Patterson-UTI Energy
Annual Report 2013

Plain-text annual report

P A T T E R S O N - U T I E N E R G Y , I N C . 2 0 1 3 A N N U A L R E P O R T Patterson-UTI Energy, Inc. subsidiaries provide onshore COMPANY PROFILE contract drilling and pressure pumping services to exploration and production companies in North America. Patterson-UTI Drilling Company LLC and its subsidiaries have more than 275 marketable land-based drilling rigs and operate primarily in oil and natural gas producing regions in the continental United States, Alaska, and western and northern Canada. Universal Pressure Pumping, Inc. and Universal Well Services, Inc. provide pressure pumping services primarily in Texas and the Appalachian Region. P A T T E R S O N - U T I E N E R G Y, I N C . 2 0 1 3 A N N U A L R E P O R T 1 Financial Highlights (dollars in thousands, except per share amounts – unaudited) 2009 2010 2011 2012 2013 Year Ended December 31, Revenues Operating income (loss) Net income (loss) Net income (loss) per share Basic Diluted Cash dividends per share Total assets Borrowings under line of credit Other long-term debt Stockholders’ equity Working capital Operational Highlights (dollars in thousands – unaudited) Contract Drilling: Revenues Average revenue per day Average direct operating costs per day Average margin per day (1) Operating days Electric rigs at end of year Mechanical rigs at end of year Total rigs at end of year Average rigs operating during the year Number of rigs operated during the year Number of wells drilled during the year Pressure Pumping: Revenues Average revenue per fracturing job Average revenue per other job Average revenue per total job Average direct operating costs per total job Average margin per total job (1) Number of fracturing jobs Number of other jobs Total number of jobs Total hydraulic horsepower at end of year $ 781,946 (48,214) (38,290) $1,462,931 200,925 116,942 $2,565,943 525,601 322,413 $2,723,414 497,361 299,477 $2,716,034 322,191 188,009 (0.25) (0.25) 0.20 2,662,152 — — 2,081,700 263,511 0.76 0.76 0.20 3,423,031 — 392,500 2,187,607 241,445 2.08 2.06 0.20 4,221,901 110,000 382,500 2,516,631 346,238 1.96 1.96 0.20 4,556,911 — 692,500 2,640,657 340,128 1.29 1.28 0.20 4,687,127 — 682,500 2,755,997 454,373 $ 599,287 17.95 $ 10.71 $ 7.24 $ 33,394 107 234 341 91 243 1,539 $ 161,441 70.88 $ 9.17 $ 23.14 $ 17.78 $ 5.36 $ 1,579 5,399 6,978 163,200 $1,081,898 17.67 $ 10.71 $ 6.96 $ 61,244 124 232 356 168 220 2,919 $ 350,608 180.21 $ 12.47 $ 46.29 $ 31.04 $ 15.25 $ 1,527 6,047 7,574 435,200 $1,669,581 21.20 $ 12.35 $ 8.85 $ 78,758 145 183 328 216 250 3,529 $ 845,803 467.85 $ 18.48 $ 99.03 $ 65.73 $ 33.30 $ 1,531 7,010 8,541 631,070 $1,821,713 22.54 $ 13.31 $ 9.23 $ 80,833 167 147 314 221 267 3,587 $ 841,771 590.70 $ 20.46 $ 122.21 $ 84.33 $ 37.88 $ 1,229 5,659 6,888 757,560 $1,679,611 24.02 $ 13.86 $ 10.17 $ 69,918 180 99 279 192 235 3,378 $ 979,166 705.57 $ 18.63 $ 161.55 $ 122.79 $ 38.76 $ 1,261 4,800 6,061 763,050 (1) Average margin represents average revenue minus average direct operating costs and excludes provisions for bad debts, other charges, depreciation, amortization and impairment and selling, general and administrative expenses. 2 C O N T R A C T D R I L L I N G While the daily average industry land drilling rig count in to improve the efficiencies in their operations through the United States decreased by 9% in 2013, the North pad drilling. While our APEX WALKING® rigs were American oil and gas industry continued the ongoing originally designed for the Rockies, they are being used trend of developing unconventional oil and gas reservoirs, in every major unconventional basin for pad drilling in and in so doing continued to grow the percentage of which we operate. horizontal wells drilled in the United States. On average, horizontal wells continued to increase in length and complexity, along with the ongoing trend to more pad drilling where there are multiple wellheads on each pad. Also in 2013, of the AC powered APEX® rigs added to the fleet, nine were the newer APEX-XK 1500® AC electric rigs, which have the same functionality and features as their predecessors, but incorporate a new Unconventional resources continued to be an important design to the structure and equipment to improve rig source of oil and natural gas for North America. move times and allow for greater “walking” clearance In order to continue to meet these challenges, we around existing wells on a pad. APEX-XK 1500® rigs increased our capacity of high-spec drilling rigs are well suited for regions such as the Permian, the and added key technologies. In 2013, the Company continued to upgrade the quality of the drilling fleet by adding 11 more AC powered APEX® rigs. Therefore, the majority of the rigs now being operated by Patterson-UTI Drilling are the Eagle Ford and the Bakken where operators require the combined features of a “walking” system with a fast moving drilling rig. We expect to complete 20 of the APEX-XK 1500® rigs in 2014, all of which are expected to have walking systems. high-spec APEX® rigs. We have continued to deliver Along with the walking system technology, we consider new APEX® rigs to the market and make performance ourselves a leader in the domain of natural gas power and safety improvements to existing high capacity technology for drilling rigs. In 2013, we added GE rigs. APEX 1500® rigs are 1,500HP electric rigs with Waukesha natural gas engines to seven drilling rigs, advanced Electronic Drilling Systems, 500 ton top drives, and continued to upgrade other drilling rigs in the iron roughnecks, hydraulic catwalks, and other highly fleet to natural gas bi-fuel technology. We believe that automated pipe handling equipment. APEX 1000® rigs using natural gas as a fuel source is an important green are 1,000HP electric rigs with advanced technology technology as it both reduces the environmental impact equipment similar to the APEX 1500®, but with a of our services and generates cost savings. At the end more compact design to fit on smaller locations, such of 2013, Patterson-UTI Drilling had 28 drilling rigs as for drilling Marcellus Shale wells in Appalachia or configured to use natural gas as the primary fuel source. Mississippi Lime wells in Kansas. We also remain a market leader in the drilling of Pad drilling continued to be a growing sector of the conventional wells of varying depths. Over the last several market and an area where Patterson-UTI holds a years, we have made substantial improvements to our leadership position. To address this growing need, overall drilling fleet to improve the drilling efficiency of APEX WALKING® rigs are designed to efficiently these wells. Improvements have included higher capacity drill multiple wells from a single pad, by “walking” pumps, high-efficiency mud systems and iron roughnecks between the wellbores without requiring time to lower for improved safety. the mast and remove the drill pipe. To further enhance the “walking” capabilities of the Patterson-UTI fleet, in 2013 we upgraded nine existing rigs with walking system technology that can be added to the APEX 1500® rigs, the APEX 1000® rigs, and previous generations of rigs in the fleet. This new feature further strengthens our ability to meet the needs of our customers as they seek During 2013, Patterson-UTI Drilling retired 48 mechanical drilling rigs from the fleet. At the end of 2013, we had more than 275 marketable land drilling rigs of which 95% had depth capacities ranging from 12,500 to 25,000 feet. P A T T E R S O N - U T I E N E R G Y, I N C . 2 0 1 3 A N N U A L R E P O R T 3 Contract Drilling Fleet at December 31, 2013: APEX 1500® rigs (including 19 with walking systems) APEX 1000® rigs (including nine with walking systems) APEX WALKING® rigs Other electric rigs (including two with walking systems) Total electric rigs Mechanical rigs Total U.S. 60 15 49 48 172 93 265 Canada — — — 8 8 6 14 Total 60 15 49 56 180 99 279 4 P R E S S U R E P U M P I N G Our pressure pumping businesses, Universal Pressure Pumping, Inc. and Universal Well Services, Inc., have added capacity over the years to meet the increased demand for our services as customers expand development of unconventional oil and gas resources and expand development of traditional resources by drilling horizontal wells. The primary source of revenues for this business segment is hydraulic fracturing services. Other services provided include cementing, acidizing and nitrogen vaporization. Our coverage of shale basins includes the Eagle Ford in south Texas, the Barnett in north Texas, as well as the Marcellus and Utica in the Appalachian region. Our pressure pumping operations also extend to the oily Permian basin in west Texas and New Mexico. These businesses have a long standing presence in most of these areas, which gives us a “home field” advantage as development increases. Our total hydraulic pumping horsepower has increased more than six-fold over the past five years from 122,850 as of December 31, 2008 to more than 750,000 as of December 31, 2013. This growth was accomplished through the purchase of new-build equipment and through the acquisition, during the fourth quarter of 2010, of the assets that are operated by Universal Pressure Pumping, Inc. New-build additions included quintuplex frac pumps, high-horsepower triplex pumps, dust control systems, and satellite-equipped mobile control centers, which allow efficient completion of complex hydraulic fracturing jobs. As the country continues to recognize and develop the huge energy resources available on land in the United States, we expect the pressure pumping industry will continue to grow. We have a strong foundation upon which to grow each of our services and take full advantage of the many opportunities that are available to us in North America. Hydraulic Fracturing Equipment Other Pumping Equipment Total Units and Horsepower 146 342,850 172 332,050 318 674,900 27 27,550 105 60,600 132 88,150 173 370,400 277 392,650 450 763,050 Pressure Pumping Fleet at December 31, 2013: Southwest Region: Number of units Approximate hydraulic horsepower Northeast Region: Number of units Approximate hydraulic horsepower Combined: Number of units Approximate hydraulic horsepower P A T T E R S O N - U T I E N E R G Y, I N C . 2 0 1 3 A N N U A L R E P O R T F I N A N C I A L R E V I E W UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K (Mark One) Í ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2013 or ‘ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission File Number 0-22664 Patterson-UTI Energy, Inc. (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 450 Gears Road, Suite 500, Houston, Texas (Address of principal executive offices) 75-2504748 (I.R.S. Employer Identification No.) 77067 (Zip Code) Registrant’s telephone number, including area code: (281) 765-7100 Securities Registered Pursuant to Section 12(b) of the Act: Title of Each Class Name of Exchange on Which Registered Common Stock, $0.01 Par Value The Nasdaq Global Select Market 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 Í 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 Í 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 Í 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 Í 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. Large accelerated filer Í Accelerated filer ‘ Non-accelerated filer ‘ Smaller reporting company ‘ is a shell company (as defined in Rule 12b-2 of the Act). Indicate by check mark whether the registrant Yes ‘ No Í The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 28, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $2.8 billion, calculated by reference to the closing price of $19.36 for the common stock on the Nasdaq Global Select Market on that date. As of February 7, 2014, the registrant had outstanding 144,233,121 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 2014 Annual Meeting of Stockholders are incorporated by reference into Part III of this report. DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue and cost expectations and backlog; financing of operations; oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional acquisitions (if further opportunities arise); impact of inflation; demand for our services; competition; equipment availability; government regulation; 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 “believes,” “budgeted,” “continue,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act. Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates, utilization, margins and planned capital expenditures, global economic conditions, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, equipment specialization and new technologies, adverse industry conditions, adverse credit and equity market conditions, difficulty in building and deploying new equipment and integrating acquisitions, shortages, delays in delivery and interruptions in supply of equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full indemnification or insurance, ability to effectively identify and enter new markets, governmental regulation, ability to realize backlog, ability to retain management and field personnel and other factors. Refer to “Risk Factors” contained in Item 1A of this Report for a more complete discussion of factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise, except as required by law. Item 1. Business Available Information PART I 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. 1 You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. Overview We own and operate one of the largest fleets of land-based drilling rigs in the United States. The Company was formed in 1978 and reincorporated in 1993 as a Delaware corporation. Our contract drilling business operates in the continental United States, Alaska, and western and northern Canada. As of December 31, 2013, we had a drilling fleet that consisted of 279 marketable land-based drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. A drilling rig is considered marketable at a point in time if it is operating or can be made ready to operate without significant capital expenditures. We also have a substantial inventory of drill pipe and drilling rig components that support our ongoing drilling operations. We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. Pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. We also own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in Texas and New Mexico. On October 1, 2010, we acquired the assets and operations of a pressure pumping business and an electric wireline business. The electric wireline business that we acquired was classified as held for sale at December 31, 2010 and sold on January 27, 2011. The results of our electric wireline business are presented as discontinued operations in this Report. Industry Segments Our revenues, operating profits and identifiable assets are primarily attributable to three industry segments: • contract drilling services, • pressure pumping services, and • oil and natural gas exploration and production. All of our industry segments had operating profits in 2013, 2012 and 2011. 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 and independent oil and natural gas operators. As of December 31, 2013, we had 279 marketable land-based drilling rigs based in the following regions: • 70 in west Texas and southeastern New Mexico, • 25 in north central and east Texas, northern Louisiana and eastern Oklahoma, • 47 in the Rocky Mountain region (Colorado, Utah, Wyoming, Montana, North Dakota and Alaska), • 55 in south Texas, • 32 in the Texas panhandle and western Oklahoma, • 36 in the Appalachian region (Pennsylvania, Ohio and West Virginia) and • 14 in western and northern Canada. 2 Our marketable drilling rigs have rated maximum depth capabilities ranging from 8,000 feet to 25,000 feet. Of these drilling rigs, 180 are electric rigs and 99 are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the power from its engines (the sole energy source for a mechanical rig) into electricity to power the rig. We also have a substantial inventory of drill pipe and drilling rig components, which may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs. Drilling rigs are typically equipped with engines, drawworks, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year as part of a program to modify, upgrade and maintain our drilling rigs to ensure that our drilling equipment is competitive. We have spent over $2.0 billion during the last three years on capital expenditures to (1) build new land drilling rigs and (2) modify, upgrade and extend the lives of components of our drilling fleet. During fiscal years 2013, 2012 and 2011, we spent approximately $505 million, $745 million and $785 million, respectively, on these capital expenditures. Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job. Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts and other related rig equipment, fuel and 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 drilling contracts are either on a well-to-well basis or a term basis. Well-to-well contracts are generally short-term in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently six months to three years) and provide for the use of the drilling rig to drill multiple wells. During 2013, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 20 days. Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of our drilling personnel and necessary maintenance expenses. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for an early termination payment to us in the event that the contract is terminated by the customer. We believe that our drilling contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each drilling contract contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer requirements or other factors. Our drilling contracts provide for payment on a daywork, footage or turnkey basis, or a combination thereof. In each case, we provide the rig and crews. Our bid for each job depends upon location, depth and anticipated complexity of the well, on-site drilling conditions, equipment to be used, estimated risks involved, estimated duration of the job, availability of drilling rigs and other factors particular to each proposed well. Under daywork contracts, we provide the drilling rig and crew to the customer. The customer supervises the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are interrupted or restricted by adverse weather conditions or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. All of the wells we drilled in 2013, 2012 and 2011 were under daywork contracts. Under footage contracts, we contract to drill a well to a certain depth under specified conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the agreed-upon depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling 3 contractor typically assumes certain risks associated with loss of the well from fire, blowouts and other risks. Although we have entered into footage contracts in the past, we did not drill any wells under footage contracts in the past three years. Under turnkey contracts, we contract to drill a well to a certain depth under specified conditions for a fixed fee. In a turnkey arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, casing, cementing, and the technical well design and engineering services during the drilling process. We also typically assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. Compensation occurs only when the agreed-upon scope of the work has been completed, which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. Given the increased exposure we have under a turnkey contract, however, profits can be significantly reduced and losses can be incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of drilling contracts. Although we have entered into turnkey contracts in the past, we did not drill any wells under turnkey contracts in the past three years. Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows: Year Ended December 31, 2013 2012 2011 Average rigs operating per day(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Number of rigs operated during the year . . . . . . . . . . . . . . . . . . . . . . . . . Number of wells drilled during the year . . . . . . . . . . . . . . . . . . . . . . . . . Number of operating days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192 235 3,378 69,918 221 267 3,587 80,833 216 250 3,529 78,758 (1) A rig is considered to be operating if it is earning revenue pursuant to a contract on a given day. 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 an important source of natural gas and oil, our customers have expanded the development of shale and other unconventional wells to help supply the long-term demand for natural gas and oil 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 1500® rigs are 1,500 horsepower electric rigs with advanced electronic drilling systems, 500 ton top drives, iron roughnecks, hydraulic catwalks, and other highly automated pipe handling equipment. APEX 1000® rigs are 1,000 horsepower electric rigs with advanced technology equipment similar to the APEX 1500® rigs, but with a more compact design to fit on smaller locations. APEX WALKING® rigs 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. Many APEX 1500® and APEX 1000® rigs have also been equipped 4 with walking systems as noted below. As of December 31, 2013 our drilling fleet was comprised of the following: Classification APEX 1500® rigs (including 19 with walking systems) . . . . . . . . . . . . . . . . . . APEX 1000® rigs (including nine with walking systems) . . . . . . . . . . . . . . . . APEX WALKING® rigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other electric rigs (including two with walking systems) Total electric rigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mechanical rigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Number of Rigs U.S. Canada Total 60 15 49 48 172 93 265 — — — 8 8 6 14 60 15 49 56 180 99 279 We estimate the depth capacity with respect to our marketable rigs as of December 31, 2013 to be as follows: Depth Rating (Ft.) 8,000 to 12,999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,000 to 14,999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,000 to 17,999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,000 to 25,000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Number of Rigs U.S. Canada Total 9 37 86 133 265 6 4 4 — 14 15 41 90 133 279 At December 31, 2013, we owned and operated 298 trucks and 398 trailers used to rig down, transport and rig up our drilling rigs. Our ownership of trucks and trailers reduces our dependency upon third parties for these services and generally enhances the efficiency of our contract drilling operations in periods of high drilling rig utilization. We perform repair and/or overhaul work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, Wyoming, Colorado, North Dakota, Pennsylvania and western Canada. Pressure Pumping Operations General — We provide pressure pumping services to oil and natural gas operators primarily in Texas (Southwest Region) and the Appalachian region (Northeast Region). Pressure pumping services consist of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require well stimulation through fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well stimulation services. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing. Pressure Pumping Contracts — Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract. The term contracts are generally entered into for a specified period of time and may include minimum revenue, usage or stage requirements. We are compensated based on a combination of charges for equipment, personnel, materials, mobilization and other items. We believe that our pressure pumping contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each pressure pumping contract contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer requirements or other factors. 5 Equipment — We have pressure pumping equipment used in providing hydraulic and nitrogen fracturing services as well as nitrogen, cementing and acid pumping services, with a total of approximately 763,000 hydraulic horsepower as of December 31, 2013. Pressure pumping equipment at December 31, 2013 included: Hydraulic Fracturing Equipment Other Pumping Equipment Total Southwest Region: Number of units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Approximate hydraulic horsepower 146 342,850 27 27,550 173 370,400 Northeast Region: Number of units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Approximate hydraulic horsepower 172 332,050 105 60,600 277 392,650 Combined: Number of units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Approximate hydraulic horsepower 318 674,900 132 88,150 450 763,050 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 that 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. Oil and Natural Gas Interests We own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in producing regions of Texas and New Mexico. Our oil and natural gas assets constituted approximately 1% of our consolidated assets as of December 31, 2013. Customers The customers of each of our contract drilling and pressure pumping business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2013, one customer accounted for approximately $286 million or 10.5% of our consolidated operating revenues. These revenues were earned in both our contract drilling and pressure pumping businesses. Competition Our contract drilling and pressure pumping businesses are highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand. The price for our services is a key competitive factor, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability, condition and technical specifications of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job. We expect that the market for land drilling and pressure pumping services will continue to be highly competitive. 6 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: • drilling of oil and natural gas wells, • hydraulic fracturing, cementing, nitrogen and acidizing and related well servicing activities, • containment and disposal of hazardous materials, oilfield waste, other waste materials and acids, • use of underground storage tanks and injection wells, and • our employees. 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 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 operation. We believe we use operating and disposal practices that are standard in the industry. However, hydrocarbons and other materials may have been disposed of, or released in or under properties currently or formerly owned or operated by us or our predecessors, which may have resulted, or may result, in soil and groundwater contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to remediation requirements under federal, state, foreign, 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: • owners and operators of sites, including prior owners and operators who are no longer active at a site; and • persons who disposed of or arranged for the disposal of “hazardous substances” found at sites. 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. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of 7 or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination. The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern: • the prevention of discharges, including oil and produced water spills, into jurisdictional waters; and • liability for drainage into such waters. 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. 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 on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production customers. See “Item 1A. Risk Factors — Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Limit or Delay Our Operations.” In Canada, a variety of Canadian 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. These laws, rules and regulations also require that facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws, rules and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment. Our operations are also subject to federal, state, foreign, regional and local laws, rules and regulations for the control of air emissions, including those associated with the Federal Clean Air Act and the Canadian Environmental Protection Act. We and our customers may be required to make capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For more information, please refer to our discussion under “Item 1A. Risk Factors — Environmental and Occupational Health and Safety Laws and Regulations, Including Violations Thereof, Could Materially Adversely Affect Our Operating Results.” We are aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the Canadian provinces of Alberta and British Columbia. 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. 8 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 to many hazards inherent Our operations are subject in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution 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 drilling and pressure pumping contracts typically contain provisions requiring our customer 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 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 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 rigs 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, our drilling rigs and certain other assets, such insurance does not cover the full replacement cost of the rigs 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 $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self-insured retention on our general liability and automobile liability insurance coverage. We self-insure a number of other risks, including loss of earnings and business interruption, and 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. If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or 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.” 9 Employees We had approximately 7,800 full-time employees at December 31, 2013. 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. 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. If 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: • the supply of and demand for oil and natural gas, including current natural gas storage capacity and usage, • the prices, and expectations about future prices, of oil and natural gas, • the supply of and demand for drilling and pressure pumping equipment, • the cost of exploring for, developing, producing and delivering oil and natural gas, • the environmental and other laws and governmental regulations regarding the exploration, development, production and delivery of oil and natural gas, and in particular, public pressure on, and legislative and regulatory interest within, federal, state, foreign, regional and local governments to stop, significantly limit or regulate drilling and pressure pumping activities, including hydraulic fracturing, and • merger and divestiture activity among oil and natural gas producers. 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 are affected by factors such as: • market supply and demand, • domestic and international military, political, economic and weather conditions, 10 • the ability of the Organization of Petroleum Exporting Countries, commonly known as OPEC, to set and maintain production and price targets, • technical advances affecting energy consumption and production, and • the price and availability of alternative fuels. All of these factors are beyond our control. Declines in the market prices of natural gas and oil caused our customers to significantly reduce their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributable to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year (WTI spot price as reported by the United States Energy Information Administration). Natural gas prices decreased in 2011 to an average of $4.00 per Mcf (Henry Hub spot price as reported by the United States Energy Information Administration). This decrease continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural gas drilling activities in 2012. During 2013, natural gas prices averaged $3.73 per Mcf, and oil prices averaged $97.91 per barrel, and demand for natural gas drilling activities continued to decline. Our average number of rigs operating remains well below the number of our available rigs. Construction of new land drilling rigs in the United States during the last decade has significantly contributed to excess capacity in total available drilling rigs. As a result of decreased drilling activity and excess capacity, our average number of rigs operating has declined from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would likely result in lower demand for our drilling rigs and pressure pumping services and could adversely affect 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 drilling rigs and pressure pumping 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 may result in reduced access to financing by our customers and reduced demand for our services. Furthermore, these factors may result in certain of our customers experiencing an inability 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. A deterioration in the global economic environment could have a material adverse effect on our business, financial condition, cash flows and results of operations. A General Excess of Operable Land Drilling Rigs, Increasing Rig Specialization and Excess Pressure Pumping Equipment May Adversely Affect Our Utilization and Profit Margins. The North American oil and natural gas services industry has experienced downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs and pressure pumping equipment available than necessary to meet demand. As a result, drilling and pressure pumping contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods. In addition, unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack of capability to successfully compete for this work. Other ongoing factors which could 11 continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include: • movement of drilling rigs from region to region, • reactivation of land-based drilling rigs, or • construction of new technology drilling rigs. Construction of new technology drilling rigs has increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has resulted in excess capacity of conventional drilling rigs. Similarly, the substantial recent increase in unconventional resource plays has led to higher demand for pressure pumping services and there has been a significant increase in the construction of new pressure pumping equipment across the industry. As a result of low natural gas prices and the construction of new equipment, there is currently an excess of pressure pumping equipment available. In circumstances of excess capacity, providers of pressure pumping services have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses. Shortages, Delays in Delivery and Interruptions in Supply of Drill Pipe, Replacement Parts, Other Equipment, Supplies and Materials Adversely Affect Our Operating Results. During periods of increased demand for drilling and pressure pumping services, the industry has experienced shortages of drill pipe, replacement parts, other equipment, supplies 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: • weather issues, whether short-term such as a hurricane, or long-term such as a drought, and • a shortage in the number of vendors able or willing to provide the necessary equipment, supplies and materials, including as a result of commitments of vendors to other customers or third parties. 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 construct and operate our drilling rigs and pressure pumping equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations. 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. to many hazards inherent Our operations are subject in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution, exposure and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our drilling and pressure pumping contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage. Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers 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 by contract or indemnification agreements. Incurring a liability for which we are not fully 12 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 rigs 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, our drilling rigs and certain other assets, such insurance does not cover the full replacement cost of the rigs 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 $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self-insured retention on our general liability and automobile liability insurance coverage. We self-insure a number of other risks, including loss of earnings and business interruption, and 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 and is not fully covered by insurance or an enforceable or recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations. New Technologies May Cause Our Operating Methods and Equipment to Become Less Competitive, and Higher Levels of Capital Expenditures May be Necessary to Remain Competitive in our Industry. The market for our services is characterized by continual technological and process developments that have resulted in, and will likely continue to result in, substantial improvements in the functionality and performance of rigs and equipment. Our customers are increasingly demanding the services of newer, higher specification drilling rigs. Accordingly, a higher level of capital expenditures may be required to maintain and improve existing rigs and equipment and purchase and construct newer, higher specification drilling rigs to meet the increasingly sophisticated needs of our customers. In addition, technological changes, process improvements and other factors that increase operational efficiencies could result in oil and natural gas wells being drilled and completed more quickly, which could reduce the number of revenue earning days. Technological and process developments in the pressure pumping business could have similar effects. In recent years, we have added drilling rigs to our fleet through new construction, and we have purchased new pressure pumping equipment. Although we take measures to ensure that we use advanced oil and natural gas drilling technology, changes in technology or improvements in competitors’ equipment could make our equipment less competitive. If we are not successful in building new rigs and pressure pumping equipment or upgrading our existing rigs and pressure pumping equipment in a timely and cost-effective manner, we could lose market share. New technologies, services or standards could render some of our services, drilling rigs or pressure pumping equipment obsolete, which could have a material adverse impact on our business, financial condition, cash flows and results of operation. 13 Our Current Backlog of Contract Drilling Revenue May Not Ultimately Be Realized as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment. As of December 31, 2013, 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 $946 million. 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, renegotiate or 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 cancel or negotiate 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 renegotiation or termination 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. The Oil Service Business Sectors in Which We Operate Are Highly Competitive with Excess Capacity, which Adversely Affects Our Operating Results. The land drilling and pressure pumping businesses are highly competitive. At times, available land drilling rigs and pressure pumping equipment exceed the demand for such equipment. This excess capacity has resulted in substantial competition for drilling and pressure pumping contracts. The ability to move drilling rigs and pressure pumping equipment from one market to another in response to market conditions heightens the competition in the industry. We believe that price competition for drilling and pressure pumping contracts will continue to be intense due to the existence of available rigs and pressure pumping equipment. As a result of competition, our utilization may decrease and/or we may be unable to maintain or increase prices for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations. Reliance on Management, Competition for Experienced Personnel and Rising Labor Costs Adversely Affect Our Operating Results. 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. During periods of high demand for our services, wage rates for operations personnel are also likely to increase, resulting in higher operating costs. An inability to obtain or attract and retain qualified personnel and increases in wage rates 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. In 2013, we received approximately 46% of our consolidated operating revenues from our ten largest customers and approximately 29% of our consolidated operating revenues from our five largest customers. During 2013, one customer accounted for approximately $286 million or 10.5% of our consolidated operating revenues. These revenues were earned in both our contract drilling and pressure pumping businesses. The loss of one or more of our larger customers could have a material adverse effect on our business, financial condition, cash flows and results of operations. 14 Growth Through the Building of New Rigs and Pressure Pumping Equipment and Rig and Other Acquisitions Are Not Assured. We have increased our drilling rig fleet and pressure pumping horsepower in the past through mergers, acquisitions and new construction. 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, contract drillers may continue to build new, high technology rigs and providers of pressure pumping services may continue to build new, high horsepower equipment. There can be no assurance that we will: • have sufficient capital resources to complete additional acquisitions or build new rigs or pressure pumping equipment, • successfully integrate additional drilling rigs, pressure pumping equipment or other assets or businesses, • effectively manage the growth and increased size of our organization, drilling fleet and pressure pumping equipment, • successfully deploy idle, stacked or additional rigs and pressure pumping equipment, • maintain the crews necessary to operate additional drilling rigs and pressure pumping equipment, or • successfully improve our financial condition, results of operations, business or prospects as a result of any completed acquisition or the building of new drilling rigs and pressure pumping equipment. We may incur substantial indebtedness to finance future acquisitions, build new drilling rigs or build new pressure pumping equipment and also may issue equity, convertible or debt securities in connection with any such acquisitions or building program. Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders. Also, continued growth could strain our management, operations, employees and other resources. 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: • substantial civil, criminal and/or administrative penalties, • modification, denial or revocation of permits or other authorizations, • imposition of limitations on our operations, and • performance of site investigatory, remedial or other corrective actions. 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, 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 15 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 NSPS to address emissions of sulfur dioxide and volatile organic compounds and NESHAPS to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are now required to use completion combustion device equipment (i.e., flaring) if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology (MACT) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. These rules may require the implementation of new operating standards which may impact our business. If these or other initiatives result in an increase in regulation, it 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 Could Increase Our Costs and Limit or Delay Our Operations. Members of the U.S. Congress and the EPA are reviewing more stringent regulation of hydraulic fracturing, a technology employed by our pressure pumping business, which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Both the EPA and the U.S. Congress are studying whether there is any link between hydraulic fracturing activities and soil or ground water contamination. As part of their respective studies, the House Subcommittee on Energy and Environment and the EPA each sent requests to a number of companies, including our company, for information on their hydraulic fracturing practices. We have responded to each of the inquiries. In addition, legislation has been proposed in the U.S. Congress to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing ground water or causing other damage. These bills, if adopted, could establish an additional level of regulation at the federal or state level that could 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. Certain states where we operate, including Texas, have adopted or are considering similar disclosure legislation. For example, Colorado, North Dakota, Montana, Texas, Louisiana, 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. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and is developing final guidance documents related to this newly asserted regulatory authority. 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. A number of federal agencies are analyzing, or have been requested to review a variety of environmental issues associated with hydraulic fracturing. For example, the EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released a progress report on December 21, 2012 outlining work currently underway and is expected to release a draft final report in 2014. In addition, the EPA announced on October 20, 2011 that it is launching a study of wastewater resulting from hydraulic fracturing activities and currently plans to propose pretreatment regulations in 2014. These ongoing or proposed studies, depending on their course, and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism. 16 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, 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. 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 greenhouse gas (“GHG”) emissions and climate change issues. Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress, and there has been a wide-ranging policy debate, both in the United States and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries to meet stringent new standards that would require substantial reductions in carbon emissions. Those reductions could be costly and difficult to implement. The EPA has adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources on an annual basis. Further, following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA finalized a rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s New Source Review Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Several states and geographic regions in the United States have also adopted legislation and regulations to reduce emissions of GHGs. Additional legislation or regulation by these states and regions, the EPA, and/or any international agreements to which the United States may become a party, that control or limit GHG emissions or otherwise seek to address climate change could adversely affect our operations. The cost of complying with any new law, regulation or treaty will depend on the details of the particular program. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws or regulations related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas. Legal Proceedings Could Have a Negative Impact on our Business. The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. 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. International Uncertainties, and Laws Related to International Opportunities 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. International operations are subject to certain political, economic and other uncertainties not encountered in U.S. operations, including increased risks of social unrest, strikes, terrorism, kidnapping of employees, nationalization, forced negotiation or modification of contracts, expropriation of equipment as well as expropriation of a particular oil company operator’s property and drilling rights, taxation policies, foreign exchange restrictions, currency rate fluctuations and general hazards associated with foreign sovereignty over certain areas in which operations are conducted. To the extent we evaluate and prepare for international opportunities and conduct any international operations, there can be no assurance that there will not be changes in local laws, regulations and administrative 17 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, our future international operations, if any, 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 law (or the administration thereof) on terms we find acceptable. in all cases be able to structure or restructure our operations to conform to local There can be no assurance that we will: • identify attractive opportunities in international markets, • have sufficient capital resources to pursue and consummate international opportunities, • successfully integrate international drilling rigs, pressure pumping equipment or other assets or businesses, • effectively manage the start-up, development and growth of an international organization and assets, • hire, attract and retain the personnel necessary to successfully conduct international operations, or • successfully improve our financial condition, results of operations, business or prospects as a result of the entry into one or more international markets. 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 of the parts of the world where contract drilling and pressure pumping activities are conducted 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 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. Our Business Is Subject to Cybersecurity Risks and Threats. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. It is possible that our business, financial and other systems could be compromised, which might not be noticed for some period of time. Risks associated with these threats include, among other things, loss of intellectual property, disruption of our and customers’ business operations and safety procedures, loss or damage to our worksite data delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events. We Are Dependent Upon Our Subsidiaries to Meet our Obligations Under Our Long Term Debt We have borrowings outstanding under our senior notes, term loan facility and, from time to time, revolving credit facility. These obligations are guaranteed by each of our existing subsidiaries other than immaterial subsidiaries. Our ability to meet our interest and principal payment obligations depends in large part on dividends 18 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 and a term loan 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 margin on LIBOR loans ranges from 2.25% to 3.25% and the margin on base rate loans ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At December 31, 2013, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of December 31, 2013, we had no borrowings outstanding under our revolving credit facility and $92.5 million outstanding under our term credit facility at an interest rate of 2.50%. A one percent increase in the interest rate on the borrowings outstanding under our term credit facility as of December 31, 2013 would increase our annual cash interest expense by approximately $900,000. Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amounts borrowed. Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby Affect the Related Purchase Price. We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law. Our restated certificate of incorporation authorizes our Board of Directors to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. It also prohibits stockholders from acting by written consent without the holding of a meeting. In addition, our bylaws impose certain advance notification requirements as to business that can be brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder. As a result of these measures and others, potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions. 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 450 Gears Road, Suite 500, Houston, Texas. Our telephone number at that address is (281) 765-7100. Our primary administrative office, which is located in Snyder, Texas, is owned and includes approximately 37,000 square feet of office and storage space. Contract Drilling Operations — Our drilling services are supported by several offices and yard facilities located throughout our areas of operations, including Texas, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania and western Canada. Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our areas of operations, including Texas, Pennsylvania, Ohio, West Virginia and Kentucky. Oil and Natural Gas Working Interests — Our interests in oil and natural gas properties are primarily located in Texas and New Mexico. We own our administrative offices in Snyder, Texas, as well as several of our other facilities. We also lease a number of facilities, and we do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to meet our needs. 19 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 3 of the Notes to Consolidated Financial Statements included in Item 8 of this Report. Item 3. Legal Proceedings. In May 2013, the U.S. Equal Employment Opportunity Commission notified the Company of cause findings related to certain of its employment practices. The cause findings relate to allegations that the Company tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. The Company and the EEOC are engaged in the statutory conciliation process. If such conciliation process is unsuccessful, the Company believes that litigation will ensue. The Company intends to defend itself vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter. Other than the matter described above, we are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our results of operations, cash flows or financial condition. Item 4. Mine Safety Disclosure. Not applicable. 20 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of PART II 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: 2012: First quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013: First quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . High Low $22.14 17.70 17.75 19.21 $25.48 25.12 22.41 26.09 $16.83 12.81 13.40 14.95 $18.59 18.96 18.83 21.29 (b) Holders As of February 7, 2014, there were approximately 1,100 holders of record of our common stock. (c) Dividends We paid cash dividends during the years ended December 31, 2012 and 2013 as follows: Per Share Total (in thousands) 2012: Paid on March 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on June 29, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on September 28, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on December 28, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013: Paid on March 29, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on June 28, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on September 30, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.05 0.05 0.05 0.05 $0.20 $0.05 0.05 0.05 0.05 $0.20 $ 7,788 7,650 7,518 7,346 $30,302 $ 7,312 7,361 7,231 7,208 $29,112 On February 5, 2014, our Board of Directors approved a cash dividend on our common stock in the amount of $0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. 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 credit facilities and other factors. 21 (e) 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, 2013. Period Covered Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in thousands)(1) October 2013(2) . . . . . . . . . . . . November 2013 . . . . . . . . . . . . . December 2013 . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . 4,459 — — 4,459 $23.15 $ — $ — $23.15 896 — — 896 $187,483 $187,483 $187,483 $187,483 (1) On September 6, 2013, we announced that our Board of Directors approved a stock buyback program authorizing purchases of up to $200 million of our common stock in open market or privately negotiated transactions. (2) We withheld 3,563 shares in October 2013 with respect to employees’ tax withholding obligations upon the vesting of restricted shares. The price used to determine the number of shares withheld was the closing price of our common stock on the last business day prior to the date the shares vested. These purchases were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan and not pursuant to the stock buyback program. 22 (e) Performance Graph The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2008 through December 31, 2013, with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group determined by us. Our peer group consists of Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Energy Services Corp. and Precision Drilling Corp. All of the companies in our peer group are providers of land-based drilling services. Nabors Industries, Ltd. also is a provider of pressure pumping services. The graph assumes investment of $100 on December 31, 2008 and reinvestment of all dividends. Pa(cid:2)erson-UTI Energy, Inc. S&P 500 Index S&P Midcap Oil Service Index (OSX) Peer Group $300 $250 $200 $150 $100 $50 $0 2008 2009 2010 2011 2012 2013 Company/Index Fiscal Year Ended December 31, 2008 ($) 2009 ($) 2010 ($) 2011 ($) 2012 ($) 2013 ($) Patterson-UTI Energy, Inc. . . . . . . . . . . . . . . . . . . . . . . . . Peer Group Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S&P 500 Stock Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oilfield Service Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . S&P MidCap Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100.00 135.50 192.50 179.97 169.86 232.96 100.00 161.96 188.47 182.58 161.04 215.29 100.00 126.46 145.51 148.59 172.37 228.19 100.00 162.11 205.75 184.05 189.89 246.06 100.00 137.38 173.98 170.96 201.53 269.04 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. 23 Item 6. Selected Financial Data. Our selected consolidated financial data as of December 31, 2013, 2012, 2011, 2010 and 2009, and for each of the five years in the period ended December 31, 2013 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. Due to the sale of our drilling and completion fluids business in January 2010 and the sale of our electric wireline business in January 2011, the results of operations for those businesses have been reclassified and are presented as discontinued operations for all periods presented. Years Ended December 31, 2013 2012 2011 2010 2009 (In thousands, except per share amounts) Statement of Operations Data: Operating revenues: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,679,611 $1,821,713 $1,669,581 $1,081,898 $ 599,287 161,441 Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,218 Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 845,803 50,559 979,166 57,257 841,771 59,930 350,608 30,425 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,716,034 2,723,414 2,565,943 1,462,931 781,946 Operating costs and expenses: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion, amortization and impairment . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . Net (gain) loss on asset disposals . . . . . . . . . . . . . . . . . . . . Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition-related expenses . . . . . . . . . . . . . . . . . . . . . . . 968,754 744,243 12,909 597,469 73,852 (3,384) — — 1,075,491 580,878 11,303 526,614 64,473 (33,806) 1,100 — 972,778 561,398 9,615 437,279 64,271 (4,999) — — 655,678 235,100 7,020 333,493 53,042 (22,812) (2,000) 2,485 357,742 124,100 7,341 289,847 43,935 3,385 3,810 — Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,393,843 2,226,053 2,040,342 1,262,006 830,160 Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 322,191 (25,750) 497,361 (21,688) 525,601 (14,883) 200,925 (10,171) (48,214) (3,341) Income (loss) from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax expense (benefit) 296,441 108,432 475,673 176,196 510,718 187,938 190,754 72,856 (51,555) (17,595) Income (loss) from continuing operations . . . . . . . . . . . . . . . $ 188,009 $ 299,477 $ 322,780 $ 117,898 $ (33,960) Income (loss) from continuing operations per common share: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.29 $ 1.96 $ 2.08 $ 0.77 $ (0.22) Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1.28 $ 1.96 $ 2.06 $ 0.76 $ (0.22) Cash dividends per common share . . . . . . . . . . . . . . . . . . . . . $ 0.20 $ 0.20 $ 0.20 $ 0.20 $ 0.20 Weighted average number of common shares outstanding: Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144,356 151,144 153,871 152,772 152,069 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145,303 151,699 155,304 153,276 152,069 Balance Sheet Data: Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,687,127 $4,556,911 $4,221,901 $3,423,031 $2,662,152 — . . . . . . . . . . . . . . . . . . . . . . . Borrowings under line of credit Other long term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 2,081,700 Stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 263,511 Working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — 110,000 382,500 2,516,631 346,238 — 682,500 2,755,997 454,373 — 392,500 2,187,607 241,445 692,500 2,640,657 340,128 24 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Management Overview — We are a leading provider of services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and pressure pumping services. In addition to these services, we also invest, on a non-operating working interest basis, in oil and natural gas properties. We acquired an electric wireline business on October 1, 2010 and sold the business on January 27, 2011. Due to our exit from the electric wireline business, we have presented the results of that business as discontinued operations in this Report. As of December 31, 2013, we had a drilling fleet that consisted of 279 marketable land-based drilling rigs. There continues to be uncertainty with respect to the global economic environment, crude oil and natural gas prices are volatile and natural gas prices have been low in recent years. Activity in our drilling business decreased in the fourth quarter of 2013 compared to the fourth quarter of 2012. In the fourth quarter of 2013, our average number of rigs operating decreased to 192, as compared to an average of 206 drilling rigs operating during the same period in 2012. 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, 2013, we have completed 124 new APEX® rigs and made performance and safety improvements to existing high capacity rigs. We have plans to complete 20 additional new APEX® rigs in 2014. In connection with horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. As of December 31, 2013, we had approximately 763,000 hydraulic horsepower in our pressure pumping fleet. This is a net increase of approximately 610,000 horsepower since the end of 2009. Low natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace has 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 backlog as of December 31, 2013 was approximately $946 million. We expect approximately $660 million of our backlog to be realized in 2014. We generally calculate our backlog by multiplying the day rate 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, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are 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 for which we have received an early termination notice, our backlog calculation includes the early termination rate, instead of the day rate, for the period we expect to receive the lower rate. See Item 1A. Risk Factors – Our Current Backlog of Contract Drilling Revenue May Not Ultimately Be Realized as Fixed-Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment. For the three years ended December 31, 2013, our operating revenues from continuing operations consisted of the following (dollars in thousands): 2013 2012 2011 Contract drilling . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . $1,679,611 979,166 57,257 62% $1,821,713 841,771 36 59,930 2 67% $1,669,581 845,803 31 50,559 2 65% 33 2 $2,716,034 100% $2,723,414 100% $2,565,943 100% Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During 2013, our average number of rigs operating was 184 in the United States and 8 in Canada compared to 214 in the United States and 7 in Canada in 2012 and 205 in the United States and 11 in Canada in 2011. Our average 25 income was primarily due to lower revenue as a result of fewer rigs operating, revenue per operating day was $24,020 in 2013 compared to $22,540 in 2012 and $21,200 in 2011. We had consolidated net income of $188 million for 2013 compared to $299 million for 2012. The decrease in consolidated net lower profitability on pressure pumping revenues, higher depreciation expense and a gain on assets disposals in 2012 with no similar gain in 2013. Depreciation, depletion, amortization and impairment expense for 2013 includes a charge of $7.9 million related to removing 48 rigs from our marketable fleet. It also includes a charge of $29.9 million related to 55 mechanical rigs that were not under contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs. 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. Natural gas prices and our monthly average number of rigs operating have declined from recent highs. In December 2013, our average number of rigs operating was 187 in the United States and 9 in Canada. We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” in Item 1A of this Report. Critical Accounting Policies In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue recognition, the use of estimates and oil and natural gas properties. Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances (“triggering events”) indicate that the carrying values of certain assets may not be recovered over their estimated remaining useful lives. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will continue to fluctuate. Based on management’s expectations of future trends, we estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured at fair value. On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling longer horizontal wells using high capacity rigs). In connection with our ongoing planning process, we evaluated our then-current fleet of marketable drilling rigs in 2013, 2012 and 2011 and identified 48, 36 and 53 rigs, during each of those years, respectively, that we determined would no longer be marketed as rigs based on our assessment of estimated expenditures to bring these rigs into condition to operate in the current environment, as well as our assessment of future demand and the suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with continuing utility to our other marketed rigs 26 were transferred to other rigs or to our yards to be used as spare equipment. The remaining components of these rigs were retired. The net book values of these assets of $7.9 million in 2013, $5.2 million in 2012 and $15.7 million in 2011 were expensed in our consolidated statements of operations. In 2013, due to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, we recorded in our consolidated statement of operations a charge of $29.9 million related to 55 mechanical rigs that were not under contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no similar charges in 2012 or 2011. We also evaluate our fleet of marketable pressure pumping equipment and in 2012 identified approximately 37,000 horsepower of pressure pumping equipment that would be retired. The net book value of these assets of $7.3 million was expensed in our consolidated statements of operations. There were no similar charges in 2013 or 2011. In light of the levels of activity and revenue per operating day experienced by us and our peers in 2013, 2012 and 2011, we concluded that no triggering events occurred during these years with respect to our contract drilling segment as a whole which would indicate that the carrying amounts of long-lived assets in that segment may not be recoverable. We also concluded that no triggering event occurred with respect to our pressure pumping segment in 2013, 2012 or 2011. Impairment considerations related to our oil and natural gas segment are discussed below. Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. We evaluate goodwill at least annually on December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our reporting units for impairment testing have been determined to be the same as our operating segments. We currently have goodwill in our contract drilling and pressure pumping operating segments. We first determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. From time to time, we may perform the first step of quantitative testing for goodwill impairment in lieu of performing a qualitative assessment. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall. In connection with our annual goodwill impairment assessment as of December 31, 2012, we determined based on an assessment of qualitative factors that it was more likely than not that the fair values of our reporting units were greater than their carrying amounts and further testing was not necessary. In making this determination, we considered the continued demand experienced during 2012 for our services in the contract drilling and pressure pumping businesses. We also considered the then current and expected levels of commodity prices for crude oil and natural gas, which influence the overall level of business activity in these operating segments. Additionally, operating results for 2012 and forecasted operating results for 2013 were also taken into account. Our overall market capitalization and the large amount of calculated excess of the fair values of our reporting units over their carrying values and lack of significant changes in the key assumptions from our 2010 quantitative Step 1 assessment of goodwill were also considered. We performed a quantitative impairment assessment of our goodwill as of December 31, 2013. In completing the first step of the analysis, we used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of the reporting units. In developing this fair value estimate, we applied key assumptions including an assumed discount rate of 11.87% for the contract drilling reporting unit and an assumed discount rate of 12.40% for the pressure pumping reporting unit. An assumed long-term growth rate of 3.00% was used for both reporting units. Based on the 27 results of the first step of the impairment test in 2013, we concluded that no impairment was indicated in our contract drilling or pressure pumping reporting units as the estimated fair value of each reporting unit exceeded its carrying value. We have undertaken extensive efforts in the past several years to upgrade our fleet of equipment and believe that we are well positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional vertical wells that has resulted primarily from low natural gas prices. In the event that market conditions weaken, we may be required to record an impairment of goodwill in our contract drilling or pressure pumping reporting units in the future, and such impairment could be material. Revenue recognition — Revenues from daywork drilling and pressure pumping activities are recognized as services are performed. Expenditures reimbursed by customers are recognized as revenue and the related expenses are recognized as direct costs. All of the wells we drilled in 2013, 2012 and 2011 were drilled under daywork contracts. Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. Key estimates used by management include: • allowance for doubtful accounts, • depreciation, depletion and amortization, • fair values of assets acquired and liabilities assumed in acquisitions, • goodwill and long-lived asset impairments, and • reserves for self-insured levels of insurance coverage. Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. Costs of exploratory wells are initially capitalized to wells-in- progress until the outcome of the drilling is known. We review wells-in-progress quarterly to determine whether sufficient progress is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, we consider the well costs to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved oil and natural gas reserves for each respective field. We review our proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and fair value. The fair 28 value estimates used in measuring impairment are based on our expectations of future commodity prices over the life of the respective field and the net future cash inflows from developing and operating these fields. We review unproved oil and natural gas properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately $4.0 million, $1.9 million and $3.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in depreciation, depletion, amortization and impairment in the consolidated statements of operations. For additional information on our accounting policies, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report. Liquidity and Capital Resources As of December 31, 2013, we had working capital of $454 million, including cash and cash equivalents of $250 million, compared to working capital of $340 million and cash and cash equivalents of $111 million at December 31, 2012. During 2013, our sources of cash flow included: • $889 million from operating activities, • $11.8 million from the exercise of stock options and related tax benefits associated with stock-based compensation, and • $10.4 million in proceeds from the disposal of property and equipment. During 2013, we used $73.5 million to repurchase shares of our common stock, $29.1 million to pay dividends on our common stock, $6.3 million to repay long-term debt and $662 million: • to build new drilling rigs and pressure pumping equipment, • to make capital expenditures for the betterment and refurbishment of our drilling rigs and pressure pumping equipment, • to acquire and procure equipment and facilities for our drilling and pressure pumping operations, and • to fund investments in oil and natural gas properties on a working interest basis. We paid cash dividends during the year ended December 31, 2013 as follows: Paid on March 29, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on June 28, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on September 30, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Per Share Total $0.05 0.05 0.05 0.05 $0.20 (in thousands) $ 7,312 7,361 7,231 7,208 $29,112 On February 5, 2014, our Board of Directors approved a cash dividend on our common stock in the amount of $0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. 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 credit facilities and other factors. On August 1, 2007, our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. On July 25, 2012, our Board of Directors terminated the remaining authority under the 2007 stock buyback program, and approved a 29 new stock buyback program authorizing purchases of up to $150 million of our common stock in open market or privately negotiated transactions. On September 6, 2013, the Company’s Board of Directors terminated any remaining authority under the 2012 stock buyback program, and approved a new stock buyback program that authorizes purchase of up to $200 million of the Company’s common stock in open market or privately negotiated transactions. As of December 31, 2013, we had remaining authorization to purchase approximately $187 million of our outstanding common stock under the new stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock. We acquired shares of stock from employees during 2013, 2012 and 2011 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options by employees. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) and not pursuant to the stock buyback program. Treasury stock acquisitions during the year ended December 31, 2013, 2012 and 2011 were as follows (dollars in thousands): 2013 2012 2011 Shares Cost Shares Cost Shares Cost Treasury shares at beginning of period . . . . . . . . . . . . . . . . . . . . . . Purchases pursuant to stock buyback programs: 2007 program . . . . . . . . . . . . . . . . 2012 program . . . . . . . . . . . . . . . . 2013 program . . . . . . . . . . . . . . . . Acquisitions Pursuant to the 2005 38,146,738 $795,051 27,487,571 $624,759 27,343,814 $620,445 — 2,567,266 602,564 — 4,708,784 5,863,451 — 51,107 12,517 70,092 98,892 — 8,689 — — 255 — — Long-Term Incentive Plan . . . . . . 951,489 22,213 86,932 1,308 135,068 4,059 Treasury shares at end of period . . . 42,268,057 $880,888 38,146,738 $795,051 27,487,571 $624,759 On September 27, 2012, we entered into a credit agreement (the “Credit Agreement”). The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The Credit Agreement replaced a previous senior unsecured revolving credit facility. The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time. The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments which commenced December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments. Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility. Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR 30 rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of December 31, 2013, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%. The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these covenants at December 31, 2013. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise. Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that to insolvency and bankruptcy such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit. in limited circumstances with respect As of December 31, 2013, we had $92.5 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. We had $39.8 million in letters of credit outstanding at December 31, 2013 and, as a result, had available borrowing capacity of approximately $460 million at that date. On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020. On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amounts of our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We will pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022. The Series A Notes and Series B Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date. The respective note purchase agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such 31 indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior quarters to interest charges for the same period. We were in compliance with these covenants at December 31, 2013. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise. Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable. We believe that our liquidity as of December 31, 2013, which includes approximately $454 million in working capital and approximately $460 million available under our $500 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all. Commitments and Contingencies — As of December 31, 2013, we maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2013, no amounts had been drawn under the letters of credit. As of December 31, 2013, we had commitments to purchase approximately $225 million of major equipment for our drilling and pressure pumping businesses. Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2016 and 2017. As of December 31, 2013, the remaining obligation under these agreements was approximately $25.2 million, of which materials with a total purchase price of approximately $7.7 million are expected to be delivered during 2014. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall. In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2013, advances of approximately $11.8 million had been made under this agreement and repayments of approximately $2.6 million had been received resulting in a balance outstanding of approximately $9.2 million. In May 2013, the U.S. Equal Employment Opportunity Commission notified us of cause findings related to certain of our employment practices. The cause findings relate to allegations that we tolerated a hostile work environment for employees based on national origin and race. The cause findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. We and the EEOC are engaged in the statutory conciliation process. If such conciliation process is unsuccessful, we believe that litigation will ensue. We intend to defend ourself vigorously and, based on the information available 32 to us at this time, we do not expect the outcome of this matter to have a material adverse effect on our financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter. Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts. Contractual Obligations The following table presents information with respect to our contractual obligations as of December 31, 2013 (dollars in thousands): Series A Notes(3) Term loan(1) . . . . . . . . . . . . . . . . . . Interest on term loan(2) . . . . . . . . . . . . . . . . . . . . . . . . . Interest on Series A Notes(4) Series B Notes(5) . . . . . . . . . . . . . . . Interest on Series B Notes(6) . . . . Equipment purchases(7) . . . . . . . . . Inventory purchases(8) . . . . . . . . . . Payments due by period $ Total 92,500 6,329 300,000 100,850 300,000 108,316 225,354 25,198 Less than 1 year $ 10,000 2,247 — 14,910 — 12,810 225,354 7,735 1-3 years 3-5 years More than 5 years $ 41,250 3,572 — 29,820 — 25,620 — 15,438 $41,250 510 — 29,820 — 25,620 — 2,025 — — 300,000 26,300 300,000 44,266 — — $1,158,547 $273,056 $115,700 $99,225 $670,566 (1) Represents repayments of borrowings under the term loan portion of the Credit Agreement. The term loan matures on September 27, 2017. (2) Interest to be paid on term loan using 2.50% rate in effect as of December 31, 2013. (3) Principal repayment of the Series A Notes is required at maturity on October 5, 2020. (4) Interest to be paid on the Series A Notes using 4.97% coupon rate. (5) Principal repayment of the Series B Notes is required at maturity on June 14, 2022 (6) Interest to be paid on the Series B Notes using 4.27% coupon rate. (7) Represents commitments to purchase major equipment to be delivered in 2014 based on expected delivery dates. (8) Represents commitments to purchase proppants and chemicals for our pressure pumping business. 33 Off-Balance Sheet Arrangements We had no off-balance sheet arrangements at December 31, 2013. Results of Operations Comparison of the years ended December 31, 2013 and 2012 The following tables summarize operations by business segment for the years ended December 31, 2013 and 2012: Contract Drilling Year Ended December 31, 2013 2012 % Change Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,679,611 968,754 (Dollars in thousands) $1,821,713 1,075,491 Margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . Depreciation, amortization and impairment . . . . . . . . . . . . . . 710,857 5,867 438,728 746,222 6,513 390,316 (7.8)% (9.9)% (4.7)% (9.9)% 12.4% Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 266,262 $ 349,393 (23.8)% Operating days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average revenue per operating day . . . . . . . . . . . . . . . . . . . . Average direct operating costs per operating day . . . . . . . . . . Average margin per operating day(1) . . . . . . . . . . . . . . . . . . . Average rigs operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ 69,918 24.02 13.86 10.17 192 $ 504,508 $ $ $ 80,833 22.54 13.31 9.23 221 $ 744,949 (13.5)% 6.6% 4.1% 10.2% (13.1)% (32.3)% (1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days. The demand for our contract drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States in recent years has contributed to an excess capacity of land drilling rigs compared to demand. Recently, customer demand has shifted away from mechanically powered drilling rigs to electric powered drilling rigs, reducing the utilization rates of our mechanically powered drilling rigs. The average market price of natural gas and oil for each of the fiscal quarters and full year in 2013 and 2012 follows: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year 2012: Average natural gas price per Mcf(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . Average oil price per Bbl(2) 2013: Average natural gas price per Mcf(1) Average oil price per Bbl(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2.45 $102.88 $ 2.28 $93.42 $ 2.88 $ 92.24 $ 3.40 $87.96 $ 2.75 $94.12 $ 3.49 $ 94.34 $ 4.01 $94.10 $ 3.55 $105.84 $ 3.85 $97.34 $ 3.73 $97.91 (1) The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration. (2) The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. 34 Revenues and direct operating costs decreased in 2013 compared to 2012 as a result of a decrease in the number of rigs operating. A greater proportion of our high specification APEX® rigs working combined with early contract termination revenues caused an increase in the average revenue per operating day. Capital expenditures were incurred in 2013 and 2012 to build new drilling rigs, to modify and upgrade existing drilling rigs and to acquire additional equipment including top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation, amortization and impairment expense included approximately $7.9 million in 2013 and approximately $5.2 million in 2012 of charges related to drilling equipment on drilling rigs that were retired from our marketable fleet. We retired 48 rigs from our marketable fleet in 2013 and retired 36 rigs from our marketable fleet in 2012. In 2013, due to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, we recorded additional depreciation, amortization and impairment expense of $29.9 million related to 55 mechanical rigs that were not under contract. Although these 55 rigs remain marketable, we have lower expectations with respect to utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no similar charges in 2012 or 2011. Significant capital expenditures incurred in recent years to add new rig capacity also contributed to the increase in depreciation expense. Pressure Pumping Year Ended December 31, 2013 2012 % Change Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in thousands) $841,771 580,878 $979,166 744,243 Margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, amortization and impairment . . . . . . . . . . . . . . . . . 234,923 17,695 129,984 260,893 17,036 111,062 16.3% 28.1% (10.0)% 3.9% 17.0% Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 87,244 $132,795 (34.3)% Fracturing jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average revenue per fracturing job . . . . . . . . . . . . . . . . . . . . . . . Average revenue per other job . . . . . . . . . . . . . . . . . . . . . . . . . . . Average revenue per total job . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average direct operating costs per total job . . . . . . . . . . . . . . . . . Average margin per total job(1) . . . . . . . . . . . . . . . . . . . . . . . . . . Margin as a percentage of total revenues(1) . . . . . . . . . . . . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,261 4,800 6,061 $ 705.57 $ 18.63 $ 161.55 $ 122.79 38.76 $ 24.0% $122,782 2.6% 1,229 (15.2)% 5,659 (12.0)% 6,888 19.4% $ 590.70 (8.9)% $ 20.46 32.2% $ 122.21 45.6% 84.33 $ 37.88 2.3% $ 31.0% (22.6)% (36.7)% $194,117 (1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues. In connection with the development of unconventional reservoirs, customers have continued to increase the average size of the fracturing jobs. As a result, we have experienced an increase in the size of these multi-stage fracturing jobs resulting in higher revenues and costs. Average revenue per fracturing job increased as a result of this increase in the larger multi-stage fracturing jobs in 2013 as compared to 2012. Average direct operating costs per total job increased primarily as a result of increased amounts of materials and labor used on the larger multi- stage fracturing jobs. Depreciation, amortization and impairment expense increased in 2013 due primarily to significant capital expenditures incurred in recent years to add capacity. In 2012, depreciation, amortization and 35 impairment expenses included approximately $7.3 million related to the retirement of certain pressure pumping equipment. There were no comparable charges in 2013. Oil and Natural Gas Production and Exploration Year Ended December 31, 2013 2012 % Change Revenues — Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenues — Natural gas and liquids . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in thousands, except commodity prices) $55,335 4,595 $51,583 5,674 (6.8)% 23.5% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenues — Total Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depletion and impairment 57,257 12,909 44,348 24,400 59,930 11,303 48,627 21,417 (4.5)% 14.2% (8.8)% 13.9% Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $19,948 $27,210 (26.7)% Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $31,245 $29,888 4.5% (1) Margin is defined as revenues less direct operating costs and excludes depletion and impairment. Oil revenues decreased as a result of lower production partially offset by higher average oil prices. Natural gas and liquids revenue increased due to higher average prices and higher production. Direct operating costs and depletion expense also increased primarily due to the addition of new wells. Depletion and impairment expense in 2013 includes approximately $4.0 million of oil and natural gas property impairments compared to approximately $1.9 million of oil and natural gas property impairments in 2012. Corporate and Other Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net gain on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2013 2012 % Change (Dollars in thousands) $50,290 $ 40,924 $ 4,357 $ 3,819 $(33,806) $ (3,384) $ — $ 1,100 $ $ 554 918 $ 22,750 $28,359 $ $ 1,691 508 $ 5,034 $ 3,926 22.9% 14.1% (90.0)% (100.0)% 65.7% 24.7% 232.9% (22.0)% Selling, general and administrative expense for 2013 increased primarily due to higher costs associated with stock-based compensation and expenses to evaluate and prepare for international growth opportunities. Selling, general and administrative expense in 2012 included a reduction in personnel costs related to the final determination of payouts under the 2009 Performance Unit Awards upon the completion of the performance period. There was no similar reduction in 2013. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on the disposal of assets in 2012 includes a gain of approximately $22.6 million associated with the sale of our flowback operations and a $4.5 million gain from the auction sale of certain excess drilling assets. An additional provision for bad debts was recorded in 2012 with no similar increase in 2013. Interest expense increased in 2013 primarily due to a full year of interest charges related to the $300 million of Series B Senior Notes issued and sold on June 14, 2012. 36 Comparison of the years ended December 31, 2012 and 2011 The following tables summarize operations by business segment for the years ended December 31, 2012 and 2011: Contract Drilling Year Ended December 31, 2012 2011 % Change Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,821,713 1,075,491 (Dollars in thousands) $1,669,581 972,778 Margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . Depreciation, amortization and impairment . . . . . . . . . . . . . . 746,222 6,513 390,316 696,803 6,408 344,312 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 349,393 $ 346,083 Operating days . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average revenue per operating day . . . . . . . . . . . . . . . . . . . . Average direct operating costs per operating day . . . . . . . . . . Average margin per operating day(1) . . . . . . . . . . . . . . . . . . . Average rigs operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ $ 80,833 22.54 13.31 9.23 221 $ 744,949 $ $ $ 78,758 21.20 12.35 8.85 216 $ 784,686 9.1% 10.6% 7.1% 1.6% 13.4% 1.0% 2.6% 6.3% 7.8% 4.3% 2.3% (5.1)% (1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per operating day is defined as margin divided by operating days. The demand for our contract drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas and oil for each of the fiscal quarters and full year in 2012 and 2011 follows: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year 2011: Average natural gas price per Mcf(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . Average oil price per Bbl(2) 2012: Average natural gas price per Mcf(1) Average oil price per Bbl(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.18 $ 93.50 $ 4.37 $102.22 $ 4.12 $89.72 $ 3.32 $93.99 $ 4.00 $94.86 $ 2.45 $102.88 $ 2.28 $ 93.42 $ 2.88 $92.24 $ 3.40 $87.96 $ 2.75 $94.12 (1) The average natural gas price represents the average monthly Henry Hub Spot price as reported by the United States Energy Information Administration. (2) The average oil price represents the average monthly WTI spot price as reported by the United States Energy Information Administration. Revenues and direct operating costs increased in 2012 compared to 2011 as a result of an increase in the number of operating days and increases in average revenue and direct operating costs per operating day. Average revenue per operating day increased in 2012 primarily due to increases in contractual day rates. Average direct operating costs per operating day increased in 2012 due primarily to higher labor-related and rig mobilization costs. The increase in operating days was largely due to increased demand during the first six months of 2012 resulting from higher oil prices and the addition of newbuild APEX® rigs into our drilling fleet. Capital 37 expenditures were incurred in 2012 and 2011 to build new drilling rigs, to modify and upgrade our drilling rigs and to acquire additional equipment including top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation, amortization and impairment expense included approximately $5.2 million in 2012 and approximately $15.7 million in 2011 of charges related to drilling equipment and drilling rigs that were retired from our marketable fleet. We retired 36 rigs from our marketable fleet in 2012 and retired 53 rigs from our marketable fleet in 2011. Significant capital expenditures incurred in recent years to add new rig capacity also contributed to the increase in depreciation expense. Pressure Pumping Year Ended December 31, 2012 2011 % Change Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in thousands) $845,803 561,398 $841,771 580,878 Margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, amortization and impairment . . . . . . . . . . . . . . . . . 260,893 17,036 111,062 284,405 17,686 73,279 (0.5)% 3.5% (8.3)% (3.7)% 51.6% Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $132,795 $193,440 (31.4)% Fracturing jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total jobs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average revenue per fracturing job . . . . . . . . . . . . . . . . . . . . . . . Average revenue per other job . . . . . . . . . . . . . . . . . . . . . . . . . . . Average revenue per total job . . . . . . . . . . . . . . . . . . . . . . . . . . . . Average direct operating costs per total job . . . . . . . . . . . . . . . . . Average margin per total job(1) . . . . . . . . . . . . . . . . . . . . . . . . . . Margin as a percentage of revenues(1) . . . . . . . . . . . . . . . . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,229 5,659 6,888 $ 590.70 $ 20.46 $ 122.21 84.33 $ 37.88 $ 31.0% 1,531 7,010 8,541 $ 467.85 18.48 $ 99.03 $ 65.73 $ 33.30 $ 33.6% $194,117 $198,061 (19.7)% (19.3)% (19.4)% 26.3% 10.7% 23.4% 28.3% 13.8% (7.7)% (2.0)% (1) Margin is defined as revenues less direct operating costs and excludes depreciation, amortization and impairment and selling, general and administrative expenses. Average margin per total job is defined as margin divided by total jobs. Margin as a percentage of revenues is defined as margin divided by revenues. Our customers have increased their activities in the development of unconventional reservoirs resulting in an increase in larger multi-stage fracturing jobs associated therewith. We have added additional equipment to meet this demand and expand our area of operations. As a result, although the total number of fracturing jobs has decreased, we have experienced an increase in these larger multi-stage fracturing jobs as a proportion of the total fracturing jobs we performed. Average revenue per fracturing job increased primarily as a result of this increase in the number of larger multi-stage fracturing jobs in 2012 as compared to 2011. Average revenue per other job increased as a result of a change in job mix. The increase in the number of larger multi-stage fracturing jobs caused an increase in average direct operating costs per total job primarily increased costs of materials and higher labor-related costs. Depreciation, amortization and impairment expense increased in 2012 due to a charge of approximately $7.3 million related to approximately 37,000 horsepower of pressure pumping equipment that was 38 retired. Significant capital expenditures incurred in recent years to add capacity also contributed to the increase in depreciation expense. Oil and Natural Gas Production and Exploration Year Ended December 31, 2012 2011 % Change Revenues — Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenues — Natural gas and liquids . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in thousands, except commodity prices) $44,495 6,064 $55,335 4,595 24.4% (24.2)% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revenues — Total Direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depletion and impairment 59,930 11,303 48,627 21,417 50,559 9,615 40,944 16,962 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $27,210 $23,982 Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $29,888 $22,884 18.5% 17.6% 18.8% 26.3% 13.5% 30.6% (1) Margin is defined as revenues less direct operating costs and excludes depletion and impairment. Oil revenues increased primarily as a result of increased production. Oil production increased primarily due to the addition of new wells. Natural gas and liquids revenue decreased as a result of lower prices partially offset by increased production. Depletion and impairment expense in 2012 includes approximately $1.9 million of oil and natural gas property impairments compared to approximately $3.0 million of oil and natural gas property impairments in 2011. Depletion expense increased approximately $5.6 million in 2012 compared to 2011 primarily due to increased production. Corporate and Other Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net gain on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2012 2011 % Change (Dollars in thousands) $40,177 $ 2,726 $ (4,999) $ — 187 $ $15,652 $ 582 $ 5,947 $ 40,924 $ 3,819 $(33,806) $ 1,100 554 $ $ 22,750 $ 508 $ 5,034 1.9% 40.1% 576.3% N/M 196.3% 45.3% (12.7)% 15.4% The increase in depreciation expense relates primarily to a new enterprise resource planning system. Gains and losses on the disposal of assets are treated as part of our corporate activities because such transactions relate to corporate strategy decisions of our executive management group. The gain on the disposal of assets in 2012 includes a gain of approximately $22.6 million associated with the sale of our flowback operations and a $4.5 million gain from the auction sale of certain excess drilling assets. A provision for bad debts was recognized in 2012 with respect to accounts receivable balances that are estimated to be uncollectible. Interest expense increased in 2012 due primarily to deferred debt issuance costs of $978,000 that were charged to expense as a result of the early termination of the prior credit facility and to interest charges related to the $300 million of 39 Series B Senior Notes issued and sold on June 14, 2012. Capital expenditures decreased in 2012 due to less activity with respect to the implementation of the new enterprise resource planning system. Discontinued Operations: Electric wireline revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Electric wireline direct operating costs . . . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss from discontinued operations, net of income taxes . . . . . . . . . . Year Ended December 31, 2012 2011 % Change (Dollars in thousands) $1,104 $1,831 $ 46 $ (209) $ (367) (100)% (100)% (100)% (100)% (100)% $— $— $— $— $— On January 27, 2011, we sold our electric wireline business, which had been acquired by us on October 1, 2010. The results of operations of this business have been classified as a discontinued operation. Income Taxes Year Ended December 31, 2013 2012 2011 Income from continuing operations before income tax . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (Dollars in thousands) $475,673 $176,196 $296,441 $108,432 $510,718 $187,938 36.6% 37.0% 36.8% The effective tax rate is a result of a federal rate of 35.0% adjusted as follows: 2013 2012 2011 Statutory tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permanent differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other, net 35.0% 35.0% 35.0% 2.5 3.7 (0.2) (1.5) (0.3) (0.6) 2.5 (0.1) (0.6) Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36.6% 37.0% 36.8% The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008) and allows a deduction of 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent difference for 2011 does not include any deduction as it is limited to taxable income and we had a tax loss in 2011. The permanent difference for 2012 does not include any deduction as it is limited to taxable income and we did not have taxable income in 2012 due to the utilization of net operating loss carryforwards. The permanent difference for 2013 includes a deduction of $10.0 million as we fully utilized our remaining net operating loss carryforwards. We record deferred federal income taxes based primarily on the temporary differences between the book and tax bases of our assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be settled. As a result of fully recognizing the benefit of our deferred income taxes, we incur deferred income tax expense as these benefits are utilized. We recognized deferred tax expense of approximately $51 million in 2013, $160 million in 2012 and $159 million in 2011. On January 1, 2010, we converted our Canadian operations from a Canadian branch to a controlled foreign corporation for federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets. 40 As a result of the above conversion, our Canadian assets are no longer directly subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, we have elected to permanently reinvest these unremitted earnings in Canada, and intend to do so for the foreseeable future. As a result, no deferred United States federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $38.5 million as of December 31, 2013. The unrecognized deferred tax liability associated with these earnings was approximately $5.9 million, net of available foreign tax credits. This liability would be recognized if we received a dividend of the unremitted earnings. Volatility of Oil and Natural Gas Prices and its Impact on Operations and Financial Condition 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 are affected by factors such as market supply and demand, domestic and international military, political, economic and weather conditions, the ability of OPEC to set and maintain production and price targets, technical advances affecting energy consumption and production and the price and availability of alternative fuels. All of these factors are beyond our control. Declines in the market prices of natural gas and oil caused our customers to significantly reduce their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributable to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year (WTI spot price as reported by the United States Energy Information Administration). Natural gas prices decreased in 2011 to an average of $4.00 per Mcf (Henry Hub spot price as reported by the United States Energy Information Administration). This decrease continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural gas drilling activities in 2012. During 2013, natural gas prices averaged $3.73 per Mcf, and oil prices averaged $97.91 per barrel, and demand for natural gas drilling activities continued to decline. Our average number of rigs operating remains well below the number of our available rigs. Construction of new land drilling rigs in the United States during the last decade has significantly contributed to excess capacity in total available drilling rigs. As a result of decreased drilling activity and excess capacity, our average number of rigs operating has declined from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would likely result in lower demand for our drilling rigs and pressure pumping services and could adversely affect 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 drilling rigs and pressure pumping services. Impact of Inflation Inflation has not had a significant impact on our operations during the three years in the period ended December 31, 2013. We believe that inflation will not have a significant near-term impact on our financial position. Recently Issued Accounting Standards In February 2013, the FASB issued an accounting standards update that requires additional disclosures regarding reclassifications out of accumulated other comprehensive income. This requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012, and became effective for us in the quarter ended March 31, 2013. The adoption of this update did not have a material impact on the disclosures included in our consolidated financial statements. We include in accumulated other comprehensive income the cumulative translation adjustment of our foreign subsidiary. 41 In February 2013, the FASB issued an accounting standards update to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. The update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The requirements in this update are effective during interim and annual periods beginning after December 15, 2013. The adoption of this update is not expected to have a material impact on our consolidated financial statements. Item 7A. Quantitative and Qualitative Disclosures About Market Risk We currently have exposure to interest rate market risk associated with any borrowings that we have under our term credit facility or our revolving credit facility. Interest is paid on the outstanding principal amount of borrowings at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.25% to 3.25% and the margin on base rate loans ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At December 31, 2013, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of December 31, 2013, we had no borrowings outstanding under our revolving credit facility and $92.5 million outstanding under our term credit facility at an interest rate of 2.50%. The interest rate on the borrowing outstanding under our term credit facility is variable and adjusts at each interest payment date based on our election of LIBOR or the base rate. A one percent increase in the interest rate on the borrowings outstanding under our term credit facility as of December 31, 2013 would increase our annual cash interest expense by approximately $900,000. We conduct a portion of our business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last several years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced and the value of our Canadian net assets will decline when they are translated to U.S. dollars. This currency risk is not material to our results of operations or financial condition. The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items. Item 8. Financial Statements and Supplementary Data. Financial Statements are filed as a part of this Report at the end of Part IV hereof beginning at page F-1, Index to Consolidated Financial Statements, and are incorporated herein by this reference. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. None. Item 9A. Controls and Procedures. Disclosure Controls and Procedures: Under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Report. Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2013, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and is accumulated and reported to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure. 42 Management’s Report on Internal Control over Financial Reporting: Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our CEO and CFO, we carried out an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2013, based on the Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, our management has concluded that our internal control over financial reporting was effective as of December 31, 2013. The effectiveness of our internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page F-2 of this Report and which is incorporated by reference into Item 8 of this Report. Changes in Internal Control over Financial Reporting: There have been no changes in our internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information. None. 43 PART III Certain information required by Part III is omitted from this Report because we expect to file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A of the Securities Exchange Act of 1934 no later than 120 days after the end of the fiscal year covered by this Report and certain information included therein is incorporated herein by reference. Item 10. Directors, Executive Officers and Corporate Governance. The information required by this Item is incorporated herein by reference to the Proxy Statement. We have adopted a Code of Business Conduct and Ethics for Senior Financial Executives, which covers, among others, our principal executive officer and principal financial and accounting officer. The text of this code is located on our website under “Governance.” Our Internet address is www.patenergy.com. We intend to disclose any amendments to or waivers from this code on our website. Item 11. Executive Compensation. The information required by this Item is incorporated herein by reference to the Proxy Statement. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The information required by this Item is incorporated herein by reference to the Proxy Statement. Item 13. Certain Relationships and Related Transactions, and Director Independence. The information required by this Item is incorporated herein by reference to the Proxy Statement. Item 14. Principal Accounting Fees and Services. The information required by this Item is incorporated herein by reference to the Proxy Statement. 44 Item 15. Exhibits and Financial Statement Schedule. (a)(1) Financial Statements PART IV See Index to Consolidated Financial Statements on page F-1 of this Report. (a)(2) Financial Statement Schedule Schedule II — Valuation and qualifying accounts is filed herewith on page S-1. All other financial statement schedules have been omitted because they are not applicable or the information required therein is included elsewhere in the financial statements or notes thereto. (a)(3) Exhibits The following exhibits are filed herewith or incorporated by reference herein. 2.1 2.2 2.3 3.1 3.2 3.3 3.4 10.1 10.2 Asset Purchase Agreement dated July 2, 2010 by and among Patterson-UTI Energy, Inc., Portofino Acquisition Company (n/k/a Universal Pressure Pumping, Inc.), Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC and Key Energy Services, Inc. (filed July 6, 2010 as Exhibit 2.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). Letter Agreement dated September 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by reference). Letter Agreement dated October 1, 2010 by and among Patterson-UTI Energy, Inc., Universal Pressure Pumping, Inc., Universal Wireline, Inc., Key Energy Services, Inc., Key Energy Pressure Pumping Services, LLC, and Key Electric Wireline Services LLC (filed November 1, 2010 as Exhibit 2.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010 and incorporated herein by reference). Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference). Amendment to Restated Certificate of Incorporation, as amended (filed August 9, 2004 as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference). Certificate of Elimination with respect to Series A Participating Preferred Stock (filed October 27, 2011 as Exhibit 3.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). Second Amended and Restated Bylaws (filed August 6, 2007 as Exhibit 3.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 and incorporated herein by reference). Registration Rights Agreement with Bear, Stearns and Co. Inc., dated March 25, 1994, as assigned to REMY Capital Partners III, L.P. (filed March 19, 2002 as Exhibit 4.3 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001 and incorporated herein by reference). Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed July 28, 2003 as Exhibit 4.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 and incorporated herein by reference).* 45 10.3 10.4 10.5 10.6 10.7 10.8 10.9 10.10 10.11 10.12 10.13 10.14 10.15 Amendment to the Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan (filed August 9, 2004 as Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 and incorporated herein by reference).* Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, including Form of Executive Officer Restricted Stock Award Agreement, Form of Executive Officer Stock Option Agreement, Form of Non-Employee Director Restricted Stock Award Agreement and Form of Non-Employee Director Stock Option Agreement (filed June 21, 2005 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by reference).* First Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). Second Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed June 6, 2008 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference). Third Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* Fourth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed April 27, 2010 as Exhibit 10.2 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* Fifth Amendment to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q and incorporated herein by reference).* Form of Cash-Settled Performance Unit Award Agreement pursuant to the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended from time to time (filed February 19, 2010 as Exhibit 10.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 and incorporated herein by reference).* Form of Amendment to Cash-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed May 4, 2010 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2010 and incorporated herein by reference).* Form of Share-Settled Performance Unit Award Agreement under the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (filed August 2, 2010 as Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 and incorporated herein by reference).* Form of Letter Agreement regarding termination, effective as of January 29, 2004, entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Kenneth N. Berns and John E. Vollmer III (filed on February 25, 2005 as Exhibit 10.23 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference).* Letter Agreement dated February 6, 2006 between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed May 1, 2006 as Exhibit 10.25 to the Company’s Annual Report on Form 10-K, as amended, and incorporated herein by reference).* Employment Agreement, dated as of September 1, 2007 between Patterson-UTI Management Services, LLC and Douglas J. Wall (filed September 24, 2012 as Exhibit 10.1 to the Company’s Current Report on Form 8-K, and incorporated herein by reference).* 46 10.16 10.17 10.18 10.19 10.20 10.21 10.22 10.23 10.24 10.25 10.26 Employment Agreement, effective as of January 1, 2012, by and between Patterson-UTI Drilling Company LLC and James M. Holcomb (filed February 10, 2012 as Exhibit 10.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2011 and incorporated herein by reference). * Form of Indemnification Agreement entered into by Patterson-UTI Energy, Inc. with each of Mark S. Siegel, Cloyce A. Talbott, Douglas J. Wall, Kenneth N. Berns, Curtis W. Huff, Terry H. Hunt, Kenneth R. Peak, Charles O. Buckner, John E. Vollmer III, Seth D. Wexler, William Andrew Hendricks, Jr. and Michael W. Conlon (filed April 28, 2004 as Exhibit 10.11 to the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2003 and incorporated herein by reference).* Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Mark S. Siegel (filed on February 4, 2004 as Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and Kenneth N. Berns (filed on February 4, 2004 as Exhibit 10.5 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of January 29, 2004, by and between Patterson-UTI Energy, Inc. and John E. Vollmer III (filed on February 4, 2004 as Exhibit 10.7 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).* First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Mark S. Siegel, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Douglas J. Wall, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and John E. Vollmer, III, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* First Amendment to Change in Control Agreement Between Patterson-UTI Energy, Inc. and Kenneth N. Berns, entered into November 1, 2007 (filed November 5, 2007 as Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 and incorporated herein by reference).* Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of November 2, 2009, by and between Patterson-UTI Energy, Inc. and Seth D. Wexler (filed November 2, 2009 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2009 and incorporated herein by reference).* Patterson-UTI Energy, Inc. Change in Control Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William Andrew Hendricks, Jr. (filed July 30, 2012 as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and incorporated herein by reference).* 47 10.27 10.28 10.29 10.30 10.31 21.1 23.1 31.1 31.2 32.1 101 Form of Offer Letter to William Andrew Hendricks, Jr. dated March 14, 2012 (filed March 16, 2012 as Exhibit 99.3 to the Company’s Current Report on Form 8-K and incorporated herein by reference).* Severance Agreement, effective as of April 2, 2012, by and between Patterson-UTI Energy, Inc. and William A. Hendricks, Jr. (filed July 30, 2012 as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 and incorporated herein by reference).* Credit Agreement dated September 27, 2012, among Patterson-UTI Energy, Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender and each of the other letter of credit issuer and lender parties thereto (filed September 28, 2012 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). Note Purchase Agreement dated October 5, 2010 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed October 6, 2010 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). Note Purchase Agreement dated June 14, 2012 by and among Patterson-UTI Energy, Inc. and the purchasers named therein (filed June 18, 2012 as Exhibit 10.1 to the Company’s Current Report on Form 8-K and incorporated herein by reference). Subsidiaries of the Registrant.+ Consent of Independent Registered Public Accounting Firm.+ Certification of Chief Executive Officer pursuant Exchange Act of 1934, as amended.+ Certification of Chief Financial Officer pursuant Exchange Act of 1934, as amended.+ to Rule 13a-14(a)/15d-14(a) of the Securities to Rule 13a-14(a)/15d-14(a) of the Securities Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 USC Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.+ The following materials from Patterson-UTI Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Stockholders’ Equity, (v) the Consolidated Statements of Cash Flows, and (vi) Notes to Consolidated Financial Statements.+ * Management Contract or Compensatory Plan identified as required by Item 15(a)(3) of Form 10-K. + Filed herewith. 48 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2013 and 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011 . . . . . . . . . Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and Page F-2 F-3 F-4 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5 Consolidated Statements of Changes In Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Schedule II — Valuation and Qualifying Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6 F-7 F-8 S-1 F-1 Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Patterson-UTI Energy, Inc.: In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Patterson-UTI Energy, Inc. and its subsidiaries (the “Company”) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. limitations, /s/ PricewaterhouseCoopers LLP Houston, Texas February 14, 2014 F-2 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS December 31, 2013 2012 (In thousands, except share data) Current assets: ASSETS Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable, net of allowance for doubtful accounts of $3,674 and $3,513 at December 31, 2013 and 2012, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Goodwill and intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deposits on equipment purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 249,509 $ 110,723 451,517 21,248 32,952 53,424 808,650 3,635,541 167,470 52,560 22,906 465,517 26,889 52,959 43,903 699,991 3,615,383 171,463 43,776 26,298 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,687,127 $4,556,911 Current liabilities: LIABILITIES AND STOCKHOLDERS’ EQUITY Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Federal and state income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current portion of long-term debt $ 173,150 10,670 160,457 10,000 $ 188,823 6,158 158,632 6,250 Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax liabilities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 354,277 682,500 887,864 6,489 359,863 692,500 857,302 6,589 Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,931,130 1,916,254 Commitments and contingencies (see Note 8) Stockholders’ equity: Preferred stock, par value $.01; authorized 1,000,000 shares, no shares issued . . . . . . . . . Common stock, par value $.01; authorized 300,000,000 shares with 186,487,246 and 184,059,900 issued and 144,219,189 and 145,913,162 outstanding at December 31, 2013 and 2012, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Retained earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Treasury stock, at cost, 42,268,057 shares and 38,146,738 shares at December 31, 2013 — — 1,865 913,505 2,707,439 14,076 1,841 863,558 2,548,542 21,767 and 2012, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (880,888) (795,051) Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,755,997 2,640,657 Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,687,127 $4,556,911 The accompanying notes are an integral part of these consolidated financial statements. F-3 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2013 2012 2011 (In thousands, except per share data) Operating revenues: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,679,611 979,166 57,257 $1,821,713 841,771 59,930 $1,669,581 845,803 50,559 Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,716,034 2,723,414 2,565,943 Operating costs and expenses: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion, amortization and impairment . . . . . . . . . . . . . . . . . . . . . . Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net gain on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 968,754 744,243 12,909 597,469 73,852 (3,384) — 1,075,491 580,878 11,303 526,614 64,473 (33,806) 1,100 972,778 561,398 9,615 437,279 64,271 (4,999) — Total operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,393,843 2,226,053 2,040,342 Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 322,191 497,361 525,601 Other income (expense): Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 918 (28,359) 1,691 554 (22,750) 508 187 (15,652) 582 Total other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (25,750) (21,688) (14,883) Income from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . . . 296,441 475,673 510,718 Income tax expense: Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57,863 50,569 15,760 160,436 28,971 158,967 Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108,432 176,196 187,938 Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss from discontinued operations, net of income taxes . . . . . . . . . . . . . . . . . . . . . . . 188,009 — 299,477 — 322,780 (367) Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 188,009 $ 299,477 $ 322,413 Basic income per common share: Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss from discontinued operations, net of income taxes . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted income per common share: Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Loss from discontinued operations, net of income taxes . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted average number of common shares outstanding: $ $ $ $ $ $ 1.29 0.00 1.29 1.28 0.00 1.28 $ $ $ $ $ $ 1.96 0.00 1.96 1.96 0.00 1.96 $ $ $ $ $ $ 2.08 0.00 2.08 2.06 0.00 2.06 Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144,356 151,144 153,871 Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145,303 151,699 155,304 Cash dividends per common share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 0.20 $ 0.20 $ 0.20 The accompanying notes are an integral part of these consolidated financial statements. F-4 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other comprehensive income, net of taxes of $0 for 2013, $0 for 2012 and $0 Year Ended December 31, 2013 2012 2011 (In thousands) $188,009 $299,477 $322,413 for 2011: Foreign currency translation adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,691) 2,308 (2,138) Total comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $180,318 $301,785 $320,275 The accompanying notes are an integral part of these consolidated financial statements. F-5 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY Common Stock Number of Shares Amount Additional Paid-in Capital Retained Earnings Accumulated Other Comprehensive Income Treasury Stock Total Balance, December 31, 2010 . . . . . . 181,538 — Net income . . . . . . . . . . . . . . . . . . . . Foreign currency translation adjustment . . . . . . . . . . . . . . . . . . Issuance of restricted stock . . . . . . . Vesting of restricted stock units . . . Forfeitures of restricted stock . . . . . Exercise of stock options . . . . . . . . . Stock-based compensation . . . . . . . . Tax benefit related to stock-based compensation . . . . . . . . . . . . . . . . Payment of cash dividends . . . . . . . Purchase of treasury stock . . . . . . . . — 782 10 (83) 1,048 — — — — Balance, December 31, 2011 . . . . . . 183,295 Net income . . . . . . . . . . . . . . . . . . . . — Foreign currency translation (In thousands) 1,815 — 796,641 1,987,999 — 322,413 21,597 — (620,445) 2,187,607 — 322,413 — — (8) 8 — — 1 (1) 11 16,800 — 20,904 — — — — — — — — — 6,393 — — (31,045) — — (2,138) — — — — — — — — — — — — — — (2,138) — — — 16,811 20,904 — — (4,314) 6,393 (31,045) (4,314) 1,833 — 840,731 2,279,367 — 299,477 19,459 — (624,759) 2,516,631 — 299,477 adjustment . . . . . . . . . . . . . . . . . . Issuance of restricted stock . . . . . . . Vesting of restricted stock units . . . Forfeitures of restricted stock . . . . . Exercise of stock options . . . . . . . . . Stock-based compensation . . . . . . . . Tax expense related to stock-based compensation . . . . . . . . . . . . . . . . Payment of cash dividends . . . . . . . Purchase of treasury stock . . . . . . . . — 792 8 (99) 64 — — — — — — (8) 8 — — 1 (1) 1 933 — 23,185 — — — — — — — (1,284) — — — — (30,302) — — 2,308 — — — — — — — — — — — — — — 2,308 — — — 934 23,185 — — (170,292) (1,284) (30,302) (170,292) Balance, December 31, 2012 . . . . . . 184,060 $1,841 $863,558 $2,548,542 Net income . . . . . . . . . . . . . . . . . . . . — 188,009 Foreign currency translation — — $21,767 — $(795,051) $2,640,657 — 188,009 adjustment . . . . . . . . . . . . . . . . . . Issuance of restricted stock . . . . . . . Vesting of restricted stock units . . . Forfeitures of restricted stock . . . . . Exercise of stock options . . . . . . . . . Stock-based compensation . . . . . . . . Tax benefit related to stock-based compensation . . . . . . . . . . . . . . . . Payment of cash dividends . . . . . . . Purchase of treasury stock . . . . . . . . — 1,312 9 (84) 1,190 — — — — — — (13) 13 — — 1 (1) 19,274 12 — 25,891 — — — — — — (7,691) — — — — — — — — — — — (7,691) — — — 19,286 25,891 — — — 4,794 — — (29,112) — — — — — — — (85,837) 4,794 (29,112) (85,837) Balance, December 31, 2013 . . . . . . 186,487 $1,865 $913,505 $2,707,439 $14,076 $(880,888) $2,755,997 The accompanying notes are an integral part of these consolidated financial statements. F-6 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2013 2012 2011 (In thousands) Cash flows from operating activities: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjustments to reconcile net income to net cash provided by operating activities: $ 188,009 $ 299,477 $ 322,413 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion, amortization and impairment Provision for bad debts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dry holes and abandonments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stock-based compensation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net gain on asset disposals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tax expense related to stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in operating assets and liabilities: Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income taxes receivable/payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Inventory and other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash used in operating activities of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . 597,469 — 89 50,569 25,891 (3,384) — 12,007 4,447 570 11,331 1,973 (100) — 526,614 1,100 308 160,436 23,185 (33,806) (1,284) 52,612 3,506 5,276 (25,199) (6,048) (837) — 437,279 — 1,213 158,967 20,904 (4,999) — (183,165) 77,618 (13,491) 41,995 18,313 (8,111) (339) Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 888,871 1,005,340 868,597 Cash flows from investing activities: Purchases of property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net cash provided by investing activities of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . (662,461) 10,386 — (973,988) 66,027 — (1,011,578) 22,495 25,500 Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (652,075) (907,961) (963,583) Cash flows from financing activities: Purchases of treasury stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tax benefit related to stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from borrowings under revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of borrowings under revolving credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from exercise of stock options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (73,510) (29,112) 4,794 — (6,250) — — — 6,959 (170,292) (30,302) — 400,000 (93,750) 123,400 (233,400) (7,581) 934 (4,314) (31,045) 6,393 — (6,250) 153,100 (43,100) — 16,811 Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (97,119) (10,991) 91,595 Effect of foreign exchange rate changes on cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (891) 389 Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138,786 110,723 86,777 23,946 (275) (3,666) 27,612 Cash and cash equivalents at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 249,509 $ 110,723 $ 23,946 Supplemental disclosure of cash flow information: Net cash (paid) received during the year for: Interest, net of capitalized interest of $7,775 in 2013, $8,673 in 2012 and $8,415 in 2011 . . . . Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (26,228) $ (16,651) $ (42,600) (7,964) Non-cash investing and financing activities: Net increase (decrease) in payables for purchases of property and equipment . . . . . . . . . . Net (increase) decrease in deposits on equipment purchases . . . . . . . . . . . . . . . . . . . . . . . . $ (26,899) $ (27,838) $ (8,784) 55,767 (13,177) 59,251 37,838 (48,459) The accompanying notes are an integral part of these consolidated financial statements. F-7 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Description of Business and Summary of Significant Accounting Policies A description of the business and basis of presentation follows: Description of business — Patterson-UTI Energy, Inc., through its wholly-owned subsidiaries (collectively referred to herein as “Patterson-UTI” or the “Company”), provides onshore contract drilling services to major and independent oil and natural gas operators in the continental United States, Alaska and western and northern Canada. The Company provides pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. The Company also invests in oil and natural gas properties on a non-operating working interest basis. Basis of presentation — The consolidated financial statements include the accounts of Patterson-UTI and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Except for wholly-owned subsidiaries, the Company has no controlling financial interests in any other entity which would require consolidation. The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which use the Canadian dollar as its functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity. A summary of the significant accounting policies follows: Management estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates. Revenue recognition — Revenues from daywork drilling and pressure pumping activities are recognized as services are performed. Expenditures reimbursed by customers are recognized as revenue and the related expenses are recognized as direct costs. All of the wells the Company drilled in 2013, 2012 and 2011 were drilled under daywork contracts. Accounts receivable — Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts represents the Company’s estimate of the amount of probable credit losses existing in the Company’s accounts receivable. The Company reviews the adequacy of its allowance for doubtful accounts at least quarterly. Significant individual accounts receivable balances and balances which have been outstanding greater than 90 days are reviewed individually for collectability. Account balances, when determined to be uncollectable, are charged against the allowance. Inventories — Inventories consist primarily of sand and other products to be used in conjunction with the Company’s pressure pumping activities. The inventories are stated at the lower of cost or market, determined by the first-in, first-out method. Property and equipment — Property and equipment is carried at cost less accumulated depreciation. Depreciation is provided on the straight-line method over the estimated useful lives. The method of depreciation does not change whenever equipment becomes idle. The estimated useful lives, in years, are shown below: Useful Lives Drilling rigs and other equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.25-15 15-20 3-12 F-8 Long-lived assets, including property and equipment, are evaluated for impairment when certain triggering events or changes in circumstances indicate that the carrying values may not be recoverable over their estimated remaining useful life. Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. Costs of exploratory wells are initially capitalized to wells-in- progress until the outcome of the drilling is known. The Company reviews wells-in-progress quarterly to determine whether sufficient progress is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, the Company considers the well costs to be impaired and recognizes the costs as expense. Geological and geophysical costs, including seismic costs, and costs to carry and retain undeveloped properties are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment and intangible development costs, are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved developed oil and natural gas reserves for each respective field. Oil and natural gas leasehold acquisition costs are depreciated, depleted and amortized using the units-of-production method, based on engineering estimates of total proved oil and natural gas reserves for each respective field. The Company reviews its proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on management’s expectation of future pricing over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and fair value. The fair value estimates used in measuring impairment are based on management’s expectations of future commodity prices over the life of the respective field and the net future cash inflows from developing and operating these fields. The Company reviews unproved oil and natural gas properties quarterly to assess potential impairment. The Company’s impairment assessment is made on a lease-by-lease basis and considers factors such as management’s intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. The Company assesses impairment of its goodwill at least annually as of December 31, or on an interim basis if events or circumstances indicate that the fair value of goodwill may have decreased below its carrying value. Maintenance and repairs — Maintenance and repairs are charged to expense when incurred. Renewals and betterments which extend the life or improve existing property and equipment are capitalized. Disposals — Upon disposition of property and equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statement of operations. Net income per common share — The Company provides a dual presentation of its net income per common share in its consolidated statements of operations: Basic net income per common share (“Basic EPS”) and diluted net income per common share (“Diluted EPS”). Basic EPS excludes dilution and is computed by first allocating earnings between common stockholders and holders of non-vested shares of restricted stock. Basic EPS is then determined by dividing the earnings attributable to common stockholders by the weighted average number of common shares outstanding during the period, excluding non-vested shares of restricted stock. Diluted EPS is based on the weighted average number of common shares outstanding plus the dilutive effect of potential common shares, including stock options, non-vested shares of restricted stock and restricted stock units. The dilutive effect of stock options and restricted stock units is determined using the treasury stock F-9 method. The dilutive effect of non-vested shares of restricted stock is based on the more dilutive of the treasury stock method or the two-class method, assuming a reallocation of undistributed earnings to common stockholders after considering the dilutive effect of potential common shares other than non-vested shares of restricted stock. The following table presents information necessary to calculate income from continuing operations per share, loss from discontinued operations per share and net income per share for the years ended December 31, 2013, 2012 and 2011, as well as potentially dilutive securities excluded from the weighted average number of diluted common shares outstanding because their inclusion would have been anti-dilutive (in thousands, except per share amounts): BASIC EPS: Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . Adjust for income attributed to holders of non-vested 2013 2012 2011 $188,009 $299,477 $322,780 restricted stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,859) (2,532) (2,545) Income from continuing operations attributed to common stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $186,150 $296,945 $320,235 Loss from discontinued operations, net . . . . . . . . . . . . . . . . . . . . Adjust for loss attributed to holders of non-vested restricted $ — $ — $ (367) stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — — 3 Loss from discontinued operations attributed to common stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ (364) Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock . . . . . . . . . . . . 144,356 151,144 153,871 Basic income from continuing operations per common share . . . Basic loss from discontinued operations per common share . . . . Basic net income per common share . . . . . . . . . . . . . . . . . . . . . . $ $ $ 1.29 0.00 1.29 $ $ $ 1.96 0.00 1.96 $ $ $ 2.08 0.00 2.08 DILUTED EPS: Income from continuing operations attributed to common stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $186,150 $296,945 $320,235 Weighted average number of common shares outstanding, excluding non-vested shares of restricted stock . . . . . . . . . . . . Add dilutive effect of potential common shares . . . . . . . . . . . 144,356 947 151,144 555 153,871 1,433 Weighted average number of diluted common shares outstanding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145,303 151,699 155,304 Diluted income from continuing operations per common share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted loss from discontinued operations per common share . . Diluted net income per common share . . . . . . . . . . . . . . . . . . . . . Potentially dilutive securities excluded as anti-dilutive . . . . . . . . $ $ $ 1.28 0.00 1.28 2,447 $ $ $ 1.96 0.00 1.96 5,416 $ $ $ 2.06 0.00 2.06 1,641 Income taxes — The asset and liability method is used in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carryforwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. If applicable, a valuation allowance is F-10 recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that such assets will be realized. The Company’s policy is to account for interest and penalties with respect to income taxes as operating expenses. Stock-based compensation — The Company recognizes the cost of share-based payments under the fair- value-based method. Under this method, compensation cost related to share-based payments is measured based on the estimated fair value of the awards at the date of grant, net of estimated forfeitures. This expense is recognized over the expected life of the awards (See Note 10). Statement of cash flows — For purposes of reporting cash flows, cash and cash equivalents include cash on deposit and money market funds. Recently Issued Accounting Standards — In February 2013, the FASB issued an accounting standards update that requires additional disclosures regarding reclassifications out of accumulated other comprehensive income. This requirement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012, and became effective for the Company in the quarter ended March 31, 2013. The adoption of this update did not have a material impact on the Company’s disclosures included in its consolidated financial statements. The Company includes in accumulated other comprehensive income the cumulative translation adjustment of its foreign subsidiary. In February 2013, the FASB issued an accounting standards update to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation within the scope of the update is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. The guidance requires an entity to measure those obligations as the sum of the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and any additional amount the reporting entity expects to pay on behalf of its co-obligors. The update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. The requirements in this update are effective during interim and annual periods beginning after December 15, 2013. The adoption of this update is not expected to have a material impact on the Company’s consolidated financial statements. 2. Discontinued Operations On January 27, 2011, the stock of the Company’s electric wireline subsidiary, Universal Wireline, Inc., was sold in a cash transaction for $25.5 million. Except for inventory, the working capital of Universal Wireline, Inc. was excluded from the sale and retained by a subsidiary of the Company. Universal Wireline, Inc. was formed in 2010 to acquire an electric wireline business. The results of operations of this business have been presented as results of discontinued operations in these consolidated financial statements. As of December 31, 2010, the assets to be disposed of were classified as held for sale. Upon being classified as held for sale, the assets to be disposed of were recorded at fair value less estimated costs to sell resulting in a charge of $2.2 million. Due to the fact that the carrying value of the assets had been adjusted to net realizable value, no significant additional gain or loss was recognized in connection with the sale. Summarized operating results from discontinued operations for the year ended December 31, 2011 are shown below (in thousands): 2011 Operating revenues from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,104 Loss from discontinued operations before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax benefit $ (576) 209 Loss from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (367) F-11 3. Property and Equipment Property and equipment consisted of the following at December 31, 2013 and 2012 (in thousands): 2013 2012 Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,749,975 183,571 80,050 12,054 $ 5,387,490 156,834 66,490 10,413 Less accumulated depreciation and depletion . . . . . . . . . . . . . . . . . . . . . 6,025,650 (2,390,109) 5,621,227 (2,005,844) Property and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,635,541 $ 3,615,383 Depreciation, depletion, amortization and impairment — The following table summarizes depreciation, depletion, amortization and impairment expense related to property and equipment and intangible assets for 2013, 2012 and 2011 (in thousands): 2013 2012 2011 Depreciation and impairment expense . . . . . . . . . . . . . . . . . . . . . Amortization expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Depletion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $573,106 3,993 20,370 $502,953 4,110 19,551 $419,183 4,110 13,986 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $597,469 $526,614 $437,279 The Company evaluates the recoverability of its long-lived assets whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable (a “triggering event”). In light of levels of activity and revenue per operating day experienced by the Company and its peers in 2011, 2012 and 2013, management concluded that no triggering event had occurred in 2011, 2012 or 2013 with respect to its contract drilling segment as a whole. The Company also concluded that no triggering event occurred with respect to its pressure pumping segment in 2011, 2012 or 2013. With respect to the long-lived assets in the Company’s oil and natural gas exploration and production segment, the Company assesses the recoverability of long-lived assets at the end of each quarter due to revisions in its oil and natural gas reserve estimates and expectations about future commodity prices. Long-lived assets are evaluated for impairment at the lowest level for which identifiable cash flows can be separated from other long-lived assets. The Company performs the first step of its impairment assessments by comparing the undiscounted cash flows for each long-lived asset or asset group to its respective carrying value. The Company’s analysis indicated that the carrying amounts of certain oil and natural gas properties were not recoverable at various testing dates in 2013, 2012 and 2011. The Company’s estimates of expected future net cash flows from impaired properties are used in measuring the fair value of such properties. The Company recorded impairment charges of $4.0 million, $1.9 million and $3.0 million in 2013, 2012 and 2011, respectively, related to its oil and natural gas properties. The Company determined the fair value of the impaired assets using internally developed unobservable inputs including future pricing and reserves (level 3 inputs in the fair value hierarchy of fair value accounting). On a periodic basis, the Company evaluates its fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling longer horizontal wells using high capacity rigs). In connection with the Company’s ongoing planning process, it evaluated its then-current fleet of marketable drilling rigs in 2013, 2012 and 2011 and identified 48, 36 and 53 rigs, during each of those years respectively, that it determined would no longer be marketed as rigs based on its assessment of estimated expenditures to bring these rigs into condition to operate in the current environment, as F-12 well as its assessment of future demand and the suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with continuing utility to the Company’s other marketed rigs were transferred to other rigs or to its yards to be used as spare equipment. The remaining components of these rigs were retired. The net book values of these assets of $7.9 million in 2013, $5.2 million in 2012 and $15.7 million in 2011 were expensed in the Company’s consolidated statements of operations. In 2013, due to a recent shift in customer demand away from mechanically powered drilling rigs to electric powered drilling rigs, the Company recorded in its consolidated statement of operations a charge of $29.9 million related to 55 mechanical rigs that were not under contract. Although these 55 rigs remain marketable, the Company has lower expectations with respect to utilization of these rigs due to the industry shift to electric powered drilling rigs. There were no similar charges in 2012 or 2011. The Company also evaluates its fleet of marketable pressure pumping equipment and in 2012 identified approximately 37,000 horsepower of pressure pumping equipment that would be retired. The net book value of these assets of $7.3 million was expensed in the Company’s consolidated statements of operations. There were no similar charges in 2013 or 2011. During 2012, the Company sold its flowback operations in a cash transaction. The sale price was $42.5 million and the Company recognized a gain on disposal of $22.6 million. Also during 2012, the Company sold at auction certain excess drilling assets. The total sale price was $10.6 million, and the Company recognized a gain on disposal of $4.5 million. 4. Goodwill and Intangible Assets Goodwill — Goodwill by operating segment as of December 31, 2013 and 2012 and changes for the years then ended are as follows (in thousands): Balance December 31, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes to goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance December 31, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes to goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Contract Drilling Pressure Pumping $86,234 — 86,234 — $67,575 — 67,575 — Total $153,809 — 153,809 — Balance December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $86,234 $67,575 $153,809 There were no accumulated impairment losses as of December 31, 2013 or 2012. Goodwill is evaluated at least annually on December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. The Company’s reporting units for impairment testing have been determined to be its operating segments. The Company first determines whether it is more likely than not that the fair value of a reporting unit is less than its carrying value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. From time to time, the Company may perform the first step of quantitative testing for goodwill impairment in lieu of performing a qualitative assessment. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall. In connection with its annual goodwill impairment assessment as of December 31, 2012, the Company determined based on an assessment of qualitative factors that it was more likely than not that the fair values of F-13 the Company’s reporting units were greater than their carrying amounts and further testing was not necessary. In making this determination, the Company considered the continued demand experienced during 2012 for its services in the contract drilling and pressure pumping businesses. The Company also considered the then current and expected levels of commodity prices for crude oil and natural gas, which influence its overall level of business activity in these operating segments. Additionally, operating results for 2012 and forecasted operating results for 2013 were also taken into account. The Company’s overall market capitalization and the large amount of calculated excess of the fair values of the Company’s reporting units over their carrying values and lack of significant changes in the key assumptions from its 2010 quantitative Step 1 assessment of goodwill were also considered. The Company performed a quantitative impairment assessment of its goodwill as of December 31, 2013. In completing the first step of the analysis, the Company used a three-year projection of discounted cash flows, plus a terminal value determined using the constant growth method to estimate the fair value of the reporting units. In developing this fair value estimate, the Company applied key assumptions including an assumed discount rate of 11.87% for the contract drilling reporting unit and an assumed discount rate of 12.40% for the pressure pumping reporting unit. An assumed long-term growth rate of 3.00% was used for both reporting units. Based on the results of the first step of the impairment test in 2013, the Company concluded that no impairment was indicated in its contract drilling or pressure pumping reporting units as the estimated fair value of each reporting unit exceeded its carrying value. The Company has undertaken extensive efforts in the past several years to upgrade its fleet of equipment and believes that it is well positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional vertical wells that has resulted primarily from low natural gas prices. In the event that market conditions weaken, the Company may be required to record an impairment of goodwill in its contract drilling or pressure pumping reporting units in the future, and such impairment could be material. Intangible Assets — Intangible assets were recorded in the pressure pumping operating segment in connection with the fourth quarter 2010 acquisition of the assets of a pressure pumping business. As a result of the purchase price allocation, the Company recorded intangible assets related to a non-compete agreement and the customer relationships acquired. These intangible assets were recorded at fair value on the date of acquisition. The non-compete agreement had a term of three years from October 1, 2010. The value of this agreement was estimated using a with and without scenario where cash flows were projected through the term of the agreement assuming the agreement is in place and compared to cash flows assuming the non-compete agreement was not in place. The intangible asset associated with the non-compete agreement was amortized on a straight- line basis over the three-year term of the agreement. Amortization expense of $350,000, $467,000 and $467,000 was recorded in the years ended December 31, 2013, 2012 and 2011, respectively, associated with the non- compete agreement. The value of the customer relationships was estimated using a multi-period excess earnings model to determine the present value of the projected cash flows associated with the customers in place at the time of the acquisition and taking into account a contributory asset charge. The resulting intangible asset is being amortized on a straight-line basis over seven years. Amortization expense of $3.6 million was recorded in each of the years ended December 31, 2013, 2012 and 2011, associated with customer relationships. For both the non-compete agreement and the customer relationships, the Company concluded no triggering events necessitating an impairment assessment had occurred in 2013, 2012 or 2011. F-14 The following table presents the gross carrying amount and accumulated amortization of intangible assets as of December 31, 2013 and 2012 (in thousands): 2013 2012 Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Non-compete agreement . . . . . . . . . . . . . . . Customer relationships . . . . . . . . . . . . . . . . $ 1,400 25,500 $ (1,400) (11,839) $ — $ 1,400 25,500 13,661 $(1,050) (8,196) Net Carrying Amount $ 350 17,304 Total intangible assets . . . . . . . . . . . . . . . . $26,900 $(13,239) $13,661 $26,900 $(9,246) $17,654 5. Accrued Expenses Accrued expenses consisted of the following at December 31, 2013 and 2012 (in thousands): Salaries, wages, payroll taxes and benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . Workers’ compensation liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Property, sales, use and other taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Insurance, other than workers’ compensation . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred revenue — current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 2012 $ 45,836 74,975 12,367 10,129 7,604 — 9,546 $ 55,430 68,441 9,749 10,419 7,664 1,523 5,406 $160,457 $158,632 Deferred revenue was recorded in 2010 in the purchase price allocation associated with the Company’s acquisition of a pressure pumping business. The deferred revenue related to out-of-market pricing agreements that were in place at the acquired business at the time of the acquisition. The deferred revenue was recognized as pressure pumping revenue over the remaining term of the pricing agreements, which have now expired. Deferred revenue of approximately $1.5 million, $7.2 million and $8.4 million was recognized in the years ended December 31, 2013, 2012 and 2011, respectively, related to these pricing agreements. 6. Asset Retirement Obligation The Company records a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. This liability is included in the caption “other” in the liabilities section of the consolidated balance sheet. The following table describes the changes to the Company’s asset retirement obligations during 2013 and 2012 (in thousands): Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities incurred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Liabilities settled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revision in estimated costs of plugging oil and natural gas wells . . . . . . . . . . . . . . 2013 2012 $4,422 375 (126) 166 — $3,455 418 (150) 163 536 Asset retirement obligation at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,837 $4,422 F-15 7. Long Term Debt Credit Facilities — On August 19, 2010, the Company entered into a committed senior unsecured Credit Agreement (the “2010 Credit Agreement”) which included a revolving credit facility that permitted aggregate borrowings of up to $400 million and a $100 million term loan facility. The term loan facility was fully drawn on installments commencing August 19, 2010. The term loan facility was payable in quarterly principal November 10, 2010. The installment amounts were scheduled to vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments and 5.00% of the original principal amount for the next subsequent three quarterly installments, with the balance due on the maturity date of August 19, 2014. The outstanding balance of the term loan facility was paid in full on June 14, 2012. On September 27, 2012, the Company entered into a Credit Agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A., as administrative agent, letter of credit issuer, swing line lender and lender, and each of the other lenders party thereto. The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The Credit Agreement replaced the 2010 Credit Agreement. The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time. The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments, which commenced December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments. Subject to customary conditions, the Company may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility. Loans under the Credit Agreement bear interest by reference, at the Company’s election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon the Company’s debt to capitalization ratio. As of December 31, 2013, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by the Company equal to the applicable margin for LIBOR rate loans times the amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%. Each domestic subsidiary of the Company other than immaterial subsidiaries has unconditionally guaranteed all existing and future indebtedness and liabilities of the other guarantors and the Company arising under the Credit Agreement and other loan documents. Such guarantees also cover obligations of the Company and any subsidiary of the Company arising under any interest rate swap contract with any person while such person is a lender under the Credit Agreement. The Credit Agreement requires compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for F-16 the same period. The Company was in compliance with these covenants at December 31, 2013. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require the Company to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy of the Company, such acceleration is automatic), and (iii) require the Company to cash collateralize any outstanding letters of credit. As of December 31, 2013, the Company had $92.5 million principal amount outstanding under the term loan facility at an interest rate of 2.50% and no amounts outstanding under the revolving credit facility. The Company had $39.8 million in letters of credit outstanding at December 31, 2013 and, as a result, had available borrowing capacity of approximately $460 million at that date. Senior Notes — On October 5, 2010, the Company completed the issuance and sale of $300 million in aggregate principal amount of its 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. The Company will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020. On June 14, 2012, the Company completed the issuance and sale of $300 million in aggregate principal amounts of its 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. The Company will pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022. The Series A Notes and Series B Notes are senior unsecured obligations of the Company which rank equally in right of payment with all other unsubordinated indebtedness of the Company. The Series A Notes and Series B Notes are guaranteed on a senior unsecured basis by each of the existing domestic subsidiaries of the Company other than immaterial subsidiaries. The Series A Notes and Series B Notes are prepayable at the Company’s option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. The Company must offer to prepay the notes upon the occurrence of any change of control. In addition, the Company must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date. The respective note purchase agreements require compliance with two financial covenants. The Company must not permit its debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. The Company also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior fiscal quarters to interest charges for the same period. The Company was in compliance with these covenants at December 31, 2013. Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective F-17 notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable. The Company incurred approximately $10.8 million in debt issuance costs during 2010 in connection with the 2010 Credit Agreement and the Series A Notes. The Company incurred approximately $7.6 million in debt issuance costs during 2012 in connection with the Series B Notes and the Credit Agreement. These costs were deferred and are recognized as interest expense over the term of the underlying debt. Interest expense related to the amortization of debt issuance costs for the 2010 Credit Agreement, the Series A Notes, the Series B Notes and the Credit Agreement was approximately $2.2 million, $3.4 million and $2.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. The amount for the year ended December 31, 2012 includes $978,000 of costs related to the early termination of the 2010 Credit Agreement. Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of December 31, 2013 (in thousands): Year ending December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 10,000 12,500 28,750 41,250 — 600,000 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $692,500 8. Commitments, Contingencies and Other Matters Commitments — As of December 31, 2013, the Company maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2013, no amounts had been drawn under the letters of credit. As of December 31, 2013, the Company had commitments to purchase approximately $225 million of major equipment for its drilling and pressure pumping businesses. The Company’s pressure pumping business has entered into agreements to purchase minimum quantities of proppants and chemicals from certain vendors. These agreements expire in 2016 and 2017. As of December 31, 2013, the remaining obligation under these agreements was approximately $25.2 million, of which materials with a total purchase price of approximately $7.7 million are expected to be delivered during 2014. In the event that the required minimum quantities are not purchased during any contract year, the Company could be required to make a liquidated damages payment to the respective vendor for any shortfall. In November 2011, the Company’s pressure pumping business entered into an agreement with a proppant vendor to advance up to $12.0 million to such vendor to finance the construction of certain processing facilities. This advance is secured by the underlying processing facilities and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2013, advances of approximately $11.8 million had been made under this agreement and repayments of approximately $2.6 had been received resulting in a balance outstanding of approximately $9.2 million. Contingencies — In May 2013, the U.S. Equal Employment Opportunity Commission notified the Company of cause findings related to certain of its employment practices. The cause findings relate to allegations that the Company tolerated a hostile work environment for employees based on national origin and race. The cause F-18 findings also allege, among other things, failure to promote, subjecting employees to adverse employment terms and conditions and retaliation. The Company and the EEOC are engaged in the statutory conciliation process. If such conciliation process is unsuccessful, the Company believes that litigation will ensue. The Company intends to defend itself vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome of this matter to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of this matter. The Company’s operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution 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 the Company to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages. Any contractual right to indemnification that the Company may have for any such risk, may be unenforceable or limited due to negligent or willful acts of commission or omission by the Company, its subcontractors and/or suppliers. The Company’s customers may dispute, or be unable to meet, their contractual indemnification obligations to the Company due to financial, legal or other reasons. Accordingly, the Company may be unable to transfer these risks to its customers by contract or indemnification agreements. Incurring a liability for which the Company is not fully indemnified or insured could have a material adverse effect on its business, financial condition, cash flows and results of operations. The Company has insurance coverage for comprehensive general liability, automobile liability, workers’ compensation and employer’s liability, and certain other specific risks. The Company has also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, the Company generally maintains a $1.0 million per occurrence deductible on its workers’ compensation and equipment insurance coverages and a $2.0 million per occurrence self-insured retention on its general liability and automobile liability insurance coverage. The Company self-insures a number of other risks, including loss of earnings and business interruption, and does not carry a significant amount of insurance to cover risks of underground reservoir damage. If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could have a material adverse effect on the Company’s business, financial condition, cash flows and results of operations. Accrued expenses related to insurance claims are set forth in Note 5. The Company is party to various legal proceedings arising in the normal course of its business. The Company does not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on its financial condition, results of operations or cash flows. Other Matters — The Company has Change in Control Agreements with its Chairman of the Board, Chief Executive Officer, two Senior Vice Presidents and its General Counsel (the “Key Employees”). Each Change in Control Agreement generally has an initial term with automatic twelve-month renewals unless the Company notifies the Key Employee at least ninety days before the end of such renewal period that the term will not be extended. If a change in control of the Company occurs during the term of the agreement and the Key Employee’s employment is terminated (i) by the Company other than for cause or other than automatically as a result of death, disability or retirement, or (ii) by the Key Employee for good reason (as those terms are defined in the Change in Control Agreements), then the Key Employee shall generally be entitled to, among other things: • a bonus payment equal to the highest bonus paid after the Change in Control Agreement was entered into (such bonus payment for each Key Employee prorated for the portion of the fiscal year preceding the termination date); • a payment equal to 2.5 times (in the case of the Chairman of the Board and Chief Executive Officer), 2 times (in the case of the Senior Vice Presidents) or 1.5 times (in the case of the General Counsel) of the sum of (i) the highest annual salary in effect for such Key Employee and (ii) the average of the three F-19 annual bonuses earned by the Key Employee for the three fiscal years preceding the termination date (or a benchmark bonus in the case of the Chief Executive Officer); and • continued coverage under the Company’s welfare plans for up to three years (in the case of the Chairman of the Board and Chief Executive Officer) or two years (in the case of the Senior Vice Presidents and General Counsel). Other than with respect to the Chief Executive Officer, each Change in Control Agreement provides the Key Employee with a full gross-up payment for any excise taxes imposed on payments and benefits received under the Change in Control Agreements or otherwise, including other taxes that may be imposed as a result of the gross-up payment. 9. Stockholders’ Equity Cash Dividends — The Company paid cash dividends during the years ended December 31, 2011, 2012 and 2013 as follows: Per Share Total (in thousands) 2011: Paid on March 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on June 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on September 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on December 30, 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2012: Paid on March 30, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on June 29, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on September 28, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on December 28, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2013: Paid on March 29, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on June 28, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on September 30, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Paid on December 31, 2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0.05 0.05 0.05 0.05 $0.20 $0.05 0.05 0.05 0.05 $0.20 $0.05 0.05 0.05 0.05 $0.20 $ 7,708 7,772 7,777 7,788 $31,045 $ 7,788 7,650 7,518 7,346 $30,302 $ 7,312 7,361 7,231 7,208 $29,112 On February 5, 2014, the Company’s Board of Directors approved a cash dividend on its common stock in the amount of $0.10 per share to be paid on March 27, 2014 to holders of record as of March 12, 2014. 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 the Company’s credit facilities and other factors. On August 1, 2007, the Company’s Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of the Company’s common stock in open market or privately negotiated transactions. On July 25, 2012, the Company’s Board of Directors terminated the remaining authority under the 2007 stock buyback program, and approved a new stock buyback program authorizing purchases of up to $150 million of common stock in open market or privately negotiated transactions. On September 6, 2013, the F-20 Company’s Board of Directors terminated any remaining authority under the 2012 stock buyback program, and approved a new stock buyback program that authorizes purchase of up to $200 million of the Company’s common stock in open market or privately negotiated transactions. As of December 31, 2013, the Company had remaining authorization to purchase approximately $187 million of the Company’s outstanding common stock under the new stock buyback program. Shares purchased under a buyback program are accounted for as treasury stock. The Company acquired shares of stock from employees during 2013, 2012 and 2011 that are accounted for as treasury stock. Certain of these shares were acquired to satisfy the exercise price in connection with the exercise of stock options by employees. The remainder of these shares was acquired to satisfy payroll tax withholding obligations upon the exercise of stock options, the settlement of performance unit awards and the vesting of restricted stock. These shares were acquired at fair market value. These acquisitions were made pursuant to the terms of the Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan (the “2005 Plan”) and not pursuant to the stock buyback program. Treasury stock acquisitions during the years ended December 31, 2013, 2012 and 2011 were as follows (dollars in thousands): 2013 2012 2011 Shares Cost Shares Cost Shares Cost Treasury shares at beginning of period . . . . 38,146,738 $795,051 27,487,571 $624,759 27,343,814 $620,445 Purchases pursuant to stock buyback programs: 2007 program . . . . . . . . . . . . . . . . . . . . . . 2012 program . . . . . . . . . . . . . . . . . . . . . . 2013 program . . . . . . . . . . . . . . . . . . . . . . Acquisitions Pursuant to the 2005 Long- — 2,567,266 602,564 — 4,708,784 51,107 5,863,451 — 12,517 70,092 98,892 — 8,689 — — 255 — — Term Incentive Plan . . . . . . . . . . . . . . . . . 951,489 22,213 86,932 1,308 135,068 4,059 Treasury shares at end of period . . . . . . . . . 42,268,057 $880,888 38,146,738 $795,051 27,487,571 $624,759 10. Stock-based Compensation The Company uses share-based payments to compensate employees and non-employee directors. The Company recognizes the cost of share-based payments under the fair-value-based method. Share-based awards consist of equity instruments in the form of stock options, restricted stock or restricted stock units and have included service and, in certain cases, performance conditions. The Company’s share-based awards have also included both cash-settled and share-settled performance unit awards. Cash-settled performance unit awards are accounted for as liability awards. Share-settled performance unit awards are accounted for as equity awards. The Company issues shares of common stock when vested stock options are exercised, when restricted stock is granted and when restricted stock units and share-settled performance unit awards vest. The Company’s shareholders have approved the 2005 Plan, and the Board of Directors adopted a resolution that no future grants would be made under any of the Company’s other previously existing plans. The Company’s share-based compensation plans at December 31, 2013 follow: Plan Name Shares Authorized for Grant Awards Outstanding Shares Available for Grant Patterson-UTI Energy, Inc. 2005 Long-Term Incentive Plan, as amended . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,250,000 8,026,643 274,071 Patterson-UTI Energy, Inc. Amended and Restated 1997 Long-Term Incentive Plan, as amended (“1997 Plan”) . . . . — 810,000 — F-21 A summary of the 2005 Plan follows: • The Compensation Committee of the Board of Directors administers the plan. • All employees, officers and directors are eligible for awards. • The Compensation Committee determines the vesting schedule for awards. Awards typically vest over one year for non-employee directors and three years for employees. • The Compensation Committee sets the term of awards and no option term can exceed 10 years. • All options granted under the plan are granted with an exercise price equal to or greater than the fair market value of the Company’s common stock at the time the option is granted. • The plan provides for awards of incentive stock options, non-incentive stock options, tandem and freestanding stock appreciation rights, restricted stock awards, other stock unit awards, performance share awards, performance unit awards and dividend equivalents. As of December 31, 2013, non-incentive stock options, restricted stock awards, restricted stock units and performance unit awards had been granted under the plan. Options granted under the 1997 Plan typically vested over three or five years as dictated by the Compensation Committee. These options have terms of no more than ten years. All options were granted with an exercise price equal to the fair market value of the related common stock at the time of grant. Restricted stock awards granted under the 1997 Plan typically vested over four years. Stock Options — The Company estimates the grant date fair values of stock options using the Black- Scholes-Merton valuation model. Volatility assumptions are based on the historic volatility of the Company’s common stock over the most recent period equal to the expected term of the options as of the date the options are granted. The expected term assumptions are based on the Company’s experience with respect to employee stock option activity. Dividend yield assumptions are based on the expected dividends at the time the options are granted. The risk-free interest rate assumptions are determined by reference to United States Treasury yields. Weighted-average assumptions used to estimate grant date fair values for stock options granted in the years ended December 31, 2013, 2012 and 2011 follow: 2013 2012 2011 Volatility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expected term (in years) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dividend yield . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk-free interest rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41.36% 48.79% 45.97% 5.00 5.00 0.89% 1.21% 0.67% 0.70% 0.87% 2.34% 5.00 Stock option activity for the year ended December 31, 2013 follows: Outstanding at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cancelled . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shares 7,827,195 692,500 (1,190,000) (10,000) — Outstanding at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,319,695 Exercisable at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,250,860 Weighted-average exercise price $20.35 $22.51 $16.21 $18.63 — $21.23 $21.29 During 2013, the Company acquired 637,624 shares of treasury stock from employees upon the exercise of stock options. Shares having a market value of $12.3 million were withheld from employees and added to treasury stock to satisfy the exercise price in connection with the exercise of the stock options. Shares having a F-22 market value of $2.9 million were withheld from employees and added to treasury stock to satisfy payroll tax withholding obligations upon the exercise of the stock options. Options outstanding at December 31, 2013 have an aggregate intrinsic value of approximately $37 million and a weighted-average remaining contractual term of 5.10 years. Options exercisable at December 31, 2013 have an aggregate intrinsic value of approximately $32 million and a weighted-average remaining contractual term of 4.45 years. Additional information with respect to options granted, vested and exercised during the years ended December 31, 2013, 2012 and 2011 follows: 2013 2012 2011 Weighted-average grant date fair value of stock options granted (per share) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aggregate grant date fair value of stock options vested during the year (in thousands) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aggregate intrinsic value of stock options exercised (in thousands) . . . $ 7.59 $ 6.37 $ 12.24 $5,240 $8,683 $5,512 $ 138 $ 5,639 $12,663 As of December 31, 2013, options to purchase 1.1 million shares were outstanding and not vested. All of these non-vested options are expected to ultimately vest. Additional information as of December 31, 2013 with respect to these non-vested options follows: Aggregate intrinsic value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted-average remaining contractual term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted-average remaining expected term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted-average remaining vesting period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrecognized compensation cost $5.0 million 8.90 years 3.90 years 1.81 years $6.3 million Restricted Stock — For all restricted stock awards to date, shares of common stock were issued when the awards were made. Non-vested shares are subject to forfeiture for failure to fulfill service conditions and, in certain cases, performance conditions. Non-forfeitable dividends are paid on non-vested shares of restricted stock. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period. Restricted stock activity for the year ended December 31, 2013 follows: Non-vested restricted stock outstanding at beginning of year . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shares 1,279,146 954,750 (653,636) (83,568) Non-vested restricted stock outstanding at end of year . . . . . . . . . . . . . . . 1,496,692 Weighted- average Grant Date Fair Value $20.03 $21.66 $20.56 $20.04 $20.84 As of December 31, 2013, approximately 1.4 million shares of non-vested restricted stock outstanding are expected to vest. Additional information as of December 31, 2013 with respect to these non-vested shares follows: Aggregate intrinsic value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted-average remaining vesting period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unrecognized compensation cost $35.5 million 1.94 years $22.5 million Restricted Stock Units — For all restricted stock unit awards made to date, shares of common stock are not issued until the units vest. Restricted stock units are subject to forfeiture for failure to fulfill service conditions. Non-forfeitable cash dividend equivalents are paid on non-vested restricted stock units. The Company uses the straight-line method to recognize periodic compensation cost over the vesting period. F-23 Restricted stock unit activity for the year ended December 31, 2013 follows: Non-vested restricted stock units outstanding at beginning of year . . . . . . . . . . . Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Weighted- average Grant Date Fair Value $20.08 $21.09 $20.01 — Shares 17,670 11,250 (8,664) — Non-vested restricted stock units outstanding at end of year . . . . . . . . . . . . . . . . 20,256 $20.67 Performance Unit Awards. In 2009, the Company granted cash-settled performance unit awards to certain executive officers (the “2009 Performance Units”). The 2009 Performance Units provided for those executive officers to receive a cash payment upon the achievement of certain performance goals established by the Compensation Committee during a specified period. The performance period for the 2009 Performance Units was the period from April 1, 2009 through March 31, 2012. The performance goals for the 2009 Performance Units were tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. These goals were considered to be market conditions under the relevant accounting standards and the market conditions were factored into the determination of the fair value of the performance units. Generally, the recipients would receive a target payment if the Company’s total shareholder return was positive and, when compared to the peer group, was at or above the 50th percentile but less than the 75th percentile and two times the target if at the 75th percentile or higher. If the Company’s total shareholder return was positive, and, when compared to the peer group, was at or above the 25th percentile but less than the 50th percentile, the recipients would only receive one-half of the target payment. The total target amount with respect to the 2009 Performance Units was approximately $3.4 million. Because the 2009 Performance Units were settled in cash at the end of the performance period, they were accounted for as liability awards and the Company’s pro-rated obligation was measured at estimated fair value at the end of each reporting period using a Monte Carlo simulation model. The performance period ended on March 31, 2012 and the Company’s total shareholder return was at the 46th percentile. The resulting cash payments totaling $1.7 million were paid in April 2012. For the year ended December 31, 2012, a compensation benefit of approximately $1.9 million was recognized. For the year ended December 31, 2011, compensation expense associated with the 2009 Performance Units was approximately $1.3 million. In 2010, 2011, 2012 and 2013, the Company granted stock-settled performance unit awards to certain executive officers (the “Stock-Settled Performance Units”). The Stock-Settled Performance Units provide for the recipients to receive a grant of shares of stock upon the achievement of certain performance goals established by the Compensation Committee during a specified period. The performance period for the Stock-Settled Performance Units is the three year period commencing on April 1 of the year of grant, but can extend for an additional two years in certain circumstances. The performance goals for the Stock-Settled Performance Units are tied to the Company’s total shareholder return for the performance period as compared to total shareholder return for a peer group determined by the Compensation Committee. These goals are considered to be market conditions under the relevant accounting standards and the market conditions are factored into the determination of the fair value of the respective performance units. Generally, the recipients will receive a target number of shares if the Company’s total shareholder return is positive and, when compared to the peer group, is at the 50th percentile and two times the target if at the 75th percentile or higher. If the Company’s total shareholder return is positive, and, when compared to the peer group, is at the 25th percentile, the recipients will only receive one-half of the target number of shares. The grant of shares when achievement is between the 25th and 75th percentile will be determined on a pro-rata basis. The performance period for the 2010 Stock-Settled Performance Units ended on March 31, 2013, and the Company’s total shareholder return was at the 93rd percentile. In April 2013, 357,500 F-24 shares were issued to settle the 2010 Stock-Settled Performance Units. The total target number of shares with respect to the Stock-Settled Performance Units is set forth below: 2013 Performance Unit Awards 2012 Performance Unit Awards 2011 Performance Unit Awards 2010 Performance Unit Awards Target number of shares . . . . . . . . . . . . . . . . 236,500 192,000 144,375 178,750 Because the Stock-Settled Performance Units are stock-settled awards, they are accounted for as equity awards and measured at fair value on the date of grant using a Monte Carlo simulation model. The fair value of the Stock-Settled Performance Units is set forth below (in thousands): 2013 Performance Unit Awards 2012 Performance Unit Awards 2011 Performance Unit Awards 2010 Performance Unit Awards Aggregate fair value at date of grant . . . . . . $5,564 $3,065 $5,569 $3,117 These fair value amounts are charged to expense on a straight-line basis over the performance period. Compensation expense associated with the Stock-Settled Performance Units is set forth below (in thousands): 2013 Performance Unit Awards 2012 Performance Unit Awards 2011 Performance Unit Awards 2010 Performance Unit Awards Year ended December 31, 2013 . . . . . . . . . . Year ended December 31, 2012 . . . . . . . . . . Year ended December 31, 2011 . . . . . . . . . . $1,391 NA NA $1,022 766 NA $1,856 $1,856 $1,392 $ 260 $1,039 $1,039 Dividends on Equity Awards — Non-forfeitable cash dividends are paid on restricted stock awards and dividend equivalents are paid on restricted stock units. These payments are recognized as follows: • Dividends are recognized as reductions of retained earnings for the portion of restricted stock awards expected to vest. • Dividends are recognized as additional compensation cost for the portion of restricted stock awards that are not expected to vest or that ultimately do not vest. • Dividend equivalents are recognized as additional compensation cost for restricted stock units. 11. Leases The Company incurred rent expense of $47.4 million, $39.0 million and $35.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. Rent expense is primarily related to short-term equipment rentals that are generally passed through to customers. The Company’s obligations under non-cancelable operating lease agreements are not material to its operations or cash flows. F-25 12. Income Taxes Components of the income tax provision applicable to federal, state and foreign income taxes for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands): 2013 2012 2011 Federal income tax expense (benefit): Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 41,558 47,136 $ (512) 156,003 $ 16,336 146,842 State income tax expense: Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Foreign income tax expense (benefit): Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88,694 155,491 163,178 11,733 4,229 15,962 4,572 (796) 3,776 12,455 5,483 17,938 3,817 (1,050) 2,767 6,056 13,196 19,252 6,579 (1,071) 5,508 Total income tax expense: Current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57,863 50,569 15,760 160,436 28,971 158,967 Total income tax expense: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $108,432 $176,196 $187,938 The difference between the statutory federal income tax rate and the effective income tax rate for the years ended December 31, 2013, 2012 and 2011 is summarized as follows: 2013 2012 2011 Statutory tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . State income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Permanent differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other, net 35.0% 35.0% 35.0% 2.5 3.7 (0.2) (1.5) (0.3) (0.6) 2.5 (0.1) (0.6) Effective tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36.6% 37.0% 36.8% The Domestic Production Activities Deduction was enacted as part of the American Jobs Creation Act of 2004 (as revised by the Emergency Economic Stabilization Act of 2008) and allows a deduction of 9% in 2010 and thereafter on the lesser of qualified production activities income or taxable income. The permanent difference for 2011 does not include any deduction as it is limited to taxable income and the Company had a tax loss in 2011. The permanent difference for 2012 does not include any deduction as it is limited to taxable income and the Company did not have taxable income in 2012 due to the utilization of net operating loss carryforwards. The permanent difference for 2013 includes a deduction of $10.0 million as the Company fully utilized its remaining net operating loss carryforwards. F-26 Expense associated with employee stock options . . . . . . . . . . . Federal benefit of state deferred tax liabilities . . . . . . . . . Other . . . . . . . . . . . . . . The tax effect of significant temporary differences representing deferred tax assets and liabilities and changes therein were as follows (in thousands): December 31, 2013 Net Change December 31, 2012 Net Change December 31, 2011 Net Change December 31, 2010 Deferred tax assets: Current: Net operating loss carryforwards . . . . . . $ — $(18,914) $ 18,914 $ (95,662) $ 114,576 $ 114,576 $ — Workers’ compensation allowance . . . . . . . . . Other . . . . . . . . . . . . . . Non-current: Net operating loss 27,612 19,647 2,534 (804) 25,078 20,451 1,074 1,651 24,004 18,800 714 146 23,290 18,654 47,259 (17,184) 64,443 (92,937) 157,380 115,436 41,944 carryforwards . . . . . . 13,452 1,690 11,762 (6,672) 18,434 11,969 6,465 16,208 1,536 14,672 1,944 12,728 1,476 11,252 22,838 14,703 67,201 816 (421) 3,621 22,022 15,124 63,580 1,762 4,454 1,488 20,260 10,670 62,092 7,105 (5,361) 15,189 13,155 16,031 46,903 88,847 Total deferred tax assets . . . 114,460 (13,563) 128,023 (91,449) 219,472 130,625 Deferred tax liabilities: Current: Other . . . . . . . . . . . . . . (14,307) (2,823) (11,484) 3,171 (14,655) 474 (15,129) Non-current: Property and equipment basis difference . . . . Other . . . . . . . . . . . . . . Total deferred tax (939,594) (15,471) (33,997) (186) (905,597) (15,285) (69,774) (2,384) (835,823) (12,901) (289,168) (1,231) (546,655) (11,670) (955,065) (34,183) (920,882) (72,158) (848,724) (290,399) (558,325) liabilities . . . . . . . . . . . . . (969,372) (37,006) (932,366) (68,987) (863,379) (289,925) (573,454) Net deferred tax liability . . . $(854,912) $(50,569) $(804,343) $(160,436) $(643,907) $(159,300) $(484,607) In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. The Company expects the deferred tax assets at December 31, 2013 and 2012 to be realized as a result of the reversal of existing taxable temporary differences giving rise to deferred tax liabilities and the generation of taxable income; therefore, no valuation allowance is considered necessary. Other deferred tax assets consist primarily of the tax effect of various allowance accounts and tax-deferred expenses expected to generate future tax benefits of approximately $34.4 million. Other deferred tax liabilities consist primarily of the tax effect of receivables from insurance companies and tax-deferred income not yet recognized for tax purposes. F-27 For income tax purposes, the Company has approximately $177 million of state net operating losses that can be carried forward as of December 31, 2013. The state net operating losses that can be carried forward, if unused, are scheduled to expire as follows: 2015 — $260,000; 2016 — $8.3 million; 2025 — $1.6 million: 2026 — $6.0 million; 2028 — $12.7 million; 2029 — $33.7 million; 2030 — $26.2 million and 2031 — $88.2 million. As of December 31, 2013, the Company had no unrecognized tax benefits. The Company has established a policy to account for interest and penalties related to uncertain income tax positions as operating expenses. As of December 31, 2013, the tax years ended December 31, 2010 through December 31, 2012 are open for examination by U.S. taxing authorities. As of December 31, 2013, the tax years ended December 31, 2009 through December 31, 2012 are open for examination by Canadian taxing authorities. On January 1, 2010, the Company converted its Canadian operations from a Canadian branch to a controlled foreign corporation for federal income tax purposes. Because the statutory tax rates in Canada are lower than those in the United States, this transaction triggered a $5.1 million reduction in deferred tax liabilities, which is being amortized as a reduction to deferred income tax expense over the weighted average remaining useful life of the Canadian assets. As a result of the above conversion, the Company’s Canadian assets are no longer directly subject to United States taxation, provided that the related unremitted earnings are permanently reinvested in Canada. Effective January 1, 2010, the Company has elected to permanently reinvest these unremitted earnings in Canada, and intends to do so for the foreseeable future. As a result, no deferred United States federal or state income taxes have been provided on such unremitted foreign earnings, which totaled approximately $38.5 million as of December 31, 2013. The unrecognized deferred tax liability associated with these earnings was approximately $5.9 million, net of available foreign tax credits. This liability would be recognized if the Company received a dividend of the unremitted earnings. 13. Employee Benefits The Company maintains a 401(k) plan for all eligible employees. The Company’s operating results include expenses of approximately $6.2 million in 2013, $5.4 million in 2012 and $4.6 million in 2011 for the Company’s contributions to the plan. 14. Business Segments The Company’s revenues, operating profits and identifiable assets are primarily attributable to three business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) the investment, on a non-operating working interest basis, in oil and natural gas properties. Each of these segments represents a distinct type of business. These segments have separate management teams which report to the Company’s chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. As discussed in Note 2, in January 2011, the Company exited the electric wireline business. Operating results for that business for the year ended December 31, 2011 is presented as discontinued operations in the consolidated statements of operations. Contract Drilling — The Company markets its contract drilling services to major and independent oil and natural gas operators. As of December 31, 2013, the Company had 279 marketable land-based drilling rigs in the continental United States, Alaska and western and northern Canada. For the years ended December 31, 2013, 2012 and, 2011, contract drilling revenue earned in Canada was $86.6 million, $79.4 million and $106 million, respectively. Additionally, long-lived assets within the contract drilling segment located in Canada totaled $69.1 million and $72.6 million as of December 31, 2013 and 2012, respectively. Pressure Pumping — The Company provides pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian region. Pressure pumping services are primarily well stimulation and cementing for the completion of new wells and remedial work on existing wells. Well stimulation involves F-28 processes inside a well designed to enhance the flow of oil, natural gas, or other desired substances from the well. Cementing is the process of inserting material between the hole and the pipe to center and stabilize the pipe in the hole. Oil and Natural Gas — The Company owns and invests in oil and natural gas assets as a non-operating working interest owner. The Company’s oil and natural gas interests are located primarily in Texas and New Mexico. Major Customer — During 2013, one customer accounted for approximately $286 million or 10.5% of the Company’s consolidated operating revenues. These revenues were earned in both the Company’s contract drilling and pressure pumping businesses. No single customer accounted for 10% or more of consolidated operating revenues in 2012 or 2011. F-29 The following tables summarize selected financial information relating to the Company’s business segments (in thousands): Revenues: Years Ended December 31, 2013 2012 2011 Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,684,878 979,166 57,257 $1,826,519 841,771 59,930 $1,673,629 845,803 50,559 Total segment revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Elimination of intercompany revenues(a) . . . . . . . . . . . . . . . . . . . . 2,721,301 (5,267) 2,728,220 (4,806) 2,569,991 (4,048) Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,716,034 $2,723,414 $2,565,943 Income from continuing operations before income taxes: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 266,262 87,244 19,948 $ 349,393 132,795 27,210 $ 346,083 193,440 23,982 Corporate and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net gain on asset disposals(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other 373,454 (54,647) 3,384 918 (28,359) 1,691 509,398 (45,843) 33,806 554 (22,750) 508 563,505 (42,903) 4,999 187 (15,652) 582 Income from continuing operations before income taxes . . . . . . . . $ 296,441 $ 475,673 $ 510,718 Identifiable assets: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate and other(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,569,588 761,199 58,656 297,684 $3,538,289 784,128 54,188 180,306 $3,252,116 748,643 44,990 176,152 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,687,127 $4,556,911 $4,221,901 Depreciation, depletion, amortization and impairment: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 438,728 129,984 24,400 4,357 $ 390,316 111,062 21,417 3,819 $ 344,312 73,279 16,962 2,726 Total depreciation, depletion, amortization and impairment . . . . . . . . $ 597,469 $ 526,614 $ 437,279 Capital expenditures: Contract drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 504,508 122,782 31,245 3,926 $ 744,949 194,117 29,888 5,034 $ 784,686 198,061 22,884 5,947 Total capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 662,461 $ 973,988 $1,011,578 (a) Includes contract drilling intercompany revenues related to drilling services provided to the oil and natural gas exploration and production segment. F-30 (b) Net gains or losses associated with the disposal of assets relate to corporate strategy decisions of the executive management group. Accordingly, the related gains or losses have been separately presented and excluded from the results of specific segments. (c) Corporate and other assets primarily include cash on hand and certain deferred tax assets. 15. Concentrations of Credit Risk Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of demand deposits, temporary cash investments and trade receivables. The Company believes it has placed its demand deposits and temporary cash investments with high credit- quality financial institutions. At December 31, 2013 and 2012, the Company’s demand deposits and temporary cash investments consisted of the following (in thousands): 2013 2012 Deposits in FDIC and SIPC-insured institutions under insurance limits . . . . . Deposits in FDIC and SIPC-insured institutions over insurance limits . . . . . . Deposits in foreign banks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 369 269,314 20,921 $ 270 161,195 22,511 Less outstanding checks and other reconciling items . . . . . . . . . . . . . . . . . . . . 290,604 (41,095) 183,976 (73,253) Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $249,509 $110,723 Concentrations of credit risk with respect to trade receivables are primarily focused on companies involved in the exploration and development of oil and natural gas properties. The concentration is somewhat mitigated by the diversification of customers for which the Company provides services. As is general industry practice, the Company typically does not require customers to provide collateral. No significant losses from individual customers were experienced during the years ended December 31, 2013, 2012 or 2011. The Company recognized a $1.1 million provision for bad debts in 2012. No provision for bad debts was recognized in 2013 or in 2011. 16. Fair Values of Financial Instruments The carrying values of cash and cash equivalents, trade receivables and accounts payable approximate fair value due to the short-term maturity of these items. These fair value estimates are considered Level 1 fair value estimates in the fair value hierarchy of fair value accounting. The estimated fair value of the Company’s outstanding debt balances (including current portion) as of December 31, 2013 and 2012 is set forth below (in thousands): December 31, 2013 December 31, 2012 Carrying Value Fair Value Carrying Value Fair Value Borrowings under credit agreements: Term loan facilities . . . . . . . . . . . . . . . . . . . . . . . 4.97% Series A Senior Notes . . . . . . . . . . . . . . . . . 4.27% Series B Senior Notes . . . . . . . . . . . . . . . . . $ 92,500 300,000 300,000 $ 92,500 304,293 286,772 $ 98,750 300,000 300,000 $ 98,750 329,281 310,591 Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $692,500 $683,565 $698,750 $738,622 The carrying values of the balances outstanding under the term loan approximate their fair values as this instrument has a floating interest rate. The fair values of the Series A Notes and Series B Notes at December 31, 2013 and 2012 are based on discounted cash flows associated with the respective notes using current market rates of interest at those respective dates. For the Series A Notes, the current market rates used in measuring this fair value were 4.52% at December 31, 2013 and 3.36% at December 31, 2012. For the Series B Notes, the current F-31 market rates used in measuring this fair value were 4.89% at December 31, 2013 and 3.70% at December 31, 2012. These fair value estimates are based on observable market inputs and are considered Level 2 fair value estimates in the fair value hierarchy of fair value accounting. 17. Quarterly Financial Information (in thousands, except per share amounts) (unaudited) 2012 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income per common share: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter $745,921 157,664 97,274 $681,112 150,894 92,538 $643,631 88,594 50,806 $652,750 100,209 58,859 Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 0.62 0.62 $ $ 0.60 0.60 $ $ 0.34 0.33 $ $ 0.40 0.40 2013 Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income per common share: $667,039 94,932 56,230 $659,316 70,606 40,768 $730,907 124,551 74,420 $658,772 32,102 16,591 Basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ 0.38 0.38 $ $ 0.28 0.28 $ $ 0.51 0.51 $ $ 0.12 0.11 F-32 PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS Description Year Ended December 31, 2013 Deducted from asset accounts: Beginning Balance Charged to Costs and Expenses Deductions(1) Ending Balance (In thousands) Allowance for doubtful accounts . . . . . . . . . . . . . $3,513 $ 0 $ 161 $3,674 Year Ended December 31, 2012 Deducted from asset accounts: Allowance for doubtful accounts . . . . . . . . . . . . . $4,887 $1,100 $(2,474) $3,513 Year Ended December 31, 2011 Deducted from asset accounts: Allowance for doubtful accounts . . . . . . . . . . . . . $5,114 $ 0 $ (227) $4,887 (1) Consists of uncollectible accounts (written off) or recovered. S-1 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Patterson-UTI Energy, Inc. has duly caused this Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES PATTERSON-UTI ENERGY, INC. By: /s/ William Andrew Hendricks, Jr. William Andrew Hendricks, Jr. President and Chief Executive Officer Date: February 14, 2014 Pursuant to the requirements of the Securities Exchange Act of 1934, this Report on Form 10-K has been signed by the following persons on behalf of Patterson-UTI Energy, Inc. and in the capacities indicated as of February 14, 2014. Signature /s/ Mark S. Siegel Mark S. Siegel /s/ William Andrew Hendricks, Jr. William Andrew Hendricks, Jr. (Principal Executive Officer) /s/ John E. Vollmer III John E. Vollmer III (Principal Financial and Accounting Officer) /s/ Kenneth N. Berns Kenneth N. Berns /s/ Charles O. Buckner Charles O. Buckner /s/ Michael W. Conlon Michael W. Conlon /s/ Curtis W. Huff Curtis W. Huff /s/ Terry H. Hunt Terry H. Hunt /s/ Cloyce A. Talbott Cloyce A. Talbott Title Chairman of the Board President and Chief Executive Officer Senior Vice President — Corporate Development, Chief Financial Officer and Treasurer Senior Vice President and Director Director Director Director Director Director Patterson-UTI Energy, Inc. Corporate Information DIRECTORS OFFICERS CORPORATE OFFICE TRANSFER AGENT Patterson-UTI Energy, Inc. 450 Gears Road, Suite 500 Houston, Texas 77067 Telephone: (281) 765-7100 Fax: (281) 765-7175 www.patenergy.com Continental Stock Transfer & Trust Company 17 Battery Place, 8th Floor New York, NY 10004 Telephone: (212) 509-4000 www.continentalstock.com COMMON STOCK Nasdaq: PTEN INDEPENDENT AUDITOR PricewaterhouseCoopers LLP Mark S. Siegel Chairman Wm. Andrew Hendricks, Jr. President and Chief Executive Officer Kenneth N. Berns Senior Vice President John E. Vollmer III Senior Vice President – Corporate Development, Chief Financial Officer and Treasurer Seth D. Wexler General Counsel and Secretary Mark S. Siegel Chairman, Patterson-UTI Energy, Inc.; President, Remy Investors and Consultants, Incorporated Kenneth N. Berns Senior Vice President, Patterson-UTI Energy, Inc. Charles O. Buckner Retired Partner, Ernst & Young LLP Michael W. Conlon Retired Partner, Fulbright & Jaworski LLP Curtis W. Huff President, Freebird Partners LP Co-Founder, Intervale Capital LLC Terry H. Hunt Energy Consultant Cloyce A. Talbott Former President and Chief Executive Officer, Patterson-UTI Energy, Inc. Patterson-UTI Energy, Inc. 450 Gears Road, Suite 500 Houston, Texas 77067 Telephone: (281) 765-7100 Fax: (281) 765-7175 www.patenergy.com 

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