Document

Large accelerated filer ¨

Accelerated filer þ

Non-accelerated filer ¨

Smaller reporting company þ

Emerging growth company ¨

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, 2018



¨	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)

(281) 406-2000

(Registrant’s telephone number, including area code)

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

None

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

Common Stock, par value $0.16 ²/₃ per share

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):

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, 2018 was $51.3 million. At March 6, 2019, there were 9,382,493 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Items 10, 11, 12, 13 and 14 of Part III will be incorporated by reference from the Form 10-K/A to be filed with the Securities and Exchange Commission.

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TABLE OF CONTENTS



		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties	25
Item 3.	Legal Proceedings	27
Item 4.	Mine Safety Disclosures	27

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	28
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 8.	Financial Statements and Supplementary Data	53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	108
Item 9A.	Controls and Procedures	108
Item 9B.	Other Information	109

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	110
Item 11.	Executive Compensation	110
Item 12.	Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters	110
Item 13.	Certain Relationships and Related Transactions, and Director Independence	110
Item 14.	Principal Accounting Fees and Services	110

PART IV
Item 15.	Exhibits and Financial Statement Schedules	111
Item 16.	Form 10-K Summary	116
	Signatures	117

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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 20 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, 2018, 2017 and 2016, see Note 16 - 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.

Recent Developments

Reorganization and Chapter 11 Proceedings

On December 12, 2018 (the “Petition Date”), Parker Drilling and certain of its U.S. subsidiaries (collectively, the “Debtors”) filed a prearranged plan of reorganization (the “Plan”) and commenced voluntary Chapter 11 proceedings (the “Chapter 11 Cases”) under title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”). Since the commencement of the Chapter 11 Cases, the Debtors have continued to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Also on December 12, 2018, prior to the commencement of the Chapter 11 Cases, the Debtors entered into a restructuring support agreement (as amended, the “RSA”) with certain significant holders (together, collectively, the “Consenting Stakeholders”) of (i) 7.50% Senior Notes due 2020 (the “7.50% Note Holders”) issued pursuant to the indenture dated July 30, 2013 (the “7.50% Notes”), by and among Parker Drilling, the subsidiary guarantors party thereto and Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”), (ii) 6.75% Senior Notes due 2022 (the “6.75% Note Holders”) issued pursuant to the indenture dated January 22, 2014 (the “6.75% Notes” and together with the 7.50% Notes, the “Senior Notes”), by and among Parker Drilling, the subsidiary guarantors party thereto and the Trustee, (iii) Parker Drilling’s existing common stock (the “Common Holders”) and (iv) Parker Drilling’s 7.25% Series A Mandatory Convertible Preferred Stock (the “Convertible Preferred Stock,” and such holders, the “Preferred Holders”) to support a restructuring (the “Restructuring”) on the terms set forth in the Plan.

On December 13, 2018, the Bankruptcy Court entered an order approving joint administration of the Chapter 11 Cases under the caption In re Parker Drilling Company, et al.

Pursuant to the terms of the RSA and the Plan, the Consenting Stakeholders and other holders of claims against or interests in the Debtors receive treatment under the Plan summarized as follows:


•	holders of claims arising from non-funded debt general unsecured obligations receive payment in full in cash as set forth in the Plan;

•

the 7.50% Note Holders receive their pro rata share of: (a) approximately 34.3 percent of the common stock (the “New Common Stock”) of Parker Drilling, as reorganized pursuant to and under the Plan (“Reorganized Parker”), subject to dilution; (b) approximately $92.6 million of a new second lien term loan of Reorganized Parker (the “New Second Lien Term Loan”); (c) the right to purchase approximately 24.3 percent of the New Common Stock to be issued pursuant to the terms of the Rights Offering (as defined in the RSA); and (d) cash sufficient to satisfy certain expenses owed to the Trustee (the “Trustee Expenses”), to the extent not otherwise paid by the Debtors;

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•

the 6.75% Note Holders receive their pro rata share of: (a) approximately 62.9 percent of the New Common Stock, subject to dilution; (b) approximately $117.4 million of the New Second Lien Term Loan; (c) the right to purchase approximately 38.9 percent of the New Common Stock to be issued pursuant to the terms of the Rights Offering; and (d) cash sufficient to satisfy the Trustee Expenses, to the extent not otherwise paid by the Debtors;


•	the Preferred Holders receive their pro rata share of: (a) 1.1 percent of the New Common Stock, subject to dilution; (b) the right to purchase approximately 14.7 percent of the New Common Stock to be issued pursuant to the terms of the Rights Offering; and (c) 40.0 percent of the warrants to acquire an aggregate of 13.5 percent of the New Common Stock (the “New Warrants”); and


•	the Common Holders receive their Pro Rata share of: (a) 1.65 percent of the New Common Stock, subject to dilution; (b) the right to purchase approximately 22.1 percent of the New Common Stock to be issued pursuant to the terms of the Rights Offering; and (c) 60.0 percent of the New Warrants.

The RSA contains certain covenants on the part of each of the Debtors and the Consenting Stakeholders, including certain limitations on the parties’ ability to pursue alternative transactions, commitments by the Consenting Stakeholders to vote in favor of the Plan and commitments of the Debtors and the Consenting Stakeholders to negotiate in good faith to finalize the documents and agreements governing the Plan. The RSA also provides for certain conditions to the obligations of the parties and for termination upon the occurrence of certain events, including, without limitation, the failure to achieve certain milestones and certain breaches by the parties under the RSA.

Since the Petition Date, the Debtors have requested and received certain approvals and authorizations from the Bankruptcy Court. This relief, together with the proposed treatment under the Plan, provides that vendors and other unsecured creditors will be paid in full and in the ordinary course of business. All existing customer and vendor contracts are expected to remain in place and be serviced in the ordinary course of business.

On March 5, 2019, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 7, 2019, the Bankruptcy Court entered an order confirming the Plan. Although the Bankruptcy Court has confirmed the Plan, the Debtors have not yet consummated all of the transactions that are contemplated by the Plan. Rather, the Debtors intend to consummate these transactions in the near future, on or before the Plan’s effective date (the “Effective Date”). As set forth in the Plan, there are certain conditions precedent to the occurrence of the Effective Date, which must be satisfied or waived in accordance with the Plan in order for the Plan to become effective and the Debtors to emerge from the Chapter 11 Cases. The Debtors anticipate that each of these conditions will be either satisfied or waived by the end of March 2019, which is the target for the Debtors’ emergence from the Chapter 11 Cases. On the Effective Date, the Debtors’ operations will, generally, no longer be governed by the Bankruptcy Court’s oversight.

The Company’s filing of the Chapter 11 Cases constituted an event of default of certain of its debt instruments described above, which accelerated the Company’s obligations under its Senior Notes. Under the Bankruptcy Code, holders of the Senior Notes are stayed from taking any action against the Company as a result of this event of default. All of the Company’s outstanding obligations under its Second Amended and Restated Credit Agreement dated as of January 26, 2015, among Parker Drilling, Bank of America, N.A., Wells Fargo Bank, National Association, Barclays Bank PLC and the other lenders and L/C issuers from time to time party thereto (as amended, the “2015 Secured Credit Agreement”) were paid prior to the filing of the Chapter 11 Cases and the 2015 Secured Credit Agreement was terminated substantially concurrent with the filing.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, Bank of America, N.A. (“Bank of America”) and Deutsche Bank AG New York Branch (“DB”) agreed to provide the Debtors with a superpriority and priming asset-based debtor-in-possession credit facility (the “DIP Facility”) on the terms set forth in the Debtor-In-Possession Financing Term Sheet attached to the RSA (the “DIP Term Sheet”). On December 14, 2018, the Debtors, Bank of America and DB entered into a Debtor-in-Possession Credit Agreement, which provides for, among other things, the DIP Facility. The DIP Facility is comprised of an asset-based revolving loan facility in an aggregate principal amount of $50.0 million, subject to availability under the borrowing base thereunder, $20.0 million of which is available for the issuance of standby letters of credit.

In connection with the Chapter 11 Cases, (i) Bank of America and DB agreed to provide, on a committed basis, the Company with an exit financing asset-based revolving loan facility on the terms set forth in the Senior Secured Asset-Based Revolving Facility Summary of Terms and Conditions attached to the RSA (the “First Lien Exit Term Sheet”) and (ii) certain Consenting Stakeholders and/or their affiliates have agreed to provide, on a committed basis, the Company with a new second lien term loan facility on the terms set forth in the New Second Lien Loan Term Sheet attached to the RSA (the “Second Lien Exit Term Sheet”). The First Lien Exit Term Sheet provides for, among other things, an asset-based revolving credit facility in an aggregate principal amount of $50.0 million, which amount may be increased to an aggregate principal amount of $100.0 million

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in the event additional commitments are received from other lenders (the “First Lien Exit Facility”). A portion of the First Lien Exit Facility in the amount of $30.0 million (the “L/C Facility”) will be available for the issuance of standby and commercial letters of credit. The Second Lien Exit Term Sheet provides for, among other things, a second lien term loan facility in an aggregate principal amount of $210.0 million (the “Second Lien Exit Facility”).

The foregoing descriptions of the First Lien Exit Term Sheet and the Second Lien Exit Term Sheet do not purport to be complete and are qualified in their entirety by reference to the First Lien Exit Term Sheet or the Second Lien Exit Term Sheet, as applicable. The effectiveness of the First Lien Exit Facility and the Second Lien Exit Facility is subject to customary closing conditions. The foregoing descriptions of the First Lien Exit Facility and the Second Lien Exit Facility do not purport to be complete and are qualified in their entirety by reference to the final, executed documents memorializing the First Lien Exit Facility and the Second Lien Exit Facility, as applicable, in each case as approved by the Bankruptcy Court.

Going Concern and Financial Reporting in Reorganization

Our commencement of the Chapter 11 Cases and the weak industry conditions have negatively impacted our results of operations and cash flows and may continue to do so in the future. These factors raise substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles which contemplate the continuation of the Company as a going concern. See Note 2 - Chapter 11 Cases in the notes to the consolidated financial statements included under Item 8. Financial Statements and Supplementary Data and Item 1A. Risk Factors for additional information regarding our debt instruments and bankruptcy proceedings under Chapter 11.

Delisting of our Common Stock from the New York Stock Exchange (the “NYSE”)

Our common stock was previously listed on the NYSE under the symbol “PKD.” As a result of our failure to satisfy the continued listing requirements of the NYSE, on December 12, 2018, our common stock was delisted from the NYSE. Since December 13, 2018, our common stock has been quoted on the OTC Pink marketplace maintained by the OTC Markets Group, Inc. (“OTC Pink”) under the symbol “PKDSQ”.

Drilling Services Business

In our Drilling Services business, we drill oil, natural gas, and geothermal wells for customers globally. 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 or 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, commissioning of customer-owned drilling rig projects, operations execution, and quality and safety management. 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. We also provide O&M services for a customer-owned rig offshore California. Our GOM barge rigs 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. 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;

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•	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.

We have rigs under contract in Alaska, Kazakhstan, the Kurdistan region of Iraq, Guatemala, Mexico, and on Sakhalin Island, Russia. In addition, we have O&M and ongoing project-related services for customer-owned rigs in California, Kuwait, Canada, Indonesia, and on Sakhalin Island, Russia.

Rental Tools Services Business

In our Rental Tools Services business, we provide premium rental equipment and services to exploration & production 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 whipstocks, fishing and related services, as well as 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 maintains an inventory of rental tools for deepwater, drilling, completion, workover, and production applications at facilities in Louisiana, Texas, Wyoming, North Dakota and West Virginia. We also provide well construction and well intervention services. 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 supplies tubular goods and other equipment to offshore GOM customers.

International Rental Tools

Our International Rental Tools segment maintains an inventory of rental tools and provides well construction, well intervention, and surface and tubular services to our customers in the Middle East, Latin America, 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.

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 2018, our largest customer, Exxon Neftegas Limited (“ENL”), accounted for approximately 25.7 percent of our total consolidated revenues. For information regarding our reportable segments and operations by geographic areas for the years ended December 31, 2018, 2017 and 2016, see Note 16 - 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

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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 both large and small suppliers. We compete against other rental tools companies based on breadth of inventory, availability of product, quality of product and service, as well as, price. In the U.S. market, our network of locations provides broad and efficient product availability for our customers. 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, 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. In addition, some tools, such as whipstocks, are sold to the customer.

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 $243.4 million as of December 31, 2018 and $240.9 million as of December 31, 2017 and is primarily attributable to the International & Alaska segment of our Drilling Services business. We estimate that, as of December 31, 2018, 54.0 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 the scope of equipment and service provided, 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

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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 $50.0 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 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.

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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,
	2018	2017
U.S. (Lower 48) Drilling	89	111
International & Alaska Drilling	1,208	1,122
U.S. Rental Tools	232	214
International Rental Tools	717	648
Corporate	179	171
Total employees	2,425	2,266

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”) and state equivalents, issue regulations to implement and enforce laws pertaining to the environment, which often require 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 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 Outer Continental Shelf Lands Act (“OCSLA”); the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”); the Resource Conservation and Recovery Act (“RCRA”); the Clean Air Act (“CAA”); the Endangered Species Act (“ESA”); the Occupational Safety and Health Act; 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 CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including jurisdictional wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In September 2015, a new EPA and U.S. Army Corps of Engineers (the “Corps”) rule defining the scope of federal jurisdiction over wetlands and other waters became effective (the “Clean Water Rule”). The Clean Water Rule was previously stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases challenging the rule. The EPA and the Corps issued a proposed rulemaking in June 2017 to repeal the Clean Water Rule, and announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction. In January 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts to hear challenges to the Clean Water Rule; following which, the previously-filed district court cases have been allowed to proceed. Following the Supreme Court’s decision, the EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 rule for two years while the agencies reconsider the rule. Multiple states and environmental groups have challenged the stay, and on August 16, 2018, a federal court in South Carolina issued an injunction against EPA’s stay of the rule. On December 11, 2018, EPA proposed a new rule defining the scope of federal jurisdiction over wetlands and other waters, a public hearing on which was originally scheduled for January 23, 2019. This hearing was indefinitely postponed during the shutdown of the federal government and has not yet been rescheduled. To the extent the rule expands the range of properties subject to the CWA’s jurisdiction, certain energy companies could face increased costs and

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delays with respect to obtaining permits for dredge and fill activities in wetland areas, which in turn could reduce demand for our services. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. The CWA and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.

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 strict and joint and several 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.

High-profile and catastrophic events, such as the 2010 Macondo (Deepwater Horizon) well incident, have heightened governmental and environmental focus on the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. Our operations, and those of our customers, are impacted by restrictions on drilling in certain areas of the U.S. Gulf of Mexico and elsewhere, including the adoption of additional safety requirements and policies regarding the approval of drilling permits and restrictions on development and production activities in the U.S. Gulf of Mexico.

On July 28, 2016, BSEE adopted a new well-control rule that will be implemented in phases over the next several years (the "2016 Well Control Rule"). This rule includes more stringent design requirements for well-control equipment used in offshore drilling operations. BSEE was directed to review the 2016 Well Control Rule pursuant to Executive Order (“EO”) 13783 (“Promoting Energy Independence and Economic Growth”) and Section 7 of EO 13795 (“Implementing an America-First Offshore Energy Strategy”), to determine if the rule should be revised to encourage energy exploration and production on the Outer Continental Shelf, while still providing for safe and environmentally responsible exploration and production activities. On May 11, 2018, BSEE announced a proposed rule intending to reduce the regulatory burden of the 2016 Well Control Rule, the comment period for which ended on August 6, 2018. We are continuing to evaluate the cost and effect that these new rules will have on our operations.

CERCLA (also known as “Superfund”) and comparable state laws impose 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. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration- and production-related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary.

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If the EPA proposes rulemaking for revised oil and gas regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Although the costs of managing solid and hazardous wastes may be significant and new regulations may be imposed, 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. In addition, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. The EPA has also adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Further, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion in October 2015. Pursuant to an order issued by the U.S. District Court for the Northern District of California in lawsuits brought by a coalition of states and environmental groups against the EPA for failing to complete initial area designations under the standard by the October 2017 statutory deadline, EPA completed all remaining initial area designations on July 17, 2018. State implementation of the revised NAAQS could result in stricter permitting requirements or delay, or limit our ability or our customers’ ability to obtain permits, and result in increased expenditures for pollution control equipment and decreased demand for our services.

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 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 and will be complete by November 2020. 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.

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 products or services.

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The federal ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on natural gas and oil leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered may exist. On February 11, 2016, the U.S. Fish and Wildlife Service (“FWS”) published a final policy which alters how it may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions and may materially delay or prohibit land access for natural gas and oil development. The designation of previously unprotected species as threatened or endangered in areas where operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our customer’s exploration and production activities that could have an adverse impact on their ability to develop and produce reserves. If our customers were to have a portion of their leases designated as critical or suitable habitat, it could have a material adverse impact on the demand for our products and services.

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.

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. 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.

Risks Related to Our Chapter 11 Proceedings

On December 12, 2018, Parker Drilling and certain of its U.S. subsidiaries filed voluntary petitions commencing the Chapter 11 Cases under the Bankruptcy Code. The Chapter 11 Cases and the Restructuring may have a material adverse impact on our business, financial condition, results of operations, and cash flows. In addition, the Chapter 11 Cases and the Restructuring may have a material adverse impact on the trading price and ultimately are expected to result in the cancellation and discharge of our securities, including our common stock. The Plan governs distributions to and the recoveries of holders of our securities.

In 2018, we engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness in private transactions. These restructuring efforts led to the execution of the RSA and commencement of the Chapter 11 Cases in the Bankruptcy Court on December 12, 2018.

The Chapter 11 Cases could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the Chapter 11 Cases continue, our senior management may be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing on our business operations. Bankruptcy Court protection also may make it more difficult to retain management and the key personnel necessary to the success and growth of our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our customers and suppliers might lose confidence in our ability to reorganize our business successfully and may seek to establish alternative commercial relationships.

Other significant risks include or relate to the following:


•	our ability to obtain the Bankruptcy Court’s approval with respect to motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases, including maintaining strategic control as debtor-in-possession;


•	our ability to consummate the Plan;


•	the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents, including our stockholders;


•	increased advisory costs to execute our reorganization;


•	our ability to maintain relationships with suppliers, customers, employees and other third parties as a result of the Chapter 11 Cases;


•	Bankruptcy Court rulings in the Chapter 11 Cases as well as the outcome of all other pending litigation and the outcome of the Chapter 11 Cases in general;


•	the length of time that we will operate with Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;


•	third-party motions in the Chapter 11 Cases, which may interfere with our ability to consummate the Plan; and


•	the potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations.

Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.

Delays in the Chapter 11 Cases may increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

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The RSA contemplates the consummation of the Plan through an orderly prearranged plan of reorganization, but there can be no assurance that we will be able to consummate the Plan. A prolonged Chapter 11 proceeding could adversely affect our relationships with customers, suppliers and employees, among other parties, which in turn could adversely affect our business, competitive position, financial condition, liquidity and results of operations and our ability to continue as a going concern. A weakening of our financial condition, liquidity and results of operations could adversely affect our ability to implement the Plan (or any other plan of reorganization). If we are unable to consummate the Plan, we may be forced to liquidate our assets.

In addition, the occurrence of the Effective Date is subject to certain conditions and requirements in addition to those described above that may not be satisfied.

We believe it is likely that our common stock will substantially decrease in value as a result of the Chapter 11 Cases.

We have a significant amount of indebtedness that is senior to our current common stock in our capital structure. Our existing common stock has substantially decreased in value during the Chapter 11 Cases. We do not foresee a market for our existing common stock after emergence from the Chapter 11 Cases. Accordingly, any trading in our common stock during the pendency of our Chapter 11 Cases is highly speculative and poses substantial risks to purchasers of our common stock.

The RSA is subject to significant conditions and milestones that may be difficult for us to satisfy.

There are certain material conditions we must satisfy under the RSA, including the timely satisfaction of milestones in the Chapter 11 Cases, which include the consummation of the Plan. Our ability to timely complete such milestones is subject to risks and uncertainties, many of which are beyond our control.

The Plan may not become effective.

While the Plan has been confirmed by the Bankruptcy Court, it may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied and, therefore, that the Plan will become effective and that the Debtors will emerge from the Chapter 11 Cases as contemplated by the Plan. If the Effective Date is delayed, the Debtors may not have sufficient cash available to operate their businesses. In that case, the Debtors may need new or additional post-petition financing, which may increase the cost of consummating the Plan. There is no assurance of the terms on which such financing may be available or if such financing will be available. If the transactions contemplated by the Plan are not completed, it may become necessary to amend the Plan. The terms of any such amendment are uncertain and could result in material additional expense and result in material delays to the Chapter 11 Cases.

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and there is substantial doubt regarding our ability to continue as a going concern.

Even if the Plan or any other Chapter 11 plan of reorganization is consummated, we may continue to face a number of risks, such as changes in economic conditions, changes in our industry, changes in demand for our services and increasing expenses. Some of these risks become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, we cannot guarantee that any Chapter 11 plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, or at all.

As a result of the Chapter 11 Cases, even with the creditor support for the restructuring under the RSA, there is substantial doubt regarding our ability to continue as a going concern. As a result, we cannot give any assurance of our ability to continue as a going concern, even though the Plan has been confirmed.

Our shares of common stock are not listed for trading on a national securities exchange.

Our common stock currently trades on OTC Pink and is not listed for trading on a national securities exchange. We can provide no assurance that our common stock will continue to trade on OTC Pink, whether broker-dealers will continue to provide public quotes of our common stock on OTC Pink, whether the trading volume of our common stock will be sufficient to provide for an efficient trading market or whether quotes for our common stock will continue on OTC Pink in the future.

Investments in securities trading on OTC Pink are generally less liquid than investments in securities trading on a national securities exchange. In addition, the trading of our common stock on OTC Pink could have other negative implications, including

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the potential loss of confidence in us by suppliers, customers and employees and the loss of institutional investor interest in our common stock. This could further depress the trading price of our common stock and could also have a long-term adverse effect on our ability to raise capital. There can be no assurance that any public market for our common stock will exist in the future or that we will be able to relist our common stock on a national securities exchange.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in the Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

As a result of the Chapter 11 Cases, our historical financial information may not be indicative of our future performance, which may be volatile.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the filing of the Chapter 11 Cases. In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to our historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to the Plan. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting may be different from historical trends.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Court provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to consummation of a plan of reorganization. With few exceptions, all claims that arose prior to December 12, 2018 or before consummation of the Plan (i) would be subject to compromise and/or treatment under the Plan and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the Plan. Any claims not ultimately discharged pursuant to the Plan could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

We may experience employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, we may experience employee attrition, and our employees may face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, liquidity and results of operations.

Risks Related to Our Business

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

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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 2018 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.

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 risen to 37.0 percent for the year ended December 31, 2018 from 36.0 percent for the year ended December 31, 2017. 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 funded 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.

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As of December 31, 2018, we had:


•	$585.0 million principal amount of debt;


•	$26.9 million of operating lease commitments; and


•	$10.0 million borrowed under the DIP Facility.

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.

As of December 12, 2018, the Company was in default under certain of its debt instruments. The Company’s filing of the Chapter 11 Cases described above accelerated the Company’s obligations under its Senior Notes. All of the Company’s outstanding obligations under its 2015 Secured Credit Agreement were paid prior to the filing of the Chapter 11 Cases and the 2015 Secured Credit Agreement was terminated substantially concurrently with such filing. Additionally, events of default under the indentures governing the Company’s Senior Notes have occurred and are continuing, including as a result of cross-defaults between such indentures.

Despite our current level of indebtedness, we may still be able to incur more debt. This could further exacerbate the risks associated with our indebtedness, including limiting our liquidity and our ability to pursue other business opportunities.

We may be able to incur additional indebtedness in the future, subject to certain limitations, including under the DIP Facility, the First Lien Exit Facility and the Second Lien Exit Facility. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

Further, under Chapter 11, transactions outside the ordinary course of business are subject to the prior approval of the Bankruptcy Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities or to adapt to changing market or industry conditions. The Debtors are subject to various covenants and events of default under the DIP Facility. In general, certain of these covenants limit the Debtors’ ability, subject to certain exceptions, to take certain actions, including:


•	selling assets outside the ordinary course of business;


•	consolidating, merging, amalgamating, liquidating, dividing, winding up, dissolving or otherwise disposing of all or substantially all of its assets;


•	granting liens; and


•	financing its investments.

If the Debtors fail to comply with these covenants or an event of default occurs under the DIP Facility, our liquidity, financial condition or operations may be materially impacted.

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. The DIP Facility may be insufficient to fund our cash requirements through emergence from bankruptcy.

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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.

Additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in the DIP Facility. 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.

Further, for the duration of the Chapter 11 Cases, we will be subject to various risks, including but not limited to (i) the inability to maintain or obtain sufficient financing sources for operations or to fund the plan of reorganization and meet future obligations, and (ii) increased legal and other professional costs associated with the Chapter 11 Cases and our reorganization.

If the transactions contemplated by the plan of reorganization are not completed and the effective date of the plan of reorganization does not occur prior to the maturity of the DIP Facility, we may need to refinance the DIP Facility. We may not be able to obtain some or all of any such financing on acceptable terms or at all.

We may be unable to repay or refinance our debt as it becomes due, whether at maturity or as a result of acceleration.

We may not be able to repay our debt as it comes due, or to refinance our debt on a timely basis or on terms acceptable to us and within the limitations contained in the DIP Facility and the indentures governing our outstanding Senior Notes. Failure to repay or to timely refinance any portion of our debt could result in a default under the terms of all our debt instruments and permit the acceleration of all indebtedness outstanding.

While we intend to take appropriate mitigating actions to refinance our indebtedness prior to maturity or otherwise extend the maturity dates, and to cure any potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient.

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.

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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 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.

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 2018, our largest customer, ENL, accounted for approximately 25.7 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

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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, 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,

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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 2018, we derived approximately 56.8 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;


•	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 20 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.

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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, over the past several years the U.S. Government has imposed additional sanctions against Russia’s oil and gas industry and certain Russian companies and individuals. 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 changing. These laws and regulations can cause delays in shipments, unscheduled operational downtime and other operational disruptions. 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. Reputational damage can also result from any failure to comply with such obligations.

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

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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. For a description of how the Restructuring could affect our ability to attract and retain personnel, see Risks Related to Our Chapter 11 Proceedings - We may experience employee attrition as a result of the Chapter 11 Cases.

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.

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.

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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.

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 9 - 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.

Our operations are subject to cyber-attacks or other cyber incidents that could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.

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Our operations are becoming increasingly dependent on digital technologies and services. We use these technologies for internal purposes, including data storage (which may include personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders), processing, and transmissions, as well as in our interactions with customers and suppliers. Digital technologies are subject to the risk of cyber-attacks, security breaches and other cyber incidents, which could include, among other things, computer viruses, malicious or destructive code, ransomware, social engineering attacks (including phishing and impersonation), hacking, denial-of-service attacks and other attacks and similar disruptions from the unauthorized use of or access to computer systems. If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other things: loss of or damage to intellectual property, proprietary or confidential information, or customer, supplier, or employee data; interruption of our business operations; and increased costs required to prevent, respond to, or mitigate cybersecurity attacks. These risks could harm our reputation and our relationships with customers, suppliers, employees, and other third parties, and may result in claims against us, including liability under laws that protect the privacy of personal information. In addition, these risks could have a material adverse effect on our business, results of operations and financial condition.

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.

For a description of how the Restructuring could affect the price of our common stock, see “Risks Related to Our Chapter 11 Proceedings”.

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 restrict 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 certain statements that may be deemed to be “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 in this Form 10-K other than statements of historical facts addressing activities, events or developments we expect, project, believe, or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Although we believe our expectations stated in this Form 10-K are based on reasonable assumptions, such statements are subject to a number of risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those implied or expressed by the forward-looking statements. These statements include, but are not limited to, statements about anticipated future financial or operational results, our financial position, and similar matters. These include risks relating to:


•	our ability to obtain the Bankruptcy Court’s approval with respect to motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases, including maintaining strategic control as debtor-in-possession;


•	our ability to consummate the Plan;


•	the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents, including our stockholders;


•	increased advisory costs to execute our reorganization;


•	any inability to maintain relationships with suppliers, customers, employees and other third parties as a result of the Chapter 11 Cases;


•	Bankruptcy Court rulings in the Chapter 11 Cases as well as the outcome of all other pending litigation and the outcome of the Chapter 11 Cases in general;


•	the length of time that we will operate with Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;


•	third-party motions in the Chapter 11 Cases, which may interfere with our ability to consummate the Plan;


•	the potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations;


•	the impact of the NYSE delisting our common stock on the liquidity and market price of our common stock and on our ability to access the public capital markets;


•	changes in worldwide economic and business conditions;


•	fluctuations in oil and natural gas prices;


•	compliance with existing laws and changes in laws or government regulations;


•	the failure to realize the benefits of, and other risks relating to, acquisitions;


•	the risk of cost overruns;


•	our ability to refinance our debt; and


•	other important factors, many of which could adversely affect market conditions, demand for our services, and costs, and all or any one of which could cause actual results to differ materially from those projected.

For more information, see Item 1A. Risk Factors of this Form 10-K. 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 statement, whether as a result of new information, future events or otherwise.

Item 1B. Unresolved Staff Comments

None.

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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, 2018:



Name	Type ⁽¹⁾	Year entered into service/ upgraded	Drilling depth rating (in feet)	Location
International & Alaska Drilling
Eastern Hemisphere
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 located in Colombia, which is currently not available for service. During 2018 we sold Rig 231 and Rig 253 which were located in Indonesia and Rig 268 which was located in Colombia.

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Item 3. Legal Proceedings

For information on Legal Proceedings, see Note 9 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data, which information is incorporated herein by reference.

For information on the Company’s Chapter 11 Cases, see Item 1. Business - Recent Developments - Reorganization and Chapter 11 Proceedings contained herein, which information is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

Parker Drilling Company’s common stock traded on NYSE under the symbol “PKD” until December 12, 2018, at which time it was removed from trading on NYSE, and began trading on the OTC Pink under the symbol “PKDSQ”. Any over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not necessarily represent actual transactions.

Stockholders

As of March 6, 2019, there were 441 stockholders of record.

Dividends

Our credit agreements 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.

Item 6. Selected Financial Data

The following table presents selected historical consolidated financial data derived from the audited consolidated financial statements of Parker Drilling Company for each of the five years in the period ended December 31, 2018. 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,
Dollars in Thousands, Except Per Share Amounts	2018			2017			2016			2015			2014
Income Statement Data
Revenues	$	480,821		$	442,520		$	427,004		$	712,183		$	968,684
Total operating income (loss)	$	(113,404	)	$	(65,805	)	$	(111,257	)	$	(17,338	)	$	120,220
Net income (loss)	$	(165,697	)	$	(118,701	)	$	(230,814	)	$	(94,284	)	$	24,461
Net income (loss) attributable to controlling interest	$	(165,697	)	$	(118,701	)	$	(230,814	)	$	(95,073	)	$	23,451
Net income (loss) available to common stockholders	$	(168,416	)	$	(121,752	)	$	(230,814	)	$	(95,073	)	$	23,451
Basic earnings (loss) per common share: ⁽¹⁾
Net income (loss)	$	(17.79	)	$	(13.07	)	$	(27.89	)	$	(11.54	)	$	3.03
Net income (loss) attributable to controlling interest	$	(17.79	)	$	(13.07	)	$	(27.89	)	$	(11.64	)	$	2.90
Net income (loss) available to common stockholders	$	(18.09	)	$	(13.40	)	$	(27.89	)	$	(11.64	)	$	2.90
Diluted earnings (loss) per common share: ⁽¹⁾
Net income (loss)	$	(17.79	)	$	(13.07	)	$	(27.89	)	$	(11.54	)	$	2.98
Net income (loss) attributable to controlling interest	$	(17.79	)	$	(13.07	)	$	(27.89	)	$	(11.64	)	$	2.86
Net income (loss) available to common stockholders	$	(18.09	)	$	(13.40	)	$	(27.89	)	$	(11.64	)	$	2.86

	Year Ended December 31,
Dollars in Thousands	2018 ⁽³⁾			2017			2016			2015			2014
Balance Sheet Data
Total assets ⁽²⁾	$	828,414		$	990,279		$	1,103,551		$	1,366,702		$	1,509,000
Long-term debt including current portion of long-term debt	$	—		$	577,971		$	576,326		$	574,798		$	603,341
Liabilities subject to compromise — principal debt only	$	585,000		$	—		$	—		$	—		$	—
Total equity	$	126,916		$	296,121		$	339,135		$	568,512		$	666,214


(1)	See Note 12 - Stockholders' Equity in Item 8. Financial Statements and Supplementary Data for details regarding the 1-for-15 reverse stock split.

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(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.


(3)	See Note 2 - Chapter 11 Cases in Item 8. Financial Statements and Supplementary Data for details regarding the reclass of long-term debt to liabilities subject to compromise and write-off of the related unamortized debt issuance costs in 2018.

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

Management’s discussion and analysis 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:



	2018		% Change		2017		% Change		2016
Worldwide Rig Count ⁽¹⁾
U.S. (land and offshore)	1,032		18	%	875		72	%	510
International ⁽²⁾	988		4	%	948		(1	)%	955
Commodity Prices ⁽³⁾
Crude Oil (Brent) per bbl	$	71.69	31	%	$	54.74	21	%	$	45.13
Crude Oil (West Texas Intermediate) per bbl	$	64.90	28	%	$	50.85	17	%	$	43.47
Natural Gas (Henry Hub) per mcf	$	3.07	2	%	$	3.02	18	%	$	2.55

(1) Estimate of drilling activity as measured by the 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.

Recent Developments

Chapter 11 Cases

On December 13, 2018, the Bankruptcy Court entered an order approving joint administration of the Chapter 11 Cases under the caption In re Parker Drilling Company, et al.

Pursuant to the terms of the RSA and the Plan, the Consenting Stakeholders and other holders of claims against or interests in the Debtors receive treatment under the Plan summarized as follows:


•	holders of claims arising from non-funded debt general unsecured obligations receive payment in full in cash as set forth in the Plan;

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•


•	the Preferred Holders receive their pro rata share of: (a) 1.1 percent of the New Common Stock, subject to dilution; (b) the right to purchase approximately 14.7 percent of the New Common Stock to be issued pursuant to the terms of the Rights Offering; and (c) 40.0 percent of the warrants to acquire an aggregate of 13.5 percent of the New Common Stock (the “New Warrants”); and


•	the Common Holders receive their Pro Rata share of: (a) 1.65 percent of the New Common Stock, subject to dilution; (b) the right to purchase approximately 22.1 percent of the New Common Stock to be issued pursuant to the terms of the Rights Offering; and (c) 60.0 percent of the New Warrants.

On March 5, 2019, the Bankruptcy Court held a hearing to determine whether the Plan should be confirmed. On March 7, 2019, the Bankruptcy Court entered an order confirming the Plan. Although the Bankruptcy Court has confirmed the Plan, the Debtors have not yet consummated all of the transactions that are contemplated by the Plan. Rather, the Debtors intend to consummate these transactions in the near future, on or before the Plan’s effective date (the “Effective Date”). As set forth in the Plan, there are certain conditions precedent to the occurrence of the Effective Date, which must be satisfied or waived in accordance with the Plan in order for the Plan to become effective and the Debtors to emerge from the Chapter 11 Cases. The Debtors anticipate that each of these conditions will be either satisfied or waived by the end of March 2019, which is the target for the Debtors' emergence from the Chapter 11 Cases. On the Effective Date, the Debtors’ operations will, generally, no longer be governed by the Bankruptcy Court's oversight.

See Note 2 - Chapter 11 Cases in Item 8. Financial Statements and Supplementary Data and Item 1A. Risk Factors for additional information regarding our Chapter 11 proceedings.

Rights Plan

On July 12, 2018, the Board of Directors of the Company declared a dividend of one right (“Right”) for each outstanding share of common stock to common stockholders of record at the close of business on July 27, 2018, which was amended by the Board of Directors on August 23, 2018 (the “Rights Plan”). On August 23, 2018, our Board of Directors approved an amendment and restatement of the Rights Plan, dated as of July 12, 2018, between the Company and Equiniti Trust Company, as rights agent (as amended and restated, the “Section 382 Rights Plan”). The purpose of the Section 382 Rights Plan is to protect value by preserving the Company’s ability to use its net operating losses and foreign tax credits (“Tax Benefits”).

Each Right entitles the registered holder to purchase from the Company a unit consisting of one one-thousandth of a share (a “Fractional Share”) of Series A Junior Participating Preferred Stock, par value $1.00 per share, at a purchase price of $52.50 per Fractional Share, subject to adjustment. Initially, the Rights are attached to all outstanding shares of common stock. The Rights will separate from the common stock and a “Distribution Date” will occur, with certain exceptions, upon the earlier of (i) 10 days following a public announcement that a person or group of affiliated or associated persons (an “Acquiring Person”) has acquired, or obtained the right to acquire, beneficial ownership of 4.9 percent or more of the outstanding shares of common stock, or (ii) 10

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business days following the commencement of a tender offer or exchange offer that would result in a person’s becoming an Acquiring Person. Each person or group of affiliated or associated persons that was a beneficial owner of 4.9 percent or more of the outstanding shares of common stock at the time of the adoption of the Section 382 Rights Plan was grandfathered in at its then-current ownership level, but the Rights will become exercisable if at any time after the adoption of the Section 382 Rights Plan, such person or group increases its ownership of common stock by one share or more. Any person or group of affiliated or associated persons who proposes to acquire 4.9 percent or more of the outstanding shares of common stock may apply to our Board of Directors in advance for an exemption. The Rights are not exercisable until the Distribution Date and will expire at the earliest of (i) the close of business on August 23, 2021, (ii) the redemption or exchange of the Rights by the Company, (iii) the date on which our Board of Directors determines that the Rights Plan is no longer necessary for the preservation of a material Tax Benefit, (iv) the beginning of a taxable year of the Company for which our Board of Directors determines that no Tax Benefits may be carried forward, (v) July 12, 2019, if the affirmative vote of the majority of the Company’s stockholders has not been obtained with respect to ratification of the Rights Plan, and (vi) the occurrence of a “qualifying offer” (as described in the Section 382 Rights Plan). If the rights become exercisable, each holder other than the Acquiring Person (and certain related parties) will be entitled to acquire shares of common stock at a 50.0 percent discount or the Company may exchange each right held by such holders for two shares of common stock.

Financial Results

Revenues increased $38.3 million, or 8.7 percent, to $480.8 million for the year ended December 31, 2018 as compared with revenues of $442.5 million for the year ended December 31, 2017. Operating gross margin increased $30.5 million to a loss of $4.8 million for the year ended December 31, 2018 as compared with a loss of $35.3 million for the year ended December 31, 2017.

Outlook

2018 was a year of constrained improvement, as the oil and gas markets wrestled with global supply and demand balance while maintaining strict capital spend discipline. After years of underinvestment and tepid activity in international markets, it appears that many countries are sanctioning new projects, though at a very gradual pace. U.S. markets grew throughout much of the first three quarters, driven mostly by unconventional wells and oil exports. Despite a sharp pullback in commodity prices in the fourth quarter, we continue to believe global market conditions are poised to improve over the medium and long term.

In our U.S. (Lower 48) Drilling segment, we anticipate utilization for our barge drilling rigs to improve slightly year-on-year, while O&M activity in this segment is set to increase as we move into the second quarter of 2019. For our International & Alaska Drilling segment, we anticipate higher activity in markets such as Alaska, Kazakhstan, and Russia will provide gradual segment improvement compared to that in 2018. The segment will likely have higher gross margin compared to 2018 as a result of activity improvement.

In our U.S. Rental Tools segment, we anticipate strong utilization of our rental equipment as demand for premium drill pipe continues, with operators seeking to capitalize on technology and improve drilling efficiencies. 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 16 - 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, 2018 Compared with Year Ended December 31, 2017

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



	Year Ended December 31,
Dollars in Thousands	2018					2017
Revenues:
U.S. (Lower 48) Drilling	$	11,729		2	%	$	12,389		3	%
International & Alaska Drilling	213,411			45	%	247,254			56	%
Total Drilling Services	225,140			47	%	259,643			59	%
U.S. Rental Tools	176,531			37	%	121,937			27	%
International Rental Tools	79,150			16	%	60,940			14	%
Total Rental Tools Services	255,681			53	%	182,877			41	%
Total revenues	$	480,821		100	%	$	442,520		100	%
Operating gross margin (loss) excluding depreciation and amortization: ⁽¹⁾
U.S. (Lower 48) Drilling	$	(7,962	)	(68	)%	$	(7,135	)	(58	)%
International & Alaska Drilling	14,136			7	%	40,702			16	%
Total Drilling Services	6,174			3	%	33,567			13	%
U.S. Rental Tools	92,679			53	%	59,140			49	%
International Rental Tools	3,864			5	%	(5,674		)	(9	)%
Total Rental Tools Services	96,543			38	%	53,466			29	%
Total operating gross margin (loss) excluding depreciation and amortization	102,717			21	%	87,033			20	%
Depreciation and amortization	(107,545		)			(122,373		)
Total operating gross margin (loss)	(4,828		)			(35,340		)
General and administrative expense	(24,545		)			(25,676		)
Loss on impairment	(50,698		)			—
Provision for reduction in carrying value of certain assets	—					(1,938		)
Gain (loss) on disposition of assets, net	(1,724		)			(2,851		)
Pre-petition restructuring charges	(21,820		)			—
Reorganization items	(9,789		)			—
Total operating income (loss)	$	(113,404	)			$	(65,805	)


(1)	Percentage amounts are calculated by dividing the operating gross margin (loss) excluding depreciation and amortization with revenue for the respective segment and business lines.

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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, 2018
Operating gross margin (loss) ⁽¹⁾	$	(15,720	)	$	(21,936	)	$	44,512	$	(11,684	)	$	(4,828	)
Depreciation and amortization	7,758			36,072			48,167		15,548			107,545
Operating gross margin (loss) excluding depreciation and amortization	$	(7,962	)	$	14,136		$	92,679	$	3,864		$	102,717
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


(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, 2018 and 2017, respectively:



	December 31,
	2018		2017
U.S. (Lower 48) Drilling
Rigs available for service ⁽¹⁾	13		13
Utilization rate of rigs available for service ⁽²⁾	10	%	11	%
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service ^{(1) (3)}	10		13
Utilization rate of rigs available for service ⁽²⁾	46	%	38	%
Latin America Region
Rigs available for service ⁽¹⁾	7		7
Utilization rate of rigs available for service ⁽²⁾	21	%	14	%
Alaska
Rigs available for service ⁽¹⁾	2		2
Utilization rate of rigs available for service ⁽²⁾	50	%	97	%
Total International & Alaska Drilling
Rigs available for service ⁽¹⁾	19		22
Utilization rate of rigs available for service ⁽²⁾	37	%	36	%

(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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(3)	The Eastern Hemisphere rigs available for service decreased due to the sale of two Indonesia rigs in the first quarter 2018 and one Papua New Guinea rig in the fourth quarter of 2017.

Drilling Services Business

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues decreased $0.7 million, or 5.3 percent, to $11.7 million for the year ended December 31, 2018, as compared with revenues of $12.4 million for the year ended December 31, 2017. The decrease was primarily due to a decrease in utilization to 10.0 percent for the year ended December 31, 2018 from 11.0 percent for the year ended December 31, 2017.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $0.8 million, or 11.6 percent, to a loss of $8.0 million for the year ended December 31, 2018, compared with a loss of $7.1 million for the year ended December 31, 2017. This decrease was primarily due to the decrease in revenues discussed above.

International & Alaska Drilling

International & Alaska Drilling segment revenues decreased $33.8 million, or 13.7 percent, to $213.4 million for the year ended December 31, 2018, compared with $247.3 million for the year ended December 31, 2017.

The change in revenues was primarily due to the following:


•	a decrease of $23.6 million driven by a decline in average revenue per day primarily resulting from certain Company-owned rigs being in standby mode during 2018 compared with operating mode during 2017;


•	a decrease of $10.9 million, excluding revenue from reimbursable costs (“reimbursable revenues”), resulting from decreased utilization for certain Company-owned rigs in Alaska and Kazakhstan, partially offset by increased utilization in the Kurdistan region of Iraq;


•	a decrease of $3.3 million in reimbursable revenues, which decreased revenues but had a minimal impact on operating margins; and


•	an increase of $2.9 million of O&M activities, excluding reimbursable revenues.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $26.6 million, or 65.3 percent, to $14.1 million for the year ended December 31, 2018, compared with $40.7 million for the year ended December 31, 2017. The decrease in operating gross margin excluding depreciation and amortization was primarily due to decrease in revenues discussed above.

Rental Tools Services Business

U.S. Rental Tools

U.S. Rental Tools segment revenues increased $54.6 million, or 44.8 percent, to $176.5 million for the year ended December 31, 2018 compared with $121.9 million for the year ended December 31, 2017. The increase was primarily driven by an increase in U.S. land rentals due to higher levels of customer activity.

U.S. Rental Tools segment operating gross margin excluding depreciation and amortization increased $33.5 million, or 56.7 percent, to $92.7 million for the year ended December 31, 2018 compared with $59.1 million for the year ended December 31, 2017. The increase was primarily due to the increase in revenues discussed above.

International Rental Tools

International Rental Tools segment revenues increased $18.2 million, or 29.9 percent, to $79.2 million for the year ended December 31, 2018 compared with $60.9 million for the year ended December 31, 2017. The increase primarily attributable to increased onshore rental activity in the Middle East.

International Rental Tools segment operating gross margin excluding depreciation and amortization increased $9.5 million, or 168.1 percent, to a gain of $3.9 million for the year ended December 31, 2018 compared with loss of $5.7 million for the year ended December 31, 2017. The increase was primarily due to the increase in revenues discussed above.

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Other Financial Data

General and administrative expense

General and administrative expense decreased $1.1 million to $24.5 million for the year ended December 31, 2018, compared with $25.7 million for the year ended December 31, 2017 primarily due to reductions in professional fees.

Loss on impairment

Loss on impairment was $50.7 million for the year ended December 31, 2018. During third quarter 2018 we had a loss on impairment of $44.0 million which consisted of $34.2 million for Gulf of Mexico inland barge asset group and $9.8 million for International barge asset group. We performed our 2018 annual goodwill impairment review during the fourth quarter, as of October 1, and determined that the carrying value of the reporting unit exceeded its fair value and, therefore, the entire goodwill balance of $6.7 million for U.S. Rental Tools segment was impaired and written off. There was no loss on impairment for the year ended December 31, 2017.

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, 2018. During the year ended December 31, 2017, we recorded $1.9 million of provision 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 functionally obsolete.

Gain (loss) on disposition of assets, net

Net losses recorded on asset dispositions were $1.7 million and $2.9 million for the years ended December 31, 2018 and December 31, 2017, respectively. The net loss for 2018 was primarily related to equipment that was deemed obsolete in the International & Alaska Drilling segment and U.S. Rental Tools segment. The net loss for 2017 was primarily related to the sale of one rig located in Papua New Guinea. We periodically sell equipment deemed excess, obsolete, or not currently required for operations.

Pre-petition restructuring charges

Pre-petition charges were $21.8 million for the year ended December 31, 2018. The pre-petition restructuring charges primarily consisted of professional fees related to the Chapter 11 Cases. There were no pre-petition charges for the year ended December 31, 2017.

Reorganization items

Reorganization items were $9.8 million for the year ended December 31, 2018. The reorganization items primarily consisted of debt finance costs related to Senior Notes, professional fees, debt finance costs related to the 2015 Secured Credit Agreement and debtor-in-possession financing costs in the amount of $5.4 million, $2.3 million, $1.2 million and $1.0 million respectively, related to the Chapter 11 Cases. There were no reorganization items for the year ended December 31, 2017.

Interest expense and income

Interest expense decreased $1.7 million to $42.6 million for the year ended December 31, 2018 compared with $44.2 million for the year ended December 31, 2017. The decrease in interest expense is because the Company discontinued accruing interest upon the commencement of the Chapter 11 Cases.

Other

Other income and expense was $2.0 million of expense and $0.1 million of income for the years ended December 31, 2018 and December 31, 2017, respectively. Other income for both periods included the impact of foreign currency fluctuations.

Income tax expense (benefit)

Income tax expense was $7.8 million on a pre-tax loss of $157.9 million for the year ended December 31, 2018, compared with $9.0 million on pre-tax loss of $109.7 million for the year ended December 31, 2017. Our effective tax rate was negative 4.9 percent for the year ended December 31, 2018, compared with negative 8.2 percent for the year ended December 31, 2017. 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.

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Income tax expense for the year ended December 31, 2018 includes a net tax expense related to the change in valuation allowance of $28.4 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 from our U.S. statutory rate of $0.1 million and $2.0 million and tax expense of $7.3 million and $13.1 million for the impact of foreign tax laws in effect for the years ended December 31, 2018 and December 31, 2017, respectively. Differences between the U.S. and foreign tax rates and laws have a significant impact in Canada, Iraq, Kazakhstan, Mexico, Russia, United Arab Emirates and the United Kingdom.

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act included significant changes to U.S. corporate income tax laws, the most notable of which was a reduction in the U.S. corporate income tax rate from 35.0 percent to 21.0 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. As a result of the Company’s net deferred tax position, inclusive of valuation allowances, the provisions of the Tax Act did not materially impact the Company’s cash tax position or effective tax rate in 2018.

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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,
Dollars in Thousands	2017					2016
Revenues:
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	%
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: ⁽¹⁾
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	%
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	)


(1)	Percentage amounts are calculated by dividing the operating gross margin (loss) excluding depreciation and amortization with revenue for the respective segment and business lines.

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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		13
Utilization rate of rigs available for service ⁽²⁾	11	%	5	%
International & Alaska Drilling
Eastern Hemisphere