PATTERSON UTI ENERGY INC - Annual Report: 2016 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2016

or

For the transition period from                      to                     

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  ☒ or    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐ or    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ☒

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2016, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $3.1 billion, calculated by reference to the closing price of $21.32 for the common stock on the Nasdaq Global Select Market on that date.

As of February 6, 2017, the registrant had outstanding 166,334,905 shares of common stock, $0.01 par value, its only class of common stock.

Documents incorporated by reference:

Portions of the registrant’s definitive proxy statement for the 2017 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

SPECIAL NOTE 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 include, without limitation, statements relating to: liquidity; revenue and cost expectations and backlog; financing of operations; oil and natural gas prices; rig counts; source and sufficiency of funds required for building new equipment, upgrading existing equipment and additional acquisitions (if opportunities arise); impact of inflation; demand for our services; competition; equipment availability; government regulation; debt service obligations; and other matters.  Our forward-looking statements can be identified by the fact that they do not relate strictly to historical or current facts and often use words such as “anticipate,” “believe,” “budgeted,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “potential,” “project,” “pursue,” “should,” “strategy,” “target,” or “will,” 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.

On December 12, 2016, we entered into an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”), pursuant to which a subsidiary of ours will be merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly owned subsidiaries (the “SSE merger”).  These forward-looking statements include, without limitation, our expectations with respect to:

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. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These risks and uncertainties also include those set forth under “Risk Factors” contained in Item 1A of this Report and in 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, as well as, among others, risks and uncertainties relating to:

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We caution that the foregoing list of factors is not exclusive.  Additional information concerning these and other risk factors is contained in this Report and may be contained in our future filings with the SEC.  The forward-looking statements speak only as of the date made and, other than as required by law, we undertake no obligation to update publicly or revise any of these forward-looking statements, whether as a result of new information, future events or otherwise.  In the event that we update any forward-looking statement, no inference should be made that we will make additional updates with respect to that statement, related matters or any other forward-looking statements.  All subsequent written and oral forward-looking statements concerning us, SSE, the SSE merger or other matters and attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements above.

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PART I

Item 1. Business

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 are a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest fleets of land-based drilling rigs and a large fleet of pressure pumping equipment.  We were formed in 1978 and reincorporated in 1993 as a Delaware corporation.  

Our contract drilling business operates in the continental United States and western Canada, and we are pursuing contract drilling opportunities outside of North America.  As of December 31, 2016, we had a drilling fleet that consisted of 202 marketed 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.  We also have a substantial inventory of drill pipe and drilling rig components that support our drilling operations.  

We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region.  Pressure pumping services consist primarily of well stimulation services (such as hydraulic fracturing) and cementing services for completion of new wells and remedial work on existing wells.  As of December 31, 2016, we had approximately 1.1 million hydraulic horsepower (approximately 1.0 million of which was hydraulic fracturing horsepower) to provide these services.  Our pressure pumping operations are supported by a fleet of other 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.  

We also manufacture and sell pipe handling components and related technology to drilling contractors in North America and other select markets.  In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.

Recent Developments

Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2014, 2015 and 2016 are as follows:

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The closing price of oil was as high as $107.95 per barrel in June 2014.  Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016.  Oil and natural gas prices have recovered substantially from the lows experienced in the first quarter of 2016.  During the fourth quarter of 2016, the Organization of Petroleum Exporting Countries (“OPEC”) and certain non-OPEC countries, including Russia, announced an agreement to cut oil production. The announcement resulted in an increase in oil prices, which averaged $51.97 per barrel in December 2016.  In response to improved prices, U.S. rig counts have been increasing, and we believe they will continue to increase throughout 2017 if prices for these commodities remain at or above current levels.  

Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but has steadily improved on a monthly basis since May 2016.  For the fourth quarter, our average rig count improved to 66 rigs in the United States, up from the third quarter average of 60 rigs.  Our rig count in the United States at December 31, 2016 of 74 rigs was 42% greater than the low of 52 rigs in April 2016; however, it was 65% less than the high of 214 rigs in October 2014.  Term contracts have supported our operating rig count during the last three years.  Based on contracts currently in place, we expect an average of 44 rigs operating under term contracts during the first quarter of 2017 and an average of 37 rigs operating under term contracts throughout 2017.

Activity levels in our pressure pumping business have also improved.  Looking forward, we expect to see further increases in activity across the industry, especially in the Permian Basin.  We have reactivated two frac spreads since mid-December 2016 at a cost of approximately $2 million per spread, including both operating and capital expenditures.  Approximately 45% of the more than one million hydraulic fracturing horsepower in our fleet remains stacked.  We expect the cost to reactivate our remaining idle frac spreads would be approximately $3 million per frac spread, including both operating and capital expenditures.

On December 12, 2016, we entered into an Agreement and Plan of Merger (the “merger agreement”) with Seventy Seven Energy Inc. (“SSE”), pursuant to which a subsidiary of ours will be merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly owned subsidiaries (the “SSE merger”).  Under the merger agreement, we will acquire all of the issued and outstanding shares of common stock of SSE in exchange for approximately 49.6 million shares of our common stock, subject to certain downward adjustments set forth in the merger agreement.  SSE provides contract drilling, pressure pumping and oilfield rental services in many of the most active oil and natural gas plays onshore in the United States.  SSE owns a fleet of 40 AC drilling rigs, approximately 93% of which are pad capable, including 28 fit-for-purpose PeakeRigs™.  The remainder of SSE’s rig fleet includes 51 SCR rigs.  Additionally, SSE owns approximately 500,000 horsepower of modern, efficient fracturing equipment located in the Anadarko Basin and Eagle Ford Shale.  The SSE oilfield rentals business has a modern, well-maintained fleet of premium rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities.

The completion of the SSE merger is subject to satisfaction or waiver of certain closing conditions, including, but not limited to, approval by our and SSE’s respective stockholders and other closing conditions set forth in the merger agreement. Subject to closing conditions, the SSE merger is expected to be completed late in the first quarter or early in the second quarter of 2017.  

Industry Segments

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

Both of these industry segments had operating losses in 2016 and 2015.  In 2014, both of these industry segments had operating profits.

We changed our reporting segment presentation in 2016, as we no longer consider our oil and natural gas exploration and production activities to be significant to an understanding of our results.  We now present the oil and natural gas exploration and production activities, drilling technology and international activities as “Other” and “Corporate” reflects only corporate activities.  This change in segment presentation was applied retrospectively to all periods presented herein.

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, independent and other oil and natural gas operators.  As of December 31, 2016, we had 202 marketed land-based drilling rigs based in the following regions:

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Our marketed drilling rigs have rated maximum depth capabilities ranging from approximately 13,000 feet to 25,000 feet.  All of these drilling rigs are electric rigs.  An electric rig converts the power from its diesel engines 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 upgrades or replacement parts for marketed rigs.  

Drilling rigs are typically equipped with engines, drawworks, top drives, 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.  We have spent approximately $1.4 billion during the last three years on capital expenditures to (1) build new land drilling rigs and (2) modify, upgrade and extend the lives of components of our drilling fleet.  During fiscal years 2016, 2015 and 2014, we spent approximately $73 million, $527 million and $772 million, respectively, on these capital expenditures.  

Depth and complexity of the well, drill site conditions and the number of wells to be drilled on a pad 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 other materials 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 bid for each job depends upon location, equipment to be used, estimated risks involved, estimated duration of the job, availability of drilling rigs and other factors particular to each proposed contract.  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 six months to three years) and provide for the use of the drilling rig to drill multiple wells.  During 2016, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 14 days.  

Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of our 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 an early termination payment to us in the event that the contract is terminated by the customer.  We believe that our drilling contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations.  However, 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 particular industry conditions, customer requirements, applicable law or other factors.  

Our drilling contracts provide for payment on a daywork basis.  Under daywork contracts, we provide the drilling rig and crew to the customer.  The customer provides the program for 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.  All of the wells we drilled in 2016, 2015 and 2014 were under daywork contracts.  

From time to time more than five years ago, we contracted to drill some wells to a certain depth under specified conditions for a fixed price per foot (on a footage basis) or for a fixed fee (on a turnkey basis).  We generally assume greater operational and economic risk drilling on a turnkey basis than on a footage basis and greater operational and economic risk drilling on a footage basis than on a daywork basis.  

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

Drilling Rigs and Related Equipment — We have made significant upgrades during the last several years to our drilling fleet to match the needs of our customers.  While conventional wells remain a source of oil and natural gas, our customers have expanded the development of shale and other unconventional wells to help supply the long-term demand for oil and natural gas in North America.  

To address our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays, we have expanded our areas of operation and improved the capability of our drilling fleet.  We have delivered new APEX^® rigs to the market and have made performance and safety improvements to existing high capacity rigs.  APEX^® rigs are electric rigs with advanced electronic drilling systems, 500 ton top drives, iron roughnecks, hydraulic catwalks, and other automated pipe handling equipment.  APEX^® rigs that are pad capable are designed to efficiently drill multiple wells from a single pad, by “walking” between the wellbores without requiring time to lower the mast and lay down the drill pipe.  As of December 31, 2016, our marketed land-based drilling fleet was comprised of the following:

The U.S. land rig industry has recently begun referring to certain high specification rigs as “super-spec” rigs.  We consider a super-spec rig to be a 1,500 horsepower, AC powered rig that has a 750,000 pound hookload, has a 7,500 psi circulating system and is pad capable.  We currently estimate there are approximately 375 super-spec rigs in the United States, which includes 65 of our APEX® rigs.

We perform repair and/or overhaul work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, Wyoming, Colorado, North Dakota, Pennsylvania and western Canada.

Pressure Pumping Operations

General — We provide pressure pumping services to oil and natural gas operators primarily in Texas (Southwest Region) and the Appalachian region (Northeast Region).  Pressure pumping services consist of well stimulation services (such as hydraulic fracturing) and cementing services 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 hydraulic 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.  

Pressure Pumping Contracts – Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract.  The term contracts are generally entered into for a specified period of time and may include minimum revenue, usage or stage requirements.  We are compensated based on a combination of charges for equipment, personnel, materials, mobilization and other items.  We believe that our pressure pumping contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations.  However, each pressure pumping 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 particular industry conditions, customer requirements, applicable law or other factors.  

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Equipment — We have pressure pumping equipment used in providing hydraulic and nitrogen fracturing services as well as nitrogen, cementing and acid pumping services, with a total of approximately 1.1 million hydraulic horsepower (approximately 1.0 million of which was hydraulic fracturing horsepower) as of December 31, 2016.  Pressure pumping equipment at December 31, 2016 included:

Our pressure pumping operations are supported by a fleet of other 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.  

Materials – Our pressure pumping operations require the use of acids, chemicals, proppants, fluid supplies and other materials, any of which can be in short supply, including severe shortages, from time to time.  We purchase these materials from various suppliers.  These purchases are made in the spot market or pursuant to other arrangements that do not cover all of our required supply and sometimes require us to purchase the supply or pay liquidated damages if we do not purchase the material.  Given the limited number of suppliers of certain of our materials, we may not always be able to make alternative arrangements if we are unable to reach an agreement with a supplier for delivery of any particular material, or should one of our suppliers fail to timely deliver our materials.

Customers

Our customer base includes major, independent and other oil and natural gas operators.  With respect to our consolidated operating revenues in 2016, we received approximately 51% from our ten largest customers and approximately 33% from our five largest customers.  During 2016, one customer accounted for approximately $124 million, or approximately 14%, of our consolidated operating revenues.  These revenues were earned in both our contract drilling and pressure pumping businesses.  The loss of, or reduction in business from, one or more of our larger customers could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Competition

The contract drilling and pressure pumping businesses are highly competitive.  Historically, available equipment used in these businesses has frequently exceeded demand, particularly in an industry downturn, such as the current market environment.  The price for our services is a key competitive factor, 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, condition and technical specifications of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job.  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, regional and local laws, rules and regulations related to various aspects of our business, including:

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To date, applicable environmental laws and regulations in the places in which we operate 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, regional and local laws, rules and regulations that relate to the oil and natural gas industry. The adoption of laws, rules and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling, completion and production, and otherwise have an adverse effect on our operations.  Federal, state, foreign, regional and local environmental laws, rules and regulations currently apply to our operations and may become more stringent in the future.  Any limitation, suspension or moratorium of the services we or others provide, whether or not short-term in nature, by a federal, state, foreign, regional or local governmental authority, could have a material adverse effect on our business, financial condition and results of operations.  

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, regional and local laws, rules 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 and implementing regulations 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. For example, in December 2016, the U.S. Environmental Protection Agency (“EPA”) and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. If changes are made to the classification of exploration and production wastes under 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, each 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 jurisdictional 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.  

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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.  

The U.S. Occupational Safety and Health Administration (“OSHA”) promulgates and enforces laws and regulations governing the protection of the health and safety of employees.  The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments and citizens.  Also, OSHA has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.  

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 shale and other unconventional formations.  Due to concerns raised relating to potential impacts of hydraulic fracturing, including on groundwater quality and seismic activity, legislative and regulatory efforts at the federal level and in some state and local jurisdictions 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.  See “Item 1A. Risk Factors – Potential Legislation and Regulation Covering Hydraulic Fracturing or Other Aspects of the Oil and Gas Industry Could Increase Our Costs and Limit or Delay Our Operations.”

In Canada, a variety of federal, provincial and municipal laws, rules 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.  Other jurisdictions where we may conduct operations have similar environmental and regulatory regimes with which we would be required to comply.  These laws, rules 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, rules 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, regional and local laws, rules and regulations for the control of air emissions, including those associated with the Federal Clean Air Act and the Canadian Environmental Protection Act.  We and our customers may be required to make capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.  For more information, please refer to our discussion under “Item 1A. Risk Factors – Environmental and Occupational Health and Safety Laws and Regulations, Including Violations Thereof, Could Materially Adversely Affect Our Operating Results.”

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 U.S. 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.  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.  See “Item 1A. Risk Factors – Legislation and Regulation of Greenhouse Gases Could Adversely Affect Our Business.”

Risks and Insurance

Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution, exposure and reservoir damage.  These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages.  These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages.

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We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance.  In general, our drilling and pressure pumping contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage.  Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers.  Our customers and other third parties may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other reasons.  Accordingly, we may be unable to transfer these risks to our customers and other third parties by contract or indemnification agreements.  Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of operations.

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.  The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our drilling rigs, pressure pumping equipment and certain other assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks.  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, a substantial portion of our drilling rigs and pressure pumping equipment and certain other assets, such insurance does not cover the full replacement cost of such drilling rigs, pressure pumping equipment or other assets.  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 $1.5 million per occurrence deductible on our workers’ compensation insurance coverage, a $1.0 million per occurrence deductible on our equipment insurance coverage, a $2.0 million per occurrence deductible on our general liability coverage and a $2.0 million per occurrence deductible on our automobile liability insurance coverage.  We also self-insure a number of other risks, including loss of earnings and business interruption and cyber risks, and we do not carry a significant amount of insurance to cover risks of underground reservoir damage.  

Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations.  Our coverage includes aggregate policy limits and exclusions.  As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage.  There can be no assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive, or that our coverage will cover a specific loss.  Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage.  Incurring a liability for which we are not fully insured or indemnified could materially adversely affect our business, financial condition, cash flows and results of operations.  

If a significant accident or other event occurs that is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.  See “Item 1A. Risk Factors – Our Operations Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims.  We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us.”

Employees

We had approximately 3,600 full-time employees as of February 7, 2017.  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 has not significantly affected our overall operations.  However, our drilling operations in Canada are subject to slow periods of activity during the annual spring thaw.  Additionally, toward the end of some years, we experience slower activity in our pressure pumping operations in connection with the holidays and as customers’ capital expenditure budgets are depleted.  Occasionally, our operations have been negatively impacted by severe weather conditions.  

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.  

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Item 1A. Risk Factors.

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, financial condition, cash flows and results of operations could be harmed. You should also refer to the other information set forth in this Report, including our consolidated financial statements and the related notes.  

We Are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Customers’ Operating and Capital Expenditures and in Oil and Natural Gas Prices May Adversely Affect Our Operating Results.

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in North America.  When these expenditures decline, our business may suffer.  Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:

In particular, our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices.  For many years, oil and natural gas prices and markets have been extremely volatile.  Prices, and expectations about future prices, are affected by factors such as:

All of these factors are beyond our control.  The closing price of oil was as high as $107.95 per barrel in June 2014.  Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016.   Oil prices averaged $49.15 during the fourth quarter of 2016.  As a result of the lower level of oil prices, our industry has experienced a severe decline in both contract drilling and pressure pumping activity levels.  Currently, our average number of rigs operating remains well below the number of our available rigs, and a significant portion of our fracturing horsepower is stacked.  

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.  Higher oil and natural gas prices do not necessarily result in increased activity because demand for our services is generally driven by our customers’ expectations of future oil and natural gas prices.  A continued decline in demand for oil and natural gas, prolonged low oil or natural gas prices or expectations of further decreases in oil and natural gas prices, would likely result in further reduced capital expenditures by our customers and decreased demand for our services, which could have a material adverse effect on our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our services.

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Global Economic Conditions May Adversely Affect Our Operating Results.  

Global economic conditions and volatility in commodity prices may cause our customers to reduce or curtail their drilling and well completion programs, which could result in a decrease in demand for our services.  In addition, uncertainty in the capital markets, whether due to global economic conditions, low commodity prices or otherwise may result in reduced access to, or an inability to obtain, financing by us, our customers and our suppliers and result in reduced demand for our services.  Furthermore, these factors may result in certain of our customers experiencing an inability or unwillingness to pay suppliers, including us.  The global economic environment in the past has experienced significant deterioration in a relatively short period, and there is no assurance that the global economic environment will not quickly deteriorate again due to one or more factors, including a decline in the price for oil or natural gas.  A deterioration in the global economic environment could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

Excess Equipment and a Highly Competitive Oil Service Industry May Adversely Affect Our Utilization and Profit Margins and the Carrying Value of our Assets.  

The North American land drilling and pressure pumping businesses are highly competitive, and at times available land drilling rigs and pressure pumping equipment exceed the demand for such equipment.  A low commodity price environment can result in substantially more drilling rigs and pressure pumping equipment being available than are needed to meet demand.  In addition, in recent years there has been a substantial increase in the construction of new technology drilling rigs and new pressure pumping equipment.  Low commodity prices and construction of new equipment can result in excess capacity and substantial competition for a declining number of drilling and pressure pumping contracts.  Even in an environment of high oil and natural gas prices and increased drilling activity, reactivation and improvement of existing drilling rigs and pressure pumping equipment, construction of new technology drilling rigs and new pressure pumping equipment, and movement of drilling rigs and pressure pumping equipment from region to region in response to market conditions or otherwise can lead to an excess supply of equipment.  In addition, we may be unable to replace fixed-term contracts that were terminated early, extend expiring contracts or obtain new contracts in the spot market, and the rates and other material terms under any new or extended contracts may be on substantially less favorable rates and terms.  Accordingly, high competition and excess equipment can cause drilling and pressure pumping contractors to have difficulty maintaining utilization and profit margins and, at times, result in operating losses.  We cannot predict the future level of competition or excess equipment in the oil and natural gas contract drilling or pressure pumping businesses or the level of demand for our contract drilling or pressure pumping services.  

The excess supply of operable land drilling rigs, increasing rig specialization and excess pressure pumping equipment, which has been exacerbated by the decline in oil and natural gas prices could affect the fair market value or our drilling and pressure pumping equipment, which in turn could result in additional impairments of our assets.  A prolonged period of lower oil and natural gas prices could result in future impairment to our long-lived assets and goodwill.

Our Operations Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims.  We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us.  

Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution, exposure and reservoir damage.  These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages.  These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages.  

We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance.  In general, our customer contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage.  Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers.  In addition, certain states, including Louisiana, New Mexico, Texas and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements.  Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us.  

Our customers and other third parties may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other reasons.  Accordingly, we may be unable to transfer these risks to our customers and other third parties by contract or indemnification agreements.  Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

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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.  The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our drilling rigs, pressure pumping equipment and certain other assets, employer’s liability, automobile liability, commercial general liability, workers’ compensation and insurance for other specific risks.  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, a substantial portion of our drilling rigs and pressure pumping equipment and certain other assets, such insurance does not cover the full replacement cost of such drilling rigs, pressure pumping equipment or other assets.  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 $1.5 million per occurrence deductible on our workers’ compensation insurance coverage, a $1.0 million per occurrence deductible on our equipment insurance coverage, a $2.0 million per occurrence deductible on our general liability coverage, and a $2.0 million per occurrence deductible on our automobile liability insurance coverage.  We also self-insure a number of other risks, including loss of earnings and business interruption and cyber risks, and we do not carry a significant amount of insurance to cover risks of underground reservoir damage.  

Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations.  Our coverage includes aggregate policy limits and exclusions.  As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage.  There can be no assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive, or that our coverage will cover a specific loss.  Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage.  Incurring a liability for which we are not fully insured or indemnified could materially adversely affect our business, financial condition, cash flows and results of operations.  

If a significant accident or other event occurs that is not fully covered by insurance or an enforceable and recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

Our Current Backlog of Contract Drilling Revenue May Continue to Decline and May Not Ultimately Be Realized, as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment.  

Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an early termination payment to us if a contract is terminated prior to the expiration of the fixed term.  However, in certain circumstances, for example, destruction of a drilling rig that is not replaced within a specified period of time, our bankruptcy, or a breach of our contract obligations, the customer may not be obligated to make an early termination payment to us.  Additionally, during depressed market conditions or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate or renegotiate or otherwise fail to honor their contractual obligations.  In addition, we may not be able to perform under these contracts due to events beyond our control, and our customers may seek to terminate or renegotiate our contracts for various reasons, including those described above.  As a result, we may be unable to realize all of our current contract drilling backlog.  In addition, the termination or renegotiation of fixed-term contracts without the receipt of early termination payments could have a material adverse effect on our business, financial condition, cash flows and results of operations.  As of December 31, 2016, our contract drilling backlog for future revenues under term contracts, which we define as contracts with a fixed term of six months or more, was approximately $417 million.  Our contract drilling backlog may continue to decline as fixed-term drilling contract coverage over time may not be offset by new contracts, including as a result of the decline in the price of oil and natural gas, capital spending reductions by our customers or other factors.  

New Technologies May Cause Our Operating Methods and Equipment to Become Less Competitive, and Higher Levels of Capital Expenditures May Be Necessary to Remain Competitive in Our Industry.  

The market for our services is characterized by continual technological and process developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance of drilling rigs and equipment.  Our customers are increasingly demanding the services of newer, higher specification drilling rigs.  Accordingly, a higher level of capital expenditures may be required to maintain and improve existing rigs and equipment and purchase and construct newer, higher specification drilling rigs to meet the increasingly sophisticated needs of our customers.  In addition, technological changes, process improvements and other factors that increase operational efficiencies could continue to result in oil and natural gas wells being drilled and completed more quickly, which could reduce the number of revenue earning days.  Technological and process developments in the pressure pumping business could have similar effects.  

In recent years, we have added drilling rigs to our fleet through new construction, and we have purchased new pressure pumping equipment.  We have also improved existing drilling rigs and pressure pumping equipment by adding equipment designed to enhance functionality and performance.  Although we take measures to ensure that we use advanced oil and natural gas drilling and pressure pumping technology, changes in technology, improvements in competitors’ equipment and changes relating to the wells to be drilled and completed could make our equipment less competitive.  

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If we are not successful keeping pace with technological advances in a timely and cost-effective manner, demand for our services may decline.  If any technology that we need to successfully compete is not available to us or that we implement in the future does not work as we expect, we may be adversely affected.  Additionally, new technologies, services or standards could render some of our services, drilling rigs or pressure pumping equipment obsolete, which could have a material adverse impact on our business, financial condition, cash flows and results of operation.  

Shortages, Delays in Delivery, and Interruptions in Supply, of Equipment and Materials Could Adversely Affect Our Operating Results.  

During periods of increased demand for drilling and pressure pumping services, the industry has experienced shortages of equipment for upgrades, drill pipe, replacement parts and other equipment and materials, including, in the case of our pressure pumping operations, proppants, acid, gel and water.  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 could result in significant delays in delivery of equipment and materials or prevent operations.  Interruptions may be caused by, among other reasons:

These price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating costs.  Severe shortages, delays in delivery and interruptions in supply could limit our ability to operate, maintain, upgrade and construct our drilling rigs and pressure pumping equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

Loss of Key Personnel and Competition for Experienced Personnel May Negatively Impact Our Financial Condition and Results of Operations

We greatly depend on the efforts of our key employees to manage our operations.  The loss of members of management could have a material adverse effect on our business.  In addition, we utilize highly skilled personnel in operating and supporting our businesses.  In times of increasing demand for our services, it may be difficult to attract and retain qualified personnel, particularly after a prolonged industry downturn.  During periods of high demand for our services, wage rates for operations personnel are also likely to increase, resulting in higher operating costs.  During periods of lower demand for our services, we may experience reductions in force and voluntary departures of key personnel, which could adversely affect our business and make it more it difficult to meet customer demands when demand for our services improves. In addition, even if it is generally a period of lower demand for our services, if there is a high demand for our services in certain areas, it may be difficult to attract and retain qualified personnel to perform services in such areas.  The loss of key employees, the failure to attract and retain qualified personnel and the increase in labor costs could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

The Loss of Large Customers Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations.  

With respect to our consolidated operating revenues in 2016, we received approximately 51% from our ten largest customers, 33% from our five largest customers and 14% from our largest customer.  The loss of, or reduction in business from, one or more of our larger customers could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

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.  While we have entered into the merger agreement with SSE, there is no assurance that the SSE merger will be completed.  The SSE merger is subject to a number of conditions, certain of which are beyond our control and may prevent, delay or otherwise materially adversely affect completion of the SSE merger.  In addition, there can be no assurance that acquisition opportunities will be available in the future or that we will be able to execute timely or efficiently any plans for building new rigs and pressure pumping equipment.  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, improved commodity prices may cause contract drillers to continue to build new, high technology rigs and providers of pressure pumping services to continue to build new, high horsepower equipment.  

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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 we 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 or convertible securities could be dilutive to existing stockholders.  Also, continued growth could strain our management, operations, employees and other resources.  See “-Risk Factors Relating to the Pending SSE Merger.”

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

Our business is subject to numerous federal, state, foreign, regional and local laws, rules and regulations governing the discharge of substances into the environment, protection of the environment and worker health and safety, 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:

In addition, environmental laws and regulations in the countries in which we operate impose a variety of requirements on “responsible parties” related to the prevention of spills and liability for damages from such spills.  As an owner and operator of land-based drilling rigs and pressure pumping equipment and a manufacturer and servicer of oilfield service equipment, we may be deemed to be a responsible party under these laws and regulations.  

Changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time.  Stricter laws, regulations or enforcement policies could significantly increase compliance costs for us and our customers and have a material adverse effect on our operations or financial position.  For example, on August 16, 2012, the EPA issued final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds and National Emissions Standards for Hazardous Air Pollutants (“NESHAPS”) to address hazardous air pollutants frequently associated with gas production and processing activities.  In June 2016, the EPA published a final rule that updates and expands the New Source Performance Standards by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In addition, the EPA has announced that it intends to impose methane emission standards for existing sources and has issued information collection requests for oil and natural gas facilities.  The EPA also published a final rule in June 2016 concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry. In November 2016, the Department of the Interior issued final rules relating to the venting, flaring and leaking of natural gas by oil and natural gas producers who operate on federal and Indian lands.  The rules limit routine flaring of natural gas, require the payment of royalties on avoidable gas losses and require plans or programs relating to gas capture and leak detection and repair.  These or other initiatives could increase costs to us and our customers or reduce demand for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

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Potential Legislation and Regulation Covering Hydraulic Fracturing or Other Aspects of the Oil and Gas Industry Could Increase Our Costs and Limit or Delay Our Operations.  

Members of the U.S. Congress and the EPA are reviewing proposals for 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.  For example, the EPA conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater.  As part of this study, the EPA sent requests to a number of companies, including our company, for information on hydraulic fracturing practices.  We responded to the inquiry.  The EPA released its final report in December 2016. It concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells.  Further, we conduct drilling and pressure pumping activities in numerous states.  Some parties believe that there is a correlation between hydraulic fracturing and other oilfield related activities and the increased occurrence of seismic activity.  When caused by human activity, such seismic activity is called induced seismicity.  The extent of this correlation, if any, is the subject of studies of both state and federal agencies. In addition, a number of lawsuits have been filed against other industry participants alleging damages and regulatory violations in connection with such activity.  These and other ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act (“SDWA”) and other aspects of the oil and gas industry.  

In addition, legislation has been proposed, but not enacted, in the U.S. Congress to amend the SDWA 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 enacted, could establish an additional level of regulation at the federal or state level that could limit or delay operational activities or increase operating costs and could result in additional regulatory burdens that could make it more difficult to perform or limit hydraulic fracturing and increase our costs of compliance and doing business.  

Regulatory efforts at the federal level and in many states have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations.  The EPA has asserted federal regulatory authority over hydraulic fracturing using fluids that contain “diesel fuel” under the SDWA Underground Injection Control Program and has released a revised guidance regarding the process for obtaining a permit for hydraulic fracturing involving diesel fuel.  In May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking, seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing.  Further, in March 2015, the Bureau of Land Management (“BLM”) issued a final rule to regulate hydraulic fracturing on Indian land. The rule requires companies to publicly disclose chemicals used in hydraulic fracturing operations to the BLM. However, in June 2016, the U.S. District Court of Wyoming struck down the rule, finding that the BLM lacked authority to promulgate the rule.  That decision is currently being appealed by the federal government.  In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works.  These regulatory initiatives could each spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities.  Certain states where we operate have adopted or are considering disclosure legislation and/or regulations.  For example, Colorado, Louisiana, Montana, North Dakota, Texas and Wyoming have adopted a variety of well construction, set back and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure.  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.  

In addition, in light of concerns about induced seismicity, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity.  For example, the Oklahoma Corporation Commission (“OCC”) has implemented volume reduction plans, and at times required shut-ins, for oil and natural gas disposal wells injecting wastewater into the Arbuckle formation. The OCC also recently released well completion seismicity guidelines for operators in the SCOOP and STACK plays that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity.

Finally, some jurisdictions have taken steps to enact hydraulic fracturing bans or moratoria.  In June 2015, New York banned high volume fracturing activities combined with horizontal drilling.  Certain communities in Colorado have also enacted bans on hydraulic fracturing.  Voters in the city of Denton, Texas approved a moratorium on hydraulic fracturing in November 2014, though it was later lifted in 2015.  These actions have been the subject of legal challenges.  

The adoption of any future federal, state, foreign, regional or local laws that impact permitting requirements for, result in reporting obligations on, or otherwise limit or ban, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing and could increase our costs of compliance and doing business and reduce demand for our services.  Regulation that significantly restricts or prohibits hydraulic fracturing could have a material adverse impact on our business, financial condition, cash flows and results of operations.  

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The Design, Manufacture, Sale and Servicing of Products, including Rig Components, May Subject Us to Liability for Personal Injury, Property Damage and Environmental Contamination Should Such Equipment Fail to Perform to Specifications.

We provide products, including rig components such as top drives, to customers involved in oil and gas exploration, development and production. Because of applications which use our products and services, a failure of such equipment, or a failure of our customer to maintain or operate the equipment properly, could cause damage to the equipment, damage to the property of customers and others, personal injury and environmental contamination, leading to claims against us.

Legislation and Regulation of Greenhouse Gases Could Adversely Affect Our Business

We are aware of the increasing focus of local, state, regional, national and international regulatory bodies on GHG emissions and climate change issues.  Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress, and there has been a wide-ranging policy debate, both in the United States and internationally, regarding the impact of these gases and possible means for their regulation.  Some of the proposals would require industries to meet stringent new standards that would require substantial reductions in carbon emissions.  Those reductions could be costly and difficult to implement.  The EPA has adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources on an annual basis.  Further, following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA finalized a rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s New Source Review Prevention of Significant Deterioration (“PSD”) and Title V programs.  This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.  However, in June 2014, the U.S. Supreme Court in UARG v. EPA limited application of this rule to sources that would otherwise need permits based on emission of conventional pollutants. In April 2015, the D.C. Circuit Court of Appeals narrowed the rule in accordance with the Supreme Court’s decision. In October 2015, the EPA finalized rules that added new sources to the scope of the GHG monitoring and reporting requirements. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities.  Also, in November 2016, the EPA published a final rule adding monitoring methods for detecting leaks from oil and gas equipment and emission factors for leaking equipment to be used to calculate and report GHG emissions resulting from equipment leaks. In addition, the United States was actively involved in the United Nations Conference on Climate Change in Paris, which led to the creation of the Paris Agreement. In April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years.  Several states and geographic regions in the United States have also adopted legislation and regulations to reduce emissions of GHGs.  Additional legislation or regulation by these states and regions, the EPA, and/or any international agreements to which the United States may become a party, that control or limit GHG emissions or otherwise seek to address climate change could adversely affect our operations.  The cost of complying with any new law, regulation or treaty will depend on the details of the particular program.  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.  Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws or regulations related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas.  

Legal Proceedings Could Have a Negative Impact on Our Business.  

The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time.  In addition, during periods of depressed market conditions, such as the one we are currently experiencing, we may be subject to an increased risk of our customers, vendors, current and former employees and others initiating legal proceedings against us. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations.  Any legal proceedings or claims, even if fully indemnified or insured, could negatively affect our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.  

Political, Economic and Social Instability Risk and Laws Associated with Conducting International Operations Could Adversely Affect Our Opportunities and Future Business.  

We currently conduct operations in Canada, and we have incurred selling, general and administrative expenses related to the evaluation of and preparation for other international opportunities. Also, through our recent Warrior acquisition, we sell products, including rig components, for use in numerous oil and gas producing regions outside of North America. International operations are subject to certain political, economic and other uncertainties generally not encountered in U.S. operations, including increased risks of social and political unrest, strikes, terrorism, war, kidnapping of employees, nationalization, forced negotiation or modification of contracts, difficulty resolving disputes and enforcing contractual rights, expropriation of equipment as well as expropriation of oil and gas exploration and drilling rights, changes in taxation policies, foreign exchange restrictions and restrictions on repatriation of income and capital, currency rate fluctuations, increased governmental ownership and regulation of the economy and industry in the

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markets in which we may operate, economic and financial instability of national oil companies, and restrictive governmental regulation, bureaucratic delays and general hazards associated with foreign sovereignty over certain areas in which operations are conducted.  

There can be no assurance that there will not be changes in local laws, regulations and administrative requirements, or the interpretation thereof, which could have a material adverse effect on the cost of entry into international markets, the profitability of international operations or the ability to continue those operations in certain areas.  Because of the impact of local laws, any future international operations in certain areas may be conducted through entities in which local citizens own interests and through entities (including joint ventures) in which we hold only a minority interest or pursuant to arrangements under which we conduct operations under contract to local entities.  While we believe that neither operating through such entities nor pursuant to such arrangements would have a material adverse effect on our operations or revenues, there can be no assurance that we will in all cases be able to structure or restructure our operations to conform to local law (or the administration thereof) on terms we find acceptable.  

There can be no assurance that we will:

In addition, the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar anti-bribery laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business.  Some parts of the world where contract drilling and pressure pumping activities are conducted or where our consumers for the Warrior products are located have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practice and could impact business.  Any failure to comply with the FCPA or other anti-bribery legislation could subject to us to civil, criminal and/or administrative penalties or other sanctions, which could have a material adverse impact on our business, financial condition and results of operation.  We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in those jurisdictions and the seizure of drilling rigs, pressure pumping equipment or other assets.  

We may incur substantial indebtedness to finance an international transaction or operations, and we also may issue equity, convertible or debt securities in connection with any such transactions or operations.  Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders.  Also, international expansion could strain our management, operations, employees and other resources.  

The occurrence of one or more events arising from the types of risks described above could have a material adverse impact on our business, financial condition and results of operations.

Our Business Is Subject to Cybersecurity Risks and Threats.  

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow.  It is possible that our business, financial and other systems could be compromised, which might not be noticed for some period of time.  Risks associated with these threats include, among other things, loss of intellectual property, disruption of our and customers’ business operations and safety procedures, loss or damage to our worksite data delivery systems, unauthorized disclosure of personal information, and increased costs to prevent, respond to or mitigate cybersecurity events.  

We Are Dependent Upon Our Subsidiaries to Meet our Obligations Under our Long-Term Debt

We have borrowings outstanding under our senior notes and, from time to time, our revolving credit facility.  These obligations are guaranteed by each of our existing U.S. 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.  

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Variable Rate Indebtedness Subjects Us to Interest Rate Risk, Which Could Cause Our Debt Service Obligations to Increase Significantly.  

We have in place a committed senior unsecured credit facility that includes a revolving credit facility.  Interest is paid on the outstanding principal amount of borrowings under the credit facility at a floating rate based on, at our election, LIBOR or a base rate.  Until September 27, 2017, the applicable margin on LIBOR rate loans varies from 2.75% to 3.25% and the applicable margin on base rate loans varies from 1.75% to 2.25%, in each case determined based upon our debt to capitalization ratio.  Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based on our excess availability under the credit facility.  As of December 31, 2016, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%.  Based on our debt to capitalization ratio at September 30, 2016, the applicable margin on LIBOR loans was 2.75% and the applicable margin on base rate loans was 1.75% as of January 1, 2017.  Based on our debt to capitalization ratio at December 31, 2016, the applicable margin on LIBOR loans will be 2.75% and the applicable margin on base rate loans will be 1.75% as of April 1, 2017.  As of December 31, 2016, we had no amounts outstanding under our revolving credit facility.  

We have in place a reimbursement agreement pursuant to which we are required to reimburse the issuing bank on demand for any amounts that it has disbursed under any of our letters of credit issued thereunder.  We are obligated to pay the issuing bank interest on all amounts not paid by us on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum.  As of December 31, 2016, no amounts had been disbursed under any letters of credit.

Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amounts borrowed.  

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.  Our restated certificate of incorporation authorizes our Board of Directors 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.  It also prohibits stockholders from acting by written consent without the holding of a meeting.  In addition, our bylaws impose certain advance notification requirements as to business that can be brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder.  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.  

Risk Factors Related to the Pending SSE Merger

Our expectations regarding our business may be impacted by the following risk factors related to the pending SSE merger:

The SSE Merger is Subject to Conditions, Including Certain Conditions That May Not Be Satisfied, or Completed on a Timely Basis, If At All.

The SSE merger is subject to a number of conditions, certain of which are beyond our control and may prevent, delay or otherwise materially adversely affect completion of the SSE merger. Notably, the completion of the SSE merger is conditioned on receiving the approval of both our and SSE’s respective stockholders. At any time prior to the receipt of such approvals, each of our board of directors and the board of directors of SSE may change its recommendation with respect to the SSE merger, in each case in response to a superior proposal or an intervening event if the applicable board of directors determines in good faith, after consultation with its outside counsel, that, among other things, the failure to do so would be inconsistent with its fiduciary duties under applicable law and complies with certain other specified conditions. Consequently, we cannot predict whether and when these conditions will be satisfied. Any delay in completing the SSE merger could cause the combined company not to realize some or all of the benefits that we expect to achieve if the SSE merger is successfully completed within its expected time frame.

Current Patterson-UTI Stockholders Will Have a Reduced Ownership and Voting Interest in the Combined Company After the SSE Merger.

We will issue up to 49,559,000 shares of common stock to SSE stockholders in the SSE merger. As a result of these issuances, SSE stockholders are expected to hold up to approximately 23% of the combined company’s outstanding common stock immediately following completion of the SSE merger.

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Our stockholders currently have the right to vote for our directors and on other matters affecting our company. Each of our stockholders will remain a stockholder of our company with a percentage ownership of the combined company that will be smaller than the stockholder’s percentage of our company prior to the SSE merger. As a result of these reduced ownership percentages, our stockholders will have less voting power in the combined company than they now have with respect to our company.

Uncertainties Associated With the SSE Merger May Cause a Loss of Key Employees, Which Could Adversely Affect the Future Business and Operations of the Combined Company.

We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plan. Our success until the SSE merger and the combined company’s success after the SSE merger will depend in part upon our ability to retain key employees. Current and prospective employees may experience uncertainty about their roles within the combined company following the SSE merger, which may have an adverse effect on our ability to attract or retain key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key employees to the same extent that we have previously been able to attract or retain our own employees.

Failure to Complete the SSE Merger Could Negatively Impact Our Future Business and Financial Results.

We cannot make any assurances that we will be able to satisfy all of the conditions to the SSE merger or succeed in any litigation brought in connection with the SSE merger. If the SSE merger is not completed, our financial results may be adversely affected and we will be subject to several risks, including but not limited to:

In addition, if the SSE merger is not completed, we may experience negative reactions from the financial markets and from our customers and employees. If the SSE merger is not completed, we cannot assure our stockholders that these risks will not materialize and will not materially and adversely affect our business, financial results and stock price.

The Merger Agreement Contains Provisions That Limit Our Ability to Pursue Alternatives to the SSE Merger, Could Discourage a Potential Competing Acquirer of Us From Making a Favorable Alternative Transaction Proposal and, in Specified Circumstances, Could Require Us to Pay a Termination Fee to SSE.

The merger agreement contains “non-solicitation” provisions that, subject to limited exceptions, restrict our ability to, among other things, directly or indirectly, solicit, initiate, facilitate, knowingly encourage or induce or take any action that could be reasonably expected to lead to the making, submission or announcement of a proposal competing with the transactions contemplated by the merger agreement. In addition, while our board of directors has the ability, in certain circumstances, to change its recommendation of the transaction to our stockholders, we cannot terminate the merger agreement to accept an alternative proposal, and SSE generally has an opportunity to modify the terms of the SSE merger and the merger agreement in response to any alternative proposals that may be made before our board of directors may withdraw or modify its recommendation. Moreover, in certain circumstances, we may be required to pay up to $7,500,000 of SSE’s expenses or we may be required to pay SSE a termination fee of either $40,000,000 or $100,000,000.

These provisions could discourage a potential third party that might have an interest in acquiring all or a significant portion of us from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per share cash or market value than the market value proposed to be received or realized in the SSE merger. In addition, these provisions might result in a potential third party acquirer proposing to pay a lower price to our stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee that may become payable in certain circumstances. If the merger agreement is terminated and we determine to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the SSE merger.

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Completion of the SSE Merger May Trigger Change in Control or Other Provisions in Certain Agreements to Which SSE is a Party.

The completion of the SSE merger may trigger change in control or other provisions in certain agreements to which SSE is a party. If we and SSE are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under the agreements, potentially terminating the agreements or seeking monetary damages. Even if we and SSE are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to SSE or the combined company.

We and SSE May be Unable to Obtain the Regulatory Clearances and Approvals Required to Complete the SSE Merger or, in Order to Do So, We May be Required to Comply With Material Restrictions or Conditions.

Under the HSR Act, neither we nor SSE may complete the SSE merger until required information and materials are furnished to the U.S. Department of Justice (“DOJ”) and the U.S. Federal Trade Commission (“FTC”), and the applicable waiting period under the HSR Act terminates or expires. On January 3, 2017, we and SSE filed the requisite notification and report forms under the HSR Act with the DOJ and the FTC. On January 13, 2017, we and SSE were notified by the FTC that the early termination of the waiting period under the HSR Act had been granted.

The SSE merger may also be subject to the regulatory requirements of other municipal, state, federal, or foreign governmental agencies and authorities. Regulatory entities may impose certain requirements or obligations as conditions for their approval or in connection with their review.

The merger agreement may require us to accept conditions from these regulators that could adversely impact the combined company without us having the right to refuse to close the SSE merger on the basis of those regulatory conditions. We cannot provide any assurance that we will obtain the necessary clearances or approvals, or that any required conditions will not have a material adverse effect on the combined company following the SSE merger or result in the abandonment of the SSE merger.

Additionally, even after the above-described statutory waiting periods have expired, and even after completion of the SSE merger, governmental authorities could seek to challenge the SSE merger. We may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

The Pendency of the SSE Merger Could Adversely Affect Our Business and Operations.

In connection with the pending SSE merger, some of our customers or vendors may delay or defer decisions, which could negatively affect our revenues, earnings, cash flows and expenses, regardless of whether the SSE merger is completed. Similarly, our current and prospective employees may experience uncertainty about their future roles with the combined company following the SSE merger, which may materially adversely affect our ability to attract, retain and motivate key personnel during the pendency of the SSE merger and which may materially adversely divert attention from the daily activities of our existing employees.

In addition, due to operating covenants in the merger agreement, we may be unable, during the pendency of the SSE merger, to pursue strategic transactions, undertake significant capital projects, undertake certain significant financing transactions and otherwise pursue other actions that are not in the ordinary course of business, even if such actions would prove beneficial to us. Further, the process of seeking to accomplish the SSE merger could also divert the focus of management from pursuing other opportunities that could be beneficial to us, without realizing any of the benefits which might have resulted had the SSE merger been completed.

Item 1B. Unresolved Staff Comments.  

None.  

Item 2. Properties  

Our property consists primarily of drilling rigs, pressure pumping equipment and related equipment.  We own substantially all of the equipment used in our businesses.  

Our corporate headquarters is in leased office space and is located at 10713 W. Sam Houston Parkway N., Suite 800, Houston, Texas, 77064.  Our telephone number at that address is (281) 765-7100.  Our primary administrative office, which is located in Snyder, Texas, is owned 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, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania and western Canada.  

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

Our manufacture, sale and service of pipe handling components are supported by offices and yard facilities located in western Canada and Texas.  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 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 incorporate by reference in response to this item the information set forth in Item 1 of this Report and the information set forth in Note 4 of the Notes to Consolidated Financial Statements included in Item 8 of this Report.  

Item 3. Legal Proceedings.  

We are party to various legal proceedings arising in the normal course of its 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, results of operations or cash flows.  

Item 4. Mine Safety Disclosure.  

Not applicable.  

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.  

(a) Market Information

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:

(b) Holders

As of February 6, 2017, there were approximately 1,126 holders of record of our common stock.  

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(c) Dividends

We paid cash dividends during the years ended December 31, 2016 and 2015 as follows:

On February 8, 2017, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on March 22, 2017 to holders of record as of March 8, 2017.  The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors.  The merger agreement prohibits us (unless consented to in advance by SSE, which consent may not be unreasonably withheld, delayed or conditioned) from paying dividends to holders of our common stock in excess of $0.02 per share per quarter until the earlier of the effective time of the SSE merger and the termination of the merger agreement in accordance with its terms.

(d) Issuer Purchases of Equity Securities

The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2016.  

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(e) Performance Graph

The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2011 through December 31, 2016, 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.  We changed our peer group in 2016 to align with the peer group used by the compensation committee of our board of directors.  In addition, our former peer group has been impacted by acquisitions over recent years.  Our new peer group consists of Atwood Oceanics Inc., Basic Energy Services, Inc., Diamond Offshore Drilling Inc., Ensco plc., Forum Energy Technologies, Inc., FMC Technologies, Inc. (n/k/a  TechnipFMC plc), Helmerich & Payne, Inc., Nabors Industries, Ltd., Noble Corp., Oceaneering International, Oil States International Inc., Precision Drilling Corporation, Parker Drilling Company, Rowan Companies Inc., Superior Energy Services, Inc., Transocean Ltd., Unit Corp. and Weatherford International Ltd.

The graph assumes investment of $100 on December 31, 2011 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.  

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Item 6. Selected Financial Data.  

Our selected consolidated financial data as of December 31, 2016, 2015, 2014, 2013 and 2012, and for each of the five years in the period ended December 31, 2016, 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.  

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Recent Developments — Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2014, 2015 and 2016 are as follows:

The closing price of oil was as high as $107.95 per barrel in June 2014.  Prices began to fall in the third quarter of 2014 and reached a twelve-year low of $26.19 in February 2016.  Oil and natural gas prices have recovered substantially from the lows experienced in the first quarter of 2016.  During the fourth quarter of 2016, OPEC and certain non-OPEC countries, including Russia, announced an agreement to cut oil production. The announcement resulted in an increase in oil prices, which averaged $51.97 per barrel in December 2016.  In response to improved prices, U.S. rig counts have been increasing, and we believe they will continue to increase throughout 2017 if prices for these commodities remain at or above current levels.  

Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but has steadily improved on a monthly basis since May 2016.  For the fourth quarter, our average rig count improved to 66 rigs in the United States, up from the third quarter average of 60 rigs.  Our rig count in the United States at December 31, 2016 of 74 rigs was 42% greater than the low of 52 rigs in April 2016; however, it was 65% less than the high of 214 rigs in October 2014.  Term contracts have supported our operating rig count during the last three years.  Based on contracts currently in place, we expect an average of 44 rigs operating under term contracts during the first quarter of 2017 and an average of 37 rigs operating under term contracts throughout 2017.

Activity levels in our pressure pumping business have also improved.  Looking forward, we expect to see further increases in activity across the industry, especially in the Permian Basin.  We have reactivated two frac spreads since mid-December 2016 at a cost of approximately $2 million per spread, including both operating and capital expenditures.  Approximately 45% of the more than one million hydraulic fracturing horsepower in our fleet remains stacked.  We expect the cost to reactivate our remaining idle frac spreads would be approximately $3 million per frac spread, including both operating and capital expenditures.

On December 12, 2016, we entered into the merger agreement with SSE, pursuant to which a subsidiary of ours will be merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly owned subsidiaries.  Under the merger agreement, we will acquire all of the issued and outstanding shares of common stock of SSE in exchange for approximately 49.6 million shares of our common stock, subject to certain downward adjustments set forth in the merger agreement.  SSE provides contract drilling, pressure pumping and oilfield rental services in many of the most active oil and natural gas plays onshore in the United States.  SSE owns a fleet of 40 AC drilling rigs, approximately 93% of which are pad capable, including 28 fit-for purpose PeakeRigs™.  The remainder of SSE’s rig fleet includes 51 SCR rigs.  Additionally, SSE owns approximately 500,000 horsepower of modern, efficient fracturing equipment located in the Anadarko Basin and Eagle Ford Shale.  The SSE oilfield rentals business has a modern, well-maintained fleet of premium rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities.

The completion of the SSE merger is subject to satisfaction or waiver of certain closing conditions, including, but not limited to, approval by our and SSE’s respective stockholders and other closing conditions set forth in the merger agreement. Subject to closing conditions, the SSE merger is expected to be completed late in the first quarter or early in the second quarter of 2017.

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Management Overview — We are a Houston, Texas-based oilfield services company that primarily owns and operates in the United States one of the largest fleets of land-based drilling rigs and a large fleet of pressure pumping equipment.  Our contract drilling business operates in the continental United States and western Canada, and we are pursuing contract drilling opportunities outside of North America.  Our pressure pumping business operates primarily in Texas and the Appalachian region.  We also manufacture and sell pipe handling components and related technology to drilling contractors in North America and other select markets.  In addition, we own and invest, as a non-operating working interest owner, in oil and natural gas assets that are primarily located in Texas and New Mexico.  

There continues to be uncertainty with respect to the global economic environment, and oil and natural gas prices have been depressed. During the fourth quarter of 2016, our average number of rigs operating in the United States was 66 compared to an average of 88 drilling rigs operating during the same period in 2015. During the fourth quarter of 2016, our average number of rigs operating in Canada was two compared to an average of three drilling rigs operating during the fourth quarter of 2015.

We have addressed our customers’ needs for drilling horizontal wells in shale and other unconventional resource plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years.  As of December 31, 2016, our rig fleet included 161 APEX^® rigs. We expect to add two new APEX^® rigs to our fleet during 2017.

In connection with the development of horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. As of December 31, 2016, we had approximately 1.1 million hydraulic horsepower in our pressure pumping fleet (approximately 1.0 million of which was hydraulic fracturing horsepower). We have increased the horsepower of our pressure pumping fleet by more than eight-fold since the beginning of 2009, although we have not ordered or committed to purchase any new horsepower since October 2014 and there is currently no new horsepower on order. In recent years, the industry-wide addition of new pressure pumping equipment to the marketplace and lower oil and natural gas prices have led to an excess supply of pressure pumping equipment in North America.

We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term of six months or more.  Our contract drilling backlog as of December 31, 2016 and 2015 was $417 million and $710 million, respectively. The decrease in backlog at December 31, 2016 from December 31, 2015, is primarily due to the revenue earned since December 31, 2015, including revenue from the receipt of early termination payments, and the expiration and termination of certain of our term contracts. Approximately 29% of the total December 31, 2016 backlog is reasonably expected to remain after 2017.  We generally calculate our backlog by multiplying the dayrate under our term drilling contracts by the number of days remaining under the contract.  The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving or incurring maintenance and repair time in excess of what is permitted under the drilling contract.  In addition, our term drilling contracts are generally subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer.  For contracts that we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the dayrate, for the period we expect to receive the lower rate.  See “Item 1A. Risk Factors – Our Current Backlog of Contract Drilling Revenue May Continue to Decline and May Not Ultimately Be Realized, as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment.”  

For the three years ended December 31, 2016, our operating revenues consisted of the following (dollars in thousands):

Generally, the profitability of our business is most impacted by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day.  During 2016, our average number of rigs operating was 63 in the United States and two in Canada compared to 120 in the United States and four in Canada in 2015, and 203 in the United States and eight in Canada in 2014.  Our average rig revenue per operating day was $23,040 in 2016 compared to $25,560 in 2015 and $23,880 in 2014.  We had a consolidated net loss of $319 million for 2016 compared to consolidated net loss of $294 million for 2015 and consolidated net income of $163 million for 2014.  The financial results for 2015 include pretax non-cash charges totaling approximately $288 million.  These charges include $125 million from the impairment of all goodwill associated with our pressure pumping business, $131 million from the write-down of drilling equipment primarily related to mechanical rigs and spare mechanical rig components, $22.0 from the write-down of pressure pumping equipment and closed facilities and $10.7 million related to the impairment of certain oil and natural gas properties.   The financial results for 2014 include a pretax non-cash charge of $77.9 million related to the retirement of mechanical rigs and the write-off of excess spare components.

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Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas.  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 services.  Conversely, in periods when these commodity prices deteriorate, the demand for our services generally weakens and we experience downward pressure on pricing for our services.  Oil and natural gas prices and our number of rigs operating have significantly declined from 2014.  In December 2016, our average number of rigs operating was 71 in the United States.  In January 2017, our average number of rigs operating increased to 76 in the United States.  

We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues, weather 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.  

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, goodwill, revenue recognition, the use of estimates and oil and natural gas properties.  

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.  

On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional, vertical wells versus drilling longer, horizontal wells using higher specification rigs).  The components comprising rigs that will no longer be marketed are evaluated, and those components with continuing utility to our other marketed rigs are transferred to other rigs or to our yards to be used as spare equipment.  The remaining components of these rigs will be retired.   In 2016, we retired 19 mechanical rigs but recorded no impairment charge as we had written down 15 of those rigs in 2015 that remained marketed.   In 2015, we identified 24 mechanical rigs and 9 non-APEX® electric rigs that would no longer be marketed.  Also, we had 15 additional mechanical rigs that were not operating.  Although these 15 rigs remained marketed at that time, we had lower expectations with respect to utilization of these rigs due to the industry shift to higher specification drilling rigs.  In 2015, we recorded a charge of $131 million related to the retirement of the 33 rigs, the 15 mechanical rigs that remained marketed but were not operating, and the write-down of excess spare rig components to their realizable values.  In 2014, we identified 55 mechanical rigs that we determined would no longer be marketed, and we recorded a charge of $77.9 million related to the retirement of these mechanical rigs and the write-off of excess spare components for the reduced size of our mechanical fleet.  

We also periodically evaluate our pressure pumping assets, and in 2015, we recorded a charge of $22.0 million for the write-down of pressure pumping equipment and certain closed facilities.  There were no similar charges in 2016 or 2014.

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 (“triggering events”).  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.  We estimate future cash flows over the life of the respective assets or asset groupings 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 at fair value.  

Based on recent commodity prices, our results of operations for the year ended December 31, 2016 and management’s expectations of operating results in future periods, we concluded that no triggering events occurred during the year ended December 31, 2016 with respect to our contract drilling or pressure pumping segments.  Our expectations of future operating results were based on the assumption that activity levels in both segments will begin to recover by early 2017 in response to improved future oil prices.  

During the third quarter of 2015, oil prices declined and averaged $46.42 per barrel, reaching a new low for 2015 of $38.22 per barrel in August 2015.  In light of these lower oil prices in August, we lowered our expectations with respect to future activity levels in both the contract drilling and pressure pumping businesses. As a result of these revised expectations of the duration of the lower oil and natural gas commodity price environment and the related deterioration of the markets for contract drilling and pressure pumping services during the third quarter of 2015, we concluded a triggering event had occurred and deemed it necessary to assess the recoverability of long-lived asset groups for both contract drilling and pressure pumping.  We performed a Step 1 analysis as required

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by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract drilling and pressure pumping segments.  With respect to these assets, future cash flows were estimated over the expected remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no impairment was indicated.  Expected cash flows, on an undiscounted basis, exceeded the carrying values of the long-lived assets within the contract drilling and pressure pumping segments by approximately 120% and 60%, respectively.  

Due to the continued deterioration of crude oil prices in the fourth quarter of 2015, we deemed it necessary to once again assess the recoverability of long-lived assets groups for both contract drilling and pressure pumping.  We performed a Step 1 analysis as required by ASC 360-10-35 to assess the recoverability of long-lived assets within our contract drilling and pressure pumping segments.  With respect to these assets, future cash flows were estimated over the expected remaining life of the assets, and we determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets, and no impairment was indicated.  Expected cash flows, on an undiscounted basis, exceeded the carrying values of the long-lived assets within the contract drilling and pressure pumping segments by approximately 120% and 100%, respectively.  

For both of the assessments performed in 2015, the expected cash flows for the contract drilling segment included the backlog of commitments for contract drilling revenues under term contracts, which was approximately $801 million and $710 million at September 30, 2015 and December 31, 2015, respectively.  Rigs not under term contracts would be subject to pricing in the spot market.  Utilization and rates for rigs in the spot market and for the pressure pumping segment were estimated based upon our historical experience in prior downturns.  Also, the expected cash flows for the contract drilling and pressure pumping segments were based on the assumption that activity levels in both segments would begin to recover in the first quarter of 2017 in response to improved oil prices.   While we believe these assumptions with respect to future pricing for oil and natural gas are reasonable, actual future prices may vary significantly from the ones that were assumed.  The timeframe over which oil and natural gas prices will recover is highly uncertain.  Potential events that could affect our assumptions regarding future prices and the timeframe for a recovery are affected by factors such as:

All of these factors are beyond our control. If the current oil and natural gas commodity price environment were to last through 2017 and beyond, our actual cash flows would likely be less than the expected cash flows used in the aforementioned 2015 assessments and could result in impairment charges in the future, and any such impairment charges could be material.  

We concluded that no triggering events occurred during the year ended December 31, 2014 with respect to our contract drilling or pressure pumping segments based on our results of the operations for the year ended December 31, 2014 and the prevailing commodity prices at that time.

Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized.  Goodwill is evaluated at least annually as of December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value.  For purposes of impairment testing, goodwill is evaluated at the reporting unit level.  Our reporting units for impairment testing have been determined to be our operating segments.  We first determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors, and if so, the resulting goodwill impairment is determined using a two-step quantitative impairment test.  From time to time, we may perform the first step of the quantitative testing for goodwill impairment in lieu of performing the qualitative assessment.  The first step of the quantitative testing is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units.  If the carrying value of a reporting unit exceeds its fair value, the second step of the quantitative testing is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities, with any remaining fair value representing the fair value of goodwill.  If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of such shortfall.

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In connection with our annual goodwill impairment assessment as of December 31, 2016, we determined based on an assessment of qualitative factors that it was more likely than not that the fair values of our contract drilling reporting unit was greater than its carrying amount and further testing was not necessary.  In making this determination, we considered the demand experienced during 2016 for our contract drilling business.  We also considered the current and expected levels of commodity prices for oil and natural gas, which influence the overall level of business activity in this reporting unit, as well as its operating results for 2016 and forecasted operating results for 2017.  Lastly, management considered our overall market capitalization at December 31, 2016 and the significant amount of calculated excess of the fair value of our reporting unit over its carrying value from our 2015 quantitative impairment assessment of goodwill.

During the third quarter of 2015, oil prices declined and averaged $46.42 per barrel, reaching a new low for 2015 of $38.22 per barrel in August 2015.  In light of these lower oil prices in August, we lowered our expectations with respect to future activity levels in both the contract drilling and pressure pumping businesses.  As a result of our revised expectations of the duration of the lower oil and natural gas commodity price environment and the related deterioration of the markets for our contract drilling and pressure pumping services, we performed a quantitative Step 1 impairment assessment of our goodwill as of September 30, 2015.  In completing the Step 1 assessment, the fair value of each reporting unit was estimated using both the income and market valuation methods. The estimate of the fair value of each reporting unit required the use of significant unobservable inputs, representative of a Level 3 fair value measurement.  The inputs included assumptions related to the future performance of our contract drilling and pressure pumping reporting units, such as future oil and natural gas prices and projected demand for our services, and assumptions related to discount rates, long-term growth rates and control premiums.

Based on the results of the Step 1 goodwill impairment test as of September 30, 2015, the fair value of the contract drilling reporting unit exceeded its carrying value by approximately 15%, and we concluded that no impairment was indicated in our contract drilling reporting unit; however, impairment was indicated in our pressure pumping reporting unit.  In the third quarter of 2015, we recognized an impairment charge of $125 million associated with the impairment of all of the goodwill in our pressure pumping reporting unit.  

In connection with our annual goodwill impairment assessment as of December 31, 2015, we performed a quantitative Step 1 impairment assessment of the goodwill in our contract drilling reporting unit.  In completing the Step 1 assessment, the fair value of the contract drilling reporting unit was estimated using both the income and market valuation methods.  The estimate of the fair value of the reporting unit required the use of significant unobservable inputs, representative of a Level 3 fair value measurement.  The inputs included assumptions related to the future performance of our contract drilling reporting unit, such as future oil and natural gas prices and projected demand for our services, and assumptions related to discount rates, long-term growth rates and control premiums.  Based on the results of the quantitative Step 1 impairment assessment of our goodwill, as of December 31, 2015, the fair value of our contract drilling reporting unit exceeded its carrying value by approximately 16%, and we concluded that no impairment was indicated in our contract drilling reporting unit.

In connection with our annual goodwill impairment assessment as of December 31, 2014, we determined based on an assessment of qualitative factors that it was more likely than not that the fair values of our reporting units were greater than their respective carrying amounts and no further testing was deemed necessary.  In making this determination, we considered the continued demand experienced during 2014 for our contract drilling and pressure pumping businesses.  We also considered the current and expected levels of commodity prices for oil and natural gas, which influence the overall level of business activity in these reporting units.  Additionally, operating results for 2014 and forecasted operating results for 2015 were also taken into account.  Lastly, management considered our overall market capitalization at December 31, 2014 and the large amount of calculated excess of the fair values of our reporting units over their respective carrying values from our 2013 quantitative impairment assessment.  

We have undertaken extensive efforts in the past several years to upgrade our fleet of equipment and believe that we are well-positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional vertical wells.  In the event that market conditions were to remain weak for a protracted period, we may be required to record an impairment of goodwill in our contract drilling reporting unit in future periods, and any such impairment could be material.  

Revenue recognition — Revenues from daywork drilling and pressure pumping activities are recognized as services are performed.  Expenditures reimbursed by customers are recognized as revenue and the related expenses are recognized as direct costs.  All of the wells we drilled in 2016, 2015 and 2014 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 (“U.S. GAAP”) 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.  

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Key estimates used by management include:

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 and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved developed oil and natural gas reserves for each respective field.  Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total 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 expected future oil and natural gas prices.  Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our expectation of future pricing 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 fair value.  The fair value estimates used in measuring impairment are based on internally developed unobservable inputs including reserve volumes and future production, pricing and operating costs (Level 3 inputs in the fair value hierarchy of fair value accounting).  The expected future net cash flows are discounted using an annual rate of 10% to determine fair value.  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 both proved and unproved oil and natural gas properties totaled approximately $2.8 million, $10.7 million and $20.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, and such amounts are included in depreciation, depletion, amortization and impairment in the consolidated statements of operations.  

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

Our liquidity as of December 31, 2016 included approximately $18.5 million in working capital and $500 million available under our revolving credit facility.  

On January 24, 2017, we entered into an agreement with certain lenders under our revolving credit facility pursuant to which we exercised approximately $95.8 million of the $100 million commitment increase feature available thereunder in order to increase the aggregate commitments under our revolving credit facility to approximately $595.8 million.  The effectiveness of the aggregate commitment increase is subject to certain conditions, including the consummation of the SSE merger and the repayment and termination of the SSE credit facility, as well as other customary conditions.

On January 27, 2017, we completed an offering of 18.2 million shares of our common stock, and we intend to use the net proceeds from this offering of approximately $470 million to fund the repayment of SSE’s outstanding net indebtedness upon closing of the SSE merger.  If the SSE merger is not consummated, we intend to use the net proceeds of the offering for general corporate purposes, which may include repayment of outstanding indebtedness or investments in working capital.

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We believe our current liquidity, together with cash expected to be generated from operations in 2017, should provide us with sufficient ability to fund our current plans to maintain and make improvements to our existing equipment, service our debt and pay cash dividends for at least the next 12 months.  If under current market conditions we desire to pursue opportunities for growth, in addition to the SSE merger, that require capital, we believe we would likely require additional debt or equity financing.  However, there can be no assurance that such capital will be available on reasonable terms, if at all.

As of December 31, 2016, we had working capital of $18.5 million, including cash and cash equivalents of $35.2 million, compared to working capital of $179 million, including cash and cash equivalents of $113 million, at December 31, 2015.  

During 2016, our sources of cash flow included:

During 2016, we used $255 million to repay long-term debt, $23.6 million to pay dividends on our common stock, $3.6 million to acquire shares of our common stock, $3.4 million to pay debt issuance costs and $120 million:

We paid cash dividends during the year ended December 31, 2016 as follows:

On February 8, 2017, our Board of Directors approved a cash dividend on our common stock in the amount of $0.02 per share to be paid on March 22, 2017 to holders of record as of March 8, 2017.  The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our debt agreements and other factors.  The merger agreement prohibits us (unless consented to in advance by SSE, which consent may not be unreasonably withheld, delayed or conditioned) from paying dividends to holders of our common stock in excess of $0.02 per share per quarter until the earlier of the effective time of the SSE merger and the termination of the merger agreement in accordance with its terms.

On September 6, 2013, our Board of Directors approved a stock buyback program that authorizes purchase of up to $200 million of our common stock in open market or privately negotiated transactions.  As of December 31, 2016, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the 2013 stock buyback program.  Shares purchased under a buyback program are accounted for as treasury stock.  

We acquired shares of stock from directors in 2016 and from employees during 2016, 2015 and 2014 that are accounted for as treasury stock.  Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options.  The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock.  These shares were acquired at fair market value.  These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan or the Patterson-UTI Energy, Inc. 2014 Long-Term Incentive Plan and not pursuant to the stock buyback program.  

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Treasury stock acquisitions during the years ended December 31, 2016, 2015 and 2014 were as follows (dollars in thousands):

2012 Credit Agreement — On September 27, 2012, we entered into a Credit Agreement (“Base Credit Agreement”).  The Base Credit Agreement (as amended, the “Credit Agreement”) is a committed senior unsecured credit facility that includes a revolving credit facility.

On July 8, 2016, we entered into Amendment No. 2 to the Credit Agreement (“Amendment No. 2”), which amended the Base Credit Agreement. The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time, subject to a borrowing base calculated by reference to ours and certain of our subsidiaries’ eligible equipment, inventory, accounts receivable and unencumbered cash as described in Amendment No. 2.  The revolving credit facility contains a letter of credit facility that is limited to $50 million and a swing line facility that is limited to $20 million, in each case outstanding at any time. 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 $600 million.  The maturity date under the Base Credit Agreement was September 27, 2017 for the revolving credit facility; however, Amendment No. 2 extended the maturity date of $357.9 million in revolving credit commitments of certain lenders to March 27, 2019.  

The term loan facility included in the Base Credit Agreement, which facility was terminated in connection with Amendment No. 2, provided for a loan of $100 million, which was drawn on December 24, 2012 and was payable in quarterly principal installments.  As a condition precedent, Amendment No. 2 required that we repay the entire outstanding principal amount of this term loan.  

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate.  Until September 27, 2017, the applicable margin on LIBOR rate loans varies from 2.75% to 3.25% and the applicable margin on base rate loans varies from 1.75% to 2.25%, in each case determined based upon our debt to capitalization ratio.  Beginning September 27, 2017, the applicable margin on LIBOR rate loans varies from 3.25% to 3.75% and the applicable margin on base rate loans varies from 2.25% to 2.75%, in each case determined based on our availability under the credit facility.  As of December 31, 2016, the applicable margin on LIBOR rate loans was 2.75% and the applicable margin on base rate loans was 1.75%.  Based on our debt to capitalization ratio at September 30, 2016, the applicable margin on LIBOR loans is 2.75% and the applicable margin on base rate loans is 1.75% as of January 1, 2017.  Based on our debt to capitalization ratio at December 31, 2016, the applicable margin on LIBOR loans will be 2.75% and the applicable margin on base rate loans will be 1.75% as of April 1, 2017.  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 rate payable to the lenders for the unused portion of the credit facility is 0.50%.

Each of our domestic subsidiaries unconditionally guarantees all existing and future indebtedness and liabilities of the other guarantors and ours arising under the Credit Agreement, other than (a) Ambar Lone Star Fluid Services LLC, (b) domestic subsidiaries that directly or indirectly have no material assets other than equity interests in, or capitalization indebtedness owed by, foreign subsidiaries, and (c) any subsidiary having total assets of less than $1 million.  Such guarantees also cover our or any of our subsidiaries arising under any interest rate swap contract with any person while such person is a lender or an affiliate of a lender under the Credit Agreement.

The Credit Agreement requires compliance with two financial covenants.  We must not permit our debt to capitalization ratio to exceed 40%.  The 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 our interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00.  The 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 covenants at December 31, 2016.

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Amendment No. 2 limits our ability to make investments in foreign subsidiaries or joint ventures such that, if the book value of all such investments since September 27, 2012 is above 20% of the total consolidated book value of our consolidated assets on a pro forma basis, we will not be able to make such investment.  Amendment No. 2 also restricts our ability to pay dividends and make equity repurchases, subject to certain exceptions, including an exception allowing such restricted payments if before and immediately after giving effect to such restricted payment, the Pro Forma Debt Service Coverage Ratio (as defined in Amendment No. 2) is at least 1.50 to 1.00.  In addition, Amendment No. 2 requires that, if our consolidated cash balance, subject to certain exclusions, is more than $100 million at the end of the day on which a borrowing is made, we can only use the proceeds from such borrowing to fund acquisitions, capital expenditures and the repurchase of indebtedness, and if such proceeds are not used in such manner within three business days, we must repay such unused proceeds on the fourth business day following such borrowings.  Amendment No. 2 also decreased the permitted amount of certain secured indebtedness of us and our subsidiaries and decreased the permitted amount of certain unsecured indebtedness of our subsidiaries.

The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants.  We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events.  If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to our insolvency and bankruptcy, such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit.

As of December 31, 2016, we had no amounts outstanding under our revolving credit facility, with available borrowing capacity of $500 million.

On January 17, 2017, we entered into Amendment No. 3 to Credit Agreement (“Amendment No. 3”), which amended the Credit Agreement by restating the definition of Consolidated EBITDA to provide for the add-back of transaction expenses related to the SSE merger.  

On January 24, 2017, we entered into an agreement with certain lenders under our revolving credit facility pursuant to which we exercised approximately $95.8 million of the $100 million commitment increase feature available thereunder in order to increase the aggregate commitments under our revolving credit facility to approximately $595.8 million.  The effectiveness of the aggregate commitment increase is subject to certain conditions, including the consummation of the SSE merger and the repayment and termination of the SSE credit facility, as well as other customary conditions.

2015 Reimbursement Agreement — On March 16, 2015, we entered into a Reimbursement Agreement (the “Reimbursement Agreement”) with The Bank of Nova Scotia (“Scotiabank”), pursuant to which we may from time to time request that Scotiabank issue an unspecified amount of letters of credit.  As of December 31, 2016, we had $38.2 million in letters of credit outstanding under the Reimbursement Agreement.

Under the terms of the Reimbursement Agreement, we will reimburse Scotiabank on demand for any amounts that Scotiabank has disbursed under any letters of credit.  Fees, charges and other reasonable expenses for the issuance of letters of credit are payable by us at the time of issuance at such rates and amounts as are in accordance with Scotiabank’s prevailing practice.  We are obligated to pay to Scotiabank interest on all amounts not paid on the date of demand or when otherwise due at the LIBOR rate plus 2.25% per annum, calculated daily and payable monthly, in arrears, on the basis of a calendar year for the actual number of days elapsed, with interest on overdue interest at the same rate as on the reimbursement amounts.

We have also agreed that if obligations under the Credit Agreement are secured by liens on any of our subsidiaries’ property, then our reimbursement obligations and (to the extent similar obligations would be secured under the Credit Agreement) other obligations under the Reimbursement Agreement and any letters of credit will be equally and ratably secured by all property subject to such liens securing the Credit Agreement.

Pursuant to a Continuing Guaranty dated as of March 16, 2015 (the “Continuing Guaranty”), our payment obligations under the Reimbursement Agreement are jointly and severally guaranteed as to payment and not as to collection by our subsidiaries that from time to time guarantee payment under the Credit Agreement.

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2015 Term Loan Agreement — On March 18, 2015, we entered into a Term Loan Agreement (the “2015 Term Loan Agreement”).  The 2015 Term Loan Agreement was a senior unsecured single-advance term loan facility pursuant to which we made a term loan borrowing of $200 million on March 18, 2015 (the “Term Loan Borrowing”).  The Term Loan Borrowing was payable in quarterly principal installments, together with accrued interest.  Loans under the 2015 Term Loan Agreement bore interest, at our election, at the per annum rate of LIBOR rate plus 3.25% or base rate plus 2.25%.

As a condition precedent to Amendment No 2, we repaid the entire outstanding principal amount under the 2015 Term Loan Agreement and terminated the agreement on July 8, 2016.

Senior Notes — 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 “Series A Notes”) in a private placement.  The Series A Notes bear interest at a rate of 4.97% per annum.  We pay interest on the Series A Notes on April 5 and October 5 of each year.  The Series A Notes will mature on October 5, 2020.  

On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amounts of our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement.  The Series B Notes bear interest at a rate of 4.27% per annum.  We pay interest on the Series B Notes on April 5 and October 5 of each year.  The Series B Notes will mature on June 14, 2022.  

The Series A Notes and Series B Notes are senior unsecured obligations, which rank equally in right of payment with all of our other unsubordinated indebtedness.  The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of our domestic subsidiaries other than subsidiaries that are not required to be guarantors under the Credit Agreement.

The Series A Notes and Series B 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 agreements.  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 respective note purchase agreements require compliance with two financial covenants.  We must not permit our debt to capitalization ratio to exceed 50% at any time.  The note purchase agreements generally define 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 our interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00.  The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period.  We were in compliance with these covenants at December 31, 2016.  We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.  

Events of default under the note purchase agreements 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 under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective 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 pursuant to the note purchase agreement to be immediately due and payable.  

Commitment Letter – On December 12, 2016 in connection with the execution of the merger agreement, we entered into a financing commitment letter (the “Commitment Letter”) with Canyon Capital Advisors LLC for a senior unsecured bridge facility in an aggregate principal amount not to exceed $150 million (the “Bridge Facility”), for the purposes of repaying or redeeming certain of SSE and its subsidiaries’ indebtedness and to pay related fees and expenses. Any undrawn commitments under the Bridge Facility will automatically terminate on the closing date of the SSE merger. The Bridge Facility will be subject to representations, warranties and covenants that, subject to certain agreed modifications, will be substantially similar to our revolving credit facility. The funding of the Bridge Facility is subject to our compliance with customary terms and conditions precedent as set forth in the Commitment Letter, including, among others: (i) the execution and delivery by us of definitive documentation consistent with the Commitment Letter and (ii) the SSE merger shall have been, or substantially simultaneously with the funding under the Bridge Facility shall be, consummated in accordance with the terms of the merger agreement. We do not currently expect to enter into the Bridge Facility.

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Commitments and Contingencies — The merger agreement provides for an expense reimbursement in an amount not to exceed $7.5 million in respect of bona fide, out of pocket expenses actually incurred by SSE in connection with the merger agreement if the merger agreement is terminated if our stockholders fail to approve the issuance of our common stock in the SSE merger.  The merger agreement also provides that we may be required to pay SSE a termination fee of $100 million in certain circumstances, including if our board of directors changes its recommendation as a result of a superior parent proposal (as defined in the merger agreement) or if the merger agreement is terminated in certain circumstances and we enter into certain types of alternative acquisition transactions within 12 months of termination. In certain other circumstances, we may be required to pay SSE a termination fee of $40 million. In no event will we be obligated to make more than one expense reimbursement payment or more than one termination fee payment to SSE.

The description of the expense reimbursement, termination payments and other provisions of the merger agreement does not purport to be complete and is qualified in its entirety by the full text of the merger agreement, which we filed with the SEC on December 13, 2016 as Exhibit 2.1 to our Current Report on Form 8-K.

As of December 31, 2016, we maintained letters of credit in the aggregate amount of $38.2 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, 2016, no amounts had been drawn under the letters of credit.  

As of December 31, 2016, we had commitments to purchase approximately $68.4 million of major equipment for our drilling and pressure pumping businesses.  

Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors.  As of December 31, 2016, the remaining obligation under these agreements was approximately $17.0 million, of which materials with a total purchase price of approximately $9.5 million were required to be purchased during 2017.  In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.  

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.  

Contractual Obligations

The following table presents information with respect to our contractual obligations as of December 31, 2016 (dollars in thousands):

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements at December 31, 2016.  

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Results of Operations

Comparison of the years ended December 31, 2016 and 2015

The following tables summarize operations by business segment for the years ended December 31, 2016 and 2015: