we had 336 currently marketable land-based drilling rigs. We provide pressure pumping services to oil and natural gas operators primarily in the Appalachian Basin. These services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We provide drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, Southeastern New Mexico, Oklahoma and the Gulf Coast region of Louisiana. Drilling and completion fluids are used by oil and natural gas operators during the drilling process to control pressure when drilling oil and natural gas wells. We are also engaged in the development, exploration, acquisition and production of oil and natural gas. Our oil and natural gas operations are focused primarily in producing regions in West and South Texas, Southeastern New Mexico, Utah and Mississippi.

 

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 assets for impairment when events or changes in circumstances indicate that the carrying values of certain assets either exceed their respective fair values or may not be recovered over their estimated remaining useful lives. 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 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 to income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Impairment charges are recorded based on discounted cash flows. There were no impairment charges to property and equipment during the years 2006, 2005 or 2004.

 

Oil and natural gas properties — 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. In accordance with Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS No. 19”) 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 the economic operating viability of the respective projects. If no progress has been made in assessing the reserves and the economic operating viability of a project after one year following the completion of drilling, we consider the costs of the well 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 of each respective field. We review our proved oil and natural gas properties for impairment when an 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 internally and 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 its net book value and discounted cash flow. Unproved oil and natural gas properties are reviewed quarterly to determine impairment. Our intent to drill, lease expiration and abandonment of area are considered. Assessment of impairment is made on a lease-by-lease basis. If an unproved property is determined to be impaired, then costs related to that property are expensed. Impairment expense of approximately $5.0 million, $4.4 million and $3.2 million for the years ended December 31, 2006, 2005 and 2004, respectively, is included in depreciation, depletion and impairment in the accompanying financial statements.

 

Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. As such, we assess impairment of our goodwill annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value.

 

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, as described below. 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 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 estimated total revenues. We recognize reimbursements received from third parties for out-of-pocket expenses incurred as revenues and account for out-of-pocket expenses as direct costs.

 

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.

 

Related Party Transactions

 

We operate certain oil and natural gas properties in which certain of our affiliated persons have participated, either individually or through entities they control. These participations have typically been through working interests in prospects or properties we originated or acquired. At December 31, 2006, affiliated persons were working interest owners in 281 of 330 total wells we operated. We make sales of working interests to reduce our economic risk in the properties. Generally, it is more efficient for us to sell the working interests to these affiliated persons than to market them to unrelated third parties. Sales of working interests to affiliated parties were made at cost, comprised of our costs of acquiring and preparing the working interests for sale plus a promote fee in some cases. These costs were paid by the working interest owners on a pro rata basis based upon their working interest ownership percentage. The price at which working interests were sold to affiliated persons was the same price as that at which working interests were sold to unaffiliated persons, except that in some cases the affiliated persons also paid a promote fee.

 

Production revenues and joint interest costs of each of the affiliated persons during 2006 for all wells operated by us in which the affiliated persons have working interests are presented in the table below. These amounts do not necessarily represent their profits or losses from these interests because the joint interest costs do not include the parties’ related drilling and leasehold acquisition costs incurred prior to January 1, 2006. These activities resulted in a payable to the affiliated persons of approximately $1.5 million and $1.5 million and a receivable from the affiliated persons of approximately $1.6 million and $1.2 million at December 31, 2006 and 2005, respectively.

 

 

 

 

Liquidity and Capital Resources

 

As of December 31, 2006, we had working capital of $335 million including cash and cash equivalents of $13 million. For 2006, our sources of cash flow included:

 

 

We used $450 million to purchase shares of our common stock in the open market, $46 million to pay dividends on our common stock, and $598 million:

 

 

On August 2, 2006, we entered into an agreement to amend our $200 million unsecured revolving line of credit (“LOC”). In connection with this amendment, the borrowing capacity under this LOC was increased to $375 million. No significant changes were made to the terms of the LOC, including the interest to be paid on outstanding balances and financial covenants. As of December 31, 2006, we had borrowed $120 million under the LOC and $60 million in letters of credit were outstanding. As a result, we had available borrowing capacity of $195 million at December 31, 2006.

 

On March 2, 2006, our Board of Directors approved a cash dividend on our common stock in the amount of $0.04 per share. The dividend of approximately $6.9 million was paid on March 30, 2006. On April 26, 2006, our Board of Directors approved an increase in our quarterly cash dividend from $0.04 to $0.08 on each outstanding share of our common stock. This dividend of approximately $13.4 million was paid on June 30, 2006 to holders of record on June 15, 2006. On August 2, 2006, our Board of Directors approved a quarterly cash dividend of $0.08 on each outstanding share of our common stock. This dividend of approximately $13.0 million was paid on September 29, 2006 to holders of record as of September 14, 2006. On October 31, 2006, our Board of Directors approved a quarterly cash dividend of $0.08 on each outstanding share of our common stock. This dividend of approximately $12.5 million was paid on December 29, 2006 to holders of record as of December 14, 2006. The amount and timing of all future dividend payments 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 March 27, 2006, our Board of Directors increased our previously authorized stock buyback program to allow for future purchases of up to $200 million of our outstanding common stock. During the second quarter of 2006, we completed the authorized buyback with the purchase of 6,704,800 shares of our common stock at a cost of approximately $200 million. On August 2, 2006, our Board of Directors again increased the previously authorized stock buyback program to allow for future purchases of up to $250 million of our outstanding common stock. During the remainder of 2006, we purchased an additional 9,940,542 shares of our common stock at a cost of approximately $250 million. Shares purchased under the stock buyback program have been accounted for as treasury stock.

 

We believe that the current level of cash and short-term investments, together with cash generated from operations, should be sufficient to meet our capital needs. From time to time, acquisition opportunities are evaluated. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Should opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, our existing credit facility and additional debt or equity financing. However, there can be no assurance that such capital would be available.

Contractual Obligations

 

The following table presents information with respect to our contractual obligations as of December 31, 2006 (dollars in thousands):

 

 

 

 

Off-Balance Sheet Arrangements

 

We had no off-balance sheet arrangements at December 31, 2006.

 

Results of Operations

 

Comparison of the years ended December 31, 2006 and 2005

 

A summary of operations by business segment for the years ended December 31, 2006 and 2005 follows:

 

 

Our average number of rigs operating increased to 296 in 2006 from 276 in 2005. The average market price of natural gas and our average rigs operating for each of the fiscal quarters and full years in 2006 and 2005 follow:

 

 

 

 

Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased as a result of increased demand for our contract drilling services and the increase in the number of marketable rigs in our fleet due to our rig activation program. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Average direct operating costs per operating day increased primarily as a result of increased compensation costs and an increase in the cost of maintenance for our rigs. Significant capital expenditures have been incurred to activate additional 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. The increase in depreciation expense was a result of the capital expenditures discussed above.

 

 

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating cost per job. The increase in jobs was attributable to increased demand for our services and increased operating capacity which has been added. Increased average revenue per job was due to increased pricing for our services and an increase in the number of larger jobs. Average direct operating costs per job increased as a result of increases in compensation and the cost of materials used in our operations as well as an increase in the number of larger jobs. Selling, general and administrative expense increased as a result of additional expenses to support the expanded operations of the pressure pumping segment. Significant capital expenditures have been incurred to add capacity and modify and upgrade existing equipment. The increase in depreciation expense was a result of the capital expenditures discussed above.

 

 

Revenues and direct operating costs increased primarily as a result of increases in the average revenue and direct operating costs per job. Average revenue and direct operating costs per job increased primarily as a result of an increase in large jobs in the Gulf of Mexico.

 

 

Direct operating costs increased primarily due to $4.2 million in costs associated with the abandonment of exploratory wells. Depreciation, depletion and impairment expense includes $5.0 million and $4.4 million incurred during 2006 and 2005, respectively, to reflect the impairment of certain oil and natural gas properties. Average net daily oil production increased due to the completion of new wells in 2006. Average net daily natural gas production decreased as a result of production declines and the sale of certain natural gas properties.

 

 

Selling, general and administrative expense increased primarily as a result of an increase of $7.8 million in stock-based compensation expense which was impacted by the adoption of a new accounting standard in 2006 requiring the expensing of stock options. Other operating expenses include bad debt expense of $5.4 million and $1.2 million in 2006 and 2005, respectively. Embezzlement costs, net of recoveries in 2005 includes payments made to or for the benefit of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company and in 2006 includes continuing professional and other costs related to the embezzlement, net of insurance proceeds of $2.0 million received in connection with the loss. Interest expense in 2006 increased due to borrowings under our line of credit during 2006.

Comparison of the years ended December 31, 2005 and 2004

 

A summary of operations by business segment for the years ended December 31, 2005 and 2004 follows:

 

 

Our average number of rigs operating increased to 276 in 2005 from 211 in 2004. The average market price of natural gas and our average rigs operating for each of the fiscal quarters and full years in 2005 and 2004 follow:

 

 

 

 

Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Operating days and average rigs operating increased as a result of the increased demand for our contract drilling services and the increase in the number of marketable rigs in our fleet due to the acquisition of land drilling assets from Key Energy Services, Inc. in January 2005 and our rig activation program. Average revenue per operating day increased as a result of increased demand and pricing for our drilling services. Significant capital expenditures were incurred during 2005 to activate additional drilling rigs to meet increased demand, 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. The increase in depreciation expense was a result of the capital expenditures discussed above.

 

 

Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. The increase in jobs in 2005 was largely due to our expanded operations in the Appalachian regions of Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the improved industry conditions as discussed in “Contract Drilling” above. Increased average revenue per job was due primarily to increased pricing for our services. Selling, general and administrative expenses increased largely as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense during 2005 was largely due to the expansion of the pressure pumping segment from 2003 through 2005 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures increased in 2005 compared to 2004 due to further expansion of services into Tennessee and Wyoming as well as modifications and upgrades to existing equipment and facilities.

 

 

Revenues and direct operating costs increased as a result of an increase in the average revenue and direct operating costs per job. Average revenue and direct operating costs per job increased primarily as a result of an

increase in the size of our offshore jobs. Selling, general and administrative expense increased primarily due to increased incentive compensation resulting from higher profitability levels.

 

 

Revenues increased due to increased market prices for oil and natural gas. Direct operating costs increased as a result of higher oilfield service cost and production taxes. Average net daily oil production decreased as a result of production declines and the sale of certain oil properties during 2005. Average net daily gas production also decreased as a result of the sale of certain natural gas properties, however, this decrease was partially offset by an increase in production. Depreciation, depletion and impairment expense includes approximately $4.4 million and $3.2 million of expenses incurred during 2005 and 2004, respectively, to impair certain oil and gas properties.

 

 

Selling, general and administrative expenses increased primarily as a result of payroll taxes attributable to the exercise of employee stock options, increased professional fees and additional compensation expense related to the issuance of restricted shares to certain key employees in 2004 and 2005. Embezzlement costs, net of recoveries includes fraudulent payments made to or for the benefit of Jonathan D. Nelson, our former CFO, for assets and services that were not received by the Company and professional fees and expenses incurred as a result of the embezzlement. Other operating expenses in 2005 includes a charge of $4.2 million to increase reserves related to the financial failure of a workers’ compensation insurance carrier used previously by the Company.

 

Income Taxes