PATTERSON UTI ENERGY INC - Annual Report: 2017 (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, 2017

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.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $4.2 billion, calculated by reference to the closing price of $20.19 for the common stock on the Nasdaq Global Select Market on that date.

As of February 16, 2018, the registrant had outstanding 222,286,372 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 2018 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 involve risk and uncertainty.  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 April 20, 2017, we completed our merger with Seventy Seven Energy Inc. (“SSE”), pursuant to which a subsidiary of ours was merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly owned subsidiaries (the “SSE merger”).  On October 11, 2017, we completed our acquisition of MS Directional, LLC (f/k/a Multi-Shot, LLC) (“MS Directional”).  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 exhaustive.  Additional information concerning these and other risk factors is contained in this Report and may be contained in our future filings with the SEC.  You are cautioned not to place undue reliance on any of our forward-looking statements.  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 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, 2017, we had a drilling fleet that consisted of 295 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 Mid-Continent and Appalachian regions.  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, 2017, we had approximately 1.6 million 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 provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States.  Our directional drilling services include directional drilling, downhole performance motors, directional surveying, measurement-while-drilling, and wireline steering tools.

We have other operations where we provide oilfield rental equipment in many of the major producing onshore oil and gas basins in the United States, and 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

On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 3.95% Senior Notes due 2028 (the “2028 Notes”) initially guaranteed on a senior unsecured basis by certain of our subsidiaries.  The net proceeds before offering expenses were approximately $521 million, of which we used $239 million to repay amounts outstanding under our revolving credit facility.  We intend to use the remainder of the net proceeds for general corporate purposes.

On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of MS Directional.  The aggregate consideration paid by us consisted of $69.8 million in cash and approximately 8.8 million shares of our common stock.  Based on the closing price of our common stock on the closing date of the transaction, the total fair value of the consideration transferred to effect the acquisition of MS Directional was approximately $257 million.  

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On December 12, 2016, we entered into an Agreement and Plan of Merger (the “merger agreement”) with SSE.  On April 20, 2017, pursuant to the merger agreement, a subsidiary of ours was merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly-owned subsidiaries.  Pursuant to the terms of the merger agreement, we acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of our common stock.  Concurrent with the closing of the merger, we repaid all of the outstanding debt of SSE totaling $472 million.  Based on the closing price of our common stock on April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion.  On April 20, 2017, following the SSE merger, SSE was merged with and into our newly-formed subsidiary named Seventy Seven Energy LLC (“SSE LLC”), with SSE LLC continuing as the surviving entity and one of our wholly-owned subsidiaries.

Through the SSE merger, we acquired a fleet of 91 drilling rigs, 36 of which we consider to be APEX® rigs. Additionally, through the SSE merger, we acquired approximately 500,000 horsepower of modern, efficient fracturing equipment located in Oklahoma and Texas.  The oilfield rentals business acquired through the SSE merger has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities.  

Operational data in the discussion and analysis in this Report includes the results of operations of the MS Directional business since October 11, 2017 and the results of operations of the SSE businesses since April 20, 2017.

Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2015, 2016 and 2017 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 modestly recovered from the lows experienced in the first quarter of 2016.  Oil prices averaged $55.37 per barrel in the fourth quarter of 2017.  

Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but has improved since the second quarter of 2016.  Our average rig count in the United States was 159 rigs for both the third and fourth quarter of 2017, with the third quarter of 2017 being the first quarter with a full quarter contribution from the rigs acquired in the SSE merger.  Our rig count in the United States at December 31, 2017 was 163 rigs.  Term contracts have supported our operating rig count during the last three years.  Based on contracts currently in place, we expect an average of 96 rigs operating under term contracts during the first quarter of 2018 and an average of 67 rigs operating under term contracts throughout 2018.

Activity levels in our pressure pumping business also improved during 2017, especially in the Permian Basin.  We reactivated two frac spreads during the third quarter and one additional frac spread during the fourth quarter.  With the addition of these three frac spreads, we exited 2017 with 23 active frac spreads or approximately 1.25 million active fracturing horsepower.

Industry Segments

Our revenues, operating income (loss) and identifiable assets are primarily attributable to two industry segments:

Our contract drilling services industry segment had operating losses in 2017, 2016 and 2015.  Our pressure pumping services industry segment had operating income in 2017 and operating losses in 2016 and 2015.  Our third industry segment, directional drilling services, is a new segment for us as a result of the MS Directional acquisition and accounted for approximately two percent of our 2017 consolidated revenues.

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See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 14 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, 2017, we had 295 marketed land-based drilling rigs based in the following regions:

Our marketed drilling rigs have rated maximum depth capabilities ranging from approximately 13,200 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 $954 million 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 2017, 2016 and 2015, we spent approximately $354 million, $73 million and $527 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 two years) and provide for the use of the drilling rig to drill multiple wells.  During 2017, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 15 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.  

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 2017, 2016 and 2015 were under daywork contracts.  

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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.  

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, 2017, 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 550 super-spec rigs in the United States, which includes 130 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 (West and South Regions) and the Mid-Continent (Mid-Con Region) and Appalachian regions (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.  

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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.  

Equipment — We have pressure pumping equipment used in providing hydraulic fracturing services as well as nitrogen, cementing and acid pumping services, with a total of approximately 1.6 million horsepower as of December 31, 2017.  Pressure pumping equipment at December 31, 2017 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.

Directional Drilling Operations

General – We generally utilize our own proprietary downhole motors and equipment to provide a comprehensive suite of directional drilling services, including directional drilling, downhole performance motors, directional surveying, measurement while drilling (“MWD”), and wireline steering tools, in most major onshore oil and natural gas basins in the United States. We generally design, manufacture and maintain our own fleet of downhole drilling motors and MWD equipment. We occasionally rent motors and equipment from third parties during periods in which we experience shortages from our vendors, which can occur during periods of increased industry activity. As a complement to our core directional drilling services, we provide downhole survey services and rent our proprietary drilling motors to both oil and natural gas operators and other oilfield service companies. Our customers primarily consist of major integrated energy companies and large North American independent oil and natural gas operators. We believe our customers use our services because of the quality of our specialized, technology-driven equipment and our well-trained and experienced workforce, which enable us to provide our customers with high-quality, reliable and safe directional drilling services.  We utilize our fleet of directional drilling motors, MWD equipment and survey equipment to provide: (1) directional drilling services, (2) third-party motor rentals and (3) downhole survey services.

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Directional Drilling Services – We provide our directional drilling services on a day-rate basis, typically under master service agreements. Revenue from directional drilling services is recognized as work progresses based on the number of days of work completed. Our day rates and other charges generally vary by location and depend on the equipment and personnel required for the job and market conditions in the region in which the services are performed. In addition to rates that are charged during periods of active directional drilling, a stand-by rate is typically agreed upon in advance and charged on a daily basis during periods when drilling is temporarily suspended while other on-site activity is conducted at the direction of the operator or another service provider.  

Third-Party Motor Rental – We rent our drilling motors on an hourly- or day-rate basis to complement our directional drilling services and optimize the utilization of our asset base. Our third-party motor rental revenue is recognized as work progresses based on the number of days or hours our motors are used or are on location.  

Downhole Survey Services – We provide our downhole survey services on a day-rate, hourly-rate or completed-job basis. Revenue for our downhole survey services is recognized upon the completion of each day’s work. Our downhole survey services are typically non-contractual.  We normally provide a quote to our customers in advance and then issue an invoice for the downhole survey services provided based on a completed field ticket.

Equipment – We generally design, manufacture, maintain and inspect our own equipment. We occasionally rent motors and equipment from third parties during periods in which we experience shortages from our vendors, which can occur during periods of increased industry activity. We have developed proprietary equipment for our drilling motors, mud pulse and electromagnetic data transfer MWD equipment and survey tools. We believe that our vertical integration strategy allows us to deliver better operational performance and higher equipment reliability to our customers. Vertical integration also allows us to build our tools more efficiently and at a lower cost than if purchased from third parties. In addition, we have the ability to upgrade our tools in response to market conditions or our customers’ job requirements, which allows us to minimize the costs and delays associated with sending equipment to original manufacturers. Our internal maintenance capability also affords us enhanced control over our supply chain and increases the effective utilization of our assets.  As of December 31, 2017, we had a comprehensive fleet of over 1,600 motors that serve both internal needs and external motor rental requirements.  In addition to our motor fleet, we had 112 MWD systems as well as downhole surveying equipment to provide accurate wellbore surveys.

Oilfield Rentals

Our oilfield rentals business has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities.  We offer an extensive line of rental tools, including a full line of tubular products specifically designed for horizontal drilling and completion, with high-torque, premium-connection drill pipe, drill collars and tubing. Additionally, we offer surface rental equipment including blowout preventers, frac tanks, mud tanks and environmental containment that encompass all phases of the hydrocarbon extraction and production process. Our air drilling equipment and services enable extraction in select basins where certain segments of formations preclude the use of drilling fluid, permitting operators to drill through problematic zones without the risk of fluid absorption and damage to the wellbore. We also provide frac-support services, including delivery of on-site frac water through a water transfer operation using innovative lay-flat pipe, and monitoring and controlling of production returns. We offer oilfield rental services in many of the major producing onshore oil and gas basins in the United States. We price our rentals and services based on the type of equipment being rented and the services being performed. Substantially all rental revenue we earn is based upon a charge for the actual period of time the rental is provided to our customer on a market-based, fixed per-day or per-hour fee.

Contracts

We believe that our contract drilling, pressure pumping, directional drilling and oilfield rentals contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations.  However, each 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.

Customers

Our customer base includes major, independent and other oil and natural gas operators.  With respect to our consolidated operating revenues in 2017, we received approximately 43% from our ten largest customers and approximately 29% from our five largest customers.  During 2017, no customer accounted for more than 10% of our consolidated operating revenues.  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.

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Backlog

Our contract drilling backlog as of December 31, 2017 and 2016 was $544 million and $417 million, respectively.  Approximately 19% of the total contract drilling backlog at December 31, 2017 is reasonably expected to remain after 2018.  See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included as a part of Item 7 of this Report for information pertaining to backlog.  

Competition

The businesses in which we operate 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 our 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:

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:

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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.  

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.  

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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 businesses in which we operate, 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 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 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 equipment and certain other assets, such insurance does not cover the full replacement cost of such 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 cybersecurity 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.”

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Employees

We had approximately 8,000 full-time employees as of February 16, 2018.  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.  

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:

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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.  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.  While oil and natural gas prices modestly recovered since the first quarter of 2016, and we have experienced an increase in the demand for our services since 2016, our average number of rigs operating remains well below the number of our available rigs, and a portion of our pressure pumping horsepower remains 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 decline in demand for oil and natural gas, prolonged low oil or natural gas prices or expectations of decreases in oil and natural gas prices, would likely result in 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.  

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 and the improvement of existing drilling rigs.  Low commodity prices and construction of new equipment and the improvement of existing drilling rigs 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, pressure pumping and directional drilling 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, pressure pumping or directional drilling businesses or the level of demand for our contract drilling, pressure pumping or directional drilling services.  

The excess supply of operable land drilling rigs, increasing rig specialization and excess pressure pumping and directional drilling equipment, which has been exacerbated by a decline in oil and natural gas prices could affect the fair market value of our drilling, pressure pumping and directional drilling 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.

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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 businesses in which we operate, 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.  

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 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 equipment and certain other assets, such insurance does not cover the full replacement cost of such 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.  

On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of our employees.  Based on the information we have available as of the date of this Report, we believe that we have adequate insurance to cover any losses, excluding the applicable insurance deductibles and investigation-related expenses.  However, if this accident is not, or another 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.  

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Our Current Backlog of Contract Drilling Revenue May 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, 2017, 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 $544 million.  Our contract drilling backlog may 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.  For these and other reasons, our contract drilling backlog may not generate sufficient liquidity for us during periods of reduced demand for our services.

New Technologies May Cause Our Operating Methods, Equipment and Services 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 other equipment.  Our customers are increasingly demanding the services of newer, higher specification drilling rigs and other equipment.  Accordingly, a higher level of capital expenditures may be required to maintain and improve existing rigs and other equipment and purchase and construct newer, higher specification drilling rigs and other equipment 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 and directional drilling businesses could have similar effects.  

In recent years, we have added drilling rigs to our fleet through new construction, purchased new pressure pumping equipment and acquired a directional drilling services company.  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, pressure pumping and directional drilling 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.  

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 equipment and services 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 oilfield 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 and other equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations.  

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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 2017, we received approximately 43% from our ten largest customers, 29% from our five largest customers and 8% 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 Acquisitions or the Building of New Rigs and Pressure Pumping Equipment Is Not Assured.  

We have increased our drilling rig fleet and pressure pumping fleet and expanded our business lines in the past through mergers, acquisitions and new construction.  For example, we completed the SSE merger and the MS Directional acquisition during 2017.  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.  

There can be no assurance that we will:

Our failure to achieve consolidation savings, to integrate acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business. In addition, we may incur liabilities arising from events prior to any acquisitions or prior to our establishment of adequate compliance oversight. While we generally seek to obtain indemnities for liabilities for events occurring before such acquisitions, these are limited in amount and duration, may be held to be unenforceable or the seller may not be able to indemnify us.

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.  

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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, a manufacturer and servicer of oilfield service equipment and a provider of directional drilling services, 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 limited 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. The EPA issued a two-year stay of these requirements in December 2017 and has indicated that the requirements could be rescinded or significantly revised in the future. 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.  

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, pressure pumping and directional drilling 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.  

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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, these rules were rescinded by rule in December 2017.  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.  

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

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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.  In June 2017, President Trump announced that the United States will withdraw from the Paris Agreement unless it is renegotiated.  The State Department informed the United Nations of the United States’ withdrawal in August 2017.  However, several states and geographic regions in the United States have 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 and Governmental Investigations Could Have a Negative Impact on Our Business, Financial Condition and Results of Operations.  

The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time.  For example, the January 22, 2018 accident at a drilling site in Pittsburg County, Oklahoma is currently under governmental investigation by the EPA, OSHA and the U.S. Chemical Safety and Hazard Investigation Board.  In addition, during periods of depressed market conditions, 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.  

Technology Disputes Could Negatively Impact Our Operations or Increase Our Costs.

Our services and products use proprietary technology and equipment, which can involve potential infringement of a third party’s rights, including patent rights.  The majority of the intellectual property rights relating to our drilling rigs, pressure pumping equipment and directional drilling services are owned by us or certain of our supplying vendors.  However, in the event that we or one of our supplying vendors becomes involved in a dispute over infringement rights relating to equipment owned or used by us, services performed by us or products provided by us, we may lose access to important equipment or our ability to provide services or products, or we could be required to cease use of some equipment or forced to modify our equipment, services or products.  We could also be required to pay license fees or royalties for the use of equipment or provision of services or products.  Technology disputes involving us or our supplying vendors could have a material adverse impact on our business, financial condition and results of operations.

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, 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 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.  

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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.  

Our operations are increasingly dependent on information technologies and services.  Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow, and include, among other things, storms and natural disasters, terrorist attacks, utility outages, theft, viruses, malware, design defects, human error, or complications encountered as existing systems are maintained, repaired, replaced, or upgraded.  Risks associated with these threats include, among other things:

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Although we utilize various procedures and controls to mitigate our exposure to such risk, cybersecurity attacks and other cyber events are evolving and unpredictable.  Moreover, we have no control over the information technology systems of our customers, suppliers, and others with which our systems may connect and communicate.  As a result, the occurrence of a cyber incident could go unnoticed for a period time.  Any such incident could have a material adverse effect on our business, financial condition and results of operations.

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.  

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.  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, 2017, the applicable margin on LIBOR rate loans was 3.50% and the applicable margin on base rate loans was 2.50%.  As of December 31, 2017, we had $268 million outstanding under our revolving credit facility at a weighted average interest rate of 5.71%.  

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, 2017, 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.  

A Downgrade in Our Credit Rating Could Negatively Impact Our Cost of and Ability to Access Capital.

Our ability to access capital markets or to otherwise obtain sufficient financing is enhanced by our senior unsecured debt ratings as provided by major U.S. credit rating agencies.  Factors that may impact our credit ratings include debt levels, liquidity, asset quality, cost structure, commodity pricing levels and other considerations.  A ratings downgrade could adversely impact our ability in the future to access debt markets, increase the cost of future debt, and potentially require us to post letters of credit for certain obligations.

We May Not Be Able to Generate Sufficient Cash to Service All of Our Debt, Including Our Senior Notes and Debt Under Our Credit Agreement, and We May Be Forced to Take Other Actions to Satisfy Our Obligations Under Our Debt, which May Not Be Successful.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

In addition, if our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our debt. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and would permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. However, our Credit Agreement and senior notes contain restrictions on our ability to dispose of assets. We may not be able to consummate those dispositions, and any proceeds may not be adequate to meet any debt service obligations then due.

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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.  

SSE is Subject to Continuing Contingent Tax Liabilities of Chesapeake Energy Corporation (“CHK”) Following its Spin-Off from CHK.

Under the Internal Revenue Code of 1986, as amended (the “Code”), and the related rules and regulations, each corporation that was a member of CHK’s consolidated tax reporting group during any taxable period or portion of any taxable period ending on or before June 30, 2014, the effective time of SSE’s spin-off, is jointly and severally liable for the federal income tax liability of the entire consolidated tax reporting group for that taxable period.  SSE has entered into a tax sharing agreement with CHK that allocates the responsibility for prior year taxes of CHK’s consolidated tax reporting group between SSE and CHK and its subsidiaries. However, if CHK were unable to pay, SSE nevertheless could be required to pay the entire amount of such taxes.

SSE’s Tax Sharing Agreement Limits its Ability to Take Certain Actions and May Require SSE to Indemnify CHK for Significant Tax Liabilities Which Cannot be Precisely Quantified at This Time.

Under the terms of SSE’s tax sharing agreement with CHK, SSE generally is responsible for all taxes attributable to its business, whether accruing before, on or after the date of the spin-off, and CHK generally is responsible for any taxes arising from the spin-off or certain related transactions that are imposed on SSE, CHK or its other subsidiaries. Although CHK generally will be responsible for any taxes arising from the spin-off, SSE would be responsible for any such taxes to the extent such taxes result from certain actions or failures to act by SSE that occur after June 30, 2014, the effective date of the tax sharing agreement. SSE’s liabilities under the tax sharing agreement could have a material adverse effect on us. At this time, we cannot precisely quantify the amount of liabilities SSE may have under the tax sharing agreement and there can be no assurances as to their final amounts.

In addition, in the tax sharing agreement SSE covenanted not to take any action, or fail to take any action, after the effective date of the tax sharing agreement, which action or failure to act is inconsistent with the spin-off qualifying under Sections 355 and 368(a)(1)(D) of the Code. As a result, SSE might determine to continue to operate certain of its business operations for the foreseeable future even if a sale or discontinuance of such business might otherwise have been advantageous.

In Connection with SSE’s Separation from CHK, CHK Indemnified SSE for Certain Liabilities. However, There Can Be No Assurance that the Indemnities Will be Sufficient to Insure SSE Against the Full Amount of Such Liabilities, or That CHK’s Ability to Satisfy its Indemnification Obligation Will Not Be Impaired in the Future.

Pursuant to the tax sharing agreement, CHK agreed to indemnify SSE for certain liabilities.  However, third parties could seek to hold SSE responsible for any of the liabilities that CHK has agreed to retain, and there can be no assurance that the indemnity from CHK will be sufficient to protect SSE against the full amount of such liabilities, or that CHK will be able to fully satisfy its indemnification obligations. Moreover, even if SSE ultimately succeeds in recovering from CHK any amounts for which SSE is held liable, SSE may be temporarily required to bear these losses.  In addition, in certain circumstances, SSE will be prohibited from making an indemnity claim until it first seeks an insurance recovery.  If CHK is unable to satisfy its indemnification obligations, the underlying liabilities could have a material adverse effect on our business, financial condition and results of operations.

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We May Not Be Able to Utilize a Portion of SSE’s or Our Net Operating Loss Carryforwards (“NOLs”) to Offset Future Taxable Income for U.S. Federal Tax Purposes, Which Could Adversely Affect Our Net Income and Cash Flows.

As of December 31, 2017, SSE had federal income tax NOLs of approximately $238.0 million, which will expire between 2034 and 2037, and, as of December 31, 2017, we had federal income tax NOLs of approximately $867.1 million, which will expire between 2035 and 2037. Utilization of these NOLs depends on many factors, including our future taxable income, which cannot be predicted with any accuracy. In addition, Section 382 of the Code generally imposes an annual limitation on the amount of an NOL that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). Determining the limitations under Section 382 is technical and highly complex. An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5% of the corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period.  In the event that an ownership change has occurred—or were to occur—with respect to a corporation following its recognition of an NOL, utilization of such NOL would be subject to an annual limitation under Section 382, generally determined by multiplying the value of the corporation’s stock at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382.  However, this annual limitation would be increased under certain circumstances by recognized built-in gains of the corporation existing at the time of the ownership change.  Any unused annual limitation with respect to an NOL generally may be carried over to later years, subject to the expiration of the NOL 20 years after it arose.

SSE underwent an ownership change in 2016 as a result of its emergence from Chapter 11 bankruptcy proceedings, and experienced another ownership change in 2017 as a result of its acquisition pursuant to the SSE merger, and the corresponding annual limitation associated with either of those changes in ownership could prevent us from fully utilizing—prior to their expiration—SSE’s NOLs as of the effective time of the SSE merger. While our issuance of stock pursuant to the SSE merger was, standing alone, insufficient to result in an ownership change with respect to us, we cannot assure you that we will not undergo an ownership change as a result of the merger taking into account other changes in ownership of our stock occurring within the relevant three-year period described above. If we were to undergo an ownership change, we may be prevented from fully utilizing our NOLs as of the time of the SSE merger prior to their expiration. Future changes in stock ownership or future regulatory changes could also limit our ability to utilize SSE’s or our NOLs. To the extent we are not able to offset future taxable income with SSE’s or our NOLs, our net income and cash flows may be adversely affected.

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 multiple offices and yard facilities located throughout our areas of operations, including Texas, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania and western Canada.  

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

Directional Drilling — Our directional drilling services are supported by multiple offices and yard facilities located throughout our areas of operations, including Texas, Oklahoma, Pennsylvania, Colorado and Montana.  

Our Oilfield Rental operations are supported by offices and yard facilities located in Texas, Oklahoma and Ohio.  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 and Oklahoma City, Oklahoma, 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.  

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Item 3. Legal Proceedings.  

On January 22, 2018, an accident at a drilling site in Pittsburg County, Oklahoma resulted in the losses of life of five people, including three of our employees. The EPA, OSHA and the U.S. Chemical Safety and Hazard Investigation Board are currently conducting investigations related to this accident.  These investigations are ongoing, and we are cooperating with the agencies regarding these investigations. The results of these investigations are not known at this time, and we are unable to determine what finding they might reach, predict what actions these agencies may require or estimate what penalties, if any, they might assess.

While we are not currently party to any claims or lawsuits relating to this accident, based on the information we have available as of the date of this Report, we believe that we have adequate insurance to cover any losses, excluding the applicable insurance deductibles and investigation-related expenses.  However, if this accident is not, or another 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.

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

Item 4. Mine Safety Disclosure.  

Not applicable.  

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PART II

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

(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 16, 2018, there were approximately 1,087 holders of record of our common stock.  

(c) Dividends

We paid cash dividends during the years ended December 31, 2017 and 2016 as follows:

On February 7, 2018, 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, 2018 to holders of record as of March 8, 2018.  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.  

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(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, 2017.  

(e) Performance Graph

The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2012 through December 31, 2017, 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 2017 to align with the peer group used by the compensation committee of our board of directors.  Our new peer group consisted of Basic Energy Services, Inc., Diamond Offshore Drilling Inc., Ensco plc., Forum Energy Technologies, Inc., Halliburton Company, Helmerich & Payne, Inc., Nabors Industries, Ltd., National Oilwell Varco, Inc., Noble Corporation plc., Oceaneering International, Oil States International Inc., Precision Drilling Corporation, Rowan Companies plc., Superior Energy Services, Inc., TechnipFMC plc, Transocean Ltd., Unit Corp. and Weatherford International plc. Our old peer group consisted of Atwood Oceanics Inc., Basic Energy Services, Inc., Diamond Offshore Drilling Inc., Ensco plc., Forum Energy Technologies, Inc., 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.

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The graph assumes investment of $100 on December 31, 2012 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, 2017, 2016, 2015, 2014 and 2013, and for each of the five years in the period ended December 31, 2017, 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. The table below includes the results of operations of SSE since the merger date of April 20, 2017 and the results of operations of MS Directional since the acquisition date of October 11, 2017.

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

Recent Developments — On January 19, 2018, we completed an offering of $525 million aggregate principal amount of our 3.95% Senior Notes due 2028 initially guaranteed on a senior unsecured basis by certain of our subsidiaries.  We used $239 million of the net proceeds from the sale to repay amounts outstanding under our revolving credit facility.  We intend to use the remainder of the net proceeds for general corporate purposes.

On October 11, 2017, we acquired all of the issued and outstanding limited liability company interests of MS Directional.  The aggregate consideration paid by us consisted of $69.8 million in cash and approximately 8.8 million shares of our common stock.  Based on the closing price of our common stock on the closing date of the transaction, the total fair value of the consideration transferred to effect the acquisition of MS Directional was approximately $257 million.  

MS Directional is a leading directional drilling services company in the United States, with operations in most major producing onshore oil and gas basins.  MS Directional provides a comprehensive suite of directional drilling services, including directional drilling, downhole performance motors, directional surveying, measurement while drilling, and wireline steering tools.  Operational and financial data in the discussion and analysis below includes the results of operations of the MS Directional business since October 11, 2017.

On December 12, 2016, we entered into the merger agreement with SSE.  On April 20, 2017, pursuant to the merger agreement, a subsidiary of ours was merged with and into SSE, with SSE continuing as the surviving entity and one of our wholly-owned subsidiaries.  Pursuant to the terms of the merger agreement, we acquired all of the issued and outstanding shares of common stock of SSE, in exchange for approximately 46.3 million shares of our common stock.  Concurrent with the closing of the merger, we repaid all of the outstanding debt of SSE totaling $472 million.  Based on the closing price of our common stock on April 20, 2017, the total fair value of the consideration transferred to effect the acquisition of SSE was approximately $1.5 billion.  On April 20, 2017, following the SSE merger, SSE was merged with and into our newly-formed subsidiary SSE LLC, with SSE LLC continuing as the surviving entity and one of our wholly-owned subsidiaries.

Through the SSE merger, we acquired a fleet of 91 drilling rigs, 36 of which we consider to be APEX® rigs. Additionally, through the SSE merger, we acquired approximately 500,000 horsepower of modern, efficient fracturing equipment located in Oklahoma and Texas.  The oilfield rentals business acquired through the SSE merger has a modern, well-maintained fleet of premium oilfield rental tools, and provides specialized services for land-based oil and natural gas drilling, completion and workover activities.  Operational and financial data in the discussion and analysis below includes the results of operations of the SSE businesses since April 20, 2017.

Quarterly average oil prices and our quarterly average number of rigs operating in the United States for 2015, 2016 and 2017 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 modestly recovered from the lows experienced in the first quarter of 2016.  Oil prices averaged $55.37 per barrel in the fourth quarter of 2017.  

Our rig count in the United States declined significantly during the industry downturn that began in late 2014, but has improved since the second quarter of 2016.  Our average rig count in the United States was 159 rigs for both the third and fourth quarter of 2017, with the third quarter of 2017 being the first quarter with a full quarter contribution from the rigs acquired in the SSE merger.  Our rig count in the United States at December 31, 2017 was 163 rigs.  Term contracts have supported our operating rig count during the last three years.  Based on contracts currently in place, we expect an average of 96 rigs operating under term contracts during the first quarter of 2018 and an average of 67 rigs operating under term contracts throughout 2018.

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Activity levels in our pressure pumping business also improved during 2017, especially in the Permian Basin.  We reactivated two frac spreads during the third quarter, and one additional frac spread during the fourth quarter.  With the addition of these three frac spreads, we exited 2017 with 23 active frac spreads or approximately 1.25 million active fracturing horsepower.

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 Mid-Continent and Appalachian regions.  We also provide a comprehensive suite of directional drilling services in most major producing onshore oil and gas basins in the United States.  We have other operations through which we provide oilfield rental tools in select markets in the United States, and 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.  

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, 2017, our rig fleet included 199 APEX^® rigs.  

In connection with the development of horizontal shale and other unconventional resource plays, in the last five years we have added equipment to perform service intensive fracturing jobs.  As of December 31, 2017, we had approximately 1.6 million horsepower in our pressure pumping fleet.  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, 2017 and 2016 was $544 million and $417 million, respectively.  Approximately 19% of the total contract drilling backlog at December 31, 2017 is reasonably expected to remain after 2018.  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.”  

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.  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.  

For the three years ended December 31, 2017, our operating revenues consisted of the following (dollars in thousands):

Generally, the revenues in our contract drilling segment are most impacted by two primary factors: our average number of rigs operating and our average revenue per operating day.  During 2017, our average number of rigs operating was 136 in the United States and two in Canada, compared to 63 in the United States and two in Canada in 2016, and 120 in the United States and four in Canada in 2015.  Our average rig revenue per operating day was $20,620 in 2017, compared to $23,040 in 2016 and $25,560 in 2015.  

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Generally, the revenues in our pressure pumping segment are most impacted by our number of fracturing jobs and the size (including whether or not we provide proppant and other materials) of those jobs, which is reflected in our average revenue per fracturing job.  We completed 622 fracturing jobs during 2017 compared to 352 fracturing jobs in 2016 and 610 fracturing jobs in 2015.  Our average revenue per fracturing job was $1.894 million in 2017 compared to $982,560 in 2016 and $1.118 million in 2015.  

For the three years ended December 31, 2017, our operating income (loss) consisted of the following (dollars in thousands):

Discussion of our operating income (loss) follows in the “Results of Operations” section of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

On December 22, 2017, significant U.S. tax law changes were enacted (“tax reform”).  Tax reform reduces the U.S. federal corporate tax rate from 35% to 21% beginning in 2018, requires companies to pay a one-time transition tax on foreign earnings that were previously tax deferred, creates new taxes on future foreign earnings, places a limitation on the tax deductibility of interest expense, accelerates the expensing of certain business assets, and reduces the amount of executive pay that will be tax deductible, among other changes.  At December 31, 2017, we had not completed our accounting for the tax effects of the tax reform, however, in certain cases, we have made a reasonable estimate of the effects on our existing deferred tax balances and the one-time transition tax.  For the items for which we were able to determine a reasonable estimate, we recognized a provisional amount in accordance with Staff Accounting Bulletin (SAB) 118 of approximately $219 million of tax benefit as a result of tax reform, which is included as a component of income tax expense from continuing operations.  See Note 12 of Notes to Consolidated Financial Statements contained in this Report for additional information related to the impact of tax reform.

The improvement in demand for our services and the income tax rate change resulted in consolidated net income of $5.9 million for 2017 compared to a consolidated net loss of $319 million for 2016 and a consolidated net loss of $294 million for 2015.  

Results of Operations

Comparison of the years ended December 31, 2017 and 2016

The following tables summarize results of operations by business segment for the years ended December 31, 2017 and 2016:

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The demand for our contract drilling services is impacted by the market price of oil and natural gas.  The average market price of oil and natural gas for each of the fiscal quarters and full year in 2017 and 2016 follows: