PARKER DRILLING CO /DE/ - Annual Report: 2017 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(MARK ONE)



	þ	Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2017



	¨	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 1-7573

PARKER DRILLING COMPANY

(Exact name of registrant as specified in its charter)



Delaware		73-0618660
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5 Greenway Plaza, Suite 100, Houston, Texas		77046
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code:

(281) 406-2000

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered:
Common Stock, par value $0.16 ²/₃ per share		New York Stock Exchange

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 ¨ No þ

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ 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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):



Large accelerated filer ¨	Accelerated filer þ	Non-accelerated filer ¨	Smaller reporting company ¨

		(Do not check if a smaller reporting company)

			Emerging growth company ¨

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

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

The aggregate market value of our common stock held by non-affiliates on June 30, 2017 was $180.9 million. At February 16, 2018, there were 138,908,085 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our definitive proxy statement for the Annual Meeting of Stockholders to be held on May 10, 2018 are incorporated by reference in Part III.

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TABLE OF CONTENTS



		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	20
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6.	Selected Financial Data	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
Item 9A.	Controls and Procedures	93
Item 9B.	Other Information	94

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	95
Item 11.	Executive Compensation	95
Item 12.	Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters	95
Item 13.	Certain Relationships and Related Transactions, and Director Independence	95
Item 14.	Principal Accounting Fees and Services	95

PART IV
Item 15.	Exhibits and Financial Statement Schedules	96
Item 16.	Form 10-K Summary	100
Signatures		101
EX-12.1
EX-21
EX-23.1
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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PART I

Item 1. Business

General

Unless otherwise indicated, the terms “Company,” “Parker,” “we,” “us” and “our” refer to Parker Drilling Company together with its subsidiaries and “Parker Drilling” refers solely to the parent, Parker Drilling Company. Parker Drilling was incorporated in the state of Oklahoma in 1954 after having been established in 1934. In March 1976, the state of incorporation of the Company was changed to Delaware. Our principal executive offices are located at 5 Greenway Plaza, Suite 100, Houston, Texas 77046.

We are an international provider of contract drilling and drilling-related services as well as rental tools and services. We have operated in over 50 countries since beginning operations in 1934, making us among the most geographically experienced drilling contractors and rental tools providers in the world. We currently have operations in 19 countries. Parker has participated in numerous world records for deep and extended-reach drilling land rigs and is an industry leader in quality, health, safety and environmental practices.

Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. We report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools. For information regarding our reportable segments and operations by geographic areas for the years ended December 31, 2017, 2016 and 2015, see Note 12 - Reportable Segments in Item 8. Financial Statements and Supplementary Data and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Our Drilling Services Business

In our Drilling Services business, we drill oil, natural gas and geothermal wells for customers in both the U.S. and international markets. We provide this service with both Company-owned rigs and customer-owned rigs. We refer to the provision of drilling services with customer-owned rigs as our operations and management (“O&M”) service in which operators own their own drilling rigs but choose Parker Drilling to operate and manage the rigs for them. The nature and scope of activities involved in drilling an oil and natural gas well is similar whether it is drilled with a Company-owned rig (as part of a traditional drilling contract) or a customer-owned rig (as part of an O&M contract). In addition, we provide project-related services, such as engineering, procurement, project management and commissioning of customer-owned drilling rig projects. We have extensive experience and expertise in drilling geologically challenging wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas.

U.S. (Lower 48) Drilling

Our U.S. (Lower 48) Drilling segment provides drilling services with our Gulf of Mexico (“GOM”) barge drilling rig fleet, and markets our U.S. (Lower 48)-based O&M services. Our GOM barge drilling fleet operates barge rigs that drill for oil and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The majority of these wells are drilled in shallow water depths ranging from 6 to 12 feet. Our rigs are suitable for a variety of drilling programs, from inland coastal waters requiring shallow draft barges, to open water drilling on both state and federal water projects requiring more robust capabilities. The barge drilling industry in the GOM is characterized by cyclical activity where utilization and dayrates are typically driven by oil and natural gas prices and our customers’ access to project financing. Contract terms typically consist of well-to-well or multi-well programs, most commonly ranging from 20 to 180 days.

International & Alaska Drilling

Our International & Alaska Drilling segment provides drilling services, using both Company-owned rigs and O&M contracts, and project-related services. The drilling markets in which this segment operates have one or more of the following characteristics:


•	customers typically are major, independent, or national oil and natural gas companies or integrated service providers;


•	drilling programs in remote locations with little infrastructure, requiring a large inventory of spare parts and other ancillary equipment and self-supported service capabilities;


•	complex wells and/or harsh environments (such as high pressures, deep depths, hazardous or geologically challenging conditions and sensitive environments) requiring specialized equipment and considerable experience to drill; and

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•	O&M contracts that generally cover periods of one year or more.

During the year ended December 31, 2017, we had rigs operating on Sakhalin Island, Russia and in Alaska, Kazakhstan, the Kurdistan Region of Iraq, and Guatemala. In addition, we had O&M and ongoing project-related services for customer-owned rigs in Kuwait, Canada and on Sakhalin Island, Russia.

Our Rental Tools Services Business

In our Rental Tools Services business, we provide premium rental equipment and services to exploration & production (“E&P”) companies, drilling contractors and service companies on land and offshore in the U.S. and select international markets. Tools we provide include standard and heavy-weight drill pipe, all of which are available with standard or high-torque connections, tubing, drill collars, pressure control equipment, including blowout preventers and more. We also provide well construction services, which include tubular running services and downhole tool rentals, well intervention services, which include whipstock, fishing and related services, and inspection and machine shop support. Rental tools are used during drilling and/or workover programs and are requested by the customer as needed, requiring us to keep a broad inventory of rental tools in stock. Rental tools are usually rented on a daily or monthly basis.

U.S. Rental Tools

Our U.S. Rental Tools segment is headquartered in New Iberia, Louisiana. We maintain an inventory of rental tools for deepwater, drilling, completion, workover, and production applications at facilities in Louisiana, Texas, Oklahoma, Wyoming, North Dakota and West Virginia. Our largest single market for rental tools is U.S. land drilling, a cyclical market driven primarily by oil and natural gas prices and our customers’ access to project financing. A portion of our U.S. rental tools business is supplying tubular goods and other equipment to offshore GOM customers.

International Rental Tools

Our International Rental Tools segment is headquartered in Dubai, United Arab Emirates. We maintain an inventory of rental tools and provide well construction, well intervention, and surface and tubular services to our customers in the Middle East, Latin America, United Kingdom, Europe, and Asia-Pacific regions.

Our Business Strategy

We intend to successfully compete in select energy services businesses that benefit our customers’ exploration, appraisal, and development programs, and in which operational execution is the key measure of success. We plan to do this by:


•	Consistently delivering innovative, reliable, and efficient results that help our customers reduce their operational risks and manage their operating costs; and


•	Over the longer-term, investing to improve and grow our existing business lines and to expand the scope of products and services we offer, both organically and through acquisitions.

Our Core Competencies

We believe our core competencies are the foundation for delivering operational excellence to our customers. Applying and strengthening these core competencies will be a key factor in our success:

Customer-Aligned Operational Excellence: Our daily focus is meeting the needs of our customers. We strive to anticipate our customers’ challenges and provide innovative, reliable and efficient solutions to help them achieve their business objectives.

Rapid Personnel Development: Motivated, skilled and effective people are critical to the successful execution of our strategy. We strive to attract and retain the best people, to develop depth and strength in key skills, and to provide a safety- and solutions-oriented workforce to our customers.

Selective and Effective Market Entry: We are selective about the services we provide, geographies in which we operate, and customers we serve. We intend to build Parker’s business in markets with the best potential for sustained growth, profitability, and operating scale. We are strategic, timely, and intentional when we enter new markets and when we grow organically or through acquisitions or investments in new business ventures.

Enhanced Asset Management and Predictive Maintenance: We believe well-maintained rigs, equipment, and rental tools are critical to providing reliable results for our customers. We employ predictive and preventive maintenance programs and training to sustain high levels of effective utilization and to provide reliable operating performance and efficiency.

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Standard, Modular and Configurable Processes and Equipment: To address the challenging and harsh environments in which our customers operate, we develop standardized processes and equipment that can be configured to meet each project’s distinct technological requirements. Repeatable processes and modular equipment leverage our investments in assets and employees, increase efficiency, and reduce disruption.

We believe there are tangible rewards from delivering value to our customers through superior execution of our core competencies. When we deliver innovative, reliable, and efficient solutions aligned with our customers’ needs, we believe we are well-positioned to earn premium rates, generate follow-on business, and create growth opportunities that enhance our financial performance and advance our strategy.

Customers and Scope of Operations

Our customer base consists of major, independent, and national oil and natural gas E&P companies and integrated service providers. Each of our segments depends on a limited number of key customers and the loss of any one or more key customers could have a material adverse effect on a segment. In 2017, our largest customer, Exxon Neftegas Limited (“ENL”), accounted for approximately 31.3 percent of our total consolidated revenues. In 2017, our second largest customer, BP Exploration Alaska, Inc. (“BP”), constituted approximately 9.7 percent of our total consolidated revenues. For information regarding our reportable segments and operations by geographic areas for the years ended December 31, 2017, 2016 and 2015, see Note 12 - Reportable Segments in Item 8. Financial Statements and Supplementary Data and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Competition

We operate in competitive businesses characterized by high capital requirements, rigorous technological challenges, evolving regulatory requirements, and challenges in securing and retaining qualified field personnel.

In drilling markets, most contracts are awarded on a competitive bidding basis and operators often consider reliability, efficiency, and safety in addition to price. We have been successful in differentiating ourselves from competitors through our drilling performance and safety record, and through providing services that help our customers manage their operating costs and mitigate their operational risks.

In international drilling markets, we compete with a number of international drilling contractors as well as local contractors. Although local drilling contractors often have lower labor and mobilization costs, we are generally able to distinguish ourselves from these companies based on our technical expertise, safety performance, quality of service, and experience. We believe our expertise in operating in challenging environments has been a significant factor in securing contracts.

In the GOM barge drilling market, we compete with a small number of contractors. We have the largest number and greatest diversity of rigs available in this market, allowing us to provide equipment and services that are well-matched to customers’ requirements. We believe the market for drilling contracts will continue to be competitive with continued focus on reliability, efficiency, and safety, in addition to price.

In rental tools markets, we compete with suppliers both larger and smaller than our business, some of which are part of larger enterprises. We compete against other rental tools companies based on breadth of inventory, availability and price of product, and quality of service. In the U.S. market, our network of locations provides broad and efficient product availability. In international markets, some of our rental tools business is obtained in conjunction with our drilling and O&M projects.

Contracts

Most drilling contracts are awarded based on competitive bidding. The rates specified in drilling contracts vary depending upon the type of rig employed, equipment and services supplied, crew complement, geographic location, term of the contract, competitive conditions, and other variables. Our contracts generally provide for an operating dayrate during drilling operations, with lower rates for periods of equipment downtime, customer stoppage, well-to-well rig moves, adverse weather, or other conditions, and no payment when certain conditions continue beyond contractually established parameters. Contracts typically provide for a different dayrate or specified fixed payments during mobilization or demobilization. The terms of most of our contracts are based on either a specified period of time or a specified number of wells. The contract term in some instances may be extended by the customer exercising options for an additional time period or for the drilling of additional wells, or by exercising a right of first refusal. Most of our contracts allow termination by the customer prior to the end of the term without penalty under certain circumstances, such as the loss of or major damage to the drilling unit or other events that cause the suspension of drilling operations beyond a specified period of time. See “Certain of our contracts are subject to cancellation by our customers without penalty and with little or no notice.” in Item 1A. Risk Factors. Certain contracts require the customer to pay an early termination fee if the customer terminates a contract before the end of the term without cause. Our project services contracts include engineering,

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procurement, and project management consulting, for which we are compensated through labor rates and cost-plus arrangements for non-labor items.

Rental tools contracts are typically on a dayrate basis with rates based on type of equipment and competitive conditions. Depending on market and competitive conditions, rental rates may be applied from the time the equipment leaves our facility or only when the equipment is actually in use by the customer. Rental contracts generally require the customer to pay for lost-in-hole or damaged equipment. Some of the services provided in the rental tools segment are billed per well section with pricing determined by the length and diameter of the well section.

Seasonality

Our rigs in the inland waters of the GOM are subject to severe weather during certain periods of the year, particularly during hurricane season from June through November, which could halt operations for prolonged periods or limit contract opportunities during that period. In addition, mobilization, demobilization, or well-to-well movements of rigs in arctic regions can be affected by seasonal changes in weather or weather so severe that conditions are deemed too unsafe to operate.

Backlog

Backlog is our estimate of the dollar amount of drilling contract revenues we expect to realize in the future as a result of executing awarded contracts. The Company’s backlog of firm orders was approximately $241 million as of December 31, 2017 and $379 million as of December 31, 2016 and is primarily attributable to the International & Alaska segment of our Drilling Services business. We estimate that, as of December 31, 2017, 46.0 percent of our backlog will be recognized as revenues within one year.

The amount of actual revenues earned and the actual periods during which revenues are earned could be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations, new contracts, and other factors. See “Our backlog of contracted revenues may not be fully realized and may reduce significantly in the future, which may have a material adverse effect on our financial position, results of operations or cash flows” in Item 1A. Risk Factors.

Insurance and Indemnification

Our contracts provide for varying levels of indemnification between ourselves and our customers. We maintain insurance with respect to personal injuries, damage to or loss of equipment, and various other business risks, including well control and subsurface risk. Our insurance policies typically have 12-month policy periods.

Our insurance program provides coverage, to the extent not otherwise paid by the customer under the indemnification provisions of the drilling or rental tool contract, for liability due to well control events and liability arising from third-party claims, including wrongful death and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees. Generally, our insurance program provides liability coverage up to $350.0 million, with retentions of $1.0 million or less.

Well control events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our insurance program provides coverage for third-party liability claims relating to sudden and accidental pollution from a well control event up to $350.0 million per occurrence. A separate limit of $10.0 million exists to cover the costs of re-drilling of the well and well control costs under a Contingent Operators Extra Expense policy. For our rig-based operations, remediation plans are in place to prevent the spread of pollutants and our insurance program provides coverage for removal, response, and remedial actions. We retain the risk for liability not indemnified by the customer below the retention and in excess of our insurance coverage.

Based upon a risk assessment and due to the high cost, high self-insured retention, and limited availability of coverage for windstorms in the GOM, we have elected not to purchase windstorm insurance for our barge rigs in the GOM. Although we

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have retained the risk for physical loss or damage for these rigs arising from a named windstorm, we have procured insurance coverage for removal of a wreck caused by a windstorm.

Our contracts provide for varying levels of indemnification from our customers and may require us to indemnify our customers in certain circumstances. Liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means we and our customers customarily assume liability for our respective personnel and property regardless of fault. In addition, our customers typically indemnify us for damage to our equipment down-hole, and in some cases, our subsea equipment, generally based on replacement cost minus some level of depreciation. However, in certain contracts we may assume liability for damage to our customer’s property and other third-party property on the rig and in other contracts we are not indemnified by our customers for damage to their property and, accordingly, could be liable for any such damage under applicable law.

Our customers typically assume responsibility for and indemnify us from any loss or liability resulting from pollution, including clean-up and removal and third-party damages, arising from operations under the contract and originating below the surface of the land or water, including losses or liability resulting from blowouts or cratering of the well. In some contracts, however, we may have liability for damages resulting from such pollution or contamination caused by our gross negligence or, in some cases, ordinary negligence.

We generally indemnify the customer for legal and financial consequences of spills of industrial waste, lubricants, solvents and other contaminants (other than drilling fluid) on the surface of the land or water originating from our rigs or equipment. We typically require our customers to retain liability for spills of drilling fluid which circulates down-hole to the drill bit, lubricates the bit and washes debris back to the surface. Drilling fluid often contains a mixture of synthetics, the exact composition of which is prescribed by the customer based on the particular geology of the well being drilled.

The above description of our insurance program and the indemnification provisions typically found in our contracts is only a summary as of the date hereof and is general in nature. Our insurance program and the terms of our drilling and rental tool contracts may change in the future. In addition, the indemnification provisions of our contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.

If any of the aforementioned operating hazards results in substantial liability and our insurance and contractual indemnification provisions are unavailable or insufficient, our financial condition, operating results, or cash flows may be materially adversely affected.

Employees

The following table sets forth the composition of our employee base:



	December 31,
	2017	2016
U.S. (Lower 48) Drilling	111	111
International & Alaska Drilling	1,122	1,078
U.S. Rental Tools	214	198
International Rental Tools	648	636
Corporate	171	176
Total employees	2,266	2,199

Environmental Considerations

Our operations are subject to numerous U.S. federal, state, and local laws and regulations, as well as the laws and regulations of other jurisdictions in which we operate, pertaining to the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations to implement and enforce laws pertaining to the environment, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive, and other protected areas; require remedial action to clean up pollution from former operations; and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect our operations and financial position, as well as those of similarly

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situated entities operating in the same markets. While our management believes that we comply with current applicable environmental laws and regulations, there is no assurance that compliance can be maintained in the future.

As an owner or operator of both onshore and offshore facilities, including mobile offshore drilling rigs in or near waters of the United States, we may be liable for the costs of clean up and damages arising out of a pollution incident to the extent set forth in federal statutes such as the Federal Water Pollution Control Act (commonly known as the Clean Water Act (“CWA”)), as amended by the Oil Pollution Act of 1990 (“OPA”); the Clean Air Act (“CAA”); the Outer Continental Shelf Lands Act (“OCSLA”); the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”); the Resource Conservation and Recovery Act (“RCRA”); the Emergency Planning and Community Right to Know Act (“EPCRA”); and the Hazardous Materials Transportation Act (“HMTA”) as well as comparable state laws. In addition, we may also be subject to civil claims arising out of any such incident.

The OPA and related regulations impose a variety of regulations on “responsible parties” related to the prevention of spills of oil or other hazardous substances and liability for damages resulting from such spills. “Responsible parties” include the owner or operator of a vessel, pipeline or onshore facility, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability for oil removal costs and a variety of public and private damages to each responsible party. The OPA also requires some facilities to demonstrate proof of financial responsibility and to prepare an oil spill response plan. Failure to comply with ongoing requirements or inadequate cooperation in a spill may subject a responsible party to civil or criminal enforcement actions.

The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. The Bureau of Safety and Environmental Enforcement (“BSEE”) regulates the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay, or restriction of activities can result from either governmental or citizen prosecution.

Our operations are also governed by laws and regulations related to workplace safety and worker health, primarily the Occupational Safety and Health Act and regulations promulgated thereunder. In addition, various other governmental and quasi-governmental agencies require us to obtain certain miscellaneous permits, licenses and certificates with respect to our operations. The kind of permits, licenses and certificates required by our operations depend upon a number of factors. We believe we have the necessary permits, licenses and certificates that are material to the conduct of our existing business.

CERCLA (also known as “Superfund”) and comparable state laws impose potential liability without regard to fault or the legality of the activity, on certain classes of persons who are considered to be responsible for the release of hazardous substances into the environment. While CERCLA exempts crude oil from the definition of hazardous substances for purposes of the statute, our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to a broad class of potentially responsible parties for all response and remediation costs, as well as natural resource damages. In addition, persons responsible for release of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up the hazardous substances released into the environment and for damages to natural resources.

RCRA and comparable state laws regulate the management and disposal of solid and hazardous wastes. Current RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, these wastes and other wastes may be otherwise regulated by EPA or state agencies. Moreover, ordinary industrial wastes, such as paint wastes, spent solvents, laboratory wastes, and used oils, may be regulated as hazardous waste. Although the costs of managing solid and hazardous wastes may be significant, we do not expect to experience more burdensome costs than competitor companies involved in similar drilling operations.

The CAA and similar state laws and regulations restrict the emission of air pollutants and may also impose various monitoring and reporting requirements. In addition, those laws may require us to obtain permits for the construction, modification, or operation of certain projects or facilities and the utilization of specific equipment or technologies to control emissions. For example, the EPA has adopted regulations known as “RICE MACT” that require the use of “maximum achievable control technology” to reduce formaldehyde and other emissions from certain stationary reciprocating internal combustion engines, which can include portable engines used to power drilling rigs.

Some scientific studies have suggested that emissions of certain gases including carbon dioxide and methane, commonly referred to as “greenhouse gases” (“GHGs”), may be contributing to the warming of the atmosphere resulting in climate change. There are a variety of legislative and regulatory developments, proposals, requirements, and initiatives that have been introduced

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in the U.S. and international regions in which we operate that are intended to address concerns that emissions of GHGs are contributing to climate change and these may increase costs of compliance for our drilling services or our customer’s operations. Among these developments, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (“UNFCC”) established a set of emission targets for GHGs that became binding on all those countries that had ratified it. The Kyoto Protocol was followed by the Paris Agreement of the 2015 UNFCC. The Paris Agreement entered into force on November 4, 2016 and, as of late 2017, had been ratified by 174 of the 197 parties to the UNFCC. However, on August 4, 2017, the United States formally communicated to the United Nations its intent to withdraw from participation in the Paris Agreement, which entails a four-year process. In response to the announced withdrawal plan, a number of state and local governments in the United States have expressed intentions to take GHG-related actions.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements 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, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations, and result in a disruption of our customers’ operations.

Executive Officers

Officers are elected each year by the board of directors following the annual stockholders’ meeting for a term of one year or until the election and qualification of their successors. The current executive officers of the Company and their ages, positions with the Company and business experience are presented below:

•

Gary G. Rich, 59, joined the Company in October 2012 as the president and chief executive officer. Mr. Rich also serves as Chairman of the Company’s board of directors. He is an industry veteran with over 30 years of global technical, commercial, and operations experience. Mr. Rich came to Parker Drilling after a 25-year career with Baker Hughes Incorporated. Mr. Rich served as vice president of global sales for Baker Hughes from August 2011 to October 2012, and prior to that role, he served as president of that company’s European operations from April 2009 to August 2011. Previously, Mr. Rich was president of Hughes Christensen Company, a division of Baker Hughes primarily focused on the production and distribution of drilling bits for the petroleum industry.

•

Michael W. Sumruld, 47, joined the Company in October 2017 as the senior vice president and chief financial officer. Prior to joining the Company, Mr. Sumruld served as vice president and chief accounting officer of LyondellBassell Industries N.V. from January through September 2017. From 2013 through 2016 Mr. Sumruld served as vice president and treasurer of Baker Hughes Incorporated; from 2012 to 2013 he served as vice president finance – Eastern Hemisphere of Baker Hughes; and in 2011 he served as Baker Hughes’s Director of Investor Relations.

•

Jon-Al Duplantier, 50, is the senior vice president, chief administrative officer, general counsel, and secretary of the Company, a position held since 2013. Mr. Duplantier has over 20 years’ experience in the oil and natural gas industry. Mr. Duplantier joined the Company in 2009 as vice president and general counsel. From 1995 to 2009, Mr. Duplantier served in several legal and business roles at ConocoPhillips, including senior counsel – Exploration and Production, vice president and general counsel – Conoco Phillips Indonesia, and vice president and general counsel – Dubai Petroleum Company. Prior to joining ConocoPhillips, he served as a patent attorney for DuPont from 1992 to 1995.

•

Bryan R. Collins, 51, was appointed president of drilling operations for the Company on January 1, 2017. Prior to this appointment, Mr. Collins served as vice president - Arctic and Latin America operations from April 2016 to December 2016, vice president of Arctic operations from March 2013 to April 2016, and global director of business development from February 2012 to March 2013. Before joining the Company, Mr. Collins served in various operational and senior management roles at Schlumberger, Ltd., including vice president for drilling and measurements operations in Russia. Prior to his time at Schlumberger, Mr. Collins served as a global account manager for ExxonMobil’s worldwide drilling operations.

Other Parker Drilling Company Officers


•	Nathaniel C. Dockray, 37, was appointed chief accounting officer in November, 2017. Mr. Dockray has also served as the Company’s director of tax and financial planning & analysis since April 2016. From January 2014 through March 2016 he was the Company’s director of tax. From December 2012 to January 2014 Mr. Dockray served as assistant

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director of tax, and prior to that he served as a senior tax manager of the Company. Prior to joining Parker Drilling, Mr. Dockray was employed by PricewaterhouseCoopers LLP.


•	David W. Tucker, 62, treasurer, joined the Company in 1978 as a financial analyst and served in various financial and accounting positions before being named chief financial officer of our formerly wholly-owned subsidiary, Hercules Offshore Corporation, in February 1998. Mr. Tucker was named treasurer of the Company in 1999.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports are made available free of charge on our website at http://www.parkerdrilling.com as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission (“SEC”). Except to the extent explicitly stated herein, documents and information on our website are not incorporated by reference herein. The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Additionally, our reports, proxy and information statements and our other SEC filings are available on an Internet website maintained by the SEC at http://www.sec.gov.

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Item 1A. Risk Factors

Our businesses involve a high degree of risk. You should consider carefully the risks and uncertainties described below and the other information included in this Form 10-K, including Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data. While these are the risks and uncertainties we believe are most important for you to consider, they are not the only risks or uncertainties facing us or which may adversely affect our business. If any of the following risks or uncertainties actually occurs, our business, financial condition, or results of operations could be adversely affected.

The volatility of prices for oil and natural gas has had, and may continue to have, a material adverse effect on our financial condition, results of operations, and cash flows.

Oil and natural gas prices and market expectations regarding potential changes in these prices are volatile and are likely to continue to be volatile in the future. Increases or decreases in oil and natural gas prices and expectations of future prices could have an impact on our customers’ long-term exploration and development activities, which in turn could materially affect our business and financial performance. Furthermore, higher oil and natural gas prices do not necessarily result immediately in increased drilling activity because our customers’ expectations of future oil and natural gas prices typically drive demand for our drilling services. The oil and natural gas industry has historically experienced periodic downturns, which have been characterized by diminished demand for oilfield services and downward pressure on the prices we charge. A prolonged downturn in the oil and natural gas industry could result in a further reduction in demand for oilfield services and could continue to adversely affect our financial condition, results of operations, and cash flows. The average price of oil during 2017 was well below the average prices in 2014. Oil and natural gas prices and demand for our services also depend upon numerous factors which are beyond our control, including:


•	the level of supply and demand for oil and natural gas;


•	the cost of exploring for, producing, and delivering oil and natural gas;


•	expectations regarding future energy prices;


•	advances in exploration, development, and production technology;


•	the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and prices;


•	the level of production by non-OPEC countries;


•	the adoption or repeal of laws and government regulations, both in the United States and other countries;


•	the imposition or lifting of economic sanctions against certain regions, persons, and other entities;


•	the number of ongoing and recently completed rig construction projects which may create overcapacity;


•	local and worldwide military, political, and economic events, including events in the oil producing regions of Africa, the Middle East, Russia, Central Asia, Southeast Asia, and Latin America;


•	weather conditions and natural disasters;


•	expansion or contraction of worldwide economic activity, which affects levels of consumer and industrial demand;


•	the rate of discovery of new oil and natural gas reserves;


•	domestic and foreign tax policies;


•	acts of terrorism in the United States or elsewhere;


•	increased demand for alternative energy sources and electric vehicles, including government initiatives to promote the use of renewable energy sources and the growing public sentiment around alternatives to oil and gas; and


•	the policies of various governments regarding exploration and development of their oil and natural gas reserves.

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Demand for the majority of our services is substantially dependent on the levels of expenditures by the oil and natural gas industry. A substantial or an extended decline in oil and natural gas prices could result in lower expenditures by the oil and natural gas industry, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Demand for the majority of our services depends substantially on the level of expenditures for the exploration, development, and production of oil or natural gas reserves by the major, independent, and national oil and natural gas E&P companies and large integrated service companies that comprise our customer base. These expenditures are generally dependent on the industry’s view of future oil and natural gas prices and are sensitive to the industry’s view of future economic growth and the resulting impact on demand for oil and natural gas. Declines in oil and natural gas prices have and may continue to result in project modifications, delays or cancellations, general business disruptions, and delays in payment of, or nonpayment of, amounts that are owed to us, any of which could continue to have a material adverse effect on our financial condition, results of operations, and cash flows. Historically, when drilling activity and spending decline, utilization and dayrates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. Sustained low oil prices have in turn caused a significant decline in the demand for drilling services over the last several years. The rig utilization rate of our International & Alaska Drilling segment has fallen to 36 percent for the year ended December 31, 2017 from 40 percent for the year ended December 31, 2016. Furthermore, operators implemented significant reductions in capital spending in their budgets, including the cancellation or deferral of existing programs, and are expected to continue to operate under reduced budgets for the foreseeable future.

We have a significant amount of debt. Our debt levels and debt agreement restrictions may have significant consequences for our future prospects, including limiting our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2017, we had:


•	$585.0 million principal amount of long-term debt;


•	$18.3 million of operating lease commitments; and


•	$5.7 million of standby letters of credit.

Our ability to meet our debt service obligations depends on our ability to generate positive cash flows from operations. We have in the past, and may in the future, incur negative cash flows from one or more segments of our operating activities. Our future cash flows from operating activities will be influenced by the demand for our drilling services, the utilization of our rigs, the dayrates that we receive for our rigs, demand for our rental tools, oil and natural gas prices, general economic conditions, and other factors affecting our operations, many of which are beyond our control.

If we are unable to service our debt obligations, we may have to take one or more of the following actions:


•	delay spending on capital projects, including maintenance projects and the acquisition or construction of additional rigs, rental tools, and other assets;


•	issue additional equity;


•	sell assets; or


•	restructure or refinance our debt.

Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, or if available, such additional indebtedness or equity financing may not be available on a timely basis, or on terms acceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized from any such asset sale. Our ability to generate sufficient cash flow from operating activities to pay the principal and interest on our indebtedness is subject to certain market conditions and other factors which are beyond our control.

Increases in the level of our debt and restrictions in the covenants contained in the instruments governing our debt could have important consequences to you. For example, they could:


•	result in a reduction of our credit rating, which would make it more difficult for us to obtain additional financing on acceptable terms;


•	require us to dedicate a substantial portion of our cash flows from operating activities to the repayment of our debt and the interest associated with our debt;

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•	limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt and creating liens on our properties;


•	place us at a competitive disadvantage compared with our competitors that have relatively less debt; and


•	make us more vulnerable to downturns in our business.

Our current operations and future growth may require significant additional capital, and the amount and terms of our indebtedness could impair our ability to fund our capital requirements.

Our business requires substantial capital. We may require additional capital in the event of growth opportunities, unanticipated maintenance requirements, or significant departures from our current business plan.

On February 14, 2018, we executed the Fifth Amendment (“Fifth Amendment”) to the Second Amended and Restated Credit Agreement (as amended, the “2015 Secured Credit Agreement”), which modified the credit facility to an Asset-Based Lending (ABL) structure and reduced the size of the Revolver from $100 million to $80 million. In addition, the Fifth Amendment eliminated the financial maintenance covenants previously in effect and replaced them with a liquidity covenant of $30 million and a monthly borrowing base calculation based on eligible rental equipment and eligible domestic accounts receivable, and removed our availability to make certain restricted payments. The liquidity covenant requires the Company to maintain a minimum of $30 million of liquidity (defined as availability under the borrowing base and cash on hand), of which $15 million is restricted, resulting in a maximum availability at any one time of the lesser of (a) an amount equal to our borrowing base minus $15 million, or (b) $65 million.

Additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in the 2015 Secured Credit Agreement and the indentures governing our outstanding 7.50% Senior Notes due 2020 (“7.50% Notes”) and 6.75% Senior Notes due 2022 (“6.75% Notes”, and collectively with the 7.50% Notes, the “Senior Notes”). Failure to obtain additional financing, should the need for it develop, could impair our ability to fund capital expenditure requirements and meet debt service requirements and could have an adverse effect on our business.

Our 2015 Secured Credit Agreement and the indentures for our Senior Notes impose significant operating and financial restrictions, which may prevent us in the future from obtaining financing or capitalizing on business opportunities.

The 2015 Secured Credit Agreement, the amendments thereto, and the indentures governing our Senior Notes impose significant operating and financial restrictions on us. These restrictions limit our ability to:


•	make investments and other restricted payments, including dividends;


•	incur additional indebtedness;


•	create liens;


•	engage in sale leaseback transactions;


•	repurchase our common stock or Senior Notes;


•	sell our assets or consolidate or merge with or into other companies; and


•	engage in transactions with affiliates.

These limitations are subject to a number of important qualifications and exceptions.

The 2015 Secured Credit Agreement also includes a liquidity covenant of $30 million and a monthly borrowing base calculation based on eligible rental equipment and eligible domestic accounts receivable. The liquidity covenant requires the Company to maintain a minimum of $30 million of liquidity (defined as availability under the borrowing base and cash on hand), of which $15 million is restricted, resulting in a maximum availability at any one time of $65 million. These covenants may adversely affect our ability to finance our future operations and capital needs and to pursue available business opportunities.

A breach of any of the covenants in the 2015 Secured Credit Agreement or in the Senior Notes could result in a default with respect to the related indebtedness. If a default were to occur, the lenders under our 2015 Secured Credit Agreement and the holders of our Senior Notes could elect to declare the indebtedness, if any outstanding at that time, together with accrued interest, immediately due and payable. If the repayment of the indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness.

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Our backlog of contracted revenues may not be fully realized and may reduce significantly in the future, which may have a material adverse effect on our financial position, results of operations, or cash flows.

Our expected revenues under existing contracts (“contracted revenues”) may not be fully realized due to a number of factors, including rig or equipment downtime or suspension of operations. Several factors could cause downtime or a suspension of operations, many of which are beyond our control, including:


•	breakdowns of our equipment or the equipment of others necessary for continuation of operations;


•	work stoppages, including labor strikes;


•	shortages of material and skilled labor;


•	severe weather or harsh operating conditions;


•	the occurrence or threat of epidemic or pandemic diseases or any government response to such occurrence or threat;


•	the early termination of contracts; and


•	force majeure events.

Liquidity issues could lead our customers to go into bankruptcy or could encourage our customers to seek to repudiate, cancel, or renegotiate our contracts for various reasons. Some of our contracts permit early termination of the contract by the customer for convenience (without cause), generally exercisable upon advance notice to us and in some cases without making an early termination payment to us. There can be no assurance that our customers will be able or willing to fulfill their contractual commitments to us.

Significant declines in oil prices, the perceived risk of low oil prices for an extended period, and the resulting downward pressure on utilization may cause some customers to consider early termination of select contracts despite having to pay early termination fees in some cases. In addition, customers may request to re-negotiate the terms of existing contracts. Furthermore, as our existing contracts roll off, we may be unable to secure replacement contracts for our rigs, equipment or services. We have been in discussions with some of our customers regarding these issues. Therefore, revenues recorded in future periods could differ materially from our current contracted revenues, which could have a material adverse effect on our financial position, results of operations or cash flows.

Certain of our contracts are subject to cancellation by our customers without penalty and with little or no notice.

In periods of extended market weakness similar to the current environment, our customers may not be able to honor the terms of existing contracts, may terminate contracts even where there may be onerous termination fees, or may seek to renegotiate contract dayrates and terms in light of depressed market conditions. Certain of our contracts are subject to cancellation by our customers without penalty and with relatively little or no notice. Significant declines in oil prices, the perceived risk of low oil prices for an extended period, and the resulting downward pressure on utilization and may cause some customers to consider early termination of select contracts despite having to pay early termination fees in some cases. When drilling market conditions are depressed, a customer may no longer need a rig or rental tools currently under contract or may be able to obtain comparable equipment at lower dayrates. Further, due to government actions, a customer may no longer be able to operate in, or it may not be economical to operate in, certain regions. As a result, customers may leverage their termination rights in an effort to renegotiate contract terms.

Our customers may also seek to terminate contracts for cause, such as the loss of or major damage to the drilling unit or other events that cause the suspension of drilling operations beyond a specified period of time. If we experience operational problems or if our equipment fails to function properly and cannot be repaired promptly, our customers will not be able to engage in drilling operations and may have the right to terminate the contracts. If equipment is not timely delivered to a customer or does not pass acceptance testing, a customer may in certain circumstances have the right to terminate the contract. The payment of a termination fee may not fully compensate us for the loss of the contract. Early termination of a contract may result in a rig or other equipment being idle for an extended period of time. The likelihood that a customer may seek to terminate a contract is increased during periods of market weakness. The cancellation or renegotiation of a number of our contracts could materially reduce our revenues and profitability.

Service contracts with national oil companies may expose us to greater risks than we normally assume in service contracts with non-governmental customers.

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We currently provide services and own rigs and other equipment that may be used in connection with projects involving national oil companies. In the future, we may expand our international operations and enter into additional, significant contracts or subcontracts relating to projects with national oil companies. The terms of these contracts may require us to resolve disputes in jurisdictions with less robust legal systems and may contain non-negotiable provisions and may expose us to greater commercial, political, environmental, operational, and other risks than we assume in other contracts. These contracts may also expose us to materially greater environmental liability and other claims for damages (including consequential damages) and personal injury related to our operations, or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, or under certain conditions that may not provide us with an early termination payment. We can provide no assurance that increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs or amount of equipment and services contracted to national oil companies with commensurate additional contractual risks. Risks that accompany contracts relating to projects with national oil companies could ultimately have a material adverse impact on our business, financial condition, and results of operation.

We derive a significant amount of our revenues from a few major customers. The loss of a significant customer could adversely affect us.

A substantial percentage of our revenues are generated from a relatively small number of customers and the loss of a significant customer could adversely affect us. In 2017, our largest customer, ENL, accounted for approximately 31.3 percent of our consolidated revenues. In 2017, our second largest customer, BP, constituted approximately 9.7 percent of our consolidated revenues. Our consolidated results of operations could be adversely affected if any of our significant customers terminate their contracts with us, fail to renew our existing contracts, or do not award new contracts to us.

A slowdown in economic activity may result in lower demand for our drilling and drilling related services and rental tools business, and could have a material adverse effect on our business.

A slowdown in economic activity in the United States or abroad could lead to uncertainty in corporate credit availability and capital market access and could reduce worldwide demand for energy and result in lower crude oil and natural gas prices. Concerns about global economic conditions have had a significant adverse impact on domestic and international financial markets and commodity prices, including oil and natural gas. Likewise, economic conditions in the United States or abroad could impact our vendors’ and suppliers’ ability to meet obligations to provide materials and services in general. All of these factors could have a material adverse effect on our business and financial results.

The contract drilling and the rental tools businesses are highly competitive and cyclical, with intense price competition.

The contract drilling and rental tools markets are highly competitive and many of our competitors in both the contract drilling and rental tools businesses may possess greater financial resources than we do. Some of our competitors also are incorporated in countries that may provide them with significant tax advantages that are not available to us as a U.S. company and which may impair our ability to compete with them for many projects.

Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Many drilling and workover rigs can be moved from one region to another in response to changes in levels of activity, provided market conditions warrant, which may result in an oversupply of rigs in an area. Many competitors construct rigs during periods of high energy prices and, consequently, the number of rigs available in some of the markets in which we operate can exceed the demand for rigs for extended periods of time, resulting in intense price competition. Most drilling contracts are awarded on the basis of competitive bids, which also results in price competition. Historically, the drilling service industry has been highly cyclical, with periods of high demand, limited equipment supply and high dayrates often followed by periods of low demand, excess equipment supply and low dayrates. Periods of low demand and excess equipment supply intensify the competition in the industry and often result in equipment being idle for long periods of time. During periods of decreased demand we typically experience significant reductions in dayrates and utilization. The Company, or its competition, may move rigs or other equipment from one geographic location to another location; the cost of which may be substantial. If we experience further reductions in dayrates or if we cannot keep our equipment utilized, our financial performance will be adversely impacted. Prolonged periods of low utilization and dayrates could result in the recognition of impairment charges on certain of our rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

Rig upgrade, refurbishment and construction projects are subject to risks and uncertainties, including delays and cost overruns, which could have an adverse impact on our results of operations and cash flows.

We regularly make significant expenditures in connection with upgrading and refurbishing our rig fleet. These activities include planned upgrades to maintain quality standards, routine maintenance and repairs, changes made at the request of customers,

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and changes made to comply with environmental or other regulations. Rig upgrade, refurbishment, and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:


•	shortages of equipment or skilled labor;


•	unforeseen engineering problems;


•	unanticipated change orders;


•	work stoppages;


•	adverse weather conditions;


•	unexpectedly long delivery times for manufactured rig components;


•	unanticipated repairs to correct defects in construction not covered by warranty;


•	failure or delay of third-party equipment vendors or service providers;


•	unforeseen increases in the cost of equipment, labor or raw materials, particularly steel;


•	disputes with customers, shipyards or suppliers;


•	latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;


•	financial or other difficulties with current customers at shipyards and suppliers;


•	loss of revenues associated with downtime to remedy malfunctioning equipment not covered by warranty;


•	unanticipated cost increases;


•	loss of revenues and payments of liquidated damages for downtime to perform repairs associated with defects, unanticipated equipment refurbishment and delays in commencement of operations; and


•	lack of ability to obtain the required permits or approvals, including import/export documentation.

Any one of the above risks could adversely affect our financial condition and results of operations. Delays in the delivery of rigs being constructed or undergoing upgrade, refurbishment, or repair may, in many cases, delay commencement of a drilling contract resulting in a loss of revenues to us, and may also cause our customer to renegotiate the drilling contract for the rig or terminate or shorten the term of the contract under applicable late delivery clauses, if any. If one of these contracts is terminated, we may not be able to secure a replacement contract on as favorable terms, if at all. Additionally, actual expenditures for required upgrades or to refurbish or construct rigs could exceed our planned capital expenditures, impairing our ability to service our debt obligations.

Our international operations are subject to governmental regulation and other risks.

We derive a significant portion of our revenues from our international operations. In 2017, we derived approximately 60 percent of our revenues from operations in countries other than the United States. Our international operations are subject to the following risks, among others:


•	political, social, and economic instability, war, terrorism, and civil disturbances;


•	economic sanctions imposed by the U.S. government against other countries, groups, or individuals, or economic sanctions imposed by other governments against the U.S. or businesses incorporated in the U.S.;


•	limitations on insurance coverage, such as war risk coverage, in certain areas;


•	expropriation, confiscatory taxation, and nationalization of our assets;


•	foreign laws and governmental regulation, including inconsistencies and unexpected changes in laws or regulatory requirements, and changes in interpretations or enforcement of existing laws or regulations;


•	increases in governmental royalties;

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•	import-export quotas or trade barriers;


•	hiring and retaining skilled and experienced workers, some of whom are represented by foreign labor unions;


•	work stoppages;


•	damage to our equipment or violence directed at our employees, including kidnapping;


•	piracy of vessels transporting our people or equipment;


•	unfavorable changes in foreign monetary and tax policies;


•	solicitation by government officials for improper payments or other forms of corruption;


•	foreign currency fluctuations and restrictions on currency repatriation;


•	repudiation, nullification, modification, or renegotiation of contracts; and


•	other forms of governmental regulation and economic conditions that are beyond our control.

We currently have operations in 19 countries. Our operations are subject to interruption, suspension, and possible expropriation due to terrorism, war, civil disturbances, political and capital instability, and similar events, and we have previously suffered loss of revenues and damage to equipment due to political violence. Civil and political disturbances in international locations may affect our operations. We may not be able to obtain insurance policies covering risks associated with these types of events, especially political violence coverage, and such policies may only be available with premiums that are not commercially reasonable.

Our international operations are subject to the laws and regulations of a number of countries with political, regulatory and judicial systems and regimes that may differ significantly from those in the U.S. Our ability to compete in international contract drilling and rental tool markets may be adversely affected by foreign governmental regulations and/or policies that favor the awarding of contracts to contractors in which nationals of those foreign countries have substantial ownership interests or by regulations requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, our foreign subsidiaries may face governmentally imposed restrictions or fees from time to time on the transfer of funds to us.

In addition, tax and other laws and regulations in some foreign countries are not always interpreted consistently among local, regional, and national authorities, which can result in disputes between us and governing authorities. The ultimate outcome of these disputes is never certain, and it is possible that the outcomes could have an adverse effect on our financial performance.

A portion of the workers we employ in our international operations are members of labor unions or otherwise subject to collective bargaining. We may not be able to hire and retain a sufficient number of skilled and experienced workers for wages and other benefits that we believe are commercially reasonable.

We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not take protective measures against exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange, or controls over the repatriation of income or capital. Given the international scope of our operations, we are exposed to risks of currency fluctuation and restrictions on currency repatriation. We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts payable in U.S. dollars or freely convertible foreign currency. In addition, some parties with which we do business could require that all or a portion of our revenues be paid in local currencies. Foreign currency fluctuations, therefore, could have a material adverse effect upon our results of operations and financial condition.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by the unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the export and re-export of certain goods, services, and technology and impose related export recordkeeping and reporting obligations. Governments may also impose economic sanctions against certain countries, persons, and other entities that may restrict or prohibit transactions involving such countries, persons, and entities. For example, in 2017 the U.S. Government imposed additional sanctions against Russia’s oil and gas industry and certain Russian companies. Our ability to engage in certain future projects in Russia or involving certain Russian customers is dependent upon whether or not our involvement in such projects is restricted under U.S. or EU sanctions laws and the extent to which any of our prospective operations in Russia or with certain Russian customers may be subject to those laws. The laws and regulations concerning import activity, export recordkeeping and reporting, export control, and economic sanctions are complex and constantly

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changing. These laws and regulations can cause delays in shipments and unscheduled operational downtime. Moreover, any failure to comply with applicable legal and regulatory trading obligations could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from governmental contracts, seizure of shipments, and loss of import and export privileges.

Our acquisitions, dispositions, and investments may not result in the realization of savings, the creation of efficiencies, the generation of cash or income, or the reduction of risk, which may have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

We continually seek opportunities to maximize efficiency and value through various transactions, including purchases or sales of assets, businesses, investments, or joint ventures. These transactions are intended to result in the realization of savings, the creation of efficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. These transactions may also affect our consolidated results of operations.

These transactions also involve risks, and we cannot ensure that:


•	any acquisitions would result in an increase in income or earnings per share;


•	any acquisitions would be successfully integrated into our operations and internal controls;


•	the due diligence prior to an acquisition would uncover situations that could result in financial or legal exposure, or that we will appropriately quantify the exposure from known risks;


•	any disposition would not result in decreased earnings, revenues, or cash flow;


•	use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other uses;


•	any dispositions, investments, acquisitions, or integrations would not divert management resources; or


•	any dispositions, investments, acquisitions, or integrations would not have a material adverse effect on our results of operations or financial condition.

Failure to comply with anti-corruption laws, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010, could result in fines, criminal penalties, negative commercial consequences and an adverse effect on our business.

The U.S. Foreign Corrupt Practices Act (FCPA), the U.K. Bribery Act 2010, and similar anti-corruption laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments or providing improper benefits for the purpose of obtaining or retaining business. Our policies mandate compliance with these anti-corruption laws. However, we operate in many parts of the world that experience corruption. If we are found to be liable for violations of these laws either due to our own acts or omissions or due to the acts or omissions of others (including our joint ventures partners, our agents or other third-party representatives), we could suffer from commercial, civil, and criminal penalties or other sanctions, which could have a material adverse effect on our business, financial condition, and results of operations.

Failure to attract and retain skilled and experienced personnel could affect our operations.

We require skilled, trained, and experienced personnel to provide our customers with the highest quality technical services and support for our drilling operations. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience we require. Competition for skilled labor and other labor required for our operations intensifies as the number of rigs activated or added to worldwide fleets or under construction increases, creating upward pressure on wages. In periods of high utilization, we have found it more difficult to find and retain qualified individuals. A shortage in the available labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. Increases in our operating costs could adversely affect our business and financial results. Moreover, the shortages of qualified personnel or the inability to obtain and retain qualified personnel could negatively affect the quality, safety, and timeliness of our operations.

We are not fully insured against all risks associated with our business.

We ordinarily maintain insurance against certain losses and liabilities arising from our operations. However, we do not insure against all operational risks in the course of our business. Due to the high cost, high self-insured retention, and limited coverage insurance for windstorms in the GOM we have elected not to purchase windstorm insurance for our inland barges in the GOM. Although we have retained the risk for physical loss or damage for these rigs arising from a named windstorm, we have procured insurance coverage for removal of a wreck caused by a windstorm. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial position, and results of operations.

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We are subject to hazards customary for drilling operations, which could adversely affect our financial performance if we are not adequately indemnified or insured.

Substantially all of our operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, cratering, oil and natural gas well fires and explosions, natural disasters, pollution, mechanical failure, and damage or loss during transportation. Some of our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather, and marine life infestations. These hazards could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations, or environmental damage, which could lead to claims by third parties or customers, suspension of operations, and contract terminations. We have had accidents in the past due to some of these hazards. Typically, we are indemnified by our customers for injuries and property damage resulting from these types of events (except for injury to our employees and subcontractors and property damage to ours and our subcontractors’ equipment). However, we could be exposed to significant loss if adequate indemnity provisions or insurance are not in place, if indemnity provisions are unenforceable or otherwise invalid, or if our customers are unable or unwilling to satisfy any indemnity obligations. We may not be able to insure against these risks or to obtain indemnification to adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event not fully insured against or for which we are not indemnified, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not continue to be available to cover any or all of these risks. For example, pollution, reservoir damage and environmental risks generally are not fully insurable. Even if such insurance is available, insurance premiums or other costs may rise significantly in the future, making the cost of such insurance prohibitive. For a description of our indemnification obligations and insurance, see Item 1. Business — Insurance and Indemnification.

Certain areas in and near the GOM are subject to hurricanes and other extreme weather conditions. When operating in and near the GOM, our drilling rigs and rental tools may be located in areas that could cause them to be susceptible to damage or total loss by these storms. In addition, damage caused by high winds and turbulent seas to our rigs, our shore bases, and our corporate infrastructure could potentially cause us to curtail operations for significant periods of time until the effects of the damage can be repaired. In addition, our rigs in arctic regions can be affected by seasonal weather so severe that conditions are deemed too unsafe for operations.

Government regulations may reduce our business opportunities and increase our operating costs.

Government regulations control and often limit access to potential markets and impose extensive requirements concerning employee privacy and safety, environmental protection, pollution control, and remediation of environmental contamination. Environmental regulations, including species protections, prohibit access to some locations and make others less economical, increase equipment and personnel costs, and often impose liability without regard to negligence or fault. In addition, governmental regulations, such as those related to climate change, emissions, and hydraulic fracturing, may discourage our customers’ activities, reducing demand for our products and services. We may be liable for damages resulting from pollution and, under United States regulations, must establish financial responsibility in order to drill offshore. See Item 1. Business — Environmental Considerations.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

Some scientific studies have suggested that emissions of greenhouse gases may be contributing to warming of the earth’s atmosphere and other climatic changes. Such studies have resulted in increased local, state, regional, national, and international attention and actions relating to issues of climate change and the effect of GHG emissions, particularly emissions from fossil fuels. For example, the United States has been involved in international negotiations regarding greenhouse gas reductions under the UNFCCC. The U.S. was among 195 nations that participated in the creation of an international accord in December 2015, the Paris Agreement, with the objective of limiting greenhouse gas emissions. The Paris Agreement entered into force on November 4, 2016 and, as of late 2017, had been ratified by 174 of the 197 parties to the UNFCC. However, on August 4, 2017, the United States formally communicated to the United Nations its intent to withdraw from participation in the Paris Agreement, which entails a four-year process. The EPA has also taken action under the CAA to regulate greenhouse gas emissions. In addition, a number of states have either proposed or implemented restrictions on greenhouse gas emissions. International accords such as the Paris Agreement may result in additional regulations to control greenhouse gas emissions. Other developments focused on restricting GHG emissions include but are not limited to the Kyoto Protocol; the European Union Emission Trading System; the United Kingdom’s Carbon Reduction Commitment; and, in the U.S., the Regional Greenhouse Gas Initiative, the Western Regional Climate Action Initiative, and various state programs. These regulations could also adversely affect market demand or pricing for our services, by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources.

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Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements 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, regulations, treaties, or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties, or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations.

We are regularly involved in litigation, some of which may be material.

We are regularly involved in litigation, claims, and disputes incidental to our business, which at times may involve claims for significant monetary amounts, some of which would not be covered by insurance. We undertake all reasonable steps to defend ourselves in such lawsuits. Nevertheless, we cannot predict the ultimate outcome of such lawsuits and any resolution which is adverse to us could have a material adverse effect on our financial condition. See Note 13 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data for a discussion of the material legal proceedings affecting us.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the demand for rental tools.

Hydraulic fracturing is a process sometimes used in the completion of oil and natural gas wells whereby water, other liquids, sand, and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, oil production. Various governmental entities (within and outside the United States) are in the process of studying, restricting, regulating, or preparing to regulate hydraulic fracturing, directly and indirectly. Many state governments require the disclosure of chemicals used in the fracturing process and, due to concerns raised relating to potential impacts of hydraulic fracturing, including on groundwater quality and seismic activity, legislative and regulatory efforts at the federal level and in some state and local jurisdictions have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. We do not directly engage in hydraulic fracturing activities. However, these and other developments could cause operational delays or increased costs in exploration and production, which could adversely affect the demand for our rental tools.

A cybersecurity incident could negatively impact our business and our relationships with customers.

Our businesses and the oil and natural gas industry in general have become increasingly dependent on digital data, computer networks, and connected infrastructure. Digital technologies are subject to the risk of cyber-attack and other failures. If our systems for protecting against cybersecurity risks prove insufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer and employee data, having our business operations interrupted, and increased costs to prevent, respond to, or mitigate cybersecurity attacks. These risks could harm our relationships with customers, employees and other third parties, and have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common stock, which would have an adverse impact on the trading volume, liquidity and market price of our common stock.

If the average closing price of our common shares were to fall below $1.00 over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE under Section 802.01C of the NYSE Listed Company Manual, we would no longer be in compliance with the NYSE’s continued listing requirements and would expect to receive a notice of noncompliance from the NYSE. The notice would have no immediate impact on the listing of our common shares, which would continue to be listed and traded on the NYSE during the six-month period described below, subject to our compliance with other continued listing standards.

We would have six months following receipt of the NYSE’s notice to regain compliance with the NYSE’s minimum share price requirement. We would be able to regain compliance at any time during the six-month cure period if on the last trading day of any calendar month during the cure period our common shares has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last trading day of such month. Notwithstanding the foregoing, if we were to determine that we must cure the price condition by taking an action that would require approval of our shareholders (such as a reverse stock split), we could also regain compliance by: (i) obtaining the requisite shareholder approval by no later than our next annual meeting and (ii) implementing the action promptly thereafter, such that the price of our common stock would promptly exceed $1.00 per share, provided that the price must remain above that level for at least the following 30 trading days. However, there is no assurance that our stockholders would vote for such proposal.

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On January 2, 2018, we received a notice from the NYSE that the average closing price of our common stock over a 30 consecutive trading day period was below $1.00 per share, and, as a result, the price per share of the common stock was below the minimum average closing price required to maintain listing on the NYSE. Though we regained compliance with the NYSE continued listing requirements on January 31, 2018, we cannot assure you that the average closing price of our common stock over a consecutive 30 trading-day period will not fall below $1.00 per share in the future. A delisting of our common stock from the NYSE could negatively impact us as it would likely reduce the liquidity and market price of our common stock; reduce the number of investors willing to hold or acquire our common stock; and negatively impact our ability to access equity markets and obtain financing.

The market price of our common stock has fluctuated significantly.

The market price of our common stock may continue to fluctuate in response to various factors and events, many of which are beyond our control, including the following:


•	the other risk factors described in this Form 10-K, including changes in oil and natural gas prices;


•	a shortfall in rig utilization, operating revenues, or net income from that expected by securities analysts and investors;


•	changes in securities analysts’ estimates of the financial performance of us or our competitors or the financial performance of companies in the oilfield service industry generally;


•	changes in actual or market expectations with respect to the amounts of exploration and development spending by oil and natural gas companies;


•	general conditions in the economy and in energy-related industries;


•	general conditions in the securities markets;


•	political instability, terrorism, or war; and


•	the outcome of pending and future legal proceedings, investigations, tax assessments, and other claims.

We do not anticipate paying any dividends on our common stock in the foreseeable future.

We do not anticipate paying any dividends on our common stock in the foreseeable future and the terms of our existing indebtedness restricts our ability to pay dividends on our common stock. Any declaration and payment of future dividends to holders of our common stock may be limited by the provisions of the Delaware General Corporation Law and our indebtedness. The future payment of dividends on our common stock will be at the sole discretion of our board of directors and will depend on many factors, including our earnings, capital requirements, financial condition, and other considerations that our board of directors deems relevant.

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FORWARD-LOOKING STATEMENTS

This Form 10-K contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended, (the Exchange Act). All statements contained in this Form 10-K, other than statements of historical facts, are forward-looking statements for purposes of these provisions. In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses we make in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are relevant. Although we believe that our assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. Each forward-looking statement speaks only as of the date of this Form 10-K, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. You should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-K could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

We lease corporate headquarters office space in Houston, Texas and own our U.S. rental tools headquarters office in New Iberia, Louisiana. We lease regional headquarters space in Dubai, United Arab Emirates related to our international rental tools segment and Eastern Hemisphere drilling operations. Additionally, we own and/or lease office space and operating facilities in various other locations, domestically and internationally, including facilities where we hold inventories of rental tools and locations in close proximity to where we provide services to our customers. Additionally, we own and/or lease facilities necessary for administrative and operational support functions.

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Land and Barge Rigs

The table below shows the locations and drilling depth ratings of our rigs as of December 31, 2017:



Name	Type⁽¹⁾	Year entered into service/ upgraded	Drilling depth rating (in feet)	Location

International & Alaska Drilling
Eastern Hemisphere
Rig 231	L	1981/1997	13,000	Indonesia
Rig 253	L	1982/1996	15,000	Indonesia
Rig 107	L	1983/2009	15,000	Kazakhstan
Rig 216	L	2001/2009	25,000	Kazakhstan
Rig 249	L	2000/2009	25,000	Kazakhstan
Rig 257	B	1999/2010	30,000	Kazakhstan
Rig 258	L	2001/2009	25,000	Kazakhstan
Rig 247	L	1981/2008	20,000	Iraq, Kurdistan Region
Rig 269	L	2008	21,000	Iraq, Kurdistan Region
Rig 265	L	2007	20,000	Iraq, Kurdistan Region
Rig 264	L	2007	20,000	Tunisia
Rig 270	L	2011	21,000	Russia
Latin America
Rig 271	L	1982/2009	30,000	Colombia
Rig 266	L	2008	20,000	Guatemala
Rig 122	L	1980/2008	18,000	Mexico
Rig 165	L	1978/2007	30,000	Mexico
Rig 221	L	1982/2007	30,000	Mexico
Rig 256	L	1978/2007	25,000	Mexico
Rig 267	L	2008	20,000	Mexico
Alaska
Rig 272	L	2013	18,000	Alaska
Rig 273	L	2012	18,000	Alaska
U.S. (Lower 48) Drilling
Rig 8	B	1978/2007	14,000	GOM
Rig 12	B	1979/2006	18,000	GOM
Rig 15	B	1978/2007	15,000	GOM
Rig 20	B	1981/2007	13,000	GOM
Rig 21	B	1979/2012	14,000	GOM
Rig 30	B	2014	18,000	GOM
Rig 50	B	1981/2006	20,000	GOM
Rig 51	B	1981/2008	20,000	GOM
Rig 54	B	1980/2006	25,000	GOM
Rig 55	B	1981/2014	25,000	GOM
Rig 72	B	1982/2005	25,000	GOM
Rig 76	B	1977/2009	30,000	GOM
Rig 77	B	2006/2006	30,000	GOM

(1) Type is defined as: L — land rig; B — barge rig.

The table above excludes Rig 121 and Rig 268, located in Colombia, which are currently not available for service. Additionally, during 2017 we sold Rig 226, located in Papua New Guinea.

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Item 3. Legal Proceedings

For information on Legal Proceedings, see Note 13 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data, which information is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Parker Drilling Company’s common stock is listed for trading on the New York Stock Exchange under the symbol “PKD.” The following table sets forth the high and low sales prices per share of our common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:



	2017				2016
Quarter	High		Low		High		Low
First	$	2.90	$	1.35	$	2.34	$	0.98
Second	$	1.85	$	1.15	$	3.16	$	2.00
Third	$	1.43	$	1.10	$	2.44	$	1.84
Fourth	$	1.20	$	0.85	$	2.90	$	1.70

Most of our stockholders maintain their shares as beneficial owners in “street name” accounts and are not, individually, stockholders of record. As of February 16, 2018, there were 1,501 holders of record of our shares and we had an estimated 16,600 beneficial owners.

Our 2015 Secured Credit Agreement and the indentures for the Senior Notes limit the payment of dividends. In the past we have not paid dividends on our common stock and we have no present intention to pay dividends on our common stock in the foreseeable future.

Issuer Purchases of Equity Securities

The Company currently has no active share repurchase programs.

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Item 6. Selected Financial Data

The following table presents selected historical consolidated financial data derived from the audited financial statements of Parker Drilling Company for each of the five years in the period ended December 31, 2017. The following financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.



	Year Ended December 31,
	2017			2016			2015			2014		2013 (1)
Dollars in Thousands, Except Per Share Amounts
Income Statement Data
Total revenues	$	442,520		$	427,004		$	712,183		$	968,684	$	874,172
Total operating income (loss)	(65,805		)	(111,257		)	(17,338		)	120,220		101,872
Net income (loss)	(118,701		)	(230,814		)	(94,284		)	24,461		27,179
Net income (loss) attributable to controlling interest	(118,701		)	(230,814		)	(95,073		)	23,451		27,015
Net income (loss) available to common stockholders	(121,752		)	(230,814		)	(95,073		)	23,451		27,015
Basic earnings per share:
Net income (loss)	$	(0.87	)	$	(1.86	)	$	(0.77	)	$	0.20	$	0.23
Net income (loss) attributable to controlling interest	$	(0.87	)	$	(1.86	)	$	(0.78	)	$	0.19	$	0.23
Net income (loss) available to common stockholders	$	(0.89	)	$	(1.86	)	$	(0.78	)	$	0.19	$	0.23
Diluted earnings per share:
Net income (loss)	$	(0.87	)	$	(1.86	)	$	(0.77	)	$	0.20	$	0.22
Net income (loss) attributable to controlling interest	$	(0.87	)	$	(1.86	)	$	(0.78	)	$	0.19	$	0.22
Net income (loss) available to common stockholders	$	(0.89	)	$	(1.86	)	$	(0.78	)	$	0.19	$	0.22
Balance Sheet Data
Total assets ⁽²⁾	$	990,279		$	1,103,551		$	1,366,702		$	1,509,000	$	1,521,775
Total long-term debt including current portion of long-term debt ⁽²⁾	577,971			576,326			574,798			603,341		640,800
Total equity	296,121			339,135			568,512			666,214		633,142


(1)	The 2013 results include $22.5 million of acquisition costs related to the acquisition of International Tubular Services Limited on April 22, 2013.


(2)	The Company adopted, effective January 1, 2016, newly issued accounting guidance ASU 2015-03, Interest - Imputation of Interest - Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the debt liability rather than as an asset.

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

Management’s discussion and analysis (MD&A) should be read in conjunction with Item 8. Financial Statements and Supplementary Data.

Executive Summary

The oil and natural gas industry is highly cyclical. Activity levels are driven by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, footage drilled, well counts, and our customers’ spending levels allocated to exploratory and development drilling.

Historical market indicators are listed below:



	2017		% Change		2016		% Change		2015
Worldwide Rig Count ⁽¹⁾
U.S. (land and offshore)	875		72	%	510		(48	)%	978
International ⁽²⁾	948		(1	)%	955		(18	)%	1,167
Commodity Prices (annual average) ⁽³⁾
Crude Oil (Brent)	$	54.74	21	%	$	45.13	(16	)%	$	53.6
Crude Oil (West Texas Intermediate)	$	50.85	17	%	$	43.47	(11	)%	$	48.78
Natural Gas (Henry Hub)	$	3.02	18	%	$	2.55	(3	)%	$	2.63

(1) Estimate of drilling activity as measured by annual average active rig count for the periods indicated - Source: Baker Hughes Rig Count.

(2) Excludes Canadian Rig Count.

(3) Average daily commodity prices for the periods indicated based on NYMEX front-month composite energy prices.

Financial Results

In the 2017 fourth quarter we generated revenues of $116.3 million, an increase of $22.3 million, or 23.7 percent, compared with the 2016 fourth quarter. In 2017, revenues totaled $442.5 million, an increase of $15.5 million, or 3.6 percent, compared with 2016. The increases were primarily driven by higher U.S. land rentals associated with continued improved customer activity.

Overview

In 2017, gross margin, excluding depreciation and amortization, increased 35 percent. This is indicative of the efforts our employees are taking to insure we continue to grow the business while maintaining focus on our costs. We have thoroughly streamlined our company's cost structure to maximize future margin, positioning the company for continued improvement going forward.

Our U.S. Rental Tools business benefited from higher spending by shale operators as our 2017 revenues increased by 70 percent compared to 2016. In our International Rental Tools business, gross margin improved throughout the year and we achieved positive gross margin in the fourth quarter. Although our drilling services business has not yet seen the impact of higher commodity prices, we are well positioned with strong customer relationships and quality equipment as the recovery unfolds.

Some of our noteworthy achievements during the year include:


•	The year 2017 was the safest in our recorded history and 95 percent of our active world-wide facilities went the entire year without a recordable incident as we continue to target zero injuries.


•	In October 2017, we attained the International Association of Drilling Contractors' Competence Assurance Accreditation.


•	2017 was a record for our rig operations group as we limited rig downtime to less than 0.5 percent. Our operating rig in Alaska achieved two years without a single minute of downtime.


•	We secured international land rig contracts throughout the year as International & Alaska Drilling segment utilization increased from a low of 32 percent in the three months ended June 30, 2017 to 40 percent for the three months ended December 31, 2017. Specifically, we were able to execute contracts in the Kurdistan Region of Iraq and in Indonesia. We

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also received a letter of intent for a second rig to begin drilling in the Kurdistan Region of Iraq early in 2018, with growing interest in our services in the region.


•	During the fourth quarter, as a part of our push to reduce the number of countries where we have one rig operations, we sold our rig in Papua New Guinea. The rig had been idle since May 2015 and we saw limited opportunity to put it to work. Closing the Papua New Guinea operation enables us to build scale in more favorable geographic locations as well as gain better returns on our assets.


•	Finally, in February 2018 we amended our 2015 Secured Credit Agreement to replace financial maintenance covenants with a borrowing base and liquidity covenant, which we believe will help ensure we have available liquidity in addition to our cash on hand, in light of the delayed recovery in international markets.

Outlook

The year 2017 was a year of transition, as the oil and gas markets began to show increasing signs that an international recovery was taking hold. After years of underinvestment and tepid activity, it appears that fundamentals are finally coming further into balance, though at a very gradual pace. North American markets are growing, driven mostly by unconventional wells and oil exports; and international markets appear to have stabilized and are positioned for growth. We continue to believe market conditions are poised to improve over the medium term.

In our U.S. (Lower 48) Drilling segment, based on discussion with operators in the region, we anticipate utilization to improve year-on-year, weighted toward the second half of the year. For our International & Alaska Drilling segment, we expect activity to gradually improve in the second half of 2018, but the segment will likely have lower gross margin compared to 2017 as a result of lower utilization in Alaska and Kazakhstan.

In our U.S. Rental Tools segment, we anticipate higher utilization of our rental equipment as U.S. land oil and gas drilling activity increases. For our International Rental Tools segment, we expect higher activity levels largely driven by the additional well construction work.

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Results of Operations

We analyze financial results for each of our reportable segments. The reportable segments presented are consistent with our reportable segments discussed in our consolidated financial statements. See Note 12 - Reportable Segments in Item 8. Financial Statements and Supplementary Data for further discussion. We monitor our reporting segments based on several criteria, including operating gross margin and operating gross margin excluding depreciation and amortization. Operating gross margin excluding depreciation and amortization is computed as revenues less direct operating expenses, and excludes depreciation and amortization expense, where applicable. Operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin excluding depreciation and amortization amounts and percentages should not be used as a substitute for those amounts reported under accounting policies generally accepted in the United States (U.S. GAAP), but should be viewed in addition to the Company’s reported results prepared in accordance with U.S. GAAP. Management believes this information provides valuable insight into the information management considers important in managing the business.

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Year Ended December 31, 2017 Compared with Year Ended December 31, 2016

Revenues increased $15.5 million, or 3.6 percent, to $442.5 million for the year ended December 31, 2017 as compared with revenues of $427.0 million for the year ended December 31, 2016. Operating gross margin increased $40.0 million to a loss of $35.3 million for the year ended December 31, 2017 as compared with a loss of $75.3 million for the year ended December 31, 2016.

The following is an analysis of our operating results for the comparable periods by reportable segment:



	Year Ended December 31,
	2017					2016
Dollars in Thousands
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	12,389		3	%	$	5,429		1	%
International & Alaska Drilling	247,254			56	%	287,332			67	%
Total Drilling Services	259,643			59	%	292,761			68	%
Rental Tools Services:
U.S. Rental Tools	121,937			27	%	71,613			17	%
International Rental Tools	60,940			14	%	62,630			15	%
Total Rental Tools Services	182,877			41	%	134,243			32	%
Total revenues	442,520			100	%	427,004			100	%
Operating gross margin (loss) excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(7,135		)	(58	)%	(14,304		)	(263	)%
International & Alaska Drilling	40,702			16	%	64,508			22	%
Total Drilling Services	33,567			13	%	50,204			17	%
Rental Tools Services:
U.S. Rental Tools	59,140			49	%	21,397			30	%
International Rental Tools	(5,674		)	(9	)%	(7,118		)	(11	)%
Total Rental Tools Services	53,466			29	%	14,279			11	%
Total operating gross margin (loss) excluding depreciation and amortization	87,033			20	%	64,483			15	%
Depreciation and amortization	(122,373		)			(139,795		)
Total operating gross margin (loss)	(35,340		)			(75,312		)
General and administrative expense	(25,676		)			(34,332		)
Provision for reduction in carrying value of certain assets	(1,938		)			—
Gain (loss) on disposition of assets, net	(2,851		)			(1,613		)
Total operating income (loss)	$	(65,805	)			$	(111,257	)

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Operating gross margin (loss) amounts are reconciled to our most comparable U.S. GAAP measure as follows:



Dollars in Thousands	U.S. (Lower 48) Drilling			International & Alaska Drilling			U.S. Rental Tools			International Rental Tools			Total
Year Ended December 31, 2017
Operating gross margin (loss)⁽¹⁾	$	(20,656	)	$	(6,248	)	$	15,651		$	(24,087	)	$	(35,340	)
Depreciation and amortization	13,521			46,950			43,489			18,413			122,373
Operating gross margin (loss) excluding depreciation and amortization	$	(7,135	)	$	40,702		$	59,140		$	(5,674	)	$	87,033
Year Ended December 31, 2016
Operating gross margin (loss)⁽¹⁾	$	(34,353	)	$	9,272		$	(22,372	)	$	(27,859	)	$	(75,312	)
Depreciation and amortization	20,049			55,236			43,769			20,741			139,795
Operating gross margin (loss) excluding depreciation and amortization	$	(14,304	)	$	64,508		$	21,397		$	(7,118	)	$	64,483


(1)	Operating gross margin (loss) is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

The following table presents our average utilization rates and rigs available for service for the years ended December 31, 2017 and 2016, respectively:



	December 31,
	2017		2016
U.S. (Lower 48) Drilling
Rigs available for service ⁽¹⁾	13.0		13.0
Utilization rate of rigs available for service ⁽²⁾	11	%	5	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service ⁽¹⁾	13.0		13.0
Utilization rate of rigs available for service ⁽²⁾	38	%	40	%
Latin America Region
Rigs available for service ⁽¹⁾	7.0		7.0
Utilization rate of rigs available for service ⁽²⁾	14	%	23	%
Alaska
Rigs available for service ⁽¹⁾	2.0		2.0
Utilization rate of rigs available for service ⁽²⁾	97	%	100	%
Total International & Alaska Drilling
Rigs available for service ⁽¹⁾	22.0		22.0
Utilization rate of rigs available for service ⁽²⁾	36	%	40	%

(1)

The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigs available for service during such year. Our method of computation of rigs available for service may not be comparable to other similarly titled measures of other companies.

(2)

Rig utilization rates are based on a weighted average basis assuming total days availability for all rigs available for service. Rigs acquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract that generate revenues during moves between locations or during mobilization or demobilization are also considered to be utilized. Our method of computation of rig utilization may not be comparable to other similarly titled measures of other companies.

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Drilling Services Business

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues increased $7.0 million, or 129.6 percent, to $12.4 million for the year ended December 31, 2017, as compared with revenues of $5.4 million for the year ended December 31, 2016. The increase was primarily due to an increase in utilization to 11.0 percent for the year ended December 31, 2017 from 5.0 percent for the year ended December 31, 2016 as well as a moderate increase in revenues per day for certain barge rigs.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization increased $7.2 million, or 50.3 percent, to a loss of $7.1 million for the year ended December 31, 2017, compared with a loss of $14.3 million for the year ended December 31, 2016. This increase was primarily due to the increase in utilization discussed above and reduced costs resulting from organizational efficiency initiatives.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $40.0 million, or 13.9 percent, to $247.3 million for the year ended December 31, 2017, compared with $287.3 million for the year ended December 31, 2016.

The decrease in revenues was primarily due to the following:


•	a decrease of $21.9 million related to our project services activities;


•	a decrease in revenues from reimbursable costs (“reimbursable revenues”) of $11.7 million, which decreased revenues but had a minimal impact on operating margins;


•	a decrease of $10.5 million resulting from a combined decrease in utilization and revenues per day for certain Company-owned rigs. The decline in revenues per day is a direct result of certain Company-owned rigs shifting to standby mode during 2017 compared with operating mode during 2016; and


•	a decrease of $5.4 million from mobilization and demobilization activities.

The decrease in revenues was partially offset by an increase of $11.3 million primarily driven by O&M activities associated with the Hibernia platform located off the Atlantic Coast of Canada.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $23.8 million, or 36.9 percent, to $40.7 million for the year ended December 31, 2017, compared with $64.5 million for the year ended December 31, 2016. The decrease in operating gross margin excluding depreciation and amortization was primarily due to a decrease in project services activities and the impact of reduced utilization discussed above.

Rental Tools Services Business

U.S. Rental Tools

U.S. Rental Tools segment revenues increased $50.3 million, or 70.3 percent, to $121.9 million for the year ended December 31, 2017 compared with $71.6 million for the year ended December 31, 2016. The increase was primarily driven by an increase in U.S. land rentals due to improved customer activity, partially offset by a decline in offshore GOM rental revenues.

U.S. Rental Tools segment operating gross margin excluding depreciation and amortization increased $37.7 million, or 176.2 percent, to $59.1 million for the year ended December 31, 2017 compared with $21.4 million for the year ended December 31, 2016. The increase was primarily due to the increase in revenues discussed above.

International Rental Tools

International Rental Tools segment revenues decreased $1.7 million, or 2.7 percent, to $60.9 million for the year ended December 31, 2017 compared with $62.6 million for the year ended December 31, 2016. The decrease was primarily attributable to a decline in offshore rental revenues somewhat offset by international land rental revenues.

International Rental Tools segment operating gross margin excluding depreciation and amortization increased $1.4 million, or 19.7 percent, to a loss of $5.7 million for the year ended December 31, 2017 compared with loss of $7.1 million for the year ended December 31, 2016. The increase was due to lower operating costs resulting from organizational efficiency initiatives.

Other Financial Data

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General and administrative expense

General and administrative expense decreased $8.6 million to $25.7 million for the year ended December 31, 2017, compared with $34.3 million for the year ended December 31, 2016 primarily due to reductions in incentive compensation and professional fees.

Provision for reduction in carrying value of certain assets

During the year ended December 31, 2017, we recorded $1.9 million of provisions for reduction in carrying value of assets, all of which was recorded in the fourth quarter of 2017. This provision was related to certain assets in the International & Alaska Drilling segment that were deemed to be functionally obsolete. There was no provision for reduction in carrying value of certain assets recorded during the year ended December 31, 2016.

Gain (loss) on disposition of assets

Net losses recorded on asset dispositions were $2.9 million and $1.6 million for the years ended December 31, 2017 and December 31, 2016, respectively. The net loss for 2017 was primarily related to the sale of one rig located in Papua New Guinea. Activity in both periods included equipment retirements. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense decreased $1.6 million to $44.2 million for the year ended December 31, 2017 compared with $45.8 million for the year ended December 31, 2016. The decrease in interest expense was primarily related to a write off of $1.1 million of debt issuance costs during the second quarter of 2016 in conjunction with the execution of an amendment to our revolving credit facility. Interest income during each of the years ended December 31, 2017 and 2016 was nominal.

Other income and expense

Other income and expense was $0.1 million of income and $0.4 million of income for the years ended December 31, 2017 and December 31, 2016, respectively. Other income for both periods included the impact of foreign currency fluctuations.

Income tax expense

On December 22, 2017 the United States enacted the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act includes significant changes to U.S. corporate income tax laws, the most notable of which is a reduction in the U.S. corporate income tax rate from 35 percent to 21 percent, effective for tax years beginning January 1, 2018, and a one-time mandatory tax on previously deferred earnings of certain foreign subsidiaries associated with the transition from a worldwide to a modified territorial tax regime. The impact of the Tax Act for the year ended December 31, 2017 is discussed in more detail in Note 5 - Income Taxes of the Consolidated Financial Statements. As a result of the Company’s net deferred tax position, inclusive of valuation allowances, the provisions of the Tax Act are not expected to materially impact the Company’s cash tax position or effective tax rate in 2018. We are continuing our analysis of the effects the Tax Act will have on the Company in future periods.

Income tax expense was $9.0 million on a pre-tax loss of $109.7 million for the year ended December 31, 2017, compared with $74.2 million on pre-tax loss of $156.6 million for the year ended December 31, 2016. Our effective tax rate was negative 8.2 percent for the year ended December 31, 2017, compared with negative 47.3 percent for the year ended December 31, 2016. Income tax expense and our annual effective tax rate are primarily affected by the statutory tax rates applied in the jurisdictions where the income or losses are earned, and our ability to receive tax benefits for losses incurred. It is also affected by discrete items, such as return-to-accrual adjustments and changes in valuation allowances, and changes in reserves for uncertain tax positions, which may occur in any given year but are not consistent from year to year.

Income tax expense for the year ended December 31, 2017 includes a net tax benefit related to the change in valuation allowance of $14.6 million. The change in valuation allowance includes a benefit of $45.3 million related to the reduction in the corporate income tax rate under the Tax Act. This benefit was reduced by the change related to current net operating losses and other deferred taxes of $30.7 million. We established the valuation allowance based on the weight of available evidence, both positive and negative, including results of recent and current operations and our estimates of future taxable income or loss by jurisdiction in which we operate. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other business considerations. Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, could require us to adjust the valuation allowances.

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We are a U.S. based company that operates internationally through various branches and subsidiaries. Accordingly, our worldwide income tax provision includes the impact of income tax rates and foreign tax laws in the jurisdictions in which our operations are conducted and income is earned. We reported tax benefits for foreign statutory rates different from our U.S. statutory rate of $2.0 million and $3.6 million and tax expense of $13.1 million and $12.7 million for the impact of foreign tax laws in effect for the years ended December 31, 2017 and December 31, 2016, respectively. Differences between the U.S. and foreign tax rates and laws have a significant impact in Iraq, Kazakhstan, Mexico, Russia, United Arab Emirates and the United Kingdom.

Certain tax payments to foreign jurisdictions are available as credits to reduce tax expense in the U.S. and other foreign jurisdictions. We reported no tax benefits for foreign tax credits for the year ended December 31, 2017 and December 31, 2016. See Note 5 - Income Taxes in Item 8. Financial Statements and Supplementary Data for further discussion.

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Year Ended December 31, 2016 Compared with Year Ended December 31, 2015

Revenues decreased $285.2 million, or 40.0 percent, to $427.0 million for the year ended December 31, 2016 as compared with revenues of $712.2 million for the year ended December 31, 2015. Operating gross margin decreased $105.0 million to a loss of $75.3 million for the year ended December 31, 2016 as compared with $29.7 million for the year ended December 31, 2015.

The following is an analysis of our operating results for the comparable periods by reportable segment:



	Year Ended December 31,
	2016					2015
Dollars in Thousands
Revenues:
Drilling Services:
U.S. (Lower 48) Drilling	$	5,429		1	%	$	30,358		4	%
International & Alaska Drilling	287,332			67	%	435,096			61	%
Total Drilling Services	292,761			68	%	465,454			65	%
Rental Tools Services:
U.S. Rental Tools	71,613			17	%	141,889			20	%
International Rental Tools	62,630			15	%	104,840			15	%
Total Rental Tools Services	134,243			32	%	246,729			35	%
Total revenues	427,004			100	%	712,183			100	%
Operating gross margin (loss) excluding depreciation and amortization:
Drilling Services:
U.S. (Lower 48) Drilling	(14,304		)	(263	)%	(5,889		)	(19	)%
International & Alaska Drilling ⁽¹⁾	64,508			22	%	109,750			25	%
Total Drilling Services	50,204			17	%	103,861			22	%
Rental Tools Services:
U.S. Rental Tools	21,397			30	%	64,833			46	%
International Rental Tools	(7,118		)	(11	)%	17,199			16	%
Total Rental Tools Services	14,279			11	%	82,032			33	%
Total operating gross margin (loss) excluding depreciation and amortization	64,483			15	%	185,893			26	%
Depreciation and amortization	(139,795		)			(156,194		)
Total operating gross margin (loss)	(75,312		)			29,699
General and administrative expense	(34,332		)			(36,190		)
Provision for reduction in carrying value of certain assets	—					(12,490		)
Gain (loss) on disposition of assets, net	(1,613		)			1,643
Total operating income (loss)	$	(111,257	)			$	(17,338	)

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Operating gross margin (loss) amounts are reconciled to our most comparable U.S. GAAP measure as follows:



Dollars in Thousands	U.S. (Lower 48) Drilling			International & Alaska Drilling		U.S. Rental Tools			International Rental Tools			Total
Year Ended December 31, 2016
Operating gross margin (loss) ⁽¹⁾	$	(34,353	)	$	9,272	$	(22,372	)	$	(27,859	)	$	(75,312	)
Depreciation and amortization	20,049			55,236		43,769			20,741			139,795
Operating gross margin (loss) excluding depreciation and amortization	$	(14,304	)	$	64,508	$	21,397		$	(7,118	)	$	64,483
Year Ended December 31, 2015
Operating gross margin (loss)⁽¹⁾	$	(28,309	)	$	45,211	$	17,380		$	(4,583	)	$	29,699
Depreciation and amortization	22,420			64,539		47,453			21,782			156,194
Operating gross margin (loss) excluding depreciation and amortization	$	(5,889	)	$	109,750	$	64,833		$	17,199		$	185,893


(1)	Operating gross margin (loss) is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

The following table presents our average utilization rates and rigs available for service for the years ended December 31, 2016 and 2015, respectively:



	December 31,
	2016		2015
U.S. (Lower 48) Drilling
Rigs available for service ⁽¹⁾	13.0		13.0
Utilization rate of rigs available for service ⁽²⁾	5	%	15	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service ⁽¹⁾	13.0		13.0
Utilization rate of rigs available for service ⁽²⁾	40	%	66	%
Latin America Region
Rigs available for service ⁽¹⁾	7.0		9.0
Utilization rate of rigs available for service ⁽²⁾	23	%	40	%
Alaska
Rigs available for service ⁽¹⁾	2.0		2.0
Utilization rate of rigs available for service ⁽²⁾	100	%	100	%
Total International & Alaska Drilling
Rigs available for service ⁽¹⁾	22.0		24.0
Utilization rate of rigs available for service ⁽²⁾	40	%	59	%

(1)

(2)

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Drilling Services Business

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues decreased $25.0 million, or 82.2 percent, to $5.4 million for the year ended December 31, 2016, as compared with revenues of $30.4 million for the year ended December 31, 2015. The decrease was largely due to lower utilization driven by substantial reductions in drilling activity by operators in the inland waters of the GOM resulting from lower oil prices. Utilization declined to 5.0 percent for the year ended December 31, 2016 from 15.0 percent for the year ended December 31, 2015, resulting in a $15.2 million decrease in revenues. The remainder of the decrease in revenues was primarily due to a decrease of $6.8 million from our O&M contract supporting three platform operations located offshore California that ended during the 2015 fourth quarter, as well as $2.2 million resulting from reduced dayrates and reimbursable revenues.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $8.4 million, or 142.4 percent, to a loss of $14.3 million for the year ended December 31, 2016, compared with a $5.9 million loss for the year ended December 31, 2015. This decrease was primarily due to the decline in utilization and reduced dayrates discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $147.8 million, or 34.0 percent, to $287.3 million for the year ended December 31, 2016, compared with $435.1 million for the year ended December 31, 2015.

The decrease in revenues was primarily due to the following:


•	a decrease of $62.3 million, excluding reimbursable revenues, resulting from decreased utilization for Company-owned rigs. Utilization for the segment decreased to 40.0 percent for the year ended December 31, 2016 from 59.0 percent for the year ended December 31, 2015. The decline in utilization was primarily due to the decline in oil prices which led to reduced customer activity;


•	a decrease of $39.8 million driven by a decline in average revenues per day resulting from certain Company-owned and customer-owned rigs shifting to standby mode during 2016 compared with operating mode during 2015, as well as a reduction in average dayrates due to pricing pressures from customers resulting from the decline in oil prices;


•	a decrease in reimbursable revenues of $17.4 million, which decreased revenues but had a minimal impact on operating margins;


•	a decrease of $16.7 million from mobilization and demobilization activities; and


•	a decrease of $12.5 million related to our project services activities.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $45.3 million, or 41.3 percent, to $64.5 million for the year ended December 31, 2016, compared with $109.8 million for the year ended December 31, 2015. The decrease in operating gross margin excluding depreciation and amortization was primarily due to the impact of reduced utilization and reduced revenues per day discussed above.

Rental Tools Services Business

U.S. Rental Tools

U.S. Rental Tools segment revenues decreased $70.3 million, or 49.5 percent, to $71.6 million for the year ended December 31, 2016 compared with $141.9 million for the year ended December 31, 2015. The decrease was primarily driven by continued reduction in customer activity and pricing pressures resulting from lower oil prices impacting both U.S. land and offshore GOM rentals.

U.S. Rental Tools segment operating gross margin excluding depreciation and amortization decreased $43.4 million, or 67.0 percent, to $21.4 million for the year ended December 31, 2016 compared with $64.8 million for the year ended December 31, 2015. The decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.

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International Rental Tools

International Rental Tools segment revenues decreased $42.2 million, or 40.3 percent, to $62.6 million for the year ended December 31, 2016 compared with $104.8 million for the year ended December 31, 2015. The decrease was due to the continued reduction in customer activity and price erosion resulting from lower oil prices across most of our markets, with the largest declines in our U.K. North Sea, Asia Pacific and Latin America operations.

International Rental Tools segment operating gross margin excluding depreciation and amortization decreased $24.3 million, or 141.3 percent, to a loss of $7.1 million for the year ended December 31, 2016 compared with gross margin of $17.2 million for the year ended December 31, 2015. The decrease was due to the declines in oil prices and customer activity discussed above, partially offset by lower operating costs resulting from cost reduction efforts.

Other Financial Data

General and administrative expense

General and administrative expense decreased $1.9 million to $34.3 million for the year ended December 31, 2016, compared with $36.2 million for the year ended December 31, 2015. General and administrative expense for the year ended December 31, 2016 benefited from reduced personnel costs and lower legal and professional fees resulting from cost savings initiatives. These benefits were partially offset by a $0.9 million net severance charge recorded in the fourth quarter of 2016 related to executive departures. In addition, during the year ended December 31, 2015 we incurred higher professional and information technology expenses as we implemented the second phase of our new enterprise resource planning system in 2015.

Provision for reduction in carrying value of certain assets

There was no provision for reduction in carrying value of certain assets recorded during the year ended December 31, 2016. During the year ended December 31, 2015, we recorded $12.5 million of provisions for reduction in carrying value of assets including, $4.8 million associated with management’s decision to exit the Drilling Services business in Colombia and $7.5 million resulting from lower levels of activity impacting certain international rental tools and drilling equipment that management concluded were no longer marketable and the carrying value was no longer recoverable.

Gain (loss) on disposition of assets

Net losses recorded on asset dispositions for the year ended December 31, 2016 were $1.6 million and net gains recorded on asset dispositions for December 31, 2015 were $1.6 million. Activity in both periods included the results of asset sales. Additionally, we periodically sell equipment deemed to be excess, obsolete, or not currently required for operations. The net gains for the year ended December 31, 2015 were primarily due to an insurance settlement received during the period related to previously realized asset losses, partially offset by losses incurred during the 2015 fourth quarter related to equipment retirements.

Interest income and expense

Interest expense increased $0.6 million to $45.8 million for the year ended December 31, 2016 compared with $45.2 million for the year ended December 31, 2015. The increase in interest expense was primarily related to a write off of $1.1 million of debt issuance costs during the second quarter of 2016 in conjunction with the execution of an amendment to the 2015 Secured Credit Agreement on May 27, 2016. Interest income during each of the years ended December 31, 2016 and 2015 was nominal.

Other income and expense

Other income and expense was $0.4 million of income and $9.7 million of expense for the years ended December 31, 2016 and December 31, 2015, respectively. Foreign currency exchange losses decreased $2.3 million for the year ended December 31, 2016 compared with the year ended December 31, 2015. In addition, during the year ended December 31, 2016 we reclassified $1.9 million of realized foreign currency translation gains from accumulated other comprehensive income. Other expense for the year ended December 31, 2015 included a $4.8 million loss on the sale of our controlling interest in a consolidated joint venture in Egypt, and a $0.9 million loss on the divestiture of our controlling interest in a consolidated joint venture in Russia.

Income tax expense

Income tax expense was $74.2 million on a pre-tax loss of $156.6 million for the year ended December 31, 2016, compared with $22.3 million on a pre-tax loss of $72.0 million for the year ended December 31, 2015. Our effective tax rate was negative 47.4 percent for the year ended December 31, 2016, compared with negative 31.0 percent for the year ended December 31, 2015. Income tax expense and our annual effective tax rate are primarily affected by recurring items, such as the relative amounts of income or loss we earn in tax paying and non-tax paying jurisdictions, the statutory tax rates applied in the jurisdictions where

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the income or losses are earned, and our ability to receive tax benefits for losses incurred. It is also affected by discrete items, such as return-to-accrual adjustments and changes in valuation allowances, and changes in reserves for uncertain tax positions, which may occur in any given year but are not consistent from year to year.

Despite the pre-tax loss for the year ended December 31, 2016, we recognized income tax expense as a result of a change in valuation allowance of $117.7 million primarily on U.S. net operating losses and other deferred tax assets of $104.7 million and certain foreign net operating losses and other deferred tax assets of $13.0 million. We established the valuation allowance based on the weight of available evidence, both positive and negative, including results of recent and current operations and our estimates of future taxable income or loss by jurisdiction in which we operate. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other business considerations. Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, could require us to adjust the valuation allowances.

We are a U.S. based company that operates internationally through various branches and subsidiaries. Accordingly, our worldwide income tax provision includes the impact of income tax rates and foreign tax laws in the jurisdictions in which our operations are conducted and income is earned. We reported tax benefits for foreign statutory rates different than our U.S. statutory rate of $3.6 million and $2.7 million and tax expense of $12.7 million and $16.0 million for the impact of foreign tax laws in effect for the years ended December 31, 2016 and December 31, 2015, respectively. Differences between the U.S. and foreign tax rates and laws have a significant impact in Colombia, Iraq, Kazakhstan, Mexico, Russia, United Arab Emirates and the United Kingdom.

Certain tax payments to foreign jurisdictions are available as credits to reduce tax expense in the U.S. and other foreign jurisdictions. We reported no tax benefits for foreign tax credits for the year ended December 31, 2016 and tax benefits for foreign tax credits of $5.6 million for the year ended December 31, 2015, which were driven primarily by our operations in Kazakhstan. See Note 6 - Income Taxes in Item 8. Financial Statements and Supplementary Data for further discussion.

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Liquidity and Capital Resources

We periodically evaluate our liquidity requirements, capital needs and availability of resources in view of expansion plans, debt service requirements, and other operational cash needs. To meet our short-term liquidity requirements we primarily rely on our cash from operations. We also have access to cash through the revolving credit facility (Revolver), subject to our compliance with the covenants contained in the 2015 Secured Credit Agreement. We expect that these sources of liquidity will be sufficient to provide us the ability to fund our current operations and required capital expenditures. We may need to fund expansion capital expenditures, acquisitions, debt principal payments, or pursuits of business opportunities that support our strategy, through additional borrowings or the issuance of additional common stock or other forms of equity. We do not pay dividends on our common stock.

Liquidity

Subsequent to December 31, 2017, we entered into the Fifth Amendment to the 2015 Secured Credit Agreement which modified the credit facility to an Asset-Based Lending (ABL) structure and reduced the size of the Revolver from $100 million to $80 million. The Fifth Amendment eliminated the financial maintenance covenants previously in effect and replaced them with a liquidity covenant of $30 million and a monthly borrowing base calculation based on eligible rental equipment and eligible domestic accounts receivable. The Liquidity covenant requires the Company to maintain a minimum of $30 million of liquidity (defined as availability under the borrowing base and cash on hand), of which $15 million is restricted, resulting in a maximum availability at any one time of $65 million. Our ability to borrow under the 2015 Secured Credit Agreement is determined by reference to our borrowing base, which as of the effective date of the Fifth Amendment was $67.5 million. The Fifth Amendment also allows for refinancing our existing Senior Notes with either secured or unsecured debt.

The following table provides a summary of our total liquidity:



	December 31, 2017
Dollars in thousands
Cash and cash equivalents on hand ⁽¹⁾	$	141,549
Availability under Revolver ⁽²⁾	94,350
Total liquidity	$	235,899

(1) As of December 31, 2017, approximately $45.6 million of the $141.5 million of cash and equivalents was held by our foreign subsidiaries.

(2) Availability under the undrawn $100.0 million Revolver was reduced by $5.7 million of letters of credit outstanding. As of December 31, 2017 we were in compliance with all covenants contained in the 2015 Secured Credit Agreement. See Note 6 - Long Term Debt for discussion regarding the Fifth Amendment to the Secured Credit Agreement executed after December 31, 2017. Had the Fifth Amendment been in effect as of December 31, 2017, availability under the Revolver would have been approximately $46.8 million based on a $67.5 million borrowing base less $15 million in restricted liquidity, less $5.7 million of letters of credit.

The earnings of foreign subsidiaries as of December 31, 2017 were reinvested to fund our international operations. If in the future we decide to repatriate earnings, the Company may be required to pay taxes on those amounts, which could reduce the liquidity of the Company at that time.

We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. As of December 31, 2017, we have no energy, commodity, or foreign currency derivative contracts.

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Cash Flow Activity

As of December 31, 2017, we had cash and cash equivalents of $141.5 million, an increase of $21.9 million from cash and cash equivalents of $119.7 million as of December 31, 2016. The following table provides a summary of our cash flow activity for the last three years:



Dollars in thousands	2017			2016			2015
Operating Activities	$	6,733		$	22,441		$	162,110
Investing Activities	(54,130		)	(26,513		)	(101,243		)
Financing Activities	69,255			(10,531		)	(35,029		)
Net change in cash and cash equivalents	$	21,858		$	(14,603	)	$	25,838

Operating Activities

Cash flows provided by operating activities were $6.7 million, $22.4 million, and $162.1 million for the years ended December 31, 2017, 2016, and 2015, respectively. Cash flows from operating activities in each period were largely impacted by our earnings and changes in working capital. Changes in working capital were a use of cash of $5.8 million for the year ended December 31, 2017, a source of cash of $38.8 million for the year ended December 31, 2016, and a source of cash of $80.7 million for the year ended December 31, 2015. In addition to the impact of earnings and working capital changes, cash flows from operating activities in each period were impacted by non-cash charges such as depreciation expense, gains and losses on asset sales, deferred tax expense and benefits, stock-based awards activity and amortization of debt issuance costs.

It is our long-term intention to utilize our operating cash flows to fund maintenance and growth of our rental tool assets and drilling rigs. Given the decline in demand in the current oil and natural gas services market over the past few years, our short-term focus is to preserve liquidity by managing our costs and capital expenditures. While the overall market for oilfield services remains challenging, we are beginning to see a market recovery that is expected to increase our working capital and capital spending as we pursue attractive investment opportunities.

Investing Activities

Cash flows used in investing activities were $54.1 million for the year ended December 31, 2017, compared with $26.5 million and $101.2 million for the years ended December 31, 2016 and 2015, respectively. Cash flows used in investing activities in 2017 and 2016 included capital expenditures of $54.5 million and $29.0 million, respectively, which were primarily used for tubular and other products for our Rental Tools Services business and rig-related maintenance. Cash flows used in investing activities in 2015 included capital expenditures of $88.2 million, primarily for tubular and other products for our Rental Tools Services business and rig-related enhancements and maintenance. In addition, during 2015 we had a use of cash of $10.4 million, net of cash acquired, for the acquisition of a business, and $3.4 million related to the purchase of the remaining noncontrolling interest in ITS Arabia Limited.

Capital expenditures for 2018 are estimated to range from $50.0 million to $60.0 million and will primarily be directed to our Rental Tools Services business inventory and maintenance capital for our Drilling Services business. Future capital spending will be evaluated based upon adequate return requirements and available liquidity.

Financing Activities

Cash flows from financing activities were a source of $69.3 million for the year ended December 31, 2017 primarily related to the issuances of common stock and Convertible Preferred Stock, which yielded combined proceeds of $72.3 million, net of underwriting discount and offering expenses. Additionally, during the year ended December 31, 2017, the Company paid dividends of $2.1 million on our Convertible Preferred Stock.

Cash flows from financing activities were a use of $10.5 million and $35.0 million for the years ended December 31, 2016 and 2015, respectively. For the 2016 comparable period, cash flows from financing activities were used primarily due to payment of $6.0 million of the contingent consideration related to the April 2015 acquisition of a business, and $3.4 million in connection with the final payment of the purchase price for the remaining noncontrolling interest of ITS Arabia Limited. For the 2015 comparable period, cash flows from financing activities were used primarily for the repayment of the $30.0 million borrowing on our Revolver in the first quarter of 2015.

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Long-Term Debt Summary

Our principal amount of long-term debt, including current portion, was $585.0 million as of December 31, 2017, which consisted of:


•	$360.0 million aggregate principal amount of 6.75% Senior Notes; and


•	$225.0 million aggregate principal amount of 7.50% Senior Notes.

6.75% Senior Notes, due July 2022

On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Senior Notes due July 2022 (6.75% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the Second Amended and Restated Senior Secured Credit Agreement, as amended from time-to-time (2015 Secured Credit Agreement) and our 7.50% Senior Notes due 2020 (7.50% Notes, and collectively with the 6.75% Notes, the Senior Notes). Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($4.6 million net of amortization as of December 31, 2017) are being amortized over the term of the notes using the effective interest rate method.

On and after January 15, 2018, we may redeem all or a part of the 6.75% Notes upon appropriate notice, at a redemption price of 103.375 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning January 15, 2020. We have not made any redemptions to date. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture limits our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.

7.50% Senior Notes, due August 2020

On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year, beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes of approximately $5.6 million ($2.4 million, net of amortization as of December 31, 2017) are being amortized over the term of the notes using the effective interest rate method.

We may redeem all or a part of the 7.50% Notes upon appropriate notice, at redemption prices decreasing each year after August 1, 2016 to par beginning August 1, 2018. As of December 31, 2017, the redemption price is 101.875 percent and we have not made any redemptions to date. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

2015 Secured Credit Agreement

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2015 Secured Credit Agreement formerly included financial maintenance covenants, including a Leverage Ratio, Consolidated Interest Coverage Ratio, Senior Secured Leverage Ratio, and Asset Coverage Ratio, many of which were suspended beginning in September 2015.

On February 21, 2017, we executed the fourth amendment to the 2015 Secured Credit Agreement (the Fourth Amendment) which, among other things, permits the sale and issuance of certain equity interests of the Company, including the Convertible Preferred Stock, and permits the Company to pay dividends on the Convertible Preferred Stock, up to certain aggregate amounts specified therein. The debt issuance costs incurred relating to the Fourth Amendment were nominal. Debt issuance costs remaining as of December 31, 2017 were $0.8 million which are being amortized through January 2020 on a straight line basis.

On February 14, 2018, we executed the Fifth Amendment to the 2015 Secured Credit Agreement (the Fifth Amendment) which modified the credit facility to an Asset-Based Lending (ABL) structure and reduced the size of the Revolver from $100 million to $80 million. The Fifth Amendment eliminated the financial maintenance covenants previously in effect and replaced them with a liquidity covenant of $30 million and a monthly borrowing base calculation based on eligible rental equipment and eligible domestic accounts receivable. The liquidity covenant requires the Company to maintain a minimum of $30 million of liquidity (defined as availability under the borrowing base and cash on hand), of which $15 million is restricted, resulting in a maximum availability at any one time of the lesser of (a) an amount equal to our borrowing base minus $15 million, or (b) $65 million. Our ability to borrow under the 2015 Secured Credit Agreement is determined by reference to our borrowing base, which as of the effective date of the Fifth Amendment was $67.5 million. The Fifth Amendment also allows for refinancing our existing Senior Notes with either secured or unsecured debt, adds the ability for the Company to designate certain of its subsidiaries as “Designated Borrowers” and removes our availability to make certain restricted payments.

Our obligations under the 2015 Secured Credit Agreement are guaranteed by substantially all of our direct and indirect domestic subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has executed guaranty agreements, and are secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the GOM and land rigs in Alaska, certain U.S.-based rental equipment of the Company and its subsidiary guarantors and the equity interests of certain of the Company’s subsidiaries. In addition to the liquidity covenant and borrowing base requirements, the 2015 Secured Credit Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness and liens, and restrictions on entry into certain affiliate transactions and payments (including payment of dividends). As of December 31, 2017, we were in compliance with all covenants contained in the 2015 Secured Credit Agreement.

Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Revolving loans are available subject to a quarterly asset coverage ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the GOM and land rigs in Alaska, and certain U.S.-based rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. As of December 31, 2017 our ability to access the Revolver was restricted to $94.4 million, due primarily to $5.7 million in letters of credit outstanding. There were no amounts drawn on the Revolver as of December 31, 2017. Had the Fifth Amendment been in effect as of December 31, 2017, our ability to access the Revolver would have been limited to approximately $46.8 million due to the impacts of (a) the reduction in commitments, (b) the borrowing base calculation, (c) the restricted fund requirement in our liquidity covenant, and (d) outstanding letters of credit.

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Summary of Contractual Cash Obligations

The following table summarizes our future contractual cash obligations as of December 31, 2017:



	Total		2018		2019		2020		2021		2022		Beyond 2022
	(Dollars in Thousands)
Contractual cash obligations:
Long-term debt — principal	$	585,000	$	—	$	—	$	225,000	$	—	$	—	$	360,000
Long-term debt — interest	172,125		41,175		41,175		41,175		24,300		24,300
Operating leases ⁽¹⁾	18,342		6,867		4,742		3,009		1,409		902		1,413
Purchase commitments ⁽²⁾	32,659		32,659		—		—		—		—		—
Total contractual obligations	$	808,126	$	80,701	$	45,917	$	269,184	$	25,709	$	25,202	$	361,413
Commercial commitments:
Standby letters of credit ⁽³⁾	$	5,650	$	4,936	$	453	$	261	$	—	$	—	$	—
Total commercial commitments	$	5,650	$	4,936	$	453	$	261	$	—	$	—	$	—


(1)	Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property.


(2)	We had purchase commitments outstanding as of December 31, 2017 related to rental tools and rig related expenditures.


(3)	As of December 31, 2017 the available capacity of the Revolver was $100 million and as of that date $5.7 million of availability had been used to support outstanding letters of credit.

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Other Matters

Business Risks

See Item 1A. Risk Factors, for a discussion of risks related to our business.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate our estimates, including those related to fair value of assets, bad debt, materials and supplies obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.

We believe the following are our most critical accounting policies as they can be complex and require significant judgments, assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are summarized in Note 1 - Summary of Significant Accounting Policies of the consolidated financial statements.

Fair Value Measurements. For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability. Our valuation technique requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjusted quoted prices for identical assets or liabilities in active markets (Level 1), (2) direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (Level 2) and (3) unobservable inputs that require significant judgment for which there is little or no market data (Level 3). When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Impairment of Property, Plant and Equipment. We evaluate the carrying amounts of long-lived assets for potential impairment when events occur or circumstances change that indicate the carrying values of such assets may not be recoverable. For example, evaluations are performed when we experience sustained significant declines in utilization and dayrates, and we do not contemplate recovery in the near future. In addition, we evaluate our assets when we reclassify property and equipment to assets held for sale or as discontinued operations as prescribed by accounting guidance related to accounting for the impairment or disposal of long-lived assets. We determine recoverability by evaluating the undiscounted estimated future net cash flows. When impairment is indicated, we measure the impairment as the amount by which the assets carrying value exceeds its fair value. Management considers a number of factors such as estimated future cash flows, appraisals and current market value analysis in determining fair value. Assets are written down to fair value if the concluded current fair value is below the net carrying value.

Goodwill. We account for all business combinations using the acquisition method of accounting. Under this method, assets and liabilities, including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill. We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative conditions or other triggering events arise. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted revenues and costs assumptions.

Intangible Assets. Our intangible assets are related to trade names, customer relationships and developed technology, which were acquired through acquisition and are generally amortized over a weighted average period of approximately three to six years. We assess the recoverability of the unamortized balance of our intangible assets when indicators of impairment are present based on expected future profitability and undiscounted expected cash flows and their contribution to our overall operations.

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Should the review indicate that the carrying value is not fully recoverable, the excess of the carrying value over the fair value of the intangible assets would be recognized as an impairment loss.

Accrual for Self-Insurance. Substantially all of our operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, cratering, oil and natural gas well fires and explosions, natural disasters, pollution, mechanical failure and damage or loss during transportation. Some of our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. These hazards could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. We have had accidents in the past due to some of these hazards.

Our contracts provide for varying levels of indemnification between ourselves and our customers, including with respect to well control and subsurface risks. We seek to obtain indemnification from our customers by contract for certain of these risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, these insurance or indemnification agreements may not adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of an insurance coverage deductible.

Based on the risks discussed above, we estimate our liability in excess of insurance coverage and accrue for these amounts in our consolidated financial statements. Accruals related to insurance are based on the facts and circumstances specific to the insurance claims and our past experience with similar claims. The actual outcome of insured claims could differ significantly from the amounts estimated. We accrue actuarially determined amounts in our consolidated balance sheet to cover self-insurance retentions for workers’ compensation, employers’ liability, general liability, automobile liability and health benefits claims. These accruals use historical data based upon actual claim settlements and reported claims to project future losses. These estimates and accruals have historically been reasonable in light of the actual amount of claims paid.

As the determination of our liability for insurance claims could be material and is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, management believes that accounting estimates related to insurance accruals are critical.

Accounting for Income Taxes. We are a U.S. company and we operate through our various foreign legal entities and their branches and subsidiaries in numerous countries throughout the world. Consequently, our tax provision is based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, we are required to estimate the income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued liabilities for tax and accounting purposes. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in different taxing jurisdictions. Current income tax expense represents either liabilities expected to be reflected on our income tax returns for the current year, nonresident withholding taxes or changes in prior year tax estimates which may result from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities reported on the consolidated balance sheet. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding amounts and sources of future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, as well as changes in tax laws, could require us to adjust the deferred tax assets and liabilities or valuation allowances, including as discussed below.

Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to expiration. Evaluations of the realizability of deferred tax assets are, by nature, highly subjective. They involve expectations about future operations and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different determinations of our ability to realize deferred tax assets. In the event that our earnings performance projections do not indicate that we will be able to benefit from our deferred tax assets, valuation allowances are established following the “more likely than not” criteria. We periodically evaluate our ability to utilize our deferred tax assets and, in accordance with accounting guidance related to accounting for income taxes, will record any resulting adjustments that may be required to deferred income tax expense in the period for which an existing estimate changes.

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We do not currently provide for deferred taxes on unremitted earnings of our foreign subsidiaries as such earnings were reinvested to fund our international operations. If the unremitted earnings were to be distributed, we could be subject to taxes and foreign withholding taxes though it is not practicable to determine the resulting liability, if any, that would result on the distribution of such earnings. We annually review our position and may elect to change our future tax position.

We apply the accounting standards related to uncertainty in income taxes. This accounting guidance requires that management make estimates and assumptions affecting amounts recorded as liabilities and related disclosures due to the uncertainty as to final resolution of certain tax matters. Because the recognition of liabilities under this interpretation may require periodic adjustments and may not necessarily imply any change in management’s assessment of the ultimate outcome of these items, the amount recorded may not accurately reflect actual outcomes.

Revenue Recognition. Contract drilling revenues and expenses, comprised of daywork drilling contracts, call-outs against master service agreements and engineering and related project service contracts, are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract; however, costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Our project related services contracts include engineering, consulting, and project management scopes of work and revenue is typically recognized on a time and materials basis.

Allowance for Doubtful Accounts. The allowance for doubtful accounts is estimated for losses that may occur resulting from disputed amounts and the inability of our customers to pay amounts owed. We estimate the allowance based on historical write-off experience and information about specific customers. We review individually, for collectability, all balances over 90 days past due as well as balances due from any customer with respect to which we have information leading us to believe that a risk exists for potential collection.

Legal and Investigation Matters. As of December 31, 2017, we have accrued an estimate of the probable and estimable costs for the resolution of certain legal and investigation matters. We have not accrued any amounts for other matters for which the liability is not probable and reasonably estimable. Generally, the estimate of probable costs related to these matters is developed in consultation with our legal advisors. The estimates take into consideration factors such as the complexity of the issues, litigation risks and settlement costs. If the actual settlement costs, final judgments, or fines, after appeals, differ from our estimates, our future financial results may be adversely affected.

Recent Accounting Pronouncements

For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated financial statements, see Note 18 - Recent Accounting Pronouncements in Item 8. Financial Statements and Supplementary Data.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Foreign Currency Exchange Rate Risk

Our international operations expose us to foreign currency exchange rate risk. There are a variety of techniques to minimize the exposure to foreign currency exchange rate risk, including customer contract payment terms and the possible use of foreign currency exchange rate risk derivative instruments. Our primary foreign currency exchange rate risk management strategy involves structuring customer contracts to provide for payment in both U.S. dollars and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. Due to various factors, including customer acceptance, local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign currency exchange rate risk needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk. Fluctuations in foreign currencies typically have not had a material impact on our overall results. In situations where payments of local currency do not equal local currency requirements, foreign currency exchange rate risk derivative instruments, specifically spot purchases, may be used to mitigate foreign exchange rate currency risk. We do not enter into derivative transactions for speculative purposes. As of December 31, 2017, we had no open foreign currency exchange rate risk derivative contracts.

Interest Rate Risk

We are exposed to changes in interest rates through our fixed rate long-term debt. Typically, the fair market value of fixed rate long-term debt will increase as prevailing interest rates decrease and will decrease as prevailing interest rates increase. The fair value of our long-term debt is estimated based on quoted market prices where applicable, or based on the present value of expected cash flows relating to the debt discounted at rates currently available to us for long-term borrowings with similar terms and maturities. The estimated fair value of our $360.0 million principal amount of 6.75% Notes, based on quoted market prices, was $296.1 million as of December 31, 2017. The estimated fair value of our $225.0 million principal amount of 7.50% Notes, based on quoted market prices, was $206.4 million as of December 31, 2017. A hypothetical 100 basis point increase in interest rates relative to market interest rates as of December 31, 2017 would decrease the fair market value of our 6.75% Notes by approximately $32.2 million and decrease the fair market value of our 7.50% Notes by approximately $22.5 million.

Impact of Fluctuating Commodity Prices

We are exposed to the impact of fluctuations in commodity prices that affect spending by E&P companies on drilling programs. Prolonged price reductions in commodity prices have led to significant reductions in drilling activity for both oil and natural gas. This has resulted in cancellations of some existing contracts for our rigs and rental tools, as well as fewer opportunities to maintain utilization for our equipment when contracted work was completed. As a result, drilling rig and rental tools utilization declined along with associated dayrates and rental rates.

In response to the prolonged reduction in market prices for oil and natural gas, many E&P companies curtailed U.S. drilling activity, cut worldwide spending, terminated certain drilling contracts, requested pricing concessions and took other measures aimed at reducing the capital and operating expenses within their supply chain. This adversely impacted our rental tools activity and pricing, as well as utilization and pricing of our drilling rigs.

We have experienced lower pricing and utilization of tools, services and rigs in the U.S. and certain international markets. Although the severity and duration of the current industry downturn is contingent upon many factors beyond our control, we have taken several steps in an effort to generate free cash flow during this period, including lowering our cost base through headcount reductions and lower idle rig costs, and reducing our capital expenditures. Drilling activity is highly dependent on oil and natural gas prices. Many E&P companies are expected to increase their worldwide spending plans for 2018.

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Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Parker Drilling Company:

Opinion on Internal Control over Financial Reporting

We have audited Parker Drilling Company’s and subsidiaries (the Company) internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), (PCAOB), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2017, and the related notes and financial statement Schedule II - Valuation and Qualifying Accounts (collectively, the consolidated financial statements), and our report dated February 21, 2018 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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 limitations, 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.

/s/ KPMG LLP

Houston, Texas

February 21, 2018

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Parker Drilling Company:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Parker Drilling Company and subsidiaries (the Company) as of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three‑year period ended December 31, 2017, and the related notes and financial statement Schedule II - Valuation and Qualifying Accounts (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 21, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 2007.

Houston, Texas

February 21, 2018

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(Dollars in Thousands, Except Per Share Data)



	Year Ended December 31,
	2017			2016			2015
Revenues	$	442,520		$	427,004		$	712,183
Expenses:
Operating expenses	355,487			362,521			526,290
Depreciation and amortization	122,373			139,795			156,194
	477,860			502,316			682,484
Total operating gross margin (loss)	(35,340		)	(75,312		)	29,699
General and administration expense	(25,676		)	(34,332		)	(36,190		)
Provision for reduction in carrying value of certain assets	(1,938		)	—			(12,490		)
Gain (loss) on disposition of assets, net	(2,851		)	(1,613		)	1,643
Total operating income (loss)	(65,805		)	(111,257		)	(17,338		)
Other income (expense):
Interest expense	(44,226		)	(45,812		)	(45,155		)
Interest income	244			58			269
Other	126			367			(9,747		)
Total other income (expense)	(43,856		)	(45,387		)	(54,633		)
Income (loss) before income taxes	(109,661		)	(156,644		)	(71,971		)
Income tax expense (benefit):
Current tax expense (benefit)	9,264			5,108			19,604
Deferred tax expense (benefit)	(224		)	69,062			2,709
Total income tax expense (benefit)	9,040			74,170			22,313
Net income (loss)	(118,701		)	(230,814		)	(94,284		)
Less: Net income attributable to noncontrolling interest	—			—			789
Net income (loss) attributable to controlling interest	(118,701		)	(230,814		)	(95,073		)
Less: Mandatory convertible preferred stock dividend	3,051			—			—
Net income (loss) available to common stockholders	$	(121,752	)	$	(230,814	)	$	(95,073	)
Basic earnings (loss) per share:	$	(0.89	)	$	(1.86	)	$	(0.78	)
Diluted earnings (loss) per share:	$	(0.89	)	$	(1.86	)	$	(0.78	)
Number of common shares used in computing earnings per share:
Basic	136,266,843			124,130,004			122,562,187
Diluted	136,266,843			124,130,004			122,562,187

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)



	Year Ended December 31,
	2017			2016			2015
Comprehensive income (loss):
Net income (loss)	$	(118,701	)	$	(230,814	)	$	(94,284	)
Other comprehensive gain (loss), net of tax:
Currency translation difference on related borrowings	643			(691		)	(2,012		)
Currency translation difference on foreign currency net investments	2,689			(4,265		)	405
Total other comprehensive gain (loss), net of tax:	3,332			(4,956		)	(1,607		)
Comprehensive income (loss)	(115,369		)	(235,770		)	(95,891		)
Comprehensive (income) loss attributable to noncontrolling interest	—			—			4,606
Comprehensive income (loss) attributable to controlling interest	$	(115,369	)	$	(235,770	)	$	(91,285	)

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Dollars in Thousands)



	December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	141,549		$	119,691
Accounts and Notes Receivable, net of allowance for bad debts of $7,564 in 2017 and $8,259 in 2016	122,511			113,231
Rig materials and supplies	31,415			32,354
Deferred costs	3,145			1,436
Other tax assets	4,889			6,475
Other current assets	14,327			13,131
Total current assets	317,836			286,318

Property, plant and equipment, net of accumulated depreciation of $1,343,105 in 2017 and $1,320,644 in 2016 (Note 4)	625,771			693,439
Goodwill (Note 2)	6,708			6,708
Intangible assets, net (Note 2)	7,128			9,928
Rig materials and supplies	18,788			22,439
Deferred income taxes	1,284			70,309
Other assets	12,764			14,410
Total assets	$	990,279		$	1,103,551
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	41,523		$	42,655
Accrued liabilities	57,723			56,186
Accrued income taxes	4,430			4,080
Total current liabilities	103,676			102,921
Long-term debt, net of unamortized debt issuance costs of $7,029 at December 31, 2017 and $8,674 at December 31, 2016	577,971			576,326
Other long-term liabilities	12,433			15,836
Long-term deferred tax liability	78			69,333
Commitments and contingencies (Note 13)	—			—
Stockholders’ equity:
Preferred Stock, $1.00 par value, 1,942,000 shares authorized, 7.25% Series A Mandatory Convertible, 500,000 shares issued and outstanding (none in 2016)	500			—
Common Stock, $0.16 ²/₃ par value, authorized 280,000,000 shares, issued and outstanding, 138,935,734 shares (125,118,365 shares in 2016)	23,140			20,837
Capital in excess of par value	744,746			675,194
Accumulated deficit	(468,753		)	(350,052		)
Accumulated Other Comprehensive Income	(3,512		)	(6,844		)
Total stockholders’ equity	296,121			339,135
Total liabilities and stockholders’ equity	$	990,279		$	1,103,551

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

(Dollars in Thousands)



	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities:
Net income (loss)	$	(118,701	)	$	(230,814	)	$	(94,284	)
Adjustments to reconcile net income (loss):
Depreciation and amortization	122,373			139,795			156,194
Accretion of contingent consideration	—			419			826
(Gain) loss on debt modification	—			1,088			—
(Gain) loss on disposition of assets	2,851			1,613			(1,643		)
Deferred tax expense (benefit)	(224		)	69,062			2,709
Provision for reduction in carrying value of certain assets	1,938			—			12,490
Excess tax benefit (expense) from stock-based compensation	—			—			(1,045		)
Expenses not requiring cash	4,251			2,518			6,136
Change in assets and liabilities:
Accounts and notes receivable	(9,628		)	60,391			103,995
Rig materials and supplies	4,710			(1,752		)	2,722
Other current assets	(1,319		)	2,140			12,548
Accounts payable and accrued liabilities	(8,714		)	(19,494		)	(27,425		)
Accrued income taxes	538			(6,422		)	(7,957		)
Other assets	8,658			3,897			(3,156		)
Net cash provided by (used in) operating activities	6,733			22,441			162,110

Cash flows from investing activities:
Capital expenditures	(54,533		)	(28,954		)	(88,197		)
Proceeds from the sale of assets	403			2,441			830
Proceeds from insurance settlements	—			—			2,500
Acquisitions, net of cash acquired	—			—			(13,806		)
Divestitures, net of cash paid	—			—			(2,570		)
Net cash provided by (used in) investing activities	(54,130		)	(26,513		)	(101,243		)

Cash flows from financing activities:
Repayments of long-term debt	—			—			(30,000		)
Proceeds from the issuance of common stock	25,200			—			—
Proceeds from the issuance of mandatory convertible preferred stock	50,000			—			—
Payment of equity issuance costs	(2,864		)	—			—
Mandatory convertible preferred stock dividend	(2,145		)	—			—
Shares surrendered in lieu of tax	(936		)	(1,156		)	(1,033		)
Payments of debt issuance costs	—			—			(1,996		)
Payment for noncontrolling interest	—			(3,375		)	—
Payment of contingent consideration	—			(6,000		)	(2,000		)
Net cash provided by (used in) financing activities	69,255			(10,531		)	(35,029		)

Net increase (decrease) in cash and cash equivalents	21,858			(14,603		)	25,838
Cash and cash equivalents at beginning of year	119,691			134,294			108,456
Cash and cash equivalents at end of year	$	141,549		$	119,691		$	134,294

Supplemental cash flow information:
Interest paid	41,175			41,175			41,393
Income taxes paid	8,422			14,341			26,208

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Dollars and Shares in Thousands)



	Shares	Preferred Stock		Common Stock		Treasury Stock			Capital in Excess of Par Value			Accumulated Deficit			Accumulated Other Comprehensive Income (Loss)			Total Controlling Stockholders’ Equity			Noncontrolling Interest			Total Stockholders’ Equity
Balances, December 31, 2014	122,046	$	—	$	20,495	$	(170	)	$	666,769		$	(24,165	)	$	(498	)	$	662,431		$	3,783		$	666,214
Activity in employees’ stock plans	1,160	—		193		—			(1,227		)	—			—			(1,034		)	—			(1,034		)
Tax benefit increase from stock-based compensation	—	—		—		—			(1,045		)	—			—			(1,045		)	—			(1,045		)
Amortization of stock-based awards	—	—		—		—			8,410			—			—			8,410			—			8,410
Disposal of noncontrolling interest related to sale of joint venture	—	—		—		—			—			—			—			—			(1,392		)	(1,392		)
Purchase of noncontrolling ownership interest	—	—		—		—			(3,787		)	—			—			(3,787		)	(2,963		)	(6,750		)
Comprehensive Income:	—	—		—		—			—			—			—			—			—			—
Net income	—	—		—		—			—			(95,073		)	—			(95,073		)	789			(94,284		)
Other comprehensive income (loss)	—	—		—		—			—			—			(1,390		)	(1,390		)	(217		)	(1,607		)
Balances, December 31, 2015	123,206	$	—	$	20,688	$	(170	)	$	669,120		$	(119,238	)	$	(1,888	)	$	568,512		$	—		$	568,512
Activity in employees’ stock plans	1,912	—		319		—			(1,475		)	—			—			(1,156		)	—			(1,156		)
Amortization of stock-based awards	—	—		—		—			7,549			—			—			7,549			—			7,549
Comprehensive Income:	—	—		—		—			—			—			—			—			—			—
Net income	—	—		—		—			—			(230,814		)	—			(230,814		)	—			(230,814		)
Other comprehensive income (loss)	—	—		—		—			—			—			(4,956		)	(4,956		)	—			(4,956		)
Balances, December 31, 2016	125,118	$	—	$	21,007	$	(170	)	$	675,194		$	(350,052	)	$	(6,844	)	$	339,135		$	—		$	339,135
Activity in employees’ stock plans	1,818	—		303		—			(1,239		)	—			—			(936		)	—			(936		)
Amortization of stock-based awards	—	—		—		—			4,006			—			—			4,006			—			4,006
Issuance of common stock	12,000	—		2,000		—			22,059			—			—			24,059			—			24,059
Issuance of mandatory convertible preferred stock	500	500		—		—			47,777			—			—			48,277			—			48,277
Mandatory convertible preferred stock dividend	—	—		—		—			(3,051		)	—			—			(3,051		)	—			(3,051		)
Comprehensive Income:	—	—		—		—			—			—			—			—			—			—
Net income (loss)	—	—		—		—			—			(118,701		)	—			(118,701		)	—			(118,701		)
Other comprehensive income (loss)	—	—		—		—			—			—			3,332			3,332			—			3,332
Balances, December 31, 2017	139,436	$	500	$	23,310	$	(170	)	$	744,746		$	(468,753	)	$	(3,512	)	$	296,121		$	—		$	296,121

See accompanying notes to the consolidated financial statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting Policies

Nature of Operations — Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. We report our Drilling Services business as two reportable segments: (1) U.S. (Lower 48) Drilling and (2) International & Alaska Drilling. We report our Rental Tools Services business as two reportable segments: (1) U.S. Rental Tools and (2) International Rental Tools.


•	customers typically are major, independent, or national oil and natural gas companies or integrated service providers;


•	drilling programs in remote locations with little infrastructure, requiring a large inventory of spare parts and other ancillary equipment and self-supported service capabilities;


•	complex wells and/or harsh environments (such as high pressures, deep depths, hazardous or geologically challenging conditions and sensitive environments) requiring specialized equipment and considerable experience to drill; and


•	O&M contracts that generally cover periods of one year or more.

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We have operated in over 50 countries since beginning operations in 1934, making us among the most geographically experienced drilling contractors and rental tools providers in the world. We currently have operations in 19 countries. Parker has set numerous world records for deep and extended-reach drilling land rigs and is an industry leader in quality, health, safety and environmental practices.

Consolidation — The consolidated financial statements include the accounts of the Company and subsidiaries in which we exercise control or have a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s losses or returns, regardless of ownership percentage. If a subsidiary of Parker Drilling has a 50 percent interest in an entity but Parker Drilling’s interest in the subsidiary or the entity does not meet the consolidation criteria described above, then that interest is accounted for under the equity method.

Noncontrolling Interest — We apply accounting standards related to noncontrolling interests for ownership interests in our subsidiaries held by parties other than Parker Drilling. We report noncontrolling interest as equity on the consolidated balance sheets and report net income (loss) attributable to controlling interest and to noncontrolling interest separately on the consolidated statements of operations.

Reclassifications — Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications did not materially affect our consolidated financial results.

Revenue Recognition — Drilling revenues and expenses, comprised of daywork drilling contracts, call-outs against master service agreements and engineering and related project service contracts, are recognized as services are performed and collection is reasonably assured. For certain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and direct costs incurred for the mobilization, are deferred and recognized over the primary term of the related drilling contract; however, costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. For contracts that are terminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met. Revenues from rental activities are recognized ratably over the rental term, which is generally less than six months. Our project-related services contracts include engineering, consulting, and project management scopes of work and revenue is typically recognized on a time and materials basis.

Reimbursable Revenues — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $57.8 million, $69.3 million, and $87.8 million during the years ended December 31, 2017, 2016, and 2015, respectively. Additionally, the Company typically receives a nominal handling fee, which is recognized as earned in revenues in our consolidated statement of operations.

Use of Estimates — The preparation of financial statements in accordance with accounting policies generally accepted in the United States (U.S. GAAP) requires management to make estimates and assumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of the financial statements, and our revenues and expenses during the periods reported. Estimates are typically used when accounting for certain significant items such as legal or contractual liability accruals, mobilization and deferred mobilization, self-insured medical/dental plans, income taxes and valuation allowance, and other items requiring the use of estimates. Estimates are based on a number of variables which may include third party valuations, historical experience, where applicable, and assumptions that we believe are reasonable under the circumstances. Due to the inherent uncertainty involved with estimates, actual results may differ from management estimates.

Purchase Price Allocation — We allocate the purchase price of an acquired business to its identifiable assets and liabilities in accordance with the acquisition method based on estimated fair values at the transaction date. Transaction and integration costs associated with an acquisition are expensed as incurred. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all available information to estimate fair values, including quoted market prices, the carrying value of acquired assets, and widely accepted valuation techniques such as discounted cash flows. We typically engage third-party appraisal firms to assist in fair value determination of inventories, identifiable intangible assets, and any other significant assets or liabilities. Judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, can materially impact our results of operations.

Goodwill — We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative conditions or other triggering events arise. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted revenues and costs assumptions. See Note 2 - Goodwill and Other Intangible Assets for further discussion.

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Intangible Assets — Our intangible assets are related to trade names, customer relationships, and developed technology, which were acquired through acquisition and are classified as definite lived intangibles, that are generally amortized over a weighted average period of approximately three to six years. We assess the recoverability of the unamortized balance of our intangible assets when indicators of impairment are present based on expected future profitability and undiscounted expected cash flows and their contribution to our overall operations. Should the review indicate that the carrying value is not fully recoverable, the excess of the carrying value over the fair value of the intangible assets would be recognized as an impairment loss. See Note 2 - Goodwill and Other Intangible Assets for further discussion.

Cash and Cash Equivalents — For purposes of the consolidated balance sheets and the consolidated statements of cash flows, the Company considers cash equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.

Accounts Receivable and Allowance for Bad Debt — Trade accounts receivable are recorded at the invoice amount and typically do not bear interest. The allowance for bad debt is estimated for losses that may occur resulting from disputed amounts and the inability of our customers to pay amounts owed. We estimate the allowance based on historical write-off experience and information about specific customers. We review individually, for collectability, all balances over 90 days past due as well as balances due from any customer with respect to which we have information leading us to believe that a risk exists for potential collection.

Account balances are charged off against the allowance when we believe it is probable the receivable will not be recovered. We do not have any off-balance-sheet credit exposure related to customers.

The components of our accounts receivable, net of allowance for bad debt balance are as follows:



	December 31,
Dollars in thousands	2017			2016
Trade	$	130,075		$	121,490
Allowance for bad debt⁽¹⁾	(7,564		)	(8,259		)
Total accounts and notes receivable, net of allowance for bad debt	$	122,511		$	113,231


(1)	Additional information on the allowance for bad debt for the years ended December 31, 2017, 2016 and 2015 is reported on Schedule II — Valuation and Qualifying Accounts.

Property, Plant and Equipment — Property, plant and equipment is carried at cost. Maintenance and most repair costs are expensed as incurred. The cost of upgrades and replacements is capitalized. The Company capitalizes software developed or obtained for internal use. Accordingly, the cost of third-party software, as well as the cost of third-party and internal personnel that are directly involved in application development activities, are capitalized during the application development phase of new software systems projects. Costs during the preliminary project stage and post-implementation stage of new software systems projects, including data conversion and training costs, are expensed as incurred. We account for depreciation of property, plant and equipment on the straight line method over the estimated useful lives of the assets after provision for salvage value. Depreciation, for tax purposes, utilizes several methods of accelerated depreciation. Depreciable lives for different categories of property, plant and equipment are as follows:



Land drilling equipment		3 to 20 years
Barge drilling equipment		3 to 20 years
Drill pipe, rental tools and other		4 to 15 years
Buildings and improvements		5 to 30 years

Leasehold improvements are depreciated over the shorter of their estimated useful lives or the term of the lease.

Impairment — We evaluate the carrying amounts of long-lived assets for potential impairment when events occur or circumstances change that indicate the carrying values of such assets may not be recoverable. We evaluate recoverability by determining the undiscounted estimated future net cash flows for the respective asset groups identified. If the sum of the estimated undiscounted cash flows is less than the carrying value of the asset group, we measure the impairment as the amount by which the assets’ carrying value exceeds the fair value of such assets. Management considers a number of factors such as estimated future cash flows from the assets, appraisals and current market value analysis in determining fair value. Assets are written down to fair value if the final estimate of current fair value is below the net carrying value. The assumptions used in the impairment evaluation are inherently uncertain and require management judgment.

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Capitalized Interest — Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. Capitalized interest costs reduce net interest expense in the consolidated statements of operations. During 2017 capitalized interest costs were nominal. Capitalized interest costs were $0.2 million and $0.2 million during 2016 and 2015, respectively.

Assets Held for Sale — We classify an asset as held for sale when the facts and circumstances meet the criteria for such classification, including the following: (a) we have committed to a plan to sell the asset, (b) the asset is available for immediate sale, (c) we have initiated actions to complete the sale, including locating a buyer, (d) the sale is expected to be completed within one year, (e) the asset is being actively marketed at a price that is reasonable relative to its fair value, and (f) the plan to sell is unlikely to be subject to significant changes or termination.

Rig Materials and Supplies — Because our international drilling generally occurs in remote locations, making timely outside delivery of spare parts uncertain, a complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operation. During periods of high rig utilization, these parts are generally consumed and replenished within a one-year period. During a period of lower rig utilization in a particular location, the parts, like the related idle rigs, are generally not transferred to other international locations until new contracts are obtained because of the significant transportation costs that would result from such transfers. We classify those parts which are not expected to be utilized in the following year as long-term assets. Additionally, our international rental tools business holds machine shop consumables and steel stock for manufacture in our machine shops and inspection and repair shops, which are classified as current assets. Rig materials and supplies are valued at the lower of cost or market value.

Deferred Costs — We defer costs related to rig mobilization and amortize such costs over the primary term of the related contract. The costs to be amortized within twelve months are classified as current.

Debt Issuance Costs — We typically defer costs associated with issuance of indebtedness, and amortize those costs over the term of the related debt using the effective interest method.

Income Taxes — Income taxes are accounted for under the asset and liability method and have been provided for based upon tax laws and rates in effect in the countries in which operations are conducted and income or losses are generated. There is little or no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes as the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits, and other benefits. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which the temporary differences are expected to be recovered or settled and the effect of changes in tax rates is recognized in income in the period in which the change is enacted. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, could require us to adjust the valuation allowances.

The Company recognizes the effect of income tax positions only if those positions are more likely than not to be sustained. Recognized income tax positions are measured at the largest amount that is greater than 50 percent likely of being realized and changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

Earnings (Loss) Per Share (EPS) — Basic earnings (loss) per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock and convertible debt are included in the diluted EPS calculation, when applicable.

Concentrations of Credit Risk — Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of trade receivables with a variety of national and international oil and natural gas companies. We generally do not require collateral on our trade receivables. We depend on a limited number of significant customers. In 2017, our largest customer, Exxon Neftegas Limited (ENL), constituted approximately 31.3 percent of our consolidated revenues. Excluding reimbursable revenues of $50.8 million, ENL constituted approximately 22.7 percent of our total consolidated revenues. In 2017, our second largest customer, BP Exploration Alaska, Inc. (BP), constituted approximately 9.7 percent of our consolidated revenues.

As of December 31, 2017 and 2016, we had deposits in domestic banks in excess of federally insured limits of approximately $97.6 million and $81.4 million, respectively. In addition, we had uninsured deposits in foreign banks as of December 31, 2017 and 2016 of $45.6 million and $39.7 million, respectively.

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Fair Value Measurements — For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability. Our valuation technique requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjusted quoted prices for identical assets or liabilities in active markets (Level 1), (2) direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (Level 2) and (3) unobservable inputs that require significant judgment for which there is little or no market data (Level 3). When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Foreign Currency — In our international rental tool business, for certain subsidiaries and branches outside the U.S., the local currency is the functional currency. The financial statements of these subsidiaries and branches are translated into U.S. dollars as follows: (i) assets and liabilities at month-end exchange rates; (ii) income, expenses and cash flows at monthly average exchange rates or exchange rates in effect on the date of the transaction; and (iii) stockholders’ equity at historical exchange rates. For those subsidiaries where the local currency is the functional currency, the resulting translation adjustment is recorded as a component of accumulated other elements of comprehensive income (loss) in the accompanying consolidated balance sheets.

Stock-Based Compensation — Under our long term incentive plan, we are authorized to issue the following: stock options; stock appreciation rights; restricted stock awards; restricted stock units; performance-based awards; and other types of awards in cash or stock to key employees, consultants, and directors. We typically grant restricted stock units (“RSUs”), performance cash units (“PCUs”), performance-based phantom stock units and time-based phantom stock units.

Stock-based compensation expense is recognized, net of an estimated forfeiture rate, which is based on historical experience and adjusted, if necessary, in subsequent periods based on actual forfeitures. We recognize stock-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as an operating cash flow.

Legal and Investigation Matters — We accrue estimates of the probable and estimable costs for the resolution of certain legal and investigation matters. We do not accrue any amounts for other matters for which the liability is not probable and reasonably estimable. Generally, the estimate of probable costs related to these matters is developed in consultation with our legal advisors. The estimates take into consideration factors such as the complexity of the issues, litigation risks and settlement costs. If the actual settlement costs, final judgments, or fines, after appeals, differ from our estimates, our future financial results may be adversely affected.

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Note 2 — Goodwill and Intangible Assets

We account for business combinations using the acquisition method of accounting. Under this method, assets and liabilities, including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill. We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative conditions or other triggering events arise. As a result of our 2017 analysis, we determined that the fair value of the reporting unit exceeded its carrying value and therefore, no goodwill impairment was identified. Should current market conditions worsen or persist for an extended period of time, an impairment of the carrying value of our goodwill could occur.

All of the Company’s goodwill and intangible assets are allocated to the International Rental Tools segment.

Goodwill

The change in the carrying amount of goodwill for the year ended December 31, 2017 is as follows:



Dollars in thousands	Goodwill
Balance at December 31, 2016	$	6,708
Additions	—
Balance at December 31, 2017	$	6,708

Of the total amount of goodwill recognized, zero is expected to be deductible for income tax purposes.

Intangible Assets

Intangible Assets consist of the following:



		Balance at December 31, 2017
Dollars in thousands	Estimated Useful Life (Years)	Gross Carrying Amount		Write-off Due to Sale⁽¹⁾			Accumulated Amortization			Net Carrying Amount
Amortized intangible assets:
Developed Technology	6	$	11,630	$	—		$	(5,330	)	$	6,300
Customer Relationships	3	5,400		(264		)	(5,136		)	—
Trade Names	5	4,940		(332		)	(3,780		)	828
Total Amortized intangible assets		$	21,970	$	(596	)	$	(14,246	)	$	7,128

(1) During the 2015 fourth quarter, we sold our controlling interest in a joint venture in Egypt resulting in the write-off of $0.6 million of intangible assets related to customer relationships and trade name.

Amortization expense was $2.8 million, $3.5 million, and $4.3 million for the year ended December 31, 2017, 2016, and 2015 respectively.

Our remaining intangibles amortization expense for the next five years is presented below:



Dollars in thousands	Expected future intangible amortization expense
2018	$	2,306
2019	$	2,306
2020	$	2,030
2021	$	486
Beyond 2021	$	—

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Note 3 — Accumulated Other Comprehensive Income

Accumulated other comprehensive income consisted of the following:



Dollars in thousands	Foreign Currency Items
December 31, 2016	$	(6,844	)
Current period other comprehensive income	3,332
December 31, 2017	$	(3,512	)

There were no amounts reclassified out of accumulated other comprehensive loss for the year ended December 31, 2017.

Note 4 — Property, Plant and Equipment

The components of our property, plant and equipment balance are as follows:



	December 31,
Dollars in Thousands	2017		2016
Property, Plant and Equipment, at cost:
Drilling Equipment	$	1,228,443	$	1,306,641
Rental Tools	552,461		516,144
Building, Land and Improvements	60,309		54,799
Other	115,910		111,142
Construction in Progress	11,753		25,357
Total Property, Plant and Equipment, at cost	1,968,876		2,014,083
Less: Accumulated Depreciation and Amortization	1,343,105		1,320,644
Property, Plant, and Equipment, Net	$	625,771	$	693,439

Depreciation expense was $119.6 million, $136.3 million and $151.9 million for the years ended December 31, 2017, 2016, and 2015, respectively.

Provision for Reduction in Carrying Value of an Asset

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets. We review the carrying amounts of long-lived assets for potential impairment when events occur, or circumstances change, which indicate the carrying values of such assets may not be recoverable.

Although no impairment of our asset groups was identified during the year ended December 31, 2017, we recorded a provision of $1.9 million for reduction in carrying value of assets. This provision was related to certain assets in the International & Alaska Drilling segment that were deemed to be excess and functionally obsolete unless significant costs were incurred to refurbish them.

Disposition of Assets

During the normal course of operations, we periodically sell equipment deemed to be excess, obsolete, or not currently required for operations. Net losses recorded on asset disposition were $2.9 million and $1.6 million for the years ended December 31, 2017 and December 31, 2016, respectively. The net loss for 2017 was primarily related to the sale of one rig located in Papua New Guinea. Activity in both periods included equipment retirements.

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Note 5 — Income Taxes

In accordance with the reduction to the U.S. corporate income tax rate from 35 percent to 21 percent, the Company has remeasured certain U.S. deferred tax assets and liabilities. However, as a result of the Company’s net deferred tax position, inclusive of valuation allowances, no net income tax expense was recorded related to this remeasurement. The Company has not recorded any income tax expense related to the one-time mandatory tax on previously deferred earnings of certain foreign subsidiaries associated with the transition from a worldwide to a modified territorial tax regime. We are continuing our analysis of the effects the Tax Act will have on the Company in future periods.

Income (loss) before income taxes is summarized below:



	Year Ended December 31,
Dollars in thousands	2017			2016			2015
United States	$	(89,233	)	$	(131,106	)	$	(77,368	)
Foreign	(20,428		)	(25,538		)	5,397
	$	(109,661	)	$	(156,644	)	$	(71,971	)

Income tax expense (benefit) is summarized as follows:



	Year Ended December 31,
Dollars in thousands	2017			2016			2015
Current:
United States:
Federal	$	80		$	(1,921	)	$	2,485
State	54			(9		)	365
Foreign	9,130			7,038			16,754

Deferred:
United States:
Federal	167			64,066			(141		)
State	—			(47		)	(4,769		)
Foreign	(391		)	5,043			7,619
	$	9,040		$	74,170		$	22,313

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Total income tax expense differs from the amount computed by multiplying income before income taxes by the U.S. federal income tax statutory rate. The reasons for this difference are as follows:



	Year Ended December 31,
	2017					2016					2015
Dollars in thousands	Amount			% of Pre-Tax Income		Amount			% of Pre-Tax Income		Amount			% of Pre-Tax Income
Computed expected tax expense	$	(38,381	)	35.0	%	$	(54,825	)	35.0	%	$	(25,190	)	35.0	%
Foreign taxes	13,084			(11.9	)%	12,688			(8.1	)%	16,043			(22.3	)%
Tax effect different from statutory rates	(2,048		)	1.9	%	(3,629		)	2.3	%	(2,729		)	3.8	%
State taxes, net of federal benefit	35			—	%	(849		)	0.5	%	(4,544		)	6.3	%
Foreign tax credits	3			—	%	20			—	%	(5,566		)	7.7	%
Change in valuation allowance (excluding impact of Tax Act)	30,704			(28.0	)%	117,707			(75.1	)%	40,676			(56.5	)%
Uncertain tax positions	194			(0.2	)%	(726		)	0.5	%	(81		)	0.1	%
Permanent differences	2,970			(2.7	)%	1,442			(0.9	)%	1,696			(2.4	)%
Prior year return to provision adjustments	2,442			(2.3	)%	2,078			(1.3	)%	1,555			(2.1	)%
Other	37			—	%	264			(0.2	)%	453			(0.6	)%
Impact of Tax Act
Effect of tax rate reduction on deferred tax	45,329			(41.3	)%	—			—	%	—			—	%
Effect of tax rate on deferred tax valuation	(45,329		)	41.3	%	—			—	%	—			—	%
Actual Tax Expense	$	9,040		(8.2	)%	$	74,170		(47.3	)%	$	22,313		(31.0	)%

The components of the Company’s deferred tax assets and liabilities as of December 31, 2017 and 2016 are shown below:



	December 31,
Dollars in thousands	2017			2016
Deferred tax assets
Deferred tax assets:
Federal net operating loss carryforwards	95,867			120,986
State net operating loss carryforwards	11,089			7,168
Other state deferred tax asset, net	1,592			2,646
Foreign Tax Credits	46,913			46,859
FIN 48	953			883
Foreign tax	36,699			29,791
Asset Impairment	8,161			27,165
Accruals not currently deductible for tax purposes	2,926			1,657
Deferred compensation	1,204			3,424
Other	74			863
Gross long-term deferred tax assets	205,478			241,442
Valuation Allowance	(157,914		)	(171,133		)
Net deferred tax assets, net of valuation allowance	47,564			70,309
Deferred tax liabilities:
Deferred tax liabilities:
Property, Plant and equipment	(38,809		)	(64,256		)
Foreign tax local	(78		)	490
Other state deferred tax liability, net	(6,140		)	(5,567		)
Intangibles	(1,331		)	—
Gross deferred tax liabilities	(46,358		)	(69,333		)
Net deferred tax asset	$	1,206		$	976

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As part of the process of preparing the consolidated financial statements, the Company is required to determine its provision for income taxes. This process involves measuring temporary and permanent differences resulting from differing treatment of items for tax and accounting purposes. These differences and the operating loss and tax credit carryforwards result in deferred tax assets and liabilities. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that all or a portion 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 of appropriate character in each taxing jurisdiction during the periods in which those temporary differences become deductible. Management considers the weight of available evidence, both positive and negative, including the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax planning strategies in making this assessment. To the extent the Company believes that it does not meet the test that recovery is more likely than not, it establishes a valuation allowance. To the extent that the Company establishes a valuation allowance or changes this allowance in a period, it adjusts the tax provision or tax benefit in the consolidated statement of operations. We use our judgment in determining provisions or benefits for income taxes, and any valuation allowance recorded against previously established deferred tax assets. We have measured the value of our deferred tax assets for the year ended December 31, 2017 based on the cumulative weight of positive and negative evidence that exists as of the date of the financial statements. Should the cumulative weight of all available positive and negative evidence change in the forecast period, the expectation of realization of deferred tax assets existing as of December 31, 2017 and prospectively may change.

The 2017 results include a decrease in our valuation allowance of $14.6 million primarily related to U.S. and certain foreign net operating losses and other deferred tax assets. Valuation allowances are established based on the weight of available evidence, both positive and negative, including results of recent and current operations and our estimates of future taxable income or loss by jurisdiction in which we operate. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other business considerations. Changes in these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, could require us to adjust the valuation allowances.

The 2016 results include an increase in our valuation allowance of $117.7 million primarily related to U.S. and certain foreign net operating losses and other deferred tax assets.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:



Dollars in thousands
Balance at January 1, 2016	$	(4,628	)
Reductions based on tax positions taken during a prior period	3
Additions based on tax positions taken during the current period	(770		)
Balance at December 31, 2017	$	(5,395	)

In many cases, our uncertain tax positions are related to tax years that remain subject to examination by tax authorities. The following describes the open tax years, by major tax jurisdiction, as of December 31, 2017:



Kazakhstan	2008-present
Mexico	2012-present
Russia	2014-present
United States — Federal	2009-present
United Kingdom	2014-present

As of December 31, 2017, we had a liability for unrecognized tax benefits of $5.4 million (all of which, if recognized, would favorably impact our effective tax rate), on which no payments were made during 2017.

The Company recognized interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2017 and December 31, 2016 we had approximately $2.1 million and $1.9 million of accrued interest and penalties related to uncertain tax positions, respectively. We recognized a $0.2 million increase in interest and nominal decrease in penalties on unrecognized tax benefits for the year ended December 31, 2017.

As of December 31, 2017, the Company has permanently reinvested accumulated undistributed earnings of foreign subsidiaries and, therefore, has not recorded a deferred tax liability related to subject earnings. Upon distribution of additional earnings in the form of dividends or otherwise, we could be subject to income taxes and withholding taxes. It is not practicable to determine precisely the amount of taxes that may be payable on the eventual remittance of these earnings due to many factors,

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including application of foreign tax credits, levels of accumulated earnings and profits at the time of remittance, and the sources of earnings remitted. The Company generally does not provide for taxes related to its undistributed earnings because such earnings either would not be taxable when remitted or they are considered to be indefinitely reinvested. Taxes that would be incurred if the undistributed earnings of other subsidiaries were distributed to their ultimate parent company would not be material.

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Note 6 — Long-Term Debt

The following table illustrates the Company’s current debt portfolio as of December 31, 2017 and December 31, 2016:



	December 31,
Dollars in thousands	2017			2016
6.75% Senior Notes, due July 2022	$	360,000		$	360,000
7.50% Senior Notes, due August 2020	225,000			225,000
Total principal	585,000			585,000
Less: unamortized debt issuance costs	(7,029		)	(8,674		)
Total long-term debt	$	577,971		$	576,326

6.75% Senior Notes, due July 2022

7.50% Senior Notes, due August 2020

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2015 Secured Credit Agreement

On January 26, 2015 we entered into the 2015 Secured Credit Agreement. The 2015 Secured Credit Agreement was originally comprised of a $200 million revolving credit facility (Revolver), which was subsequently reduced to $100 million. The 2015 Secured Credit Agreement formerly included financial maintenance covenants, including a Leverage Ratio, Consolidated Interest Coverage Ratio, Senior Secured Leverage Ratio, and Asset Coverage Ratio, many of which were suspended beginning in September 2015.

On February 14, 2018, we executed the Fifth Amendment to the 2015 Secured Credit Agreement (the Fifth Amendment) which modified the credit facility to an Asset-Based Lending (ABL) structure and reduced the size of the Revolver from $100 million to $80 million. The Fifth Amendment eliminated the financial maintenance covenants previously in effect and replaced them with a liquidity covenant of $30 million and a monthly borrowing base calculation based on eligible rental equipment and eligible domestic accounts receivable. The liquidity covenant requires the Company to maintain a minimum of $30 million of liquidity (defined as availability under the borrowing base and cash on hand), of which $15 million is restricted, resulting in a maximum availability at any one time of the lesser of (a) an amount equal to our borrowing base minus $15 million, or (b) $65 million. Our ability to borrow under the 2015 Secured Credit Agreement determined by reference to our borrowing base, which as of the effective date of the Fifth Amendment was $67.5 million. The Fifth Amendment also allows for refinancing our existing Senior Notes with either secured or unsecured debt, adds the ability for the Company to designate certain of its subsidiaries as “Designated Borrowers” and removes our availability to make certain restricted payments.

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Note 7 — Fair Value of Financial Instruments

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis. For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.

The fair value measurement and disclosure requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic No. 820, Fair Value Measurement and Disclosures requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows:


•	Level 1 — Unadjusted quoted prices for identical assets or liabilities in active markets;


•	Level 2 — Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets; and


•	Level 3 — Unobservable inputs that require significant judgment for which there is little or no market data.

When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the entire measurement even though we may also have utilized significant inputs that are more readily observable. The amounts reported in our consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value.

Fair value of our debt instruments is determined using Level 2 inputs. Fair values and related carrying values of our debt instruments were as follows for the periods indicated:



	December 31, 2017				December 31, 2016
Dollars in thousands	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term Debt
6.75% Notes	$	360,000	$	296,100	$	360,000	$	311,400
7.50% Notes	225,000		206,438		225,000		201,375
Total	$	585,000	$	502,538	$	585,000	$	512,775

Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or Level 2 to Level 3. There were no transfers between levels of the fair value hierarchy or any changes in the valuation techniques used during the year ended December 31, 2017.

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Note 8 — Stock-Based Compensation

Stock Plan

Stock-based compensation awards were granted to employees under the Company’s 2010 Long-Term Incentive Plan, as Amended and Restated as of May 10, 2016 (the Stock Plan). The Stock Plan was approved by the stockholders at the Annual Meeting of Stockholders on May 10, 2016. The Stock Plan authorizes the compensation committee or the board of directors to issue stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance-based awards, time-based awards, and other types of awards in cash or stock to key employees, consultants, and directors. The maximum number of shares that may be delivered pursuant to the awards granted under the Stock Plan is 16,800,000 shares of common stock. As of December 31, 2017 there were 4,617,521 shares remaining available under the Stock Plan.

Stock-Based Awards

Stock-based awards generally vest over three years. Stock-based compensation expense is recognized net of an estimated forfeiture rate, which is based on historical experience and adjusted, if necessary, in subsequent periods based on actual forfeitures. We recognize stock-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow.

In 2017, we issued three types of stock-based awards: restricted stock units (RSUs), performance-based phantom stock units and time-based phantom stock units:


•	RSUs entitle a grantee to receive a share of common stock on a specified vesting date. RSUs are service-based awards and compensation expense is recognized ratably over the applicable vesting period. The grant-date fair value of nonvested RSUs is determined based on the closing trading price of the Company’s shares on the grant date. RSUs are settled in shares of our common stock upon vesting.

•

Performance-based phantom stock units are performance-based awards and represent the equivalent of one share of common stock as of the grant date. Compensation costs for performance-based phantom stock units are recognized based on the change in fair value of the awards during the performance period. Performance-based phantom stock units vest fully at the end of a three-year performance period and are settled in cash upon vesting.


•	Time-based phantom stock units are service-based awards and represent the equivalent of one share of common stock as of the grant date. Compensation costs for time-based phantom stock units are recognized ratably over a three-year vesting period and based on the change in fair value of the awards during the three-year period. Time-based phantom stock units are settled in cash upon vesting.

The following table presents RSUs granted, vested and forfeited during 2017 under the Stock Plan:



	Units		Weighted Average Grant-Date Fair Value
Nonvested at January 1, 2017	5,333,522		$	2.85
Granted	2,711,546		$	1.42
Vested	(2,512,552	)	$	3.41
Forfeited	(998,338	)	$	2.29
Nonvested at December 31, 2017	4,534,178		$	1.81

We issued 2,711,546 units, 3,289,569 units, and 2,996,151 units, respectively, of RSUs during 2017, 2016 and 2015, respectively, to selected key personnel. The per-share weighted-average grant-date fair value of units granted during 2017, 2016, and 2015 was $1.42, $2.07, and $3.08, respectively. Stock-based compensation expense is included in our consolidated statements of operations in “General and administration expenses.”

Total stock-based compensation expense recognized relating to RSUs for the years ended December 31, 2017, 2016, and 2015 was $4.0 million, $7.5 million, and $8.4 million, respectively, all of which was related to nonvested RSUs. The total fair value of the units vested during the years ended December 31, 2017, 2016, and 2015 was $8.6 million, $10.0 million, and $8.0 million, respectively. The fair value of RSUs is determined based on the closing trading price of the Company’s stock on the grant date.

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Nonvested RSUs as of December 31, 2017 totaled 4,534,178 and total unrecognized compensation cost related to unamortized RSUs was $3.3 million as of December 31, 2017. The remaining unrecognized compensation cost related to non-vested RSUs will be amortized over a weighted-average vesting period of approximately 33 months.

The following table presents time-based phantom stock units granted, vested, and forfeited during 2017 under the Stock Plan:



	Time-Based Phantom Stock Units
Nonvested at January 1, 2017	985,938
Granted	648,755
Vested	(299,796	)
Forfeited	(216,793	)
Nonvested at December 31, 2017	1,118,104

In 2017 we issued 648,755 units and 1,188,854 units of time-based phantom stock units during 2017 and 2016 to selected key personnel. We did not issue any time-based phantom stock units in 2015.

Compensation expense recognized related to time-based phantom stock units for the year ended December 31, 2017 was nominal. Expense recognized for the year ended December 31, 2016 was $1.4 million.

Performance-Based Awards

In 2017, we issued two types of performance-based awards: Performance Cash Units (PCUs) and performance-based phantom stock units.

PCUs are performance-based awards that contain payout conditions which are based on our performance against a group of selected peer companies with regard to relative return on capital employed (ROCE) over a three-year performance period. Each PCU has a nominal value of $100.00. A maximum of 200 percent of the number of PCUs granted may be earned if performance at the maximum level is achieved. PCUs vest to the extent earned at the end of a three-year performance period and are settled in cash.

Performance-based phantom stock units are performance-based awards denominated in a number of shares which contain payout conditions based on our performance against a group of selected peer companies with regard to relative total shareholder return (TSR) over a three-year performance period. They represent a grant of hypothetical stock to the equivalent number of shares of common stock but, with the employee receiving cash upon vesting. We used a simulation-based option pricing approach to determine the fair value of these awards. A maximum of 250 percent of the number of performance-based phantom stock units granted may be earned if performance at the maximum level is achieved. Performance-based phantom stock units vest to the extent earned at the end of the three-year performance period and are settled in cash.

We evaluate the terms of each award to determine if the award should be accounted for as equity or a liability under the stock compensation rules of U.S. GAAP. PCUs and performance-based phantom stock units are classified as liability awards.

For performance-based awards with graded vesting conditions, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. For market-based awards that vest at the end of the service period, we recognize compensation expense on a straight-line basis through the end of the service period.

The following table presents PCUs granted, vested, and forfeited during 2017 under the Stock Plan:



	PCUs
Nonvested at January 1, 2017	26,352
Granted	14,153
Vested	(11,022	)
Forfeited	(6,462	)
Nonvested at December 31, 2017	23,021

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In 2017, 2016, and 2015 we issued 14,153 units, 17,091 units, and 17,091 units, respectively, of PCUs to selected key personnel.

Compensation expense recognized related to PCUs for the years ended December 31, 2017, 2016, and 2015 was $1.0 million, $2.3 million, and $2.3 million, respectively.

The following table presents performance-based phantom stock units granted, vested, and forfeited during 2017 under the Stock Plan:



	Performance-Based Phantom Stock Units
Nonvested at January 1, 2017	1,315,228
Granted	660,370
Vested	(348,962	)
Forfeited	(315,579	)
Nonvested at December 31, 2017	1,311,057

In 2017, 2016, and 2015 we issued 660,370 units, 1,164,880 units, and 541,127 units, respectively, of performance-based phantom stock units to selected key personnel.

Compensation expense recognized related to performance-based phantom stock units for the year ended December 31, 2017 was a gain of $0.9 million, and an expense of $1.3 million, and $0.4 million for the years ended December 31, 2016 and 2015, respectively.

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Note 9 — Earnings (Loss) Per Share (EPS)

Basic earnings (loss) per share is computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock, convertible debt and equity are included in the diluted EPS calculation, when applicable.

The following table represents the computation of earnings per share for the twelve months ended December 31, 2017 and 2016, respectively:



	For the Year Ended December 31, 2017
	Net Income (Loss) Available to Common Stockholders (Numerator)			Shares (Denominator)	Per-Share Amount
				Shares (Denominator)	Per-Share Amount
Basic earnings (loss) per common share	$	(121,752,000	)	136,266,843	$	(0.89	)
Effect of dilutive securities:
Restricted stock units⁽¹⁾				—	$	—
Mandatory convertible preferred stock⁽²⁾
Diluted earnings (loss) per common share	$	(121,752,000	)	136,266,843	$	(0.89	)

	For the Year Ended December 31, 2016
	Net Income (Loss) Available to Common Stockholders (Numerator)			Shares (Denominator)	Per-Share Amount
				Shares (Denominator)	Per-Share Amount
Basic earnings (loss) per common share	$	(230,814,000	)	124,130,004	$	(1.86	)
Effect of dilutive securities:
Restricted stock units⁽¹⁾				—	$	—
Diluted earnings (loss) per common share	$	(230,814,000	)	124,130,004	$	(1.86	)

	For the Year Ended December 31, 2015
	Net Income (Loss) Available to Common Stockholders (Numerator)			Shares (Denominator)	Per-Share Amount
				Shares (Denominator)	Per-Share Amount
Basic earnings (loss) per common share	$	(95,073,000	)	122,562,187	$	(0.78	)
Effect of dilutive securities:
Restricted stock units⁽¹⁾				—	$	—
Diluted earnings (loss) per common share	$	(95,073,000	)	122,562,187	$	(0.78	)


(1)	For each of the years ended December 31, 2017, 2016, and 2015, all common shares potentially issuable in connection with outstanding restricted stock unit awards have been excluded from the calculation of diluted EPS as the Company incurred losses during the periods, therefore, inclusion of such potential common shares would be anti-dilutive.


(2)	Weighted average common shares issuable upon the assumed conversion of our Convertible Preferred Stock (as defined below) totaling 23,809,500 shares were excluded from the computation of diluted EPS as such shares would be anti-dilutive.

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Note 10 — Common and Preferred Stock Issuances

In February 2017, we issued 12,000,000 shares of common stock, par value $0.16 ²/₃ per share, at the public offering price of $2.10 per share, and 500,000 shares of 7.25% Series A Mandatory Convertible Preferred Stock (Convertible Preferred Stock), par value $1.00 per share, with a liquidation preference of $100 per share, for total net proceeds of $72.3 million, after underwriting discount and offering expenses.

The dividends on our Convertible Preferred Stock will be payable on a cumulative basis when, as and if declared by our board of directors, or an authorized committee of our board of directors, at an annual rate of 7.25 percent of the liquidation preference of $100 per share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of cash and shares of our common stock on March 31, June 30, September 30 and December 31 of each year, commencing on June 30, 2017 and ending on, and including, March 31, 2020.

Unless converted earlier, each share of our Convertible Preferred Stock will automatically convert into between 41.4079 and 47.6190 shares of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”), subject to anti-dilution adjustments. The number of shares of our common stock issuable on conversion will be determined based on the volume weighted-average price, of our common stock over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day immediately preceding March 31, 2020. Except in limited circumstances, at any time prior to March 31, 2020, a holder may convert Convertible Preferred Stock into shares of our common stock at the minimum conversion rate of 41.4079 shares of common stock per share of Convertible Preferred Stock, subject to anti-dilution adjustments.

On May 9, 2017, our board of directors declared a cash dividend of $2.4771 per share of our Convertible Preferred Stock for the period from and including February 22, 2017 through and including June 29, 2017, which was paid on June 30, 2017 to mandatory convertible preferred shareholders of record as of June 15, 2017. On August 3, 2017, the audit committee, on behalf of our board of directors declared a cash dividend of $1.8125 per share of our Convertible Preferred Stock for the period from and including June 30, 2017 through and including September 29, 2017, which was paid on October 2, 2017 to mandatory convertible preferred shareholders of record as of September 15, 2017. On December 4, 2017, our audit committee, on behalf of our board of directors declared a cash dividend of $1.8125 per share of our Convertible Preferred Stock for the period from and including September 30, 2017 through and including December 30, 2017, which was paid on January 2, 2018 to mandatory convertible preferred shareholders of record as of December 15, 2017.

Note 11 — Employee Benefit Plan

The Company sponsors a defined contribution 401(k) plan (the Plan) in which substantially all U.S. employees are eligible to participate. The Company match was suspended in May 2016 and resumed in May 2017. During 2017 the Company matched 25 percent of each participant’s pre-tax contributions in an amount not exceeding 6 percent of the participant’s compensation, up to the maximum amount of contributions allowed by law. The costs of matching contributions to the Plan were $0.7 million, $1.1 million and $4.0 million in 2017, 2016 and 2015, respectively. Plan participants hired prior to July 2017 become 100 percent vested immediately in the Company’s matching contributions, and plan participants hired after July 2017 become vested on a pro-rata basis over three years.

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Note 12 — Reportable Segments

Within the four reportable segments, we have aggregated our Arctic, Eastern Hemisphere and Latin America business units under International & Alaska Drilling, one business unit under U.S. (Lower 48) Drilling, one business unit under U.S. Rental Tools and one business unit under International Rental Tools, for a total of six business units. The Company has aggregated each of its business units in one of the four reporting segments based on the guidelines of the FASB ASC Topic No. 280, Segment Reporting. We eliminate inter-segment revenues and expenses. We disclose revenues under the four reportable segments based on the similarity of the use and markets for the groups of products and services within each segment.

Drilling Services Business

U.S. (Lower 48) Drilling

International & Alaska Drilling


•	customers typically are major, independent, or national oil and natural gas companies or integrated service providers;


•	drilling programs in remote locations with little infrastructure, requiring a large inventory of spare parts and other ancillary equipment and self-supported service capabilities;


•	complex wells and/or harsh environments (such as high pressures, deep depths, hazardous or geologically challenging conditions and sensitive environments) requiring specialized equipment and considerable experience to drill; and


•	O&M contracts that generally cover periods of one year or more.

Rental Tools Services Business

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construction services, which include tubular running services and downhole tool rentals, well intervention services, which include whipstock, fishing and related services, and inspection and machine shop support. Rental tools are used during drilling and/or workover programs and are requested by the customer as needed, requiring us to keep a broad inventory of rental tools in stock. Rental tools are usually rented on a daily or monthly basis.

U.S. Rental Tools

International Rental Tools

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The following table represents the results of operations by reportable segment:



	Year Ended December 31,
Dollars in thousands	2017			2016			2015
Revenues: ⁽¹⁾
Drilling Services:
U.S. (Lower 48) Drilling	$	12,389		$	5,429		$	30,358
International & Alaska Drilling	247,254			287,332			435,096
Total Drilling Services	259,643			292,761			465,454
Rental Tools Services:
U.S. Rental Tools	121,937			71,613			141,889
International Rental Tools	60,940			62,630			104,840
Total Rental Tools Services	182,877			134,243			246,729
Total revenues	442,520			427,004			712,183
Operating gross margin: ⁽²⁾
Drilling Services:
U.S. (Lower 48) Drilling	(20,656		)	(34,353		)	(28,309		)
International & Alaska Drilling	(6,248		)	9,272			45,211
Total Drilling Services	(26,904		)	(25,081		)	16,902
Rental Tools Services:
U.S. Rental Tools	15,651			(22,372		)	17,380
International Rental Tools	(24,087		)	(27,859		)	(4,583		)
Total Rental Tools Services	(8,436		)	(50,231		)	12,797
Total operating gross margin	(35,340		)	(75,312		)	29,699
General and administrative expense	(25,676		)	(34,332		)	(36,190		)
Provision for reduction in carrying value of certain assets	(1,938		)	—			(12,490		)
Gain (loss) on disposition of assets, net	(2,851		)	(1,613		)	1,643
Total operating income (loss)	(65,805		)	(111,257		)	(17,338		)
Interest expense	(44,226		)	(45,812		)	(45,155		)
Interest income	244			58			269
Other income (loss)	126			367			(9,747		)
Income (loss) from continuing operations before income taxes	$	(109,661	)	$	(156,644	)	$	(71,971	)


(1)	For the years ended December 31, 2017, 2016, and 2015, our largest customer, ENL, constituted approximately 31.3 percent, 38.7 percent, and 27.9 percent, respectively, of our total consolidated revenues and approximately 55.9 percent, 57.5 percent, and 45.6 percent, respectively, of our International & Alaska Drilling segment revenues.

Excluding reimbursable revenues of $50.8 million, $67.0 million, and $75.8 million, ENL constituted approximately 22.7 percent, 27.5 percent, and 19.7 percent, respectively, of our total consolidated revenues and approximately 46.1 percent, 45.0 percent, and 35.3 percent, respectively of our International & Alaska Drilling segment revenues.

For the year ended December 31, 2017, our second largest customer, BP, constituted 9.7 percent, of our total consolidated revenues and approximately 17.4 percent of our International & Alaska Drilling segment revenues.


(2)	Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense.

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The following table represents capital expenditures and depreciation and amortization by reportable segment:



	Year Ended December 31,
Dollars in thousands	2017		2016		2015
Capital expenditures:
U.S. (Lower 48) Drilling	$	230	$	264	$	2,731
International & Alaska Drilling	3,673		5,258		13,458
U.S. Rental Tools	39,948		10,848		47,673
International Rental Tools	8,584		9,725		19,516
Corporate	2,098		2,859		4,819
Total capital expenditures	$	54,533	$	28,954	$	88,197
Depreciation and amortization: ⁽¹⁾
U.S. (Lower 48) Drilling	$	13,521	$	20,049	$	22,420
International & Alaska Drilling	46,950		55,236		64,539
U.S. Rental Tools	43,489		43,769		47,453
International Rental Tools	18,413		20,741		21,782
Total depreciation and amortization	$	122,373	$	139,795	$	156,194


(1)	For presentation purposes, for the years then ended December 31, 2017, 2016 and 2015 depreciation for corporate assets of $8.7 million, $8.3 million, and $7.5 million, respectively, has been allocated to the corresponding reportable segments.

The following table represents identifiable assets by reportable segment:



	Year Ended December 31,
Dollars in Thousands	2017		2016
Identifiable assets:
U.S. (Lower 48) Drilling	$	62,980	$	77,628
International & Alaska Drilling	421,753		591,120
U.S. Rental Tools	198,664		126,289
International Rental Tools	168,511		170,431
Total identifiable assets	851,908		965,468
Corporate	138,371		138,083
Total assets	$	990,279	$	1,103,551

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The following table represents selected geographic information:



	Year Ended December 31,
Dollars in Thousands	2017		2016		2015
Revenues by geographic area:
Russia	$	139,144	$	142,538	$	165,193
Other CIS	23,768		33,659		61,145
EMEA & Asia	64,572		79,870		148,015
Latin America	11,594		12,952		69,989
United States	177,630		127,596		231,779
Other⁽¹⁾	25,812		30,389		36,062
Total revenues	$	442,520	$	427,004	$	712,183

Long-lived assets by geographic area:⁽²⁾
Russia	$	19,415	$	21,395
Other CIS	29,402		35,914
EMEA & Asia	108,621		116,857
Latin America	38,959		48,528
United States	429,374		470,745
Other⁽¹⁾	—		—
Total long-lived assets	$	625,771	$	693,439


(1)	This category includes our Canada O&M operations and our project services activities. Revenues generated by our project service activities benefit our various geographic locations.


(2)	Long-lived assets consist of property, plant and equipment, net.

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Note 13 — Commitments and Contingencies

The Company has various lease agreements for office space, equipment, vehicles and personal property. These obligations extend through 2025 and are typically non-cancelable. Most leases contain renewal options and certain of the leases contain escalation clauses. Future minimum lease payments as of December 31, 2017, under operating leases with non-cancelable terms are as follows:



Dollars in Thousands	Year Ended December 31,
2018	$	6,867
2019	4,742
2020	3,009
2021	1,409
2022	902
Thereafter	1,413
Total	$	18,342

Total rent expense for all operating leases amounted to $23.8 million, $21.8 million and $19.2 million for the years then ended December 31, 2017, 2016, and 2015, respectively.

Self Insurance

We are self-insured for certain losses relating to workers’ compensation, employers’ liability, general liability (for onshore liability), protection and indemnity (for offshore liability) and property damage. Our exposure (that is, the retention or deductible) per occurrence is $250,000 for worker’s compensation and employer’s liability, and $500,000 for general liability, protection and indemnity and maritime employers’ liability (Jones Act). There is no annual aggregate deductible for protection and indemnity and maritime employers’ liability claims. The annual aggregate deductible is reduced by every dollar that exceeds the $500,000 per occurrence retention. We also assume retention for foreign casualty exposures of $100,000 for workers’ compensation, employers’ liability, and $1,000,000 for general liability losses and a $100,000 deductible for auto liability claims. For all primary insurances mentioned above, the Company has excess coverage for those claims that exceed the retention and annual aggregate deductible. We maintain actuarially-determined accruals in our consolidated balance sheets to cover the self-insurance retentions.

We have self-insured retentions for certain other losses relating to rig, equipment, property, business interruption and political, war, and terrorism risks which vary according to the type of rig and line of coverage. Political risk insurance is procured for international operations. However, this coverage may not adequately protect us against liability from all potential consequences.

As of December 31, 2017 and 2016, our gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $3.2 million and $3.9 million, respectively and the related insurance recoveries/receivables were $1.9 million and $1.5 million, respectively.

Other Commitments

We have entered into employment agreements with certain members of management with automatic one year renewal periods at expiration dates. The agreements provide for, among other things, compensation, benefits and severance payments. The employment agreements also provide for lump sum compensation and benefits in the event of termination within two years following a change in control of the Company.

Contingencies

We are a party to various lawsuits and claims arising out of the ordinary course of business. We estimate the range of our liability related to pending litigation when we believe the amount or range of loss can be estimated. We record our best estimate of a loss when the loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and claims, the ultimate outcome may differ significantly from our estimates. In the opinion of management and based on liability accruals provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our consolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particular reporting period.

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Note 14 — Related Party Transactions

Consulting Agreement

On December 31, 2013, Robert L. Parker, Jr., our former Executive Chairman, retired as an employee of the Company. Mr. Parker continued to serve as Chairman of the Company’s board of directors until the annual meeting of stockholders held in 2014, at which time Mr. Parker was elected to the board for a three-year term.

In connection with Mr. Parker’s retirement, the Company and Mr. Parker entered into a Retirement and Separation Agreement dated as of November 1, 2013 (the “Retirement Agreement”). Under the terms of the Retirement Agreement, in 2014 Mr. Parker received a cash bonus of $411,188, a cash payment of $1,096,687 pursuant to the 2010 Long-Term Incentive Program of the Company’s Stock Plan, and a severance payment of $2,488,024. The value of benefits provided by the Company to Mr. Parker in 2014 was $12,876. In 2015, Mr. Parker received a cash payment of $706,082 pursuant to the 2010 Long-Term Incentive Program of the Company’s Stock Plan. The value of benefits provided by the Company to Mr. Parker in 2015 was $14,441.

In addition, Mr. Parker was paid $250,000 during each of 2015, 2016 and 2017 in exchange for his agreement to provide additional support to the Company when needed in matters where his historical and industry knowledge, client relationships and related expertise could be of particular benefit to the Company’s interests.

Other Related Party Agreements

During 2015 we purchased the legal rights to certain rental tool software from two employees and a relative of the employees. As part of the purchase, we paid $180,000 to the relative of the employees in 2015 and $90,000 to each employee in both January 2016 and 2017.

In 2015, one of our directors acquired $550,000 aggregate principal amount of our 7.50% Notes and $650,000 aggregate principal amount of our 6.75% Notes.

Note 15 — Supplementary Information

The significant components of “Accrued liabilities” on our consolidated balance sheets as of December 31, 2017 and 2016 are presented below:



	Year Ended December 31,
Dollars in Thousands	2017		2016
Accrued liabilities:
Accrued Payroll & Related Benefits	$	27,252	$	20,714
Accrued Interest Expense	18,169		18,169
Accrued Professional Fees & Other	7,888		13,039
Deferred Mobilization Fees	3,149		2,681
Workers’ Compensation Liabilities, net	1,265		1,583
Total accrued liabilities	$	57,723	$	56,186

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Note 16 — Parent, Guarantor, Non-Guarantor Unaudited Consolidating Condensed Financial Statements

Set forth on the following pages are the consolidating condensed financial statements of Parker Drilling. The Company’s 2015 Secured Credit Agreement and Senior Notes are fully and unconditionally guaranteed by substantially all of our direct and indirect domestic subsidiaries other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, subject to the following customary release provisions:


•	in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) a subsidiary of the Company;


•	in connection with any sale of such amount of capital stock as would result in such guarantor no longer being a subsidiary to a person that is not (either before or after giving effect to such transaction) a subsidiary of the Company;


•	if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary;


•	if the guarantee by a guarantor of all other indebtedness of the Company or any other guarantor is released, terminated or discharged, except by, or as a result of, payment under such guarantee; or


•	upon legal defeasance or covenant defeasance (satisfaction and discharge of the indenture).

There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate financial statements for each guarantor company are not provided as the company complies with the exception to Rule 3-10(f) of Regulation S-X. All guarantor subsidiaries are owned 100 percent by the parent company.

We are providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of December 31, 2017 and December 31, 2016 and for the years ended December 31, 2017, 2016, and 2015. The consolidating condensed financial statements present investments in both the consolidated and unconsolidated subsidiaries using the equity method of accounting.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)



	Year ended December 31, 2017
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	168,490		$	355,044		$	(81,014	)	$	442,520
Operating expenses	—			94,546			341,955			(81,014		)	355,487
Depreciation and amortization	—			81,260			41,113			—			122,373
Total operating gross margin (loss)	—			(7,316		)	(28,024		)	—			(35,340		)
General and administration expense ⁽¹⁾	(323		)	(24,887		)	(466		)	—			(25,676		)
Provision for reduction in carrying value of certain assets	—			—			(1,938		)	—			(1,938		)
Gain (loss) on disposition of assets, net	—			(247		)	(2,604		)	—			(2,851		)
Total operating income (loss)	(323		)	(32,450		)	(33,032		)	—			(65,805		)
Other income (expense):
Interest expense	(47,135		)	(220		)	(7,906		)	11,035			(44,226		)
Interest income	831			744			9,704			(11,035		)	244
Other	—			71			55			—			126
Equity in net earnings of subsidiaries	(40,752		)	—			—			40,752			—
Total other income (expense)	(87,056		)	595			1,853			40,752			(43,856		)
Income (loss) before income taxes	(87,379		)	(31,855		)	(31,179		)	40,752			(109,661		)
Income tax expense (benefit):
Current tax expense (benefit)	26,537			(22,494		)	5,221			—			9,264
Deferred tax expense (benefit)	4,785			(7,750		)	2,741			—			(224		)
Total income tax expense (benefit)	31,322			(30,244		)	7,962			—			9,040
Net income (loss)	(118,701		)	(1,611		)	(39,141		)	40,752			(118,701		)
Less: Net income attributable to noncontrolling interest	—			—			—			—			—
Net income (loss) attributable to controlling interest	$	(118,701	)	$	(1,611	)	$	(39,141	)	$	40,752		$	(118,701	)
Less: Mandatory convertible preferred stock dividend	$	3,051		$	—		$	—		$	—		$	3,051
Net income (loss) available to common stockholders	$	(121,752	)	$	(1,611	)	$	(39,141	)	$	40,752		$	(121,752	)

(1)General and administration expenses for field operations are included in operating expenses.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)



	Year ended December 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	152,263		$	380,931		$	(106,190	)	$	427,004
Operating expenses	—			103,013			365,698			(106,190		)	362,521
Depreciation and amortization	—			90,218			49,577			—			139,795
Total operating gross margin (loss)	—			(40,968		)	(34,344		)	—			(75,312		)
General and administration expense ⁽¹⁾	(410		)	(29,355		)	(4,567		)	—			(34,332		)
Provision for reduction in carrying value of certain assets	—			—			—			—			—
Gain (loss) on disposition of assets, net	—			(565		)	(1,048		)	—			(1,613		)
Total operating income (loss)	(410		)	(70,888		)	(39,959		)	—			(111,257		)
Other income (expense):
Interest expense	(48,160		)	(642		)	(6,434		)	9,424			(45,812		)
Interest income	758			695			8,029			(9,424		)	58
Other	—			484			(117		)	—			367
Equity in net earnings of subsidiaries	(94,469		)	—			—			94,469			—
Total other income (expense)	(141,871		)	537			1,478			94,469			(45,387		)
Income (loss) before income taxes	(142,281		)	(70,351		)	(38,481		)	94,469			(156,644		)
Income tax expense (benefit):
Current tax expense (benefit)	40,562			(35,572		)	118			—			5,108
Deferred tax expense (benefit)	47,971			14,846			6,245			—			69,062
Total income tax expense (benefit)	88,533			(20,726		)	6,363			—			74,170
Net income (loss)	(230,814		)	(49,625		)	(44,844		)	94,469			(230,814		)
Less: Net income attributable to noncontrolling interest	—			—			—			—			—
Net income (loss) attributable to controlling interest	$	(230,814	)	$	(49,625	)	$	(44,844	)	$	94,469		$	(230,814	)
Less: Mandatory convertible preferred stock dividend	$	—		$	—		$	—		$	—		$	—
Net income (loss) available to common stockholders	$	(230,814	)	$	(49,625	)	$	(44,844	)	$	94,469		$	(230,814	)

(1)General and administration expenses for field operations are included in operating expenses.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)

(Unaudited)



	Year ended December 31, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Total revenues	$	—		$	254,182		$	584,204		$	(126,203	)	$	712,183
Operating expenses	—			143,563			508,930			(126,203		)	526,290
Depreciation and amortization	—			95,071			61,123			—			156,194
Total operating gross margin (loss)	—			15,548			14,151			—			29,699
General and administration expense ⁽¹⁾	(1,279		)	(38,643		)	3,732			—			(36,190		)
Provision for reduction in carrying value of certain assets	—			(2,088		)	(10,402		)	—			(12,490		)
Gain (loss) on disposition of assets, net	—			439			1,204			—			1,643
Total operating income (loss)	(1,279		)	(24,744		)	8,685			—			(17,338		)
Other income (expense):
Interest expense	(47,659		)	(1,035		)	(11,579		)	15,118			(45,155		)
Interest income	1,424			852			13,111			(15,118		)	269
Loss on extinguishment of debt	—			—			—			—			—
Other	—			(200		)	(9,547		)	—			(9,747		)
Equity in net earnings of subsidiaries	(36,631		)	—			—			36,631			—
Total other income (expense)	(82,866		)	(383		)	(8,015		)	36,631			(54,633		)
Income (loss) before income taxes	(84,145		)	(25,127		)	670			36,631			(71,971		)
Income tax expense (benefit):
Current tax expense (benefit)	29,643			(22,970		)	12,931			—			19,604
Deferred tax expense (benefit)	(18,715		)	11,718			9,706			—			2,709
Total income tax expense (benefit)	10,928			(11,252		)	22,637			—			22,313
Net income (loss)	(95,073		)	(13,875		)	(21,967		)	36,631			(94,284		)
Less: Net income attributable to noncontrolling interest	—			—			789			—			789
Net income (loss) attributable to controlling interest	$	(95,073	)	$	(13,875	)	$	(22,756	)	$	36,631		$	(95,073	)
Less: Mandatory convertible preferred stock dividend	$	—		$	—		$	—		$	—		$	—
Net income (loss) available to common stockholders	$	(95,073	)	$	(13,875	)	$	(22,756	)	$	36,631		$	(95,073	)


(1)	General and administration expenses for field operations are included in operating expenses.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



	Year Ended December 31, 2017
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income (loss):
Net income (loss)	$	(118,701	)	$	(1,611	)	$	(39,141	)	$	40,752	$	(118,701	)
Other comprehensive gain (loss), net of tax:
Currency translation difference on related borrowings	—			—			643			—		$	643
Currency translation difference on foreign currency net investments	—			—			2,689			—		$	2,689
Total other comprehensive gain (loss), net of tax:	—			—			3,332			—		3,332
Comprehensive income (loss) attributable to controlling interest	$	(118,701	)	$	(1,611	)	$	(35,809	)	$	40,752	$	(115,369	)

PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



	Year Ended December 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income (loss):
Net income (loss)	$	(230,814	)	$	(49,625	)	$	(44,844	)	$	94,469	$	(230,814	)
Other comprehensive gain (loss), net of tax:
Currency translation difference on related borrowings	—			—			(691		)	—		(691		)
Currency translation difference on foreign currency net investments	—			—			(4,265		)	—		(4,265		)
Total other comprehensive gain (loss), net of tax:	—			—			(4,956		)	—		(4,956		)
Comprehensive income (loss) attributable to controlling interest	$	(230,814	)	$	(49,625	)	$	(49,800	)	$	94,469	$	(235,770	)

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

(Unaudited)



	Year ended December 31, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations		Consolidated
Comprehensive income:
Net income (loss)	$	(95,073	)	$	(13,875	)	$	(21,967	)	$	36,631	$	(94,284	)
Other comprehensive gain (loss), net of tax:
Currency translation difference on related borrowings	—			—			(2,012		)	—		(2,012		)
Currency translation difference on foreign currency net investments	—			—			405			—		405
Total other comprehensive gain (loss), net of tax:	—			—			(1,607		)	—		(1,607		)
Comprehensive income (loss)	(95,073		)	(13,875		)	(23,574		)	36,631		(95,891		)
Comprehensive (income) loss attributable to noncontrolling interest	—			—			4,606			—		4,606
Comprehensive income (loss) attributable to controlling interest	$	(95,073	)	$	(13,875	)	$	(18,968	)	$	36,631	$	(91,285	)

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)



	December 31, 2017
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	75,342		$	20,655		$	45,552		$	—		$	141,549
Accounts and notes receivable, net	—			32,338			90,173			—			122,511
Rig materials and supplies	—			(3,025		)	34,440			—			31,415
Deferred costs	—			17			3,128			—			3,145
Other tax assets	—			—			4,889			—			4,889
Other current assets	—			6,345			7,982			—			14,327
Total current assets	75,342			56,330			186,164			—			317,836
Property, plant and equipment, net	(19		)	428,556			197,234			—			625,771
Goodwill	—			6,708			—			—			6,708
Intangible assets, net	—			7,128			—			—			7,128
Investment in subsidiaries and intercompany advances	2,955,050			2,971,456			3,955,553			(9,882,059		)	—
Other noncurrent assets	(261,232		)	237,755			537,124			(480,811		)	32,836
Total assets	$	2,769,141		$	3,707,933		$	4,876,075		$	(10,362,870	)	$	990,279
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	(51,060		)	179,247			588,536			(617,477		)	99,246
Accrued income taxes	76,883			(56,870		)	(15,583		)	—			4,430
Total current liabilities	25,823			122,377			572,953			(617,477		)	103,676
Long-term debt, net	577,971			—			—			—			577,971
Other long-term liabilities	2,867			5,741			3,825			—			12,433
Deferred tax liability	(1		)	—			79			—			78
Intercompany payable	1,865,810			1,465,744			2,430,340			(5,761,894		)	—
Total liabilities	2,472,470			1,593,862			3,007,197			(6,379,371		)	694,158
Total equity	296,671			2,114,071			1,868,878			(3,983,499		)	296,121
Total liabilities and stockholders’ equity	$	2,769,141		$	3,707,933		$	4,876,075		$	(10,362,870	)	$	990,279

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)

(Unaudited)



	December 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	65,000		$	14,365		$	40,326		$	—		$	119,691
Accounts and notes receivable, net	—			15,749			97,482			—			113,231
Rig materials and supplies	—			(5,369		)	37,723			—			32,354
Deferred costs	—			16			1,420			—			1,436
Other tax assets	(50,296		)	35,733			21,038			—			6,475
Other current assets	—			5,555			7,576			—			13,131
Total current assets	14,704			66,049			205,565			—			286,318
Property, plant and equipment, net	(19		)	469,927			223,531			—			693,439
Goodwill	—			6,708			—			—			6,708
Intangible assets, net	—			9,434			494			—			9,928
Investment in subsidiaries and intercompany advances	2,979,413			2,932,375			3,676,402			(9,588,190		)	—
Other noncurrent assets	(253,679		)	301,771			539,877			(480,811		)	107,158
Total assets	$	2,740,419		$	3,786,264		$	4,645,869		$	(10,069,001	)	$	1,103,551
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	(10,080		)	149,210			577,188			(617,477		)	98,841
Accrued income taxes	—			1,576			2,504			—			4,080
Total current liabilities	(10,080		)	150,786			579,692			(617,477		)	102,921
Long-term debt, net	576,326			—			—			—			576,326
Other long-term liabilities	2,867			9,338			3,631			—			15,836
Deferred tax liability	(28		)	73,039			(3,678		)	—			69,333
Intercompany payables	1,828,317			1,437,417			2,161,864			(5,427,598		)	—
Total liabilities	2,397,402			1,670,580			2,741,509			(6,045,075		)	764,416
Total equity	343,017			2,115,684			1,904,360			(4,023,926		)	339,135
Total liabilities and stockholders’ equity	$	2,740,419		$	3,786,264		$	4,645,869		$	(10,069,001	)	$	1,103,551

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Year Ended December 31, 2017
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(118,701	)	$	(1,611	)	$	(39,141	)	$	40,752		(118,701		)
Adjustments to reconcile net income (loss):
Depreciation and amortization	—			81,260			41,113			—			122,373
(Gain) loss on disposition of assets	—			247			2,604			—			2,851
Deferred tax expense (benefit)	4,785			(7,750		)	2,741			—			(224		)
Provision for reduction in carrying value of certain assets	—			—			1,938			—			1,938
Expenses not requiring cash	5,651			(218		)	9,880			(11,062		)	4,251
Change in assets and liabilities:
Accounts and notes receivable	—			(16,540		)	13,483			(6,571		)	(9,628		)
Rig materials and supplies	—			(760		)	5,470			—			4,710
Other current assets	(50,296		)	34,941			14,036			—			(1,319		)
Accounts payable and accrued liabilities	(4,393		)	56,354			262,884			(323,559		)	(8,714		)
Accrued income taxes	79,319			(60,882		)	(17,899		)	—			538
Other assets	24,722			(35,829		)	(280,675		)	300,440			8,658
Net cash provided by (used in) operating activities	(58,913		)	49,212			16,434			—			6,733

Cash flows from investing activities:
Capital expenditures	—			(42,990		)	(11,543		)	—			(54,533		)
Proceeds from the sale of assets	—			68			335			—			403
Net cash provided by (used in) investing activities	—			(42,922		)	(11,208		)	—			(54,130		)

Cash flows from financing activities:
Proceeds from the issuance of common stock	25,200			—			—			—			25,200
Proceeds from the issuance of mandatory convertible preferred stock	50,000			—			—			—			50,000
Payment of equity issuance costs	(2,864		)	—			—			—			(2,864		)
Mandatory convertible preferred stock dividend	(2,145		)	—			—			—			(2,145		)
Shares surrendered in lieu of tax	(936		)	—			—			—			(936		)
Net cash provided by (used in) financing activities	69,255			—			—			—			69,255

Net increase (decrease) in cash and cash equivalents	10,342			6,290			5,226			—			21,858
Cash and cash equivalents at beginning of year	65,000			14,365			40,326			—			119,691
Cash and cash equivalents at end of year	$	75,342		$	20,655		$	45,552		$	—		$	141,549

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Year Ended December 31, 2016
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(230,814	)	$	(49,625	)	$	(44,844	)	$	94,469		(230,814		)
Adjustments to reconcile net income (loss):
Depreciation and amortization	—			90,218			49,577			—			139,795
Accretion of contingent consideration	—			419			—			—			419
Loss on extinguishment of debt	1,088			—			—			—			1,088
(Gain) loss on disposition of assets	—			565			1,048			—			1,613
Deferred tax expense (benefit)	47,971			14,846			6,245			—			69,062
Expenses not requiring cash	9,545			(1,624		)	(5,403		)	—			2,518
Equity in net earnings (losses) of subsidiaries	94,469			—			—			(94,469		)	—
Change in assets and liabilities:
Accounts and notes receivable	—			25,923			34,468			—			60,391
Rig materials and supplies	—			(73		)	(1,679		)	—			(1,752		)
Other current assets	50,296			(35,322		)	(12,834		)	—			2,140
Accounts payable and accrued liabilities	(121,016		)	97,315			4,207			—			(19,494		)
Accrued income taxes	(10,381		)	(626		)	4,585			—			(6,422		)
Other assets	(299		)	101			4,095			—			3,897
Net cash provided by (used in) operating activities	(159,141		)	142,117			39,465			—			22,441

Cash flows from investing activities:
Capital expenditures	—			(15,384		)	(13,570		)	—			(28,954		)
Proceeds from the sale of assets	—			437			2,004			—			2,441
Net cash provided by (used in) investing activities	—			(14,947		)	(11,566		)	—			(26,513		)

Cash flows from financing activities:
Payment for noncontrolling interest	(3,375		)	—			—			—			(3,375		)
Payment of contingent consideration	—			(6,000		)	—			—			(6,000		)
Shares surrendered in lieu of tax	(1,156		)										(1,156		)
Intercompany advances, net	154,687			(120,659		)	(34,028		)	—			—
Net cash provided by (used in) financing activities	150,156			(126,659		)	(34,028		)	—			(10,531		)

Net increase (decrease) in cash and cash equivalents	(8,985		)	511			(6,129		)	—			(14,603		)
Cash and cash equivalents at beginning of year	73,985			13,854			46,455			—			134,294
Cash and cash equivalents at end of year	$	65,000		$	14,365		$	40,326		$	—		$	119,691

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PARKER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)

(Unaudited)



	Year Ended December 31, 2015
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(95,073	)	$	(13,875	)	$	(21,967	)	$	36,631		$	(94,284	)
Adjustments to reconcile net income (loss):
Depreciation and amortization	—			95,071			61,123			—			156,194
Accretion of contingent consideration	—			826			—			—			826
Gain (loss) on disposition of assets	—			(439		)	(1,204		)	—			(1,643		)
Deferred tax expense (benefit)	(18,715		)	11,718			9,706			—			2,709
Excess tax benefit (expense) from stock-based compensation	(1,045		)	—			—			—			(1,045		)
Provision for reduction in carrying value of certain assets	—			2,088			10,402			—			12,490
Expenses not requiring cash	7,344			854			(2,062		)	—			6,136
Equity in net earnings of subsidiaries	36,631			—			—			(36,631		)	—
Change in assets and liabilities:
Accounts and notes receivable	(33		)	61,818			42,210			—			103,995
Rig materials and supplies	—			51			2,671			—			2,722
Other current assets	19,885			(16,257		)	8,920			—			12,548
Accounts payable and accrued liabilities	10,228			(21,396		)	(16,257		)	—			(27,425		)
Accrued income taxes	15,368			(9,405		)	(13,920		)	—			(7,957		)
Other assets	(198,955		)	186,591			9,208			—			(3,156		)
Net cash provided by (used in) operating activities	(224,365		)	297,645			88,830			—			162,110
Cash flows from investing activities:
Capital expenditures	—			(58,817		)	(29,380		)	—			(88,197		)
Proceeds from the sale of assets	—			500			330			—			830
Proceeds from insurance settlements	—			—			2,500			—			2,500
Acquisitions, net of cash acquired	(3,375		)	(10,431		)	—			—			(13,806		)
Divestitures, net of cash paid	—			—			(2,570		)	—			(2,570		)
Net cash provided by (used in) investing activities	(3,375		)	(68,748		)	(29,120		)	—			(101,243		)
Cash flows from financing activities:
Proceeds from debt issuance	—			—			—			—			—
Repayments of long term debt	(30,000		)	—			—			—			(30,000		)
Payments of debt issuance costs	(1,996		)	—			—			—			(1,996		)
Payment of contingent consideration	—			(2,000		)	—			—			(2,000		)
Shares surrendered in lieu of tax	(1,033		)										(1,033		)
Intercompany advances, net	298,026			(226,589		)	(71,437		)	—			—
Net cash provided by (used in) financing activities	264,997			(228,589		)	(71,437		)	—			(35,029		)

Net increase (decrease) in cash and cash equivalents	37,257			308			(11,727		)	—			25,838
Cash and cash equivalents at beginning of year	36,728			13,546			58,182			—			108,456
Cash and cash equivalents at end of year	$	73,985		$	13,854		$	46,455		$	—		$	134,294

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Note 17 — Selected Quarterly Financial Data



	Quarter
Year 2017	First			Second			Third			Fourth			Total
	(Dollars in Thousands Except Per Share Amounts)
	(Unaudited)
Revenues	$	98,271		$	109,607		$	118,308		$	116,334		$	442,520
Operating gross margin (loss)	$	(19,745	)	$	(11,016	)	$	121		$	(4,700	)	$	(35,340	)
Operating income (loss)	$	(27,137	)	$	(17,632	)	$	(6,815	)	$	(14,221	)	$	(65,805	)
Net income (loss) attributable to controlling interest	$	(39,809	)	$	(29,888	)	$	(20,311	)	$	(28,693	)	$	(118,701	)
Net income (loss) available to common stockholders	$	(39,809	)	$	(31,127	)	$	(21,217	)	$	(29,599	)	$	(121,752	)
Basic earnings per share — net income (loss)⁽¹⁾	$	(0.31	)	$	(0.23	)	$	(0.15	)	$	(0.21	)	$	(0.89	)
Diluted earnings per share — net income (loss)⁽¹⁾	$	(0.31	)	$	(0.23	)	$	(0.15	)	$	(0.21	)	$	(0.89	)
	Quarter
Year 2016	First			Second			Third			Fourth			Total
	(Dollars in Thousands Except Per Share Amounts)
	(Unaudited)
Revenues	$	130,503		$	105,287		$	97,189		$	94,025		$	427,004
Operating gross margin (loss)	$	(13,428	)	$	(20,225	)	$	(21,965	)	$	(19,694	)	$	(75,312	)
Operating income (loss)	$	(23,269	)	$	(28,222	)	$	(29,576	)	$	(30,190	)	$	(111,257	)
Net income (loss) attributable to controlling interest	$	(95,835	)	$	(39,822	)	$	(46,228	)	$	(48,929	)	$	(230,814	)
Net income (loss) available to common stockholders	$	(95,835	)	$	(39,822	)	$	(46,228	)	$	(48,929	)	$	(230,814	)
Basic earnings per share — net income (loss)	$	(0.78	)	$	(0.32	)	$	(0.37	)	$	(0.39	)	$	(1.86	)
Diluted earnings per share — net income (loss)	$	(0.78	)	$	(0.32	)	$	(0.37	)	$	(0.39	)	$	(1.86	)

(1)

As a result of shares issued during the year, earnings (loss) per share for each of the year’s four quarters, which are based on weighted average shares outstanding during each quarter, may not equal the annual earnings (loss) per share, which is based on the weighted average shares outstanding during the year. Additionally, as a result of rounding to the thousands, earnings per share may not equal the year-to-date results.

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Note 18 — Recent Accounting Pronouncements

In January 2017, the FASB issued Accounting Standards Update (ASU) No. 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. The standard simplifies the subsequent measurement of goodwill by eliminating the second step of the goodwill impairment test. This standard is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. Effective January 1, 2017, we adopted ASU 2017-04 and it did not have a material impact on our consolidated statements of financial position, results of operations, cash flows, and on the disclosures contained in our notes to the consolidated financial statements.

In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The ASU requires entities to recognize at the transaction date the income tax consequences of intercompany asset transfers other than inventory. The standard becomes effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, but only at the beginning of the annual period for which no financial statements have been issued or been made available for issuance. Effective January 1, 2017, we adopted ASU 2016-16 prospectively and it did not have a material impact on our consolidated statements of financial position, results of operations and cash flows.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The ASU is intended to reduce diversity in current practice regarding the manner in which certain cash receipts and cash payments are presented and classified in the cash flow statement. The standard becomes effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. Effective January 1, 2017, we adopted ASU 2016-15 retrospectively and it did not have a material impact on our statement of cash flows.

In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718). The objective of this update is to simplify several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The standard became effective for public companies for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Effective January 1, 2017, we adopted ASU 2016-09. The adoption did not have a material impact on our consolidated statements of financial position, results of operations or cash flows. In accordance with the ASU requirements, we adopted certain aspects of the ASU as follows:

•

Accounting for excess tax benefits and certain tax deficiencies - The guidance requires all excess tax benefits, and certain tax deficiencies to be recorded through the income statement instead of additional paid in capital, where the activity was historically recorded. We adopted this change prospectively. There is no cumulative effect of the adoption as we have no unrecognized excess tax benefits or minimum withholding requirements that impact the income statement and, accordingly, prior periods have not been adjusted.

•

Cash flow presentation of excess tax benefits and certain tax deficiencies - We adopted this change retrospectively. Tax related cash flows from share based payments are to be presented as operating activities in the statement of cash flows. Consequently, activity for the year ended December 31, 2016 and 2015, recorded through equity, has been reclassified from financing activities to operating activities in the statement of cash flows. The impact of such reclassification was nominal for 2016. For the year ended December 31, 2015, we have reclassified $1.0 million from operating activities to financing activities.


•	Accounting for forfeitures - We have made an entity-wide accounting policy election to continue to estimate forfeitures and adjust the estimate when it is likely to change. This election does not change our current policy and, accordingly, there is no impact on our consolidated statements of financial position, results of operations or cash flows.

•

Cash paid to a tax authority when shares are withheld to satisfy the employer’s statutory income tax withholding obligation - We adopted this change retrospectively. The activity is now required to be presented as financing activities in the statement of cash flows. For the year ended December 31, 2016 and 2015, we have reclassified $1.2 million and $1.0 million, respectively, from operating activities to financing activities.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This accounting standards update requires (a) an entity to separate the lease components from the non-lease components in a contract where the lease component will be accounted for under ASU 2016-02 and the non-lease component will be accounted for under ASU 2014-09, (b) recognition of lease assets and lease liabilities by lessees and derecognition of the leased asset and recognition of a net investment in the lease by the lessor and (c) additional disclosure requirements for both lessees and lessors. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, although early adoption is permitted. Upon

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adoption, a retrospective approach is required for leases that exist, or are entered into, after the beginning of the earliest comparative period presented. Under the updated accounting standard, we have determined that our drilling contracts may contain a lease component; therefore, our adoption of the standard could require that we separately recognize revenues associated with the lease and service components. We will adopt ASU 2016-02 on January 1, 2019, and we expect to apply the modified retrospective approach. Our adoption, and the ultimate effect on our consolidated financial statements, will be based on an evaluation of the contract-specific facts and circumstances, and such effect could introduce variability to the timing of our revenue recognition relative to current accounting standards. We are evaluating the requirements to determine the effect such requirements may have on our consolidated statements of financial position, results of operations, cash flows and on the disclosures contained in our notes to the consolidated financial statements upon the adoption of ASU 2016-02. Depending on the results of the evaluation our ultimate conclusions may vary.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) which is effective for annual reporting periods that begin after December 15, 2017. This ASU supersedes the revenue recognition requirements in ASC 605 - Revenue Recognition and most industry-specific guidance throughout the Codification and provides a five step analysis for transactions to determine how and when revenue is recognized. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services and should be applied retrospectively to each prior reporting period presented or retrospectively with the cumulative effect of initially applying the ASU recognized at the date of initial application. Effective January 1, 2018, we adopted ASU 2014-09 using the modified retrospective approach, in which we will record the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, as an adjustment to opening retained earnings. In applying the new standard, we plan to account for the integrated services provided within our drilling, O&M and rentals contracts as a single performance obligation composed of a series of distinct time increments, which will be satisfied over time. We will determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. Consideration that does not relate to a distinct good or service, such as mobilization and contract preparation revenue, will be allocated across the single performance obligation and recognized ratably over the term of the contract. All other components of consideration within a contract, including the dayrate revenue, will continue to be recognized in the period when the services are performed. We do not anticipate the adoption of the new standard to have a material impact on our consolidated statements of financial position, results of operations and cash flows. Expanded revenue disclosures are expected in our notes to the consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40). The objective of this update is to provide guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and provide footnote disclosures. The amendments in this update become effective for public companies for the annual period after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. Effective January 1, 2017, we adopted ASU 2014-15 prospectively and it did not have a material impact on our consolidated statements of financial position, results of operations, cash flows, and on the disclosures contained in our notes to the consolidated financial statements.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended (the Exchange Act), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2017 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and is (2) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Management’s Annual Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that:


•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;


•	provide reasonable assurance transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States,


•	provide reasonable assurance that receipts and expenditures of the Company are being made only in accordance with authorization of management and directors of the Company; and


•	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 limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate.

The Company’s management with the participation of the chief executive officer and chief financial officer assessed the effectiveness of our internal control over financial reporting as of December 31, 2017 based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management’s assessment included evaluation of the design and testing of the operational effectiveness of our internal control over financial reporting. Management reviewed the results of its assessment with the audit committee of the board of directors.

Based on that assessment and those criteria, management has concluded that our internal control over financial reporting was effective as of December 31, 2017.

KPMG LLP, our independent registered public accounting firm that audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued a report with respect to our internal control over financial reporting as of December 31, 2017.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Item 9B. Other Information

None.

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PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

Information with respect to directors can be found under the captions “Item 1 — Election of Directors” and “Board of Directors” in our 2018 Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2018. Such information is incorporated herein by reference.

Information with respect to executive officers can be found in Item 1. Business - Executive Officers of this Form 10-K.

Information with respect to our audit committee and audit committee financial expert can be found under the caption “The Audit Committee” of our 2018 Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2018 and is incorporated herein by reference.

The information in our 2018 Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2018 set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.

We have adopted the Parker Drilling Code of Conduct (CC) which includes a code of ethics that is applicable to the chief executive officer, chief financial officer, controller and other senior financial personnel as required by the SEC. The CC includes provisions that will ensure compliance with the code of ethics required by the SEC and with the minimum requirements under the corporate governance listing standards of the NYSE. The CC is publicly available on our website at http://www.parkerdrilling.com. If any waivers of the CC occur that apply to a director, the chief executive officer, the chief financial officer, the controller or senior financial personnel or if the Company materially amends the CC, we will disclose the nature of the waiver or amendment on the website or in a current report on Form 8-K within four business days.

Item 11. Executive Compensation

The information under the captions “Executive Compensation,” “Fees and Benefit Plans for Non-Employee Directors,” “2017 Director Compensation Table,” and “Compensation Committee Report” in our 2018 Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2018 is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters

The information required by this item is hereby incorporated by reference to the information appearing under the captions “Security Ownership of Officers, Directors and Principal Stockholders” and “Equity Compensation Plan Information” in our 2018 Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2018.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is hereby incorporated by reference to such information appearing under the captions “Certain Relationships and Related Party Transactions” and “Director Independence Determination” in our 2018 Proxy Statement for the Annual Meeting of Stockholders to be held on May 10, 2018.

Item 14. Principal Accounting Fees and Services

The information required by this item is hereby incorporated by reference to the information appearing under the captions “Audit and Non-Audit Fees” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firm” in our 2018 Proxy Statement for the Annual Meeting of the Stockholders to be held on May 10, 2018.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this report:

(1) Financial Statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8:



	Page
Report of Independent Registered Public Accounting Firm	47
Consolidated Statement of Operations for the years ended December 31, 2017, 2016 and 2015	48
Consolidated Statement of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015	49
Consolidated Balance Sheet as of December 31, 2017 and 2016	50
Consolidated Statement of Cash Flows for the years ended December 31, 2017, 2016 and 2015	51
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2017, 2016 and 2015	52
Notes to the Consolidated Financial Statements	53
(2) Financial Statement Schedule:
Schedule II — Valuation and qualifying accounts	99

(3) Exhibits:



Exhibit Number		Description

2.1	—	Sale and Purchase Agreement, dated April 22, 2013, among ITS Tubular Services (Holdings) Limited, as Seller, Ian David Green, John Bruce Cartwright and Graham Douglas Frost, as joint administrators of the Seller, ITS Holdings, Inc. and PD International Holdings C.V., Parker Drilling Offshore Corporation and Parker Drilling Company (Incorporated by reference to Exhibit 2.1 to Parker Drilling Company’s Current Report on Form 8-K filed on April 23, 2013).

3.1	—	Restated Certificate of Incorporation of the Company, as amended on May 16, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).

3.2	—	By-laws of Parker Drilling Company, as amended and restated as of March 9, 2017 (Incorporated by reference to Exhibit 3.1 to Parker Drilling Company’s Current Report on Form 8-K filed on March 14, 2017).

3.3	—	Certificate of Designations of 7.25% Series A Mandatory Convertible Preferred Stock of Parker Drilling Company, dated February 27, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on February 27, 2017).

4.1	—	Indenture, dated July 30, 2013, between Parker Drilling Company, the subsidiary guarantors from time to time parties hereto, as, collectively, Guarantors, and The Bank of New York Mellon Trust Company, N.A. as Trustee (Incorporated by reference to Exhibit 4.1 to Parker Drilling Company’s Current Report on Form 8-K filed on July 31, 2013).

4.2	—	Form of 7.500% Senior Note due 2020 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on July 31, 2013).

4.3	—	Indenture, dated January 22, 2014, among Parker Drilling Company, the Guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on January 28, 2014).

4.4	—	Form of 6.750% Senior Note due 2022 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on January 28, 2014).

10.1	—	Parker Drilling Company Incentive Compensation Plan (as amended and restated effective January 1, 2009) (incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K filed on March 1, 2011).*

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10.2	—	Parker Drilling Company 2010 Long-Term Incentive Plan (as amended and restated effective May 8, 2013) (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement filed on March 28, 2013).*

10.3	—	Form of Parker Drilling Company Restricted Stock Unit Incentive Agreement under the 2010 LTIP (as amended and restated effective May 8, 2013) (incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K filed on February 25, 2015).*

10.4	—	Form of Parker Drilling Company Performance Cash Unit Award Incentive Agreement under the 2010 LTIP (as amended and restated effective May 8, 2013) (incorporated by reference to Exhibit 10.8 to the Company’s Annual Report on Form 10-K filed on February 25, 2015).*

10.5	—	Form of Parker Drilling Company Performance-Based Phantom Stock Unit Award Incentive Agreement under the 2010 LTIP (as amended and restated effective May 8, 2013) (incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K filed on February 25, 2016).*

10.6	—	Form of Parker Drilling Company Time-Based Phantom Stock Unit Award Incentive Agreement under the 2010 LTIP (as amended and restated effective May 8, 2013) (incorporated by reference to Exhibit 10.7 to the Company’s Annual Report on Form 10-K filed on February 21, 2017).*

10.7	—	Parker Drilling Company 2010 Long-Term Incentive Plan (as amended and restated as of May 10, 2016) (incorporated by reference to Appendix A of the Company’s Notice of Annual Meeting of Stockholders and Proxy Statement filed on March 31, 2016).*

10.8	—	Form of Parker Drilling Company Restricted Stock Unit Incentive Agreement under the 2010 LTIP (as amended as of May 10, 2016) (incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K filed on February 21, 2017).*

10.9	—	Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executive officer of Parker Drilling Company (incorporated by reference to Exhibit 10(g) to the Company’s Annual Report on Form 10-K filed on March 20, 2003).*

10.10	—	Employment Agreement between Mr. Jon-Al Duplantier and Parker Drilling Company, effective March 21, 2011 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 25, 2011).*

10.11	—	First Amendment dated August 29, 2011 to Employment Agreement between Mr. Jon-Al Duplantier and Parker Drilling Company, effective March 21, 2011 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on August 30, 2011).*

10.12	—	Employment Agreement, dated as of September 17, 2012, by and between Parker Drilling Company and Gary Rich (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 24, 2012).*

10.13	—	Retirement and Separation Agreement, dated November 1, 2013, between Parker Drilling Company and Robert L. Parker, Jr. (incorporated by reference to Exhibit 10.1 to Parker Drilling Company’s Current Report on Form 8-K filed on November 4, 2013).*

10.14	—	Second Amended and Restated Credit Agreement, dated January 26, 2015, among Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K filed on February 25, 2015).

10.15	—	First Amendment to the Second Amended and Restated Credit Agreement, dated June 1, 2015, among Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on August 6, 2015).

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10.16	—	Second Amendment to the Second Amended and Restated Credit Agreement, dated September 29, 2015, among Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on November 4, 2015).

10.17	—	Third Amendment to the Second Amended and Restated Credit Agreement, dated May 27, 2016, among Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on August 3, 2016).

10.18	—	Fourth Amendment to the Second Amended and Restated Credit Agreement, dated February 21, 2017, among Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 27, 2017).

10.19	—	Employment Agreement dated September 21, 2017 by and between Parker Drilling Company and Michael W. Sumruld (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 26, 2017).*

10.20	—	Fifth Amendment to the Second Amended and Restated Credit Agreement, dated February 14, 2018, among Parker Drilling Company, as Borrower, and Bank of America, N.A., as Administrative Agent and L/C Issuer.

12.1	—	Computation of Ratio of Earnings to Fixed Charges.

21	—	Subsidiaries of the Registrant.

23.1	—	Consent of KPMG LLP — Independent Registered Public Accounting Firm.

31.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.

31.2	—	Michael W. Sumruld, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.

32.1	—	Gary G. Rich, Chairman, President and Chief Executive Officer, 18 U.S.C. Section 1350 Certification.

32.2	—	Michael W. Sumruld, Senior Vice President and Chief Financial Officer, 18 U.S.C. Section 1350 Certification.

101.INS	—	XBRL Instance Document.

101.SCH	—	XBRL Taxonomy Schema Document.

101.CAL	—	XBRL Calculation Linkbase Document.

101.LAB	—	XBRL Label Linkbase Document.

101.PRE	—	XBRL Presentation Linkbase Document.

101.DEF	—	XBRL Definition Linkbase Document.

____________________________

* — Management contract, compensatory plan or agreement.

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PARKER DRILLING COMPANY AND SUBSIDIARIES

Schedule II—Valuation and Qualifying Accounts



Classifications	Balance at beginning of year		Charged to cost and expenses			Charged to other accounts			Deductions			Balance at end of year
Dollars in Thousands
Year Ended December 31, 2017
Allowance for bad debt	$	8,259	$	444		$	(414	)	$	(725	)	$	7,564
Allowance for obsolete rig materials and supplies	$	1,166	65			—			(422		)	809
Deferred tax valuation allowance	$	171,133	$	(14,625	)	$	1,406		$	—		$	157,914
Year Ended December 31, 2016
Allowance for bad debt	$	8,694	$	1,483		$	4		$	(1,922	)	$	8,259
Allowance for obsolete rig materials and supplies	$	626	978			$	(3	)	$	(435	)	$	1,166
Deferred tax valuation allowance	$	51,105	$	117,707		$	2,321		$	—		$	171,133
Year Ended December 31, 2015
Allowance for bad debt	$	11,188	$	341		$	(825	)	$	(2,010	)	$	8,694
Allowance for obsolete rig materials and supplies	$	530	$	—		$	236		$	(140	)	$	626
Deferred tax valuation allowance	$	9,922	$	40,676		$	507		$	—		$	51,105

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Item 16. Form 10-K Summary

None.

100

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.



	PARKER DRILLING COMPANY

	By:		/s/ Michael W. Sumruld
			Michael W. Sumruld
			Senior Vice President and Chief Financial Officer

Date: February 21, 2018

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



	Signature	Title	Date

By:	/s/ Gary G. Rich	Chairman, President, and Chief Executive Officer (Principal Executive Officer)	February 21, 2018
	Gary G. Rich

By:	/s/ Michael W. Sumruld	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 21, 2018
	Michael W. Sumruld

By:	/s/ Nathaniel C. Dockray	Principal Accounting Officer (Principal Accounting Officer)	February 21, 2018
	Nathaniel C. Dockray	Principal Accounting Officer (Principal Accounting Officer)

By:	/s/ Jonathan M. Clarkson	Director	February 21, 2018
	Jonathan M. Clarkson

By:	/s/ Peter T. Fontana	Director	February 21, 2018
	Peter T. Fontana

By:	/s/ Gary R. King	Director	February 21, 2018
	Gary R. King

By:	/s/ Robert L. Parker Jr.	Director	February 21, 2018
	Robert L. Parker Jr.

By:	/s/ Richard D. Paterson	Director	February 21, 2018
	Richard D. Paterson

By:	/s/ Zaki Selim	Director	February 21, 2018
	Zaki Selim

101