UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
FORM 10-K
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
Or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT of 1934
For the transition period from to
Commission File Number 1-7573
PARKER DRILLING COMPANY
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
73-0618660
(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):
Large accelerated filer ¨
Accelerated filer þ
Non-accelerated filer ¨
Smaller reporting company þ
Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ
The aggregate market value of our common stock held by non-affiliates on June 30, 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.
Table of contents
TABLE OF CONTENTS
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
PART I
PART II
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits and Financial Statement Schedules
Form 10-K Summary
Signatures
PART IV
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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
Substantially all of our operations are subject to hazards that are customary for oil and natural gas drilling operations, including
blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, cratering, oil and natural
gas well fires and explosions, natural disasters, pollution, mechanical failure, and damage or loss during transportation. Some of our fleet is
also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding,
collision, damage from severe weather, and marine life infestations. These hazards could result in damage to or destruction of drilling
equipment, personal injury and property damage, suspension of operations, or environmental damage, which could lead to claims by third
parties or customers, suspension of operations, and contract terminations. We have had accidents in the past due to some of these hazards.
Our contracts provide for varying levels of indemnification between ourselves and our customers. 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:
U.S. (Lower 48) Drilling
International & Alaska Drilling
U.S. Rental Tools
International Rental Tools
Corporate
Total employees
Environmental Considerations
December 31,
2018
2017
89
1,208
232
717
179
2,425
111
1,122
214
648
171
2,266
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
Plan;
to consummate
the
the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents, including our
stockholders;
increased
reorganization;
advisory
costs
to
execute
our
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.
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•
•
•
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•
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
commitments; and
of
operating
lease
$10.0 million borrowed under
Facility.
the DIP
•
•
•
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
business;
the ordinary course of
consolidating, merging, amalgamating, liquidating, dividing, winding up, dissolving or otherwise disposing of all or substantially
all of its assets;
granting
and
liens;
financing
investments.
its
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
disturbances;
instability, war,
terrorism, and civil
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
royalties;
in
governmental
import-export
barriers;
quotas
or
trade
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
equipment;
unfavorable changes
policies;
transporting our people or
in foreign monetary and
tax
solicitation by government officials for improper payments or other forms of
corruption;
foreign currency
repatriation;
fluctuations and
restrictions on currency
repudiation,
contracts; and
nullification, modification,
or
renegotiation
of
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.
Hydraulic fracturing is a process sometimes used in the completion of oil and natural gas wells whereby water, other liquids, sand,
and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, oil production. Various governmental
entities (within and outside the United States) are in the process of studying, restricting, regulating, or preparing to regulate hydraulic
fracturing, directly and indirectly. Many state governments require the disclosure of chemicals used in the fracturing process and, due to
concerns raised relating to potential impacts of hydraulic fracturing, including on groundwater quality and seismic activity, legislative and
regulatory efforts at the federal level and in some state and local jurisdictions have been initiated to render permitting and compliance
requirements more stringent for hydraulic fracturing or prohibit the activity altogether. We do not directly engage in hydraulic fracturing
activities. However, these and other developments could cause operational delays or increased costs in exploration and production, which
could adversely affect the demand for our rental tools.
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
industries;
in
the economy and
in energy-related
general conditions
markets;
in
the
securities
political
war; and
instability,
terrorism,
or
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
Plan;
to consummate
the
the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents, including our
stockholders;
increased
reorganization;
advisory
costs
to
execute
our
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
conditions;
in worldwide
economic
and business
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;
risk
the
overruns;
of
cost
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
International & Alaska Drilling
Eastern Hemisphere
Rig 107
Rig 216
Rig 249
Rig 257
Rig 258
Rig 247
Rig 269
Rig 265
Rig 264
Rig 270
Latin America
Rig 271
Rig 266
Rig 122
Rig 165
Rig 221
Rig 256
Rig 267
Alaska
Rig 272
Rig 273
U.S. (Lower 48) Drilling
Rig 8
Rig 12
Rig 15
Rig 20
Rig 21
Rig 30
Rig 50
Rig 51
Rig 54
Rig 55
Rig 72
Rig 76
Rig 77
Type (1)
Year entered
into service/
upgraded
Drilling
depth rating
(in feet)
Location
L
L
L
B
L
L
L
L
L
L
L
L
L
L
L
L
L
L
L
B
B
B
B
B
B
B
B
B
B
B
B
B
1983/2009
2001/2009
2000/2009
1999/2010
2001/2009
1981/2008
2008
2007
2007
2011
1982/2009
2008
1980/2008
1978/2007
1982/2007
1978/2007
2008
2013
2012
1978/2007
1979/2006
1978/2007
1981/2007
1979/2012
2014
1981/2006
1981/2008
1980/2006
1981/2014
1982/2005
1977/2009
2006/2006
15,000
25,000
25,000
30,000
25,000
20,000
21,000
20,000
20,000
21,000
30,000
20,000
18,000
30,000
30,000
25,000
20,000
18,000
18,000
14,000
18,000
15,000
13,000
14,000
18,000
20,000
20,000
25,000
25,000
25,000
30,000
30,000
Kazakhstan
Kazakhstan
Kazakhstan
Kazakhstan
Kazakhstan
Iraq, Kurdistan Region
Iraq, Kurdistan Region
Iraq, Kurdistan Region
Tunisia
Russia
Colombia
Guatemala
Mexico
Mexico
Mexico
Mexico
Mexico
Alaska
Alaska
GOM
GOM
GOM
GOM
GOM
GOM
GOM
GOM
GOM
GOM
GOM
GOM
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.
Dollars in Thousands, Except Per Share Amounts
Income Statement Data
Revenues
Total operating income (loss)
Net income (loss)
Net income (loss) attributable to controlling interest
Net income (loss) available to common stockholders
Basic earnings (loss) per common share: (1)
Net income (loss)
Net income (loss) attributable to controlling interest
Net income (loss) available to common stockholders
Diluted earnings (loss) per common share: (1)
Net income (loss)
Net income (loss) attributable to controlling interest
Net income (loss) available to common stockholders
Dollars in Thousands
Balance Sheet Data
Total assets (2)
Long-term debt including current portion of long-term debt
Liabilities subject to compromise — principal debt only
Total equity
Year Ended December 31,
2018
2017
2016
2015
2014
$
480,821 $
442,520 $
427,004 $
(65,805) $ (111,257) $
$ (113,404) $
$ (165,697) $ (118,701) $ (230,814) $
$ (165,697) $ (118,701) $ (230,814) $
$ (168,416) $ (121,752) $ (230,814) $
712,183 $
(17,338) $
(94,284) $
(95,073) $
(95,073) $
968,684
120,220
24,461
23,451
23,451
$
$
$
$
$
$
$
$
$
$
(17.79) $
(17.79) $
(18.09) $
(13.07) $
(13.07) $
(13.40) $
(27.89) $
(27.89) $
(27.89) $
(11.54) $
(11.64) $
(11.64) $
(17.79) $
(17.79) $
(18.09) $
(13.07) $
(13.07) $
(13.40) $
(27.89) $
(27.89) $
(27.89) $
(11.54) $
(11.64) $
(11.64) $
3.03
2.90
2.90
2.98
2.86
2.86
2018 (3)
2017
2016
2015
2014
Year Ended December 31,
828,414 $
— $
585,000 $
126,916 $
990,279 $ 1,103,551 $ 1,366,702 $ 1,509,000
603,341
577,971 $
—
— $
666,214
296,121 $
574,798 $
— $
568,512 $
576,326 $
— $
339,135 $
(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)
International (2)
Commodity Prices (3)
Crude Oil (Brent) per bbl
$
Crude Oil (West Texas Intermediate) per bbl $
$
Natural Gas (Henry Hub) per mcf
1,032
988
71.69
64.90
3.07
18%
4%
31% $
28% $
2% $
875
948
54.74
50.85
3.02
72 %
(1)%
21 % $
17 % $
18 % $
510
955
45.13
43.47
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 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;
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•
•
•
•
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;
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.
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
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. We eliminate inter-segment
revenues and expenses.
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
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.
The following is an analysis of our operating results for the comparable periods by reportable segment:
Dollars in Thousands
Revenues:
U.S. (Lower 48) Drilling
International & Alaska Drilling
Total Drilling Services
U.S. Rental Tools
International Rental Tools
Total Rental Tools Services
Total revenues
Operating gross margin (loss) excluding depreciation and amortization: (1)
U.S. (Lower 48) Drilling
International & Alaska Drilling
Total Drilling Services
U.S. Rental Tools
International Rental Tools
Total Rental Tools Services
Total operating gross margin (loss) excluding depreciation and amortization
Depreciation and amortization
Total operating gross margin (loss)
General and administrative expense
Loss on impairment
Provision for reduction in carrying value of certain assets
Gain (loss) on disposition of assets, net
Pre-petition restructuring charges
Reorganization items
Total operating income (loss)
3 %
56 %
59 %
27 %
14 %
41 %
100 %
(58)%
16 %
13 %
49 %
(9)%
29 %
20 %
Year Ended December 31,
2018
2017
11,729
213,411
225,140
176,531
79,150
255,681
480,821
(7,962)
14,136
6,174
92,679
3,864
96,543
102,717
(107,545)
(4,828)
(24,545)
(50,698)
—
(1,724)
(21,820)
(9,789)
(113,404)
2 % $
45 %
47 %
37 %
16 %
53 %
100 % $
(68)% $
7 %
3 %
53 %
5 %
38 %
21 %
$
12,389
247,254
259,643
121,937
60,940
182,877
442,520
(7,135)
40,702
33,567
59,140
(5,674)
53,466
87,033
(122,373)
(35,340)
(25,676)
—
(1,938)
(2,851)
—
—
(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
Year Ended December 31, 2018
Operating gross margin (loss) (1)
Depreciation and amortization
Operating gross margin (loss) excluding
depreciation and amortization
Year Ended December 31, 2017
Operating gross margin (loss) (1)
Depreciation and amortization
Operating gross margin (loss) excluding
depreciation and amortization
U.S. (Lower 48)
Drilling
International &
Alaska Drilling U.S. Rental Tools
International
Rental Tools
Total
$
$
$
$
(15,720) $
7,758
(21,936) $
36,072
44,512 $
48,167
(11,684) $
15,548
(4,828)
107,545
(7,962) $
14,136 $
92,679 $
3,864 $
102,717
(20,656) $
13,521
(6,248) $
46,950
15,651 $
43,489
(24,087) $
18,413
(35,340)
122,373
(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:
U.S. (Lower 48) Drilling
Rigs available for service (1)
Utilization rate of rigs available for service (2)
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1) (3)
Utilization rate of rigs available for service (2)
Latin America Region
Rigs available for service (1)
Utilization rate of rigs available for service (2)
Alaska
Rigs available for service (1)
Utilization rate of rigs available for service (2)
Total International & Alaska Drilling
Rigs available for service (1)
Utilization rate of rigs available for service (2)
December 31,
2018
2017
13
10%
10
46%
7
21%
2
50%
19
37%
13
11%
13
38%
7
14%
2
97%
22
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
increase of $2.9 million of O&M activities, excluding reimbursable
an
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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Table of contents
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:
Dollars in Thousands
Revenues:
U.S. (Lower 48) Drilling
International & Alaska Drilling
Total Drilling Services
U.S. Rental Tools
International Rental Tools
Total Rental Tools Services
Total revenues
Operating gross margin (loss) excluding depreciation and amortization: (1)
U.S. (Lower 48) Drilling
International & Alaska Drilling
Total Drilling Services
U.S. Rental Tools
International Rental Tools
Total Rental Tools Services
Total operating gross margin (loss) excluding depreciation and amortization
Depreciation and amortization
Total operating gross margin (loss)
General and administrative expense
Provision for reduction in carrying value of certain assets
Gain (loss) on disposition of assets, net
Total operating income (loss)
Year Ended December 31,
2017
2016
3 % $
56 %
59 %
27 %
14 %
41 %
100 % $
(58)% $
16 %
13 %
49 %
(9)%
29 %
20 %
$
$
$
12,389
247,254
259,643
121,937
60,940
182,877
442,520
(7,135)
40,702
33,567
59,140
(5,674)
53,466
87,033
(122,373)
(35,340)
(25,676)
(1,938)
(2,851)
1 %
67 %
68 %
17 %
15 %
32 %
100 %
(263)%
22 %
17 %
30 %
(11)%
11 %
15 %
5,429
287,332
292,761
71,613
62,630
134,243
427,004
(14,304)
64,508
50,204
21,397
(7,118)
14,279
64,483
(139,795)
(75,312)
(34,332)
—
(1,613)
$
(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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Table of contents
Operating gross margin (loss) amounts are reconciled to our most comparable U.S. GAAP measure as follows:
Dollars in Thousands
Year Ended December 31, 2017
Operating gross margin (loss) (1)
Depreciation and amortization
Operating gross margin (loss) excluding
depreciation and amortization
Year Ended December 31, 2016
Operating gross margin (loss) (1)
Depreciation and amortization
Operating gross margin (loss) excluding
depreciation and amortization
U.S. (Lower 48)
Drilling
International &
Alaska Drilling U.S. Rental Tools
International
Rental Tools
Total
$
$
$
(20,656) $
13,521
(6,248) $
46,950
15,651 $
43,489
(24,087) $
18,413
(35,340)
122,373
(7,135) $
40,702 $
59,140 $
(5,674) $
87,033
(34,353) $
20,049
9,272 $
55,236
(22,372) $
43,769
(27,859) $
20,741
(75,312)
139,795
$
(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:
U.S. (Lower 48) Drilling
Rigs available for service (1)
Utilization rate of rigs available for service (2)
International & Alaska Drilling
Eastern Hemisphere
Rigs available for service (1)
Utilization rate of rigs available for service (2)
Latin America Region
Rigs available for service (1)
Utilization rate of rigs available for service (2)
Alaska
Rigs available for service (1)
Utilization rate of rigs available for service (2)
Total International & Alaska Drilling
Rigs available for service (1)
Utilization rate of rigs available for service (2)
December 31,
2017
2016
13
11%
13
38%
7
14%
2
97%
22
36%
13
5%
13
40%
7
23%
2
100%
22
40%
(1) The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was
under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is
0.5 rigs available for service during such year. Our method of computation of rigs available for service may not be comparable
to other similarly titled measures of other companies.
(2) Rig utilization rates are based on a weighted average basis assuming total days availability for all rigs available for service.
Rigs acquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs
that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs
under contract that generate revenues during moves between locations or during mobilization or demobilization are also
considered to be utilized. Our method of computation of rig utilization may not be comparable to other similarly titled
measures of other companies.
40
Table of contents
Drilling Services Business
U.S. (Lower 48) Drilling
U.S. (Lower 48) Drilling segment revenues increased $7.0 million, or 128.2 percent, to $12.4 million for the year ended
December 31, 2017, as compared with revenues of $5.4 million for the year ended December 31, 2016. The increase was primarily due to
an increase in utilization to 11.0 percent for the year ended December 31, 2017 from 5.0 percent for the year ended December 31, 2016 as
well as a moderate increase in revenues per day for certain barge rigs.
U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization increased $7.2 million, or 50.1
percent, to a loss of $7.1 million for the year ended December 31, 2017, compared with a loss of $14.3 million for the year ended
December 31, 2016. This increase was primarily due to the increase in utilization discussed above and reduced costs resulting from
organizational efficiency initiatives.
International & Alaska Drilling
International & Alaska Drilling segment revenues decreased $40.0 million, or 13.9 percent, to $247.3 million for the year ended
December 31, 2017, compared with $287.3 million for the year ended December 31, 2016.
The decrease in revenues was primarily due to the following:
•
•
•
•
a decrease of $21.9 million related to our project services
activities;
a decrease in reimbursable revenues of $11.7 million, which decreased revenues but had a minimal impact on operating
margins;
a decrease of $10.5 million resulting from a combined decrease in utilization and revenues per day for certain Company-
owned rigs. The decline in revenues per day is a direct result of certain Company-owned rigs shifting to standby mode
during 2017 compared with operating mode during 2016; and
a decrease of $5.4 million from mobilization and demobilization
activities.
The decrease in revenues was partially offset by an increase of $11.3 million primarily driven by O&M activities associated with
the Hibernia platform located off the Atlantic Coast of Canada.
International & Alaska Drilling segment operating gross margin excluding depreciation and amortization decreased $23.8 million,
or 36.9 percent, to $40.7 million for the year ended December 31, 2017, compared with $64.5 million for the year ended December 31,
2016. The decrease in operating gross margin excluding depreciation and amortization was primarily due to a decrease in project services
activities and the impact of reduced utilization discussed above.
Rental Tools Services Business
U.S. Rental Tools
U.S. Rental Tools segment revenues increased $50.3 million, or 70.3 percent, to $121.9 million for the year ended December 31,
2017 compared with $71.6 million for the year ended December 31, 2016. The increase was primarily driven by an increase in U.S. land
rentals due to improved customer activity, partially offset by a decline in offshore GOM rental revenues.
U.S. Rental Tools segment operating gross margin excluding depreciation and amortization increased $37.7 million, or 176.4
percent, to $59.1 million for the year ended December 31, 2017 compared with $21.4 million for the year ended December 31, 2016. The
increase was primarily due to the increase in revenues discussed above.
International Rental Tools
International Rental Tools segment revenues decreased $1.7 million, or 2.7 percent, to $60.9 million for the year ended
December 31, 2017 compared with $62.6 million for the year ended December 31, 2016. The decrease was primarily attributable to a
decline in offshore rental revenues somewhat offset by international land rental revenues.
International Rental Tools segment operating gross margin excluding depreciation and amortization increased $1.4 million, or 20.3
percent, to a loss of $5.7 million for the year ended December 31, 2017 compared with loss of $7.1 million for the year ended
December 31, 2016. The increase was due to lower operating costs resulting from organizational efficiency initiatives.
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Table of contents
Other Financial Data
General and administrative expense
General and administrative expense decreased $8.6 million to $25.7 million for the year ended December 31, 2017, compared with
$34.3 million for the year ended December 31, 2016 primarily due to reductions in incentive compensation and professional fees.
Provision for reduction in carrying value of certain assets
During the year ended December 31, 2017, we recorded $1.9 million of provisions for reduction in carrying value of assets, all of
which was recorded in the fourth quarter of 2017. This provision was related to certain assets in the International & Alaska Drilling
segment that were deemed to be functionally obsolete. There was no provision for reduction in carrying value of certain assets recorded
during the year ended December 31, 2016.
Gain (loss) on disposition of assets, net
Net losses recorded on asset dispositions were $2.9 million and $1.6 million for the years ended December 31, 2017 and
December 31, 2016, respectively. The net loss for 2017 was primarily related to the sale of one rig located in Papua New Guinea. Activity
in both periods included equipment retirements. We periodically sell equipment deemed excess, obsolete, or not currently required for
operations.
Interest expense and income
Interest expense decreased $1.6 million to $44.2 million for the year ended December 31, 2017 compared with $45.8 million for
the year ended December 31, 2016. The decrease in interest expense was primarily related to a write off of $1.1 million of debt issuance
costs during the second quarter of 2016 in conjunction with the execution of an amendment to the revolving credit facility. Interest income
during each of the years ended December 31, 2017 and 2016 was nominal.
Other
Other income and expense was $0.1 million of income and $0.4 million of income for the years ended December 31, 2017 and
December 31, 2016, respectively. Other income for both periods included the impact of foreign currency fluctuations.
Income tax expense (benefit)
On December 22, 2017, the United States enacted the Tax Act. The Tax Act includes significant changes to U.S. corporate income
tax laws, the most notable of which is a reduction in the U.S. corporate income tax rate from 35.0 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. The impact of the Tax Act for the year ended December 31, 2017
is discussed in more detail in Note 8 - Income Taxes of the consolidated financial statements. As a result of the Company’s net deferred tax
position, inclusive of valuation allowances, the provisions of the Tax Act are not expected to materially impact the Company’s cash tax
position or effective tax rate in 2018. We are continuing our analysis of the effects the Tax Act will have on the Company in future
periods.
Income tax expense was $9.0 million on a pre-tax loss of $109.7 million for the year ended December 31, 2017, compared with
$74.2 million on pre-tax loss of $156.6 million for the year ended December 31, 2016. Our effective tax rate was negative 8.2 percent for
the year ended December 31, 2017, compared with negative 47.3 percent for the year ended December 31, 2016. Income tax expense and
our annual effective tax rate are primarily affected by the statutory tax rates applied in the jurisdictions where the income or losses are
earned, and our ability to receive tax benefits for losses incurred. It is also affected by discrete items, such as return-to-accrual adjustments
and changes in valuation allowances, and changes in reserves for uncertain tax positions, which may occur in any given year but are not
consistent from year to year.
Income tax expense for the year ended December 31, 2017 includes a net tax benefit related to the change in valuation allowance
of $14.6 million. The change in valuation allowance includes a benefit of $45.3 million related to the reduction in the corporate income tax
rate under the Tax Act. This benefit was reduced by the change related to current net operating losses and other deferred taxes of $30.7
million. We established the valuation allowance based on the weight of available evidence, both positive and negative, including results of
recent and current operations and our estimates of future taxable income or loss by jurisdiction in which we operate. In order to determine
the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding
future taxable income, where rigs will be deployed and other business considerations. Changes in these estimates and assumptions,
including changes in tax laws and other changes impacting our ability to recognize the underlying deferred tax assets, could require us to
adjust the valuation allowances.
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Table of contents
We are a U.S. based company that operates internationally through various branches and subsidiaries. Accordingly, our worldwide
income tax provision includes the impact of income tax rates and foreign tax laws in the jurisdictions in which our operations are conducted
and income is earned. We reported tax benefits for foreign statutory rates different from our U.S. statutory rate of $2.0 million and $3.6
million and tax expense of $13.1 million and $12.7 million for the impact of foreign tax laws in effect for the years ended December 31,
2017 and December 31, 2016, respectively. Differences between the U.S. and foreign tax rates and laws have a significant impact in Iraq,
Kazakhstan, Mexico, Russia, United Arab Emirates and the United Kingdom.
Certain tax payments to foreign jurisdictions are available as credits to reduce tax expense in the U.S. and other foreign
jurisdictions. We reported no tax benefits for foreign tax credits for the year ended December 31, 2017 and December 31, 2016. See Note 8
- Income Taxes in Item 8. Financial Statements and Supplementary Data for further discussion.
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Liquidity and Capital Resources
The Company’s commencement of the Chapter 11 Cases constituted a default under certain of its debt instruments that 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. However, 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 the filing.
The Chapter 11 Cases and weak industry conditions have deteriorated our operational results 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 accounting principles accepted in the United States of America which
contemplate the continuation of the Company as a going concern.
In order to decrease the Company’s level of indebtedness and maintain the Company’s liquidity at levels sufficient to meet its
commitments, the Company has undertaken a number of actions, including minimizing capital expenditures and further reducing its
recurring operating expenses. The Company believes that even after taking these actions, it did not have sufficient liquidity to satisfy its
debt service obligations, meet other financial obligations, comply with its debt covenants, and execute its business plan. As a result, the
Debtors filed petitions for reorganization under Chapter 11 of the Bankruptcy Code.
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.
Liquidity
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 (the “DIP 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 DIP Facility is
available for the issuance of standby letters of credit. The borrowing base is equal to:
(1) 85.0 percent of the aggregate net amount of eligible domestic accounts receivable,
plus
(2) the
of:
lowest
(a) 90.0 percent of net book value of eligible rental
equipment
(b) 60.0 percent of net equipment orderly liquidation value of eligible rental equipment;
or
(c) $37.5 million minus certain reserves, calculated as set forth in the DIP Credit
Agreement.
The borrowing base under the DIP Facility was calculated to be $50.0 million at the time of effectiveness of the DIP Facility,
which was reduced by $10.0 million of outstanding loans under the DIP Facility as of December 31, 2018 and accrued interest on the
debtor-in-possession financing, resulting in availability under the DIP Facility of $40.0 million.
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 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. Letters of credit outstanding under the DIP Facility may be rolled over and deemed
outstanding under the L/C Facility. 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”).
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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.
The following table provides a summary of our total liquidity:
Dollars in thousands
Cash and cash equivalents (1)
Restricted cash
Availability under debtor-in-possession financing
Total liquidity
December 31,
2018
$
$
48,602
10,389
39,968
98,959
(1) As of December 31, 2018, approximately $32.9 million of the $48.6 million of cash and equivalents was held by our foreign
subsidiaries.
The earnings of foreign subsidiaries as of December 31, 2018 were reinvested to fund our international operations. If in the future
we decide to repatriate earnings, the Company may be required to pay taxes on those amounts, which could reduce the liquidity of the
Company at that time.
We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party
financial obligations. As of December 31, 2018, we have no energy, commodity, or foreign currency derivative contracts.
Cash Flow Activity
As of December 31, 2018, we had cash, cash equivalents and restricted cash of $59.0 million, a decrease of $82.6 million from
cash, cash equivalents and restricted cash equivalents of $141.5 million as of December 31, 2017. The following table provides a summary
of our cash flow activity for the last three years:
Dollars in thousands
Operating Activities
Investing Activities
Financing Activities
Net change in cash, cash equivalents and restricted cash
Operating Activities
2018
2017
2016
$
$
(17,050) $
(69,214)
3,706
(82,558) $
6,733 $
(54,130)
69,255
21,858 $
22,441
(26,513)
(10,531)
(14,603)
Cash flows used in operating activities were $17.1 million for the year ended December 31, 2018 while cash flows provided by
operating activities were $6.7 million, and $22.4 million for the years ended December 31, 2017 and 2016, respectively. Cash flows from
operating activities in each period were largely impacted by our operating results and changes in working capital. Changes in working
capital were a use of cash of $23.6 million for the year ended December 31, 2018, a use of cash of $5.8 million for the year ended
December 31, 2017, and a source of cash of $38.8 million for the year ended December 31, 2016.
It is our long-term intention to utilize our operating cash flows to fund maintenance and growth of our rental tool assets and
drilling rigs. Given the decline in demand in the current oil and natural gas services market over the past few years, our short-term focus is
to preserve liquidity by managing our costs and capital expenditures. While the overall market for oilfield services remains challenging, we
are beginning to see a market recovery that is expected to increase our earnings, working capital and capital spending as we pursue
attractive investment opportunities.
Investing Activities
Cash flows used in investing activities were $69.2 million for the year ended December 31, 2018, compared with $54.1 million
and $26.5 million for the years ended December 31, 2017 and 2016, respectively. Cash flows used in investing activities in 2018, 2017 and
2016 included capital expenditures of $70.6 million, $54.5 million and $29.0 million respectively, which were primarily used for tubular
and other products for our Rental Tools Services business and rig-related maintenance.
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Capital expenditures for 2019 are estimated to be approximately $90.0 million and will primarily be directed to our Rental Tools
Services business inventory and maintenance capital for our Drilling Services business. Future capital spending will be evaluated based
upon adequate return requirements and available liquidity.
Financing Activities
Cash flows from financing activities were a source of $3.7 million for the year ended December 31, 2018 primarily related to
amounts borrowed against the DIP Facility of $10.0 million and payments of $3.6 million, $1.4 million and $1.0 million for dividends on
our Convertible Preferred Stock, debt issuance cost related to the Fifth Amendment to the 2015 Secured Credit Agreement and debtors-in-
possession financing costs respectively.
Cash flows from financing activities were a source of $69.3 million for the years ended December 31, 2017 primarily related to the
issuances of common stock and Convertible Preferred Stock, which yielded combined proceeds of $72.3 million, net of underwriting
discount and offering expenses. Additionally, during the year ended December 31, 2017, the Company paid dividends of $2.1 million on
our Convertible Preferred Stock. Cash flows from financing activities were a use of $10.5 million for the years ended December 31,
2016 primarily due to payment of $6.0 million of the contingent consideration related to the April 2015 acquisition of a business, and $3.4
million in connection with the final payment of the purchase price for the remaining noncontrolling interest of ITS Arabia Limited.
Debt Summary
Our principal amount of debt was $585.0 million as of December 31, 2018, which consisted of:
•
•
$360.0 million aggregate principal amount of 6.75% Notes;
and
$225.0 million aggregate principal amount of 7.50%
Notes.
6.75% Senior Notes, due July 2022
On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Notes pursuant to an Indenture between the
Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the “6.75% Notes Indenture”). The 6.75% Notes are
general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured
indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteed indebtedness under the 2015
Secured Credit Agreement and our 7.50% Notes. Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning
July 15, 2014. Debt issuance costs related to the 6.75% Notes were approximately $7.6 million. Unamortized debt issuance costs were $3.8
million prior to the commencement of the Chapter 11 Cases. After the commencement of the Chapter 11 Cases, the carrying amount of
debt was adjusted to the claim amount and all unamortized debt issuance costs prior to the commencement of the Chapter 11 Cases were
fully expensed.
We may redeem all or a part of the 6.75% Notes upon appropriate notice, at redemption prices decreasing each year after January
15, 2018 to par beginning January 15, 2020. As of December 31, 2018, the redemption price is 103.4 percent and we have not made any
redemptions to date. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent of the
aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The 6.75% Notes Indenture limits our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make
other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or
guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other
payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x)
engage in certain business activities. Additionally, the 6.75% Notes Indenture contains certain restrictive covenants designating certain
events as events of default. These covenants are subject to a number of important exceptions and qualifications.
7.50% Senior Notes, due August 2020
On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the
Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the “7.50% Notes Indenture”). The 7.50% Notes are
general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured
indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteed indebtedness under the 2015
Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year,
beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes were approximately $5.6 million. Unamortized debt issuance
costs were $1.6 million prior to the commencement of the Chapter 11 Cases. After the
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commencement of the Chapter 11 Cases, the carrying amount of debt was adjusted to the claim amount and all unamortized debt issuance
costs prior to the commencement of the Chapter 11 Cases were fully expensed.
Beginning August 1, 2018, we may redeem all or a part of the 7.50% Notes upon appropriate notice at par. We have not made any
redemptions to date. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the
aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The 7.50% Notes Indenture limits our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make
other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or
guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other
payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and
(x) engage in certain business activities. Additionally, the 7.50% Notes Indenture contains certain restrictive covenants designating certain
events as events of default. These covenants are subject to a number of important exceptions and qualifications.
The commencement of the Chapter 11 Cases constituted an event of default that accelerated the Company’s obligations under the
indenture governing the 6.75% Notes and the 7.50% Notes. However, any efforts to enforce such payment obligations are automatically
stayed under the provisions of the Bankruptcy Code.
2015 Secured Credit Agreement
On January 26, 2015 we entered into the 2015 Secured Credit Agreement. The 2015 Secured Credit Agreement was originally
comprised of a $200 million revolving credit facility (the “Revolver”). The 2015 Secured Credit Agreement formerly included financial
maintenance covenants, including a leverage ratio, consolidated interest coverage ratio, senior secured leverage ratio, and asset coverage
ratio, many of which were suspended beginning in September 2015. We executed various amendments prior to February 14, 2018, which
reduced the size of the Revolver from $200.0 million to $100.0 million.
On February 14, 2018, we executed the Fifth Amendment to the 2015 Secured Credit Agreement (the “Fifth Amendment”) which
modified the credit facility to an asset-based lending structure and reduced the size of the Revolver from $100 million to $80 million. The
Fifth Amendment eliminated the financial maintenance covenants previously in effect and replaced them with a liquidity covenant of $30
million and a monthly borrowing base calculation based on eligible rental equipment and eligible domestic accounts receivable. The
liquidity covenant required the Company to maintain a minimum of $30 million of liquidity (defined as availability under the borrowing
base and cash on hand), of which $15 million was restricted, resulting in a maximum availability at any one time of the lesser of (a) an
amount equal to our borrowing base minus $15 million, or (b) $65 million. Our ability to borrow under the 2015 Secured Credit Agreement
was determined by reference to our borrowing base. The Fifth Amendment also allowed for refinancing our existing Senior Notes with
either secured or unsecured debt, added the ability for the Company to designate certain of its subsidiaries as “Designated Borrowers” and
removed our ability to make certain restricted payments.
On July 12, 2018, we executed the Sixth Amendment to the 2015 Secured Credit Agreement (the “Sixth Amendment”) which
permitted the Company to make Restricted Payments (as defined in the 2015 Secured Credit Agreement) in the form of certain Equity
Interests (as defined in the 2015 Secured Credit Agreement).
On October 25, 2018, we entered into a Consent Agreement and a Cash Collateral Agreement, whereby we could open bank
accounts not subject to the 2015 Secured Credit Agreement for the purpose of depositing cash to secure certain Letters of Credit. On
October 30, 2018, we deposited $10.0 million into a cash collateral account to support the letters of credit outstanding, which is included in
the restricted cash balance on the consolidated balance sheet.
Our obligations under the 2015 Secured Credit Agreement were guaranteed by substantially all of our direct and indirect domestic
subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has
executed guaranty agreements, and were secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the
GOM and land rigs in Alaska, certain U.S.-based rental equipment of the Company and its subsidiary guarantors and the equity interests of
certain of the Company’s subsidiaries. In addition to the liquidity covenant and borrowing base requirements, the 2015 Secured Credit
Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness and liens, and restrictions on entry
into certain affiliate transactions and payments (including certain payments of dividends).
Our Revolver was available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrued at
either:
•
Base Rate plus an Applicable Rate
or
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•
LIBOR plus an Applicable
Rate.
All of the Company’s obligations under the 2015 Secured Credit Agreement were paid prior to the commencement of the Chapter
11 Cases, and the 2015 Secured Credit Agreement, including the Revolver thereunder, was terminated concurrently with the
commencement of the Chapter 11 Cases. Unamortized debt issuance costs of $1.2 million were fully expensed upon termination of the
2015 Secured Credit Agreement.
Summary of Contractual Cash Obligations
The following table summarizes our future contractual cash obligations as of December 31, 2018:
Total
2019
2020
2021
2022
2023
Beyond 2023
Dollars in thousands
Contractual cash obligations:
Debt — principal
Operating leases (1)
Purchase commitments (2)
Debtor in possession financing
Total contractual obligations
$ 658,633 $ 642,409 $
$ 585,000 $ 585,000 $
26,946
36,687
10,000
10,722
36,687
10,000
— $
7,887
—
—
7,887 $
— $
4,193
—
—
4,193 $
— $
1,968
—
—
1,968 $
— $
1,540
—
—
1,540 $
Commercial commitments:
Standby letters of credit
Total commercial commitments
$
$
9,188 $
9,188 $
8,482 $
8,482 $
543 $
543 $
163 $
163 $
— $
— $
— $
— $
—
636
—
—
636
—
—
(1) Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal
property.
(2) We had purchase commitments outstanding as of December 31, 2018 related to rental tools and rig related
expenditures.
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Other Matters
Business Risks
See Item 1A. Risk Factors, for a discussion of risks related to our business.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of
these consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets
and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting
period. On an ongoing basis, we evaluate our estimates, including those related to fair value of assets, bad debt, materials and supplies
obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for
which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that we
believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of
assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results
could differ from these estimates.
We believe the following are our most critical accounting policies as they can be complex and require significant judgments,
assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are
summarized in Note 1 - Summary of Significant Accounting Policies of the consolidated financial statements.
Fair Value Measurements
For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair
value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants in the principal market for the asset or liability. Our valuation technique requires inputs that we
categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjusted quoted prices for
identical assets or liabilities in active markets (Level 1), (2) direct or indirect observable inputs, including quoted prices or other market
data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (Level 2) and (3) unobservable
inputs that require significant judgment for which there is little or no market data (Level 3). When multiple input levels are required for a
valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even
though we may have also utilized significant inputs that are more readily observable.
Impairment of Property, Plant and Equipment
We evaluate the carrying amounts of long-lived assets for potential impairment when events occur or circumstances change that
indicate the carrying values of such assets may not be recoverable. For example, evaluations are performed when we experience sustained
significant declines in utilization and dayrates, and we do not contemplate recovery in the near future. In addition, we evaluate our assets
when we reclassify property and equipment to assets held for sale or as discontinued operations as prescribed by accounting guidance
related to accounting for the impairment or disposal of long-lived assets. We determine recoverability by evaluating the undiscounted
estimated future net cash flows. When impairment is indicated, we measure the impairment as the amount by which the assets carrying
value exceeds its fair value. Management considers a number of factors such as estimated future cash flows, appraisals and current market
value analysis in determining fair value. Assets are written down to fair value if the concluded current fair value is below the net carrying
value.
Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by
our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization
levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.
Goodwill
We account for all business combinations using the acquisition method of accounting. Under this method, assets and liabilities,
including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price
over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill.
We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative conditions
or other triggering events arise. The quantitative impairment test we perform for goodwill utilizes certain assumptions, including forecasted
revenues and costs assumptions.
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Intangible Assets
Our intangible assets are related to trade names and developed technology, which were acquired through acquisition and are
generally amortized over a weighted average period of approximately three to six years. We assess the recoverability of the unamortized
balance of our intangible assets when indicators of impairment are present based on expected future profitability and undiscounted
expected cash flows and their contribution to our overall operations. Should the review indicate that the carrying value is not fully
recoverable, the excess of the carrying value over the fair value of the intangible assets would be recognized as an impairment loss.
Accrual for Self-Insurance
Substantially all of our operations are subject to hazards that are customary for oil and natural gas drilling operations, including
blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, cratering, oil and natural
gas well fires and explosions, natural disasters, pollution, mechanical failure and damage or loss during transportation. Some of our fleet is
also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding,
collision, damage from severe weather and marine life infestations. These hazards could result in damage to or destruction of drilling
equipment, personal injury and property damage, suspension of operations or environmental damage, which could lead to claims by third
parties or customers, suspension of operations and contract terminations. We have had accidents in the past due to some of these hazards.
Our contracts provide for varying levels of indemnification between ourselves and our customers, including with respect to well
control and subsurface risks. We seek to obtain indemnification from our customers by contract for certain of these risks. We also maintain
insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. To the extent that
we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance.
However, these insurance or indemnification agreements may not adequately protect us against liability from all of the consequences of the
hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of an
insurance coverage deductible.
Based on the risks discussed above, we estimate our liability in excess of insurance coverage and accrue for these amounts in our
consolidated financial statements. Accruals related to insurance are based on the facts and circumstances specific to the insurance claims
and our past experience with similar claims. The actual outcome of insured claims could differ significantly from the amounts estimated.
We accrue actuarially determined amounts in our consolidated balance sheet to cover self-insurance retentions for workers’ compensation,
employers’ liability, general liability, automobile liability and health benefits claims. These accruals use historical data based upon actual
claim settlements and reported claims to project future losses. These estimates and accruals have historically been reasonable in light of the
actual amount of claims paid.
As the determination of our liability for insurance claims could be material and is subject to significant management judgment and
in certain instances is based on actuarially estimated and calculated amounts, management believes that accounting estimates related to
insurance accruals are critical.
Accounting for Income Taxes
We are a U.S. company and we operate through our various foreign legal entities and their branches and subsidiaries in numerous
countries throughout the world. Consequently, our tax provision is based upon the tax laws and rates in effect in the countries in which our
operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these
jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, we are required to estimate the
income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with
assessing temporary differences resulting from differing treatment of items, such as depreciation, amortization and certain accrued
liabilities for tax and accounting purposes. Our effective tax rate for financial statement purposes will continue to fluctuate from year to
year as our operations are conducted in different taxing jurisdictions. Current income tax expense represents either liabilities expected to be
reflected on our income tax returns for the current year, nonresident withholding taxes or changes in prior year tax estimates which may
result from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or
liabilities reported on the consolidated balance sheet. Valuation allowances are established to reduce deferred tax assets when it is more
likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets
or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding amounts and sources of future
taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, as well as changes in tax laws,
could require us to adjust the deferred tax assets and liabilities or valuation allowances, including as discussed below.
Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to
expiration. Evaluations of the realizability of deferred tax assets are, by nature, highly subjective. They involve expectations about
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future operations and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future
utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different determinations of
our ability to realize deferred tax assets. In the event that our earnings performance projections do not indicate that we will be able to
benefit from our deferred tax assets, valuation allowances are established following the “more likely than not” criteria. We periodically
evaluate our ability to utilize our deferred tax assets and, in accordance with accounting guidance related to accounting for income taxes,
will record any resulting adjustments that may be required to deferred income tax expense in the period for which an existing estimate
changes.
We do not currently provide for deferred taxes on unremitted earnings of our foreign subsidiaries as such earnings were reinvested
to fund our international operations. If the unremitted earnings were to be distributed, we could be subject to taxes and foreign withholding
taxes though it is not practicable to determine the resulting liability, if any, that would result on the distribution of such earnings. We
annually review our position and may elect to change our future tax position.
We apply the accounting standards related to uncertainty in income taxes. This accounting guidance requires that management
make estimates and assumptions affecting amounts recorded as liabilities and related disclosures due to the uncertainty as to final resolution
of certain tax matters. Because the recognition of liabilities under this interpretation may require periodic adjustments and may not
necessarily imply any change in management’s assessment of the ultimate outcome of these items, the amount recorded may not accurately
reflect actual outcomes.
Revenue Recognition
Contract drilling revenues and expenses, comprised of daywork drilling contracts, call-outs against master service agreements and
engineering and related project service contracts, are recognized as services are performed and collection is reasonably assured. For certain
contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments
received, and direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract; however,
costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.
Reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs. For contracts that are terminated prior
to the specified term, early termination payments received by us are recognized as revenues when all contractual requirements are met.
Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Our project related
services contracts include engineering, consulting, and project management scopes of work and revenue is typically recognized on a time
and materials basis.
Allowance for Doubtful Accounts
The allowance for doubtful accounts is estimated for losses that may occur resulting from disputed amounts and the inability of
our customers to pay amounts owed. We estimate the allowance based on historical write-off experience and information about specific
customers. We review individually, for collectability, all balances over 90 days past due as well as balances due from any customer with
respect to which we have information leading us to believe that a risk exists for potential collection.
Legal and Investigative Matters
As of December 31, 2018, we have accrued an estimate of the probable and estimable costs for the resolution of certain legal and
investigation matters. We have not accrued any amounts for other matters for which the liability is not probable and reasonably estimable.
Generally, the estimate of probable costs related to these matters is developed in consultation with our legal advisors. The estimates take
into consideration factors such as the complexity of the issues, litigation risks and settlement costs. If the actual settlement costs, final
judgments, or fines, after appeals, differ from our estimates, our future financial results may be adversely affected.
Recent Accounting Pronouncements
For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated
financial statements, see Note 17 - Selected Quarterly Financial Data (Unaudited) in Item 8. Financial Statements and Supplementary Data .
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Foreign Currency Exchange Rate Risk
Our international operations expose us to foreign currency exchange rate risk. There are a variety of techniques to minimize the
exposure to foreign currency exchange rate risk, including customer contract payment terms and the possible use of foreign currency
exchange rate risk derivative instruments. Our primary foreign currency exchange rate risk management strategy involves structuring
customer contracts to provide for payment in both U.S. dollars and local currency. The payment portion denominated in local currency is
based on anticipated local currency requirements over the contract term. Due to various factors, including customer acceptance, local
banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign currency
exchange rate risk needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk.
Fluctuations in foreign currencies typically have not had a material impact on our overall results. In situations where payments of local
currency do not equal local currency requirements, foreign currency exchange rate risk derivative instruments, specifically spot purchases,
may be used to mitigate foreign exchange rate currency risk. We do not enter into derivative transactions for speculative purposes. As of
December 31, 2018, we had no open foreign currency exchange rate risk derivative contracts.
Interest Rate Risk
We are exposed to changes in interest rates through our fixed rate debt. Typically, the fair market value of fixed rate debt will
increase as prevailing interest rates decrease and will decrease as prevailing interest rates increase. The fair value of our debt is estimated
based on quoted market prices where applicable, or based on the present value of expected cash flows relating to the debt discounted at
rates currently available to us for long-term borrowings with similar terms and maturities. The estimated fair value of our $360.0 million
principal amount of 6.75% Notes, based on quoted market prices, was $180.0 million as of December 31, 2018. The estimated fair value of
our $225.0 million principal amount of 7.50% Notes, based on quoted market prices, was $117.0 million as of December 31, 2018. A
hypothetical 100 basis point increase in interest rates relative to market interest rates as of December 31, 2018 would decrease the fair
market value of our 6.75% Notes by approximately $12.4 million and decrease the fair market value of our 7.50% Notes by approximately
$7.6 million.
Impact of Fluctuating Commodity Prices
We are exposed to the impact of fluctuations in commodity prices that affect spending by E&P companies on drilling programs.
Prolonged price reductions in commodity prices have led to significant reductions in drilling activity for both oil and natural gas. This has
resulted in cancellations of some existing contracts for our rigs and rental tools, as well as fewer opportunities to maintain utilization for our
equipment when contracted work was completed. As a result, drilling rig and rental tools utilization declined along with associated dayrates
and rental rates.
In response to the prolonged reduction in market prices for oil and natural gas, many E&P companies curtailed U.S. drilling
activity, cut worldwide spending, terminated certain drilling contracts, requested pricing concessions and took other measures aimed at
reducing the capital and operating expenses within their supply chain. This adversely impacted our rental tools activity and pricing, as well
as utilization and pricing of our drilling rigs.
We have experienced lower pricing and utilization of tools, services and rigs in the U.S. and certain international markets.
Although the severity and duration of the current industry downturn is contingent upon many factors beyond our control, we have taken
several steps in an effort to generate free cash flow during this period, including lowering our cost base through headcount reductions and
lower idle rig costs, and reducing our capital expenditures. Drilling activity is highly dependent on oil and natural gas prices. Many E&P
companies are expected to increase their worldwide spending plans for 2019.
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Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Stockholders and Board of Directors
Parker Drilling Company:
Opinion on Internal Control Over Financial Reporting
We have audited Parker Drilling Company and subsidiaries (Debtor in Possession) (the “Company”) internal control over financial
reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
consolidated balance sheets of the Company as of December 31, 2018 and 2017, the related consolidated statements of operations,
comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018,
and the related notes and financial statement Schedules II - Valuation and Qualifying Accounts (collectively, the consolidated financial
statements), and our report dated March 11, 2019 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control
over Financial Reporting in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting
based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the
Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our
audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing
the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that
our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Houston, Texas
March 11, 2019
/s/ KPMG LLP
53
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Report of Independent Registered Public Accounting Firm
The Stockholders and Board of Directors
Parker Drilling Company:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Parker Drilling Company and subsidiaries (Debtor In Possession) (the
“Company”) as of December 31, 2018 and 2017, the related consolidated statements of operations, comprehensive income (loss),
stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018, and the related notes and the
financial statement Schedule II - Valuation and Qualifying Accounts (collectively, the consolidated financial statements). In our opinion,
the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018
and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in
conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the
Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 11,
2019, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Going Concern
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As
discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations, and is facing risk
and uncertainties surrounding its Chapter 11 proceedings that raise substantial doubt about its ability to continue as a going concern.
Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any
adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion
on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or
fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements,
whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the
accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the
consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
We have served as the Company’s auditor since 2007.
Houston, Texas
March 11, 2019
/s/ KPMG LLP
54
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands, Except Per Share Data)
December 31,
2018
2017
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Accounts and Notes Receivable, net of allowance for bad debts of $7,767 at December 31, 2018
and $7,564 at December 31, 2017
Rig materials and supplies
Deferred costs
Other tax assets
Other current assets
Total current assets
Property, plant and equipment, net of accumulated depreciation of $951,798 at December 31, 2018
and $1,343,105 at December 31, 2017 (Note 3)
Goodwill (Note 4)
Intangible assets, net (Note 4)
Rig materials and supplies
Deferred income taxes
Other non-current assets
Total assets
Current Liabilities:
LIABILITIES AND STOCKHOLDERS’ EQUITY
Debtor in possession financing (Note 2)
Accounts payable
Accrued liabilities
Accrued income taxes
Total current liabilities
Long-term debt, net of unamortized debt issuance costs of $7,029 at December 31, 2017
Other long-term liabilities
Long-term deferred tax liability
Commitments and contingencies (Note 9)
Total liabilities not subject to compromise
Liabilities subject to compromise (Note 2)
Stockholders’ equity:
Preferred stock, $1.00 par value, 1,942,000 shares authorized, 7.25% Series A Mandatory
Convertible, 500,000 shares issued and outstanding
Common Stock, $0.16 2/3 par value, authorized 18,666,667 shares, issued and outstanding,
9,384,669 shares (9,262,382 shares in 2017) (1)
Capital in excess of par value (1)
Accumulated deficit
Accumulated other comprehensive income (loss)
Total stockholders’ equity
Total liabilities and stockholders’ equity
(1) See Note 12 - Stockholders' Equity for details regarding the 1-for-15 reverse stock
split.
See accompanying notes to the consolidated financial statements.
55
$
$
$
$
48,602 $
10,389
141,549
—
122,511
31,415
3,145
4,889
14,327
317,836
625,771
6,708
7,128
18,788
1,284
12,764
990,279
—
41,523
57,723
4,430
103,676
577,971
12,433
78
—
694,158
—
136,437
36,245
4,353
2,949
27,929
266,904
534,371
—
4,821
12,971
2,143
7,204
828,414 $
10,000 $
39,678
35,385
3,385
88,448
—
11,544
510
100,502
600,996
500
500
1,398
766,347
(634,450)
(6,879)
126,916
828,414 $
1,378
766,508
(468,753)
(3,512)
296,121
990,279
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in Thousands, Except Per Share Data)
Revenues
Expenses:
Operating expenses
Depreciation and amortization
Total operating gross margin (loss)
General and administrative expense
Loss on impairment
Provision for reduction in carrying value of certain assets
Gain (loss) on disposition of assets, net
Pre-petition restructuring charges
Reorganization items
Total operating income (loss)
Other income (expense):
Interest expense
Interest income
Other
Total other income (expense)
Income (loss) before income taxes
Income tax expense (benefit):
Current tax expense
Deferred tax expense (benefit)
Total income tax expense (benefit)
Net income (loss)
Less: Convertible preferred stock dividend
Net income (loss) available to common stockholders
Basic earnings (loss) per common share: (1)
Diluted earnings (loss) per common share: (1)
Number of common shares used in computing earnings per share:
Basic (1)
Diluted (1)
Year Ended December 31,
2018
480,821 $
2017
442,520 $
2016
427,004
$
378,104
107,545
485,649
(4,828)
(24,545)
(50,698)
—
(1,724)
(21,820)
(9,789)
(113,404)
(42,565)
91
(2,023)
(44,497)
(157,901)
355,487
122,373
477,860
(35,340)
(25,676)
—
(1,938)
(2,851)
—
—
(65,805)
(44,226)
244
126
(43,856)
(109,661)
8,225
(429)
7,796
(165,697)
2,719
(168,416) $
(18.09) $
(18.09) $
9,264
(224)
9,040
(118,701)
3,051
(121,752) $
(13.40) $
(13.40) $
$
$
$
362,521
139,795
502,316
(75,312)
(34,332)
—
—
(1,613)
—
—
(111,257)
(45,812)
58
367
(45,387)
(156,644)
5,108
69,062
74,170
(230,814)
—
(230,814)
(27.89)
(27.89)
9,311,722
9,311,722
9,084,456
9,084,456
8,275,334
8,275,334
(1) See Note 12 - Stockholders' Equity for details regarding the 1-for-15 reverse stock
split.
See accompanying notes to the consolidated financial statements.
56
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
Net income (loss)
Other comprehensive income (loss), net of tax:
Currency translation difference on related borrowings
Currency translation difference on foreign currency net investments
Total other comprehensive income (loss), net of tax:
Comprehensive income (loss)
Year Ended December 31,
2018
(165,697) $
2017
(118,701) $
2016
(230,814)
(646)
(2,721)
(3,367)
(169,064) $
643
2,689
3,332
(115,369) $
(691)
(4,265)
(4,956)
(235,770)
$
$
See accompanying notes to the consolidated financial statements.
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss):
Depreciation and amortization
Accretion on contingent consideration
(Gain) loss on debt modification
Gain (loss) on disposition of assets, net
Deferred tax expense (benefit)
Loss on impairment
Reorganization items
Provision for reduction in carrying value of certain assets
Expenses not requiring cash
Change in assets and liabilities:
Accounts and notes receivable
Rig materials and supplies
Other current assets
Other non-current assets
Accounts payable and accrued liabilities
Accrued income taxes
Net cash provided by (used in) operating activities
Cash flows from investing activities:
Capital expenditures
Proceeds from the sale of assets
Net cash provided by (used in) investing activities
Cash flows from financing activities:
Proceeds from borrowing under DIP facility
Payment of DIP facility costs
Convertible preferred stock dividend
Payments of debt issuance costs
Shares surrendered in lieu of tax
Proceeds from the issuance of common stock
Proceeds from the issuance of convertible preferred stock
Payment of equity issuance costs
Payment of contingent consideration
Payment for noncontrolling interest
Year Ended December 31,
2018
2017
2016
$
(165,697) $
(118,701) $
(230,814)
107,545
—
—
1,724
(429)
50,698
7,538
—
5,151
(15,235)
249
(10,860)
13,019
(9,489)
(1,264)
(17,050)
(70,567)
1,353
(69,214)
10,000
(975)
(3,625)
(1,443)
(251)
—
—
—
—
—
3,706
(82,558)
141,549
58,991 $
122,373
—
—
2,851
(224)
—
—
1,938
4,251
(9,628)
4,710
(1,319)
8,658
(8,714)
538
6,733
(54,533)
403
(54,130)
—
—
(2,145)
—
(936)
25,200
50,000
(2,864)
—
—
69,255
21,858
119,691
141,549 $
139,795
419
1,088
1,613
69,062
—
—
—
2,518
60,391
(1,752)
2,140
3,897
(19,494)
(6,422)
22,441
(28,954)
2,441
(26,513)
—
—
—
—
(1,156)
—
—
—
(6,000)
(3,375)
(10,531)
(14,603)
134,294
119,691
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
$
Supplemental cash flow information:
Interest paid
Income taxes paid
Restructuring costs paid
41,175
8,625
6,638
See accompanying notes to the consolidated financial statements.
41,175
8,422
—
41,175
14,341
—
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Dollars and Shares in Thousands)
Convertible
Preferred
Stock
Shares (1)
Common
Stock
Treasury
Stock
Capital in
Excess of
Par Value
Accumulated
Deficit
Accumulated
Other
Comprehensive
Income (Loss)
Total
Stockholders’
Equity
8,214 $
— $
1,373 $
(170) $ 688,435 $ (119,238) $
(1,888) $ 568,512
127
—
—
—
—
—
—
—
21
—
(1,177)
—
7,549
—
—
—
(1,156)
—
7,549
—
—
—
(230,814)
—
(230,814)
—
—
(4,956)
(4,956)
8,341
—
1,394
(170)
694,807
(350,052)
(6,844)
339,135
121
—
800
—
—
—
20
—
—
(956)
—
4,006
134
—
23,925
—
—
—
—
—
—
(936)
—
4,006
—
24,059
—
48,277
—
(3,051)
500
500
—
—
—
—
—
—
—
—
—
—
—
47,777
—
(3,051)
—
—
—
(118,701)
—
(118,701)
—
—
3,332
3,332
9,762
500
1,548
(170)
766,508
(468,753)
(3,512)
296,121
123
—
—
—
—
—
—
—
—
—
20
—
—
—
—
—
(275)
—
2,833
—
(2,719)
—
—
—
—
(255)
—
2,833
—
(2,719)
—
—
—
(165,697)
—
(165,697)
—
—
(3,367)
(3,367)
9,885 $
500 $
1,568 $
(170) $ 766,347 $ (634,450) $
(6,879) $ 126,916
Balances, December 31,
2015
Activity in employees’
stock plans
Amortization of stock-
based awards
Comprehensive Income:
Net income
Other comprehensive
income (loss)
Balances, December 31,
2016
Activity in employees’
stock plans
Amortization of stock-
based awards
Issuance of common
stock
Issuance of mandatory
convertible preferred
stock
Convertible preferred
stock dividend
Comprehensive Income:
Net income
Other comprehensive
income (loss)
Balances, December 31,
2017
Activity in employees’
stock plans
Amortization of stock-
based awards
Convertible preferred
stock dividend
Comprehensive Income:
Net income (loss)
Other comprehensive
income (loss)
Balances, December 31,
2018
(1) See Note 12 - Stockholders' Equity for details regarding the 1-for-15 reverse stock
split.
See accompanying notes to the consolidated financial statements.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
Organization and Nature of Operations
Parker Drilling Company, incorporated in Delaware, and its wholly-owned subsidiaries (“Parker Drilling” or the “Company” or
“we” or “us” or “our”) is 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.
Basis of Presentation
The consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“U.S.
GAAP”) and are audited. In the opinion of Parker Drilling, these consolidated financial statements include all adjustments which, unless
otherwise disclosed, are of a normal recurring nature, necessary for their fair presentation for the periods presented.
Consolidation
The consolidated financial statements include the accounts of the Company and subsidiaries in which we exercise control or have
a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s losses or returns,
regardless of ownership percentage. If a subsidiary of Parker Drilling has a 50.0 percent interest in an entity but Parker Drilling’s interest in
the subsidiary or the entity does not meet the consolidation criteria described above, then that interest is accounted for under the equity
method.
Noncontrolling Interest
We apply accounting standards related to noncontrolling interests for ownership interests in our subsidiaries held by parties other
than Parker Drilling. We report noncontrolling interest as equity on the consolidated balance sheets and report net income (loss)
attributable to controlling interest and to noncontrolling interest separately on the consolidated statements of operations.
Reclassifications
Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These
reclassifications did not materially affect our consolidated financial results.
Use of Estimates
The preparation of our consolidated financial statements in accordance with U.S. GAAP requires management to make estimates
and assumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of the
consolidated financial statements, and our revenues and expenses during the periods reported. Estimates are typically used when
accounting for certain significant items such as legal or contractual liability accruals, self-insured medical/dental plans, impairment, income
taxes and valuation allowance, and other items requiring the use of estimates. Estimates are based on a number of variables, which may
include third party valuations, historical experience, where applicable, and assumptions that we believe are reasonable under the
circumstances. Due to the inherent uncertainty involved with estimates, actual results may differ from management estimates.
Revenue Recognition
See Note 14 - Revenue from Contracts with Customers for further discussion of our revenue recognition policy.
Goodwill
We account for business combinations using the acquisition method of accounting. Under this method, assets and liabilities,
including any remaining noncontrolling interests, are recognized at fair value at the date of acquisition. The excess of the purchase price
over the fair value of assets acquired, net of liabilities assumed, plus the value of any noncontrolling interests, is recognized as goodwill.
We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative conditions
or other triggering events arise that indicate that the fair value of the reporting unit has decreased below its carrying value. In order to
estimate the fair value of the reporting unit, the Company used a weighting of the discounted cash flow, guideline public company and
guideline transaction method. The Company engages third-party appraisal firms to assist in f
60
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air value determination of the reporting unit. The quantitative impairment test we perform for goodwill utilizes certain assumptions,
including forecasted revenues and costs assumptions. See Note 4 - Goodwill and Intangible Assets for further discussion.
Intangible Assets
Our intangible assets are related to developed technology and trade names, which were acquired through acquisition and are
classified as definite lived intangibles that are generally amortized over a weighted average period of approximately three to six years. We
assess the recoverability of the unamortized balance of our intangible assets when indicators of impairment are present based on expected
future profitability and undiscounted expected cash flows and their contribution to our overall operations. Should the review indicate that
the carrying value is not fully recoverable, the excess of the carrying value over the fair value of the intangible assets would be recognized
as an impairment loss. See Note 4 - Goodwill and Intangible Assets for further discussion.
Cash, Cash equivalents and Restricted Cash
For purposes of the consolidated balance sheets and the consolidated statements of cash flows, the Company considers cash
equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.
Dollars in thousands
Cash and cash equivalents
Restricted cash
Cash, cash equivalents and restricted cash at end of period
December 31,
2018
2017
$
$
48,602 $
10,389
58,991 $
141,549
—
141,549
The restricted cash balance includes $9.8 million into a cash collateral account to support the letters of credit outstanding and $0.6
million held as compensating balances in the ordinary course of business for purchases and utilities.
Accounts Receivable and Allowance for Bad Debt
Trade accounts receivable are recorded at the invoice amount and typically do not bear interest. The allowance for bad debt is
estimated for losses that may occur resulting from disputed amounts and the inability of our customers to pay amounts owed. We estimate
the allowance based on historical write-off experience and information about specific customers. We review individually, for collectability,
all balances over 90 days past due as well as balances due from any customer with respect to which we have information leading us to
believe that a risk exists for potential collection.
Account balances are charged off against the allowance when we believe it is probable the receivable will not be recovered. We
do not have any off-balance-sheet credit exposure related to customers.
The components of our accounts receivable, net of allowance for bad debt balance are as follows:
Dollars in thousands
Trade
Allowance for bad debt (1)
Total accounts and notes receivable, net of allowance for bad debt
December 31,
2018
2017
$
$
144,204 $
(7,767)
136,437 $
130,075
(7,564)
122,511
(1) Additional information on the allowance for bad debt for the years ended December 31, 2018, 2017 and 2016 is reported on
Schedule II — Valuation and Qualifying Accounts.
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Property, Plant and Equipment
Property, plant and equipment is carried at cost. Maintenance and most repair costs are expensed as incurred. The cost of upgrades
and replacements is capitalized. The Company capitalizes software developed or obtained for internal use. Accordingly, the cost of third-
party software, as well as the cost of third-party and internal personnel that are directly involved in application development activities, are
capitalized during the application development phase of new software systems projects. Costs during the preliminary project stage and post-
implementation stage of new software systems projects, including data conversion and training costs, are expensed as incurred. We account
for depreciation of property, plant and equipment on the straight-line method over the estimated useful lives of the assets after provision for
salvage value. Depreciation, for tax purposes, utilizes several methods of accelerated depreciation. Depreciable lives for different
categories of property, plant and equipment are as follows:
Computer, office equipment and other
Land drilling equipment
Barge drilling equipment
Drill pipe, rental tools and other
Buildings and improvements
3 to 10 years
3 to 20 years
3 to 20 years
4 to 15 years
5 to 30 years
Leasehold improvements are depreciated over the shorter of their estimated useful lives or the term of the lease.
Impairment
We evaluate the carrying amounts of long-lived assets for potential impairment when events occur or circumstances change that
indicate the carrying values of such assets may not be recoverable. We evaluate recoverability by determining the undiscounted estimated
future net cash flows for the respective asset groups identified. If the sum of the estimated undiscounted cash flows is less than the carrying
value of the asset group, we measure the impairment as the amount by which the assets’ carrying value exceeds the fair value of such
assets. Management considers a number of factors such as estimated future cash flows from the assets, appraisals and current market value
analysis in determining fair value. Assets are written down to fair value if the final estimate of current fair value is below the net carrying
value. The assumptions used in the impairment evaluation are inherently uncertain and require management judgment.
Capitalized Interest
Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized
interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying
assets. Capitalized interest costs reduce net interest expense in the consolidated statements of operations. Capitalized interest costs were
$0.1 million during 2018. During 2017 and 2016 capitalized interest costs were nominal and $0.2 million, respectively.
Assets Held for Sale
We classify an asset as held for sale when the facts and circumstances meet the criteria for such classification, including the
following: (a) we have committed to a plan to sell the asset, (b) the asset is available for immediate sale, (c) we have initiated actions to
complete the sale, including locating a buyer, (d) the sale is expected to be completed within one year, (e) the asset is being actively
marketed at a price that is reasonable relative to its fair value, and (f) the plan to sell is unlikely to be subject to significant changes or
termination.
Rig Materials and Supplies
Because our international drilling generally occurs in remote locations, making timely outside delivery of spare parts uncertain, a
complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operation. During periods of high rig
utilization, these parts are generally consumed and replenished within a one-year period. During a period of lower rig utilization in a
particular location, the parts, like the related idle rigs, are generally not transferred to other international locations until new contracts are
obtained because of the significant transportation costs that would result from such transfers. We classify those parts which are not
expected to be utilized in the following year as long-term assets. Additionally, our international rental tools business holds machine shop
consumables and steel stock for manufacture in our machine shops and inspection and repair shops, which are classified as current assets.
Rig materials and supplies are valued at the lower of cost or market value.
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Deferred Costs
We defer costs related to rig mobilization and amortize such costs over the primary term of the related contract. The costs to be
amortized within twelve months are classified as current.
Debt Issuance Costs
We typically defer costs associated with issuance of indebtedness, and amortize those costs over the term of the related debt using
the effective interest method.
Income Taxes
Income taxes are accounted for under the asset and liability method and have been provided for based upon tax laws and rates in
effect in the countries in which operations are conducted and income or losses are generated. There is little or no expected relationship
between the provision for or benefit from income taxes and income or loss before income taxes as the countries in which we operate have
taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits, and other
benefits. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the carrying
amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets
and liabilities are measured using enacted tax rates in effect for the year in which the temporary differences are expected to be recovered or
settled and the effect of changes in tax rates is recognized in income in the period in which the change is enacted. Valuation allowances are
established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be
realized. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make estimates
and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and
assumptions, including changes in tax laws and other changes affecting our ability to recognize the underlying deferred tax assets, could
require us to adjust the valuation allowances.
The Company recognizes the effect of income tax positions only if those positions are more likely than not to be
sustained. Recognized income tax positions are measured at the largest amount that is greater than 50.0 percent likely of being realized and
changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
Earnings (Loss) Per Share (EPS)
Basic earnings (loss) per share is computed by dividing net income (loss) available to common stockholders by the weighted
average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock,
assumed conversion of convertible stock and convertible debt are included in the diluted EPS calculation, when applicable.
Concentrations of Credit Risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist primarily of trade receivables
with a variety of national and international oil and natural gas companies. We generally do not require collateral on our trade receivables.
We depend on a limited number of significant customers. In 2018, our largest customer, Exxon Neftegas Limited (“ENL”), constituted
approximately 25.7 percent of our consolidated revenues. Excluding revenues from reimbursable cost (“reimbursable revenues”) of $47.2
million, ENL constituted approximately 17.9 percent of our total consolidated revenues.
As of December 31, 2018 and 2017, we had deposits in domestic banks in excess of federally insured limits of approximately $27.5
million and $97.6 million, respectively. In addition, we had uninsured deposits in foreign banks as of December 31, 2018 and 2017 of $32.9
million and $45.6 million, respectively.
Fair Value Measurements
For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair
value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants in the principal market for the asset or liability. Our valuation technique requires inputs that we
categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjusted quoted prices for
identical assets or liabilities in active markets (Level 1), (2) direct or indirect observable inputs, including quoted prices or other market
data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (Level 2) and (3) unobservable
inputs that require significant judgment for which there is little or no market data (Level 3). When multiple input levels are required for a
valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even
though we may have also utilized significant inputs that are more readily observable.
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Foreign Currency
In our international rental tool business, for certain subsidiaries and branches outside the U.S., the local currency is the functional
currency. The financial statements of these subsidiaries and branches are translated into U.S. dollars as follows: (i) assets and liabilities at
month-end exchange rates; (ii) income, expenses and cash flows at monthly average exchange rates or exchange rates in effect on the date
of the transaction; and (iii) stockholders’ equity at historical exchange rates. For those subsidiaries where the local currency is the
functional currency, the resulting translation adjustment is recorded as a component of accumulated other elements of comprehensive
income (loss) in the accompanying consolidated balance sheets.
Stock-Based Compensation
Under our long-term incentive plan, we are authorized to issue the following: stock options; stock appreciation rights; restricted
stock awards; restricted stock units; performance-based awards; and other types of awards in cash or stock to key employees, consultants,
and directors. We typically grant restricted stock units, time-based phantom stock units, performance cash units, and performance-based
phantom stock units.
Stock-based compensation expense is recognized, net of an estimated forfeiture rate, which is based on historical experience and
adjusted, if necessary, in subsequent periods based on actual forfeitures. We recognize stock-based compensation expense in the same
financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of
recognized compensation costs are reported as an operating cash flow.
Legal and Investigative Matters
We accrue estimates of the probable and estimable costs for the resolution of certain legal and investigative matters. We do not
accrue any amounts for other matters for which the liability is not probable and reasonably estimable. Generally, the estimate of probable
costs related to these matters is developed in consultation with our legal advisors. The estimates take into consideration factors such as the
complexity of the issues, litigation risks and settlement costs. If the actual settlement costs, final judgments, or fines, after appeals, differ
from our estimates, our future financial results may be adversely affected.
Reverse Stock Split
On July 27, 2018, the Company’s 1-for- 15 reverse stock split of its common stock became effective. Unless otherwise indicated,
all common share and per common share data have been retroactively restated for all periods presented. The reverse stock split did not
affect the par value of the common stock. Shareholders who otherwise would have been entitled to receive a fractional share of common
stock as a result of the reverse stock split received cash in lieu of such fractional share. The Company’s 7.25% Series A Mandatory
Convertible Preferred Stock (“Convertible Preferred Stock”) was not subject to the reverse stock split, as proportionate adjustments were
made to the minimum and maximum conversion rates of the Convertible Preferred Stock.
Bankruptcy
On December 12, 2018 (the “Petition Date”), the Company 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”). The consolidated financial statements included herein have been prepared as if we were a going
concern and in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic No.
852 - Reorganizations. See Note 2 - Chapter 11 Cases for further details.
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Note 2 - Chapter 11 Cases
On the Petition Date, the Debtors filed the Plan and commenced the Chapter 11 Cases under title 11 of the Bankruptcy Code in 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.
In addition to Parker Drilling, the U.S. subsidiaries included as debtors in the Chapter 11 Cases are 2M-TEK, Inc., Anachoreta,
Inc., Pardril, Inc., Parker Aviation Inc., Parker Drilling Arctic Operating, LLC, Parker Drilling Company North America, Inc., Parker
Drilling Company of Niger, Parker Drilling Company of Oklahoma, Incorporated, Parker Drilling Company of South America, Inc., Parker
Drilling Management Services, Ltd., Parker Drilling Offshore Company, LLC, Parker Drilling Offshore USA, L.L.C., Parker North
America Operations, LLC, Parker Technology, Inc., Parker Technology, L.L.C., Parker Tools, LLC, Parker-VSE, LLC, Quail Tools, L.P.,
and Quail USA, LLC. 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.
Restructuring Support Agreement
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;
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
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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, 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. On the Effective Date, the Debtors’ operations will, generally, no longer be governed by the
Bankruptcy Court's oversight.
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 (the “DIP 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 DIP Facility is
available for the issuance of standby letters of credit. The borrowing base is equal to:
(1) 85.0 percent of the aggregate net amount of eligible domestic accounts receivable,
plus
(2) the
of:
lowest
(a) 90.0 percent of net book value of eligible rental
equipment
(b) 60.0 percent of net equipment orderly liquidation value of eligible rental equipment;
or
(c) $37.5 million minus certain reserves, calculated as set forth in the DIP Credit
Agreement.
The borrowing base under the DIP Facility was calculated to be $50.0 million at the time of effectiveness of the DIP Facility,
which was reduced by $10.0 million of outstanding loans under the DIP Facility as of December 31, 2018 and accrued interest on the
debtor-in-possession financing, resulting in availability under the DIP Facility of $40.0 million.
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 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. Letters of credit outstanding under the DIP Facility may be rolled over and deemed
outstanding under the L/C Facility. 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”).
Backstop Commitment Agreement
On December 12, 2018, Parker entered into a Backstop Commitment Agreement (as amended and restated from time to time, the
“Backstop Commitment Agreement”) with the Commitment Parties (as defined in the Backstop Commitment Agreement), pursuant to
which the Commitment Parties agreed to backstop the Rights Offering. In accordance with the Plan and certain Rights Offering procedures
(filed with the Bankruptcy Court on the Petition Date) , Parker will grant the 7.50% Note Holders, the 6.75% Note Holders, the Preferred
Holders, and the Common Holders, including the Commitment Parties, the right to purchase shares of New Common Stock (the “Rights
Offering Shares”) upon the closing of the transactions contemplated by the Backstop
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Commitment Agreement for an aggregate purchase price of $95.0 million. Under the Backstop Commitment Agreement, the Commitment
Parties agreed to purchase any Rights Offering Shares that are not duly subscribed for pursuant to the Rights Offering at the Per Share
Purchase Price (as defined in the Backstop Commitment Agreement).
Under the Backstop Commitment Agreement, Parker has paid the Commitment Parties a cash put option premium of $7.6 million
(the “Put Option Cash Premium”) and an advance for estimated professional fees of the Commitment Parties. If the closing of the Backstop
Commitment Agreement occurs, the Put Option Cash Premium will be remitted to Parker in exchange for 3.4 percent of New Common
Stock (the “Put Option Equity Premium”). In certain circumstances where the Backstop Commitment Agreement has been terminated or
the transactions contemplated thereby are not consummated, the Commitment Parties will be entitled to keep the Put Option Cash
Premium. The Put Option Cash Premium has been paid, and the Put Option Equity Premium shall be issued, in each case, to the
Commitment Parties pro rata based on the amount of their respective backstop commitments.
The rights to purchase New Common Stock in the Rights Offering, any shares issued upon the exercise thereof, and all shares
issued to the Commitment Parties in respect of their backstop commitments pursuant to the Put Option Equity Premium will be issued in
reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant
to section 1145 of the Bankruptcy Code. All shares issued to the Commitment Parties pursuant to the Backstop Commitment Agreement in
respect of their respective commitments will be issued in reliance upon the exemption from registration under the Securities Act provided
by Section 4(a)(2) thereof and/or Regulation D thereunder. As a condition to the closing of the transactions contemplated by the Backstop
Commitment Agreement, Parker will enter into a registration rights agreement with the Commitment Parties desiring to be a party thereto
requiring Parker to register the Commitment Parties’ securities under the Securities Act.
The Commitment Parties’ commitments to backstop the Rights Offering and the other transactions contemplated by the Backstop
Commitment Agreement are conditioned upon satisfaction of all applicable conditions set forth in the Backstop Commitment Agreement.
The issuances of New Common Stock pursuant to the Rights Offering and the Backstop Commitment Agreement are conditioned upon,
among other things, the occurrence of the Effective Date.
Chapter 11 Accounting
The consolidated financial statements included herein have been prepared as if we were a going concern and in accordance with
FASB ASC Topic No. 852 - Reorganizations.
Going Concern
Weak industry conditions have negatively impacted our results of operations and cash flows and may continue to do so in the
future. In order to decrease the Company’s level of indebtedness and maintain the Company’s liquidity at levels sufficient to meet its
commitments, the Company undertook a number of actions, including minimizing capital expenditures and further reducing its recurring
operating expenses. The Company believes that even after taking these actions, it would not have sufficient liquidity to satisfy its debt
service obligations, meet other financial obligations and comply with its debt covenants. As a result, the Debtors filed petitions for
reorganization under Chapter 11 of the Bankruptcy Code.
Industry conditions and the risks and uncertainties associated with the Chapter 11 proceedings, raise substantial doubt about our
ability to continue as a going concern. The 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. The Chapter 11 reorganization
plan supports our going concern assessment.
Pre-petition restructuring charges
Any expenses, gains and losses that are realized or incurred before the Petition Date and in relation to the Chapter 11 Cases are
recorded under pre-petition restructuring charges on our consolidated statements of operations.
Pre-petition restructuring charges were $21.8 million for the year ended December 31, 2018, which primarily consisted of
professional fees related to the Chapter 11 Cases.
Reorganization items
Any expenses, gains and losses that are realized or incurred subsequent to and as a direct result of the Chapter 11 Cases are
recorded under reorganization items on our consolidated statements of operations.
Reorganization items were $9.8 million for the year ended December 31, 2018, which consisted of:
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Dollars in thousands
6.75% Senior Notes, due July 2022 - unamortized debt issuance costs
7.50% Senior Notes, due August 2020 - unamortized debt issuance costs
2015 Secured Credit Agreement - unamortized debt issuance costs
Professional fees
DIP facility costs
Reorganization items
December 31,
2018
$
$
3,775
1,580
1,208
2,251
975
9,789
Debtor in possession financing
Amounts borrowed against the DIP Facility as of December 31, 2018 were $10.0 million.
Liabilities subject to compromise
Pre-petition unsecured and under-secured obligations that may be impacted by the Chapter 11 Cases have been classified as
liabilities subject to compromise on our consolidated balance sheet. These liabilities are reported at the amounts expected to be allowed as
claims by the Bankruptcy Court, although they may be settled for less.
Liabilities subject to compromise as of December 31, 2018 were $601.0 million, which consisted of:
Dollars in thousands
6.75% Senior Notes, due July 2022
7.50% Senior Notes, due August 2020
Accrued interest on Senior Notes
Liabilities subject to compromise
December 31,
2018
$
360,000
225,000
15,996
600,996
$
The principal balance on the 6.75% Notes and 7.50% Notes of $360.0 million and $225.0 million has been reclassed from long-
term debt to liabilities subject to compromise as of December 31, 2018. See also Note 6 - Debt for further details.
Accrued interest on the 6.75% Notes and 7.50% Notes was also reclassed from accrued liabilities to liabilities subject to
compromise as of December 31, 2018. Contractual interest expense on our Senior Notes amounts to $41.2 million for the year ended
December 31, 2018 which is in excess of $39.1 million included in interest expense on the consolidated statements of operations because
the Company has discontinued accruing interest on the Petition Date in accordance with FASB ASC Topic No. 852 - Reorganizations. We
have not made any interest payments on our 6.75% Notes or 7.50% Notes since the commencement of the Chapter 11 Cases.
Convertible preferred stock dividend
We have not declared or made any cash dividend payments on our 7.25% Series A Mandatory Convertible Preferred Stock since
the commencement of the Chapter 11 Cases. We may issue additional equity securities which may dilute current equity interests.
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Debtor Financial Statements
Following are the consolidated financial statements of the entities included in the Chapter 11 Cases:
PARKER DRILLING COMPANY (DEBTOR IN POSSESSION)
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Accounts and Notes Receivable, net of allowance for bad debts of $808 at December 31, 2018 (1)
Rig materials and supplies
Deferred costs
Other tax assets
Other current assets
Total current assets
Property, plant and equipment, net of accumulated depreciation of $526,166 at December 31, 2018
Intangible assets, net
Rig materials and supplies
Deferred income taxes
Intra-group advances
Investment in subsidiaries
Other non-current assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Total assets
Current Liabilities:
Debtor in possession financing
Accounts payable (2)
Accrued liabilities
Accrued income taxes
Total current liabilities
Other long-term liabilities (3)
Long-term deferred tax liability
Total liabilities not subject to compromise
Liabilities subject to compromise
Total stockholders’ equity
Total liabilities and stockholders’ equity
(1)
(2)
(3)
Includes intra-group receivables in the amount of $174.7
million.
Includes intra-group payables in the amount of $213.2
million.
Includes intra-group liabilities in the amount of $314.6
million.
69
December 31,
2018
$
$
$
$
15,226
10,389
223,296
1,650
975
183,356
18,329
453,221
369,510
4,821
7,036
23,576
549,460
893,550
1,452
2,302,626
10,000
286,840
28,184
204,518
529,542
728,218
36,463
1,294,223
600,996
407,407
2,302,626
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PARKER DRILLING COMPANY (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
Revenues
Expenses:
Operating expenses
Depreciation and amortization
Total operating gross margin (loss)
General and administrative expense
Loss on impairment
Gain (loss) on disposition of assets, net
Pre-petition restructuring charges
Reorganization items
Total operating income (loss)
Other income (expense):
Interest expense
Interest income
Other
Equity in net earnings of subsidiaries
Total other income (expense)
Income (loss) before income taxes
Income tax expense (benefit):
Current tax expense
Deferred tax expense (benefit)
Total income tax expense (benefit)
Net income (loss)
Less: Convertible preferred stock dividend
Net income (loss) attributable to debtor entities
70
Year Ended
December 31,
2018
203,585
$
115,269
76,353
191,622
11,963
(23,539)
(40,917)
(1,347)
(21,820)
(9,789)
(85,449)
(45,488)
1,152
6
(33,040)
(77,370)
(162,819)
1,517
1,361
2,878
(165,697)
2,719
(168,416)
$
Table of contents
PARKER DRILLING COMPANY (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss):
Depreciation and amortization
Gain (loss) on disposition of assets, net
Deferred tax expense (benefit)
Loss on impairment
Reorganization items
Expenses not requiring cash
Equity in net earnings of subsidiaries
Change in assets and liabilities:
Accounts and notes receivable
Rig materials and supplies
Other current assets
Other non-current assets
Accounts payable and accrued liabilities
Accrued income taxes
Net cash provided by (used in) operating activities
Cash flows from investing activities:
Capital expenditures
Proceeds from the sale of assets
Net cash provided by (used in) investing activities
Cash flows from financing activities:
Proceeds from borrowing under DIP facility
Payment of DIP facility costs
Convertible preferred stock dividend
Payments of debt issuance costs
Shares surrendered in lieu of tax
Net cash provided by (used in) financing activities
Net increase (decrease) in cash and cash equivalents
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
71
Year Ended
December 31,
2018
$
(165,697)
76,353
1,347
1,361
40,917
7,538
4,224
33,040
(2,189)
(4,454)
(41,564)
2,586
(559)
29,818
(17,279)
(56,897)
87
(56,810)
10,000
(975)
(3,625)
(1,443)
(251)
3,706
(70,383)
95,998
25,615
$
Table of contents
Note 3 - Property, Plant and Equipment
The components of our property, plant and equipment balance are as follows:
Dollars in Thousands
Property, plant and equipment, at cost:
Drilling equipment
Rental tools
Building, land and improvements
Other
Construction in progress
Total property, plant and equipment, at cost
Less: Accumulated depreciation and amortization
Property, plant, and equipment, net
December 31,
2018
2017
$
$
720,037 $
581,107
58,193
115,977
10,855
1,486,169
951,798
534,371 $
1,228,443
552,461
60,309
115,910
11,753
1,968,876
1,343,105
625,771
Depreciation expense was $105.2 million, $119.6 million and $136.3 million for the years ended December 31, 2018, 2017, and
2016, respectively.
Loss on impairment
During the third quarter of 2018, we noted that historically, our barge rig utilization has trended closely with oil prices in periods
of both decline and recovery. Management determined the divergence between oil prices and utilization for our Gulf of Mexico inland
barge and International barge asset groups necessitated performance of a recoverability analysis for these two asset groups. Average
quarterly oil prices have increased sequentially beginning in the third quarter of 2017, reaching an average quarterly 3-year high in the third
quarter of 2018, while our utilization remained flat for the nine months ending September 30, 2018 as compared to the year ended
December 31, 2018.
Based upon our recoverability analysis, where the carrying values exceeded both estimated future undiscounted cash flows and a
subsequent aggregate fair value determination based upon a cost approach method, we determined the Gulf of Mexico inland barge and
International barge asset groups were impaired. The significant unobservable inputs to the cost approach method included replacement
costs and remaining economic life. See also Note 7 - Fair Value Measurements.
We estimated the fair values to be $19.7 million and $3.4 million for the Gulf of Mexico inland barge asset group and the
International barge asset group, respectively. We recognized a pretax impairment loss of approximately $44.0 million in total, or $34.2
million and $9.8 million for the Gulf of Mexico inland barge asset group and the International barge asset group, respectively, for the year
ended December 31, 2018. The Gulf of Mexico inland barge asset group is reported as part of the U.S. (Lower 48) Drilling segment and the
International barge asset group is reported as part of the International & Alaska Drilling segment.
Provision for reduction in carrying value of certain assets
No provision for reduction in carrying value was identified during the year ended year ended December 31, 2018. We recorded a
provision of $1.9 million for reduction in carrying value of assets for the year ended December 31, 2017. This provision was related to
certain assets in the International & Alaska Drilling segment that were deemed to be excess and functionally obsolete unless significant
costs were incurred to refurbish them.
Gain (loss) on disposition of assets
During the normal course of operations, we periodically sell equipment deemed excess, obsolete, or not currently required for
operations. Net losses recorded on asset disposition 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. Activity in both periods included equipment retirements.
72
Table of contents
Note 4 - Goodwill and Intangible Assets
We perform our annual goodwill impairment review during the fourth quarter, as of October 1, and more frequently if negative
conditions or other triggering events arise that indicate that the fair value of the reporting unit has decreased below its carrying value. As a
result of our 2018 annual goodwill impairment analysis, we determined that the carrying value of the 2MTek reporting unit exceeded its
fair value and, therefore, the entire goodwill balance was impaired and written off. The impairment resulted due to the transfer of 2MTek
reporting unit from International Rental Tools segment to the U.S. Rental Tools segment. Goodwill impairment is recorded in the loss on
impairment line item in the consolidated statement of operations for the year ended December 31, 2018.
All of the Company’s goodwill and intangible assets are allocated to the U.S. Rental Tools segment.
Goodwill
The change in the carrying amount of goodwill for the year ended December 31, 2018 is as follows:
Dollars in thousands
Balance at December 31, 2017
Goodwill impairment
Balance at December 31, 2018
Goodwill
6,708
(6,708 )
—
$
$
Of the total amount of goodwill recognized, zero is expected to be deductible for income tax purposes.
Intangible Assets
Intangible Assets consist of the following:
Dollars in thousands
Developed technology
Trade Names
Total intangible assets
Balance at December 31, 2018
Estimated Useful
Life (Years)
6
5
Gross Carrying
Amount
Write-off Due to
Sale
Accumulated
Amortization
Net Carrying
Amount
$
$
11,630 $
4,940
16,570 $
— $
(332)
(332) $
(7,269) $
(4,148)
(11,417) $
4,361
460
4,821
Amortization expense was $2.3 million, $2.8 million, and $3.5 million for the year ended December 31, 2018, 2017, and 2016
respectively.
Our remaining intangibles amortization expense for the next five years is presented below:
Dollars in thousands
2019
2020
2021
2022
Beyond 2022
73
Expected future
intangible
amortization
expense
$
$
$
$
$
2,306
2,030
485
—
—
Table of contents
Note 5 - Supplementary Accrued Liabilities Information
The significant components of accrued liabilities on our consolidated balance sheets as of December 31, 2018 and 2017 are
presented below:
Dollars in Thousands
Accrued liabilities:
Accrued payroll & related benefits
Accrued interest expense
Accrued professional fees & other
Deferred mobilization fees
Workers’ compensation liabilities, net
Total accrued liabilities
74
Year Ended December 31,
2018
2017
$
$
20,736 $
32
9,578
4,082
957
35,385 $
27,252
18,169
7,888
3,149
1,265
57,723
Table of contents
Note 6 - Debt
The following table illustrates the Company’s debt portfolio as of December 31, 2018 and December 31, 2017:
Dollars in thousands
6.75% Senior Notes, due July 2022
7.50% Senior Notes, due August 2020
Total principal
Less: unamortized debt issuance costs
Total debt
6.75% Senior Notes, due July 2022
December 31,
2018
360,000 $
225,000
585,000
—
585,000 $
2017
360,000
225,000
585,000
(7,029)
577,971
$
$
On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Notes pursuant to an Indenture between the
Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the “ 6.75% Notes Indenture”). The 6.75% Notes are
general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured
indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteed indebtedness under the
Second Amended and Restated Senior Secured Credit Agreement, as amended from time-to-time (“2015 Secured Credit Agreement”) and
our 7.50% Senior Notes, due 2020 (“7.50% Notes”, and collectively with the 6.75% Notes, the “Senior Notes”). Interest on the 6.75%
Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes were
approximately $7.6 million. Unamortized debt issuance costs were $3.8 million prior to the commencement of the Chapter 11 Cases. After
the commencement of the Chapter 11 Cases, the carrying amount of debt was adjusted to the claim amount and all unamortized debt
issuance costs prior to the commencement of the Chapter 11 Cases were fully expensed.
We may redeem all or a part of the 6.75% Notes upon appropriate notice at redemption prices decreasing each year after January
15, 2018 to par beginning January 15, 2020. As of December 31, 2018, the redemption price is 103.4 percent and we have not made any
redemptions to date. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent of the
aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The 6.75% Notes Indenture limits our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make
other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or
guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions, (vii) incur dividend or other
payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x)
engage in certain business activities. Additionally, the 6.75% Notes Indenture contains certain restrictive covenants designating certain
events as events of default. These covenants are subject to a number of important exceptions and qualifications.
7.50% Senior Notes, due August 2020
On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the
Company and The Bank of New York Mellon Trust Company, N.A., as trustee (the “ 7.50% Notes Indenture”). The 7.50% Notes are
general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured
indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteed indebtedness under the 2015
Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year,
beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes were approximately $5.6 million. Unamortized debt issuance
costs were $1.6 million prior to the commencement of the Chapter 11 Cases. After the commencement of the Chapter 11 Cases, the
carrying amount of debt was adjusted to the claim amount and all unamortized debt issuance costs prior to the commencement of the
Chapter 11 Cases were fully expensed.
Beginning August 1, 2018, we may redeem all or a part of the 7.50% Notes upon appropriate notice at par. We have not made any
redemptions to date. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the
aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The 7.50% Notes Indenture limits our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make
other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or
guarantee additional indebtedness, (v) create or incur liens, (vi) enter into sale and leaseback transactions,
75
Table of contents
(vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into
transactions with affiliates, and (x) engage in certain business activities. Additionally, the 7.50% Notes Indenture contains certain
restrictive covenants designating certain events as events of default. These covenants are subject to a number of important exceptions and
qualifications.
The commencement of the Chapter 11 Cases constituted an event of default that accelerated the Company’s obligations under the
indenture governing the 6.75% Notes and the 7.50% Notes. However, any efforts to enforce such payment obligations are automatically
stayed under the provisions of the Bankruptcy Code. The principal balance on the 6.75% Notes and 7.50% Notes of $360.0 million and
$225.0 million has been reclassed from long-term debt to liabilities subject to compromise as of December 31, 2018. See also Note 2 -
Chapter 11 Cases for further details.
2015 Secured Credit Agreement
On January 26, 2015 we entered into the 2015 Secured Credit Agreement. The 2015 Secured Credit Agreement was originally
comprised of a $200.0 million revolving credit facility (the “Revolver”). The 2015 Secured Credit Agreement formerly included financial
maintenance covenants, including a leverage ratio, consolidated interest coverage ratio, senior secured leverage ratio, and asset coverage
ratio, many of which were suspended beginning in September 2015. We executed various amendments prior to February 14, 2018, which
reduced the size of the Revolver from $200.0 million to $100.0 million.
On February 14, 2018, we executed the Fifth Amendment to the 2015 Secured Credit Agreement (the “Fifth Amendment”) which
modified the credit facility to an asset-based lending structure and reduced the size of the Revolver from $100.0 million to $80.0
million. The Fifth Amendment eliminated the financial maintenance covenants previously in effect and replaced them with a liquidity
covenant of $30.0 million and a monthly borrowing base calculation based on eligible rental equipment and eligible domestic accounts
receivable. The liquidity covenant required the Company to maintain a minimum of $30.0 million of liquidity (defined as availability under
the borrowing base and cash on hand), of which $15.0 million was restricted, resulting in a maximum availability at any one time of the
lesser of (a) an amount equal to our borrowing base minus $15.0 million, or (b) $65.0 million. Our ability to borrow under the 2015
Secured Credit Agreement was determined by reference to our borrowing base. The Fifth Amendment also allowed for refinancing our
existing Senior Notes with either secured or unsecured debt, added the ability for the Company to designate certain of its subsidiaries as
“Designated Borrowers” and removed our ability to make certain restricted payments.
On July 12, 2018, we executed the Sixth Amendment to the 2015 Secured Credit Agreement (the “Sixth Amendment”) which
permitted the Company to make Restricted Payments (as defined in the 2015 Secured Credit Agreement) in the form of certain Equity
Interests (as defined in the 2015 Secured Credit Agreement).
On October 25, 2018, we entered into a Consent Agreement and a Cash Collateral Agreement, whereby we could open bank
accounts not subject to the 2015 Secured Credit Agreement for the purpose of depositing cash to secure certain Letters of Credit. On
October 30, 2018, we deposited $10.0 million into a cash collateral account to support the letters of credit outstanding, which is included in
the restricted cash balance on the consolidated balance sheet.
Our obligations under the 2015 Secured Credit Agreement were guaranteed by substantially all of our direct and indirect domestic
subsidiaries, other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which has
executed guaranty agreements, and were secured by first priority liens on our accounts receivable, specified rigs including barge rigs in the
GOM and land rigs in Alaska, certain U.S.-based rental equipment of the Company and its subsidiary guarantors and the equity interests of
certain of the Company’s subsidiaries. In addition to the liquidity covenant and borrowing base requirements, the 2015 Secured Credit
Agreement contains customary affirmative and negative covenants, such as limitations on indebtedness and liens, and restrictions on entry
into certain affiliate transactions and payments (including certain payments of dividends).
Our Revolver was available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrued at
either:
•
•
Base Rate plus an Applicable Rate
or
LIBOR plus an Applicable
Rate.
All of the Company’s obligations under the 2015 Secured Credit Agreement were paid prior to the commencement of the Chapter
11 Cases, and the 2015 Secured Credit Agreement, including the Revolver thereunder, was terminated concurrently with the
commencement of the Chapter 11 Cases. See also Note 2 - Chapter 11 Cases for further details. Unamortized debt issuance costs of $1.2
million were fully expensed upon termination of the 2015 Secured Credit Agreement.
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Note 7 - Fair Value Measurements
Certain of our assets and liabilities are required to be measured at fair value on a recurring basis. For purposes of recording fair
value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value
at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the
principal market for the asset or liability.
The fair value measurement and disclosure requirements of FASB ASC Topic No. 820 - Fair Value Measurement and Disclosures
requires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows:
•
•
•
Level 1 — Unadjusted quoted prices for identical assets or liabilities in active
markets;
Level 2 — Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in
active markets or identical assets or liabilities in less active markets; and
Level 3 — Unobservable inputs that require significant judgment for which there is little or no market
data.
When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest
level of input that is significant to the entire measurement even though we may also have utilized significant inputs that are more readily
observable. The amounts reported in our consolidated condensed balance sheets for cash and cash equivalents, restricted cash, accounts
receivable, and accounts payable approximate fair value.
Fair value of our debt instruments is determined using Level 2 inputs. Fair values and related carrying values of our debt
instruments were as follows for the periods indicated:
Dollars in thousands
Debt
6.75% Notes
7.50% Notes
Total
December 31, 2018
December 31, 2017
Carrying
Amount
Fair Value
Carrying
Amount
Fair Value
$
$
360,000 $
225,000
585,000 $
180,000 $
117,000
297,000 $
360,000 $
225,000
585,000 $
296,100
206,438
502,538
During the year, Property, Plant and Equipment for the Gulf of Mexico inland barge and International barge asset groups was
impaired and written down to their estimated fair values. The estimated fair value was determined using Level 3 inputs. See Note 3 -
Property, Plant and Equipment for further details.
Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or Level 2 to Level 3. There were no
transfers between levels of the fair value hierarchy or any changes in the valuation techniques used during the year ended December 31,
2018.
Note 8 - Income Taxes
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.
In accordance with the reduction to the U.S. corporate income tax rate from 35.0 percent to 21.0 percent, the Company remeasured
certain U.S. deferred tax assets and liabilities as of December 31, 2017. However, as a result of the Company’s net deferred tax position,
inclusive of valuation allowances, no net income tax expense was recorded related to this remeasurement. The Company did not incur any
income tax expense related to the one-time mandatory tax on previously deferred earnings of certain foreign subsidiaries associated with
the transition from a worldwide to a modified territorial tax regime.
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Table of contents
Income (loss) before income taxes is summarized below:
Dollars in thousands
United States
Foreign
Income (loss) before income taxes
Income tax expense (benefit) is summarized as follows:
Dollars in thousands
Current tax expense
Federal
State
Foreign
Total current tax expense
Deferred tax expense (benefit)
Federal
State
Foreign
Total deferred tax expense (benefit)
Total income tax expense (benefit)
Year Ended December 31,
2018
(145,954) $
(11,947)
2017
(89,233) $
(20,428)
2016
(131,106)
(25,538)
(157,901) $
(109,661) $
(156,644)
Year Ended December 31,
2018
2017
2016
(14) $
229
8,010
8,225 $
— $
—
(429)
(429) $
80 $
54
9,130
9,264 $
167 $
—
(391)
(224) $
(1,921)
(9)
7,038
5,108
64,066
(47)
5,043
69,062
7,796 $
9,040 $
74,170
$
$
$
$
$
$
$
Total income tax expense differs from the amount computed by multiplying income before income taxes by the U.S. federal
income tax statutory rate. The reasons for this difference are as follows:
Dollars in thousands
Computed expected tax expense
Foreign taxes
Tax effect different from statutory rates
State taxes, net of federal benefit
Foreign tax credits
Change in valuation allowance (excluding
impact of Tax Act)
Uncertain tax positions
Permanent differences
Prior year return to provision adjustments
Other
Impact of Tax Act
Effect of tax rate reduction on deferred
tax
Effect of tax rate on deferred tax
valuation
Income tax expense (benefit)
2018
2017
2016
Year Ended December 31,
Amount
$ (33,160)
7,321
(68)
(2,552)
—
28,353
(221)
8,008
50
65
% of Pre-Tax
Income
Amount
% of Pre-Tax
Income
Amount
% of Pre-Tax
Income
21.0 % $ (38,381)
13,084
(4.6)%
(2,048)
— %
35
1.6 %
3
— %
(18.0)%
0.1 %
(5.1)%
— %
0.1 %
30,704
194
2,970
2,442
37
35.0 % $ (54,825)
12,688
(11.9)%
(3,629)
1.9 %
(849)
— %
20
— %
(28.0)%
(0.2)%
(2.7)%
(2.3)%
— %
117,707
(726)
1,442
2,078
264
35.0 %
(8.1)%
2.3 %
0.5 %
— %
(75.1)%
0.5 %
(0.9)%
(1.3)%
(0.2)%
—
— %
45,329
(41.3)%
—
— %
—
7,796
$
— %
(4.9)% $
(45,329)
9,040
41.3 %
(8.2)% $
—
74,170
— %
(47.3)%
78
Table of contents
The components of the Company’s deferred tax assets and liabilities as of December 31, 2018 and 2017 are shown below:
Dollars in thousands
Deferred tax assets
Deferred tax assets:
Federal net operating loss carryforwards
State net operating loss carryforwards
Excess interest
Other state deferred tax asset, net
Foreign tax credits
FIN 48
Foreign tax
Accruals not currently deductible for tax purposes
Deferred compensation
Other
Total deferred tax assets
Valuation allowance
Net deferred tax assets, net of valuation allowance
Deferred tax liabilities:
Deferred tax liabilities:
Property, plant and equipment
Foreign tax local
Other state deferred tax liability, net
Intangibles
Total deferred tax liabilities
Net deferred tax asset
December 31,
2018
2017
109,002 $
13,168
6,230
1,201
46,913
887
40,190
3,119
816
1,297
222,823
(186,267)
36,556 $
95,867
11,089
—
626
46,913
953
36,699
2,926
1,204
74
196,351
(157,914)
38,437
(28,440) $
(510)
(5,096)
(877)
(34,923)
1,633 $
(30,648)
(78)
(5,174)
(1,331)
(37,231)
1,206
$
$
$
$
As part of the process of preparing the consolidated financial statements, the Company is required to determine its provision for
income taxes. This process involves measuring temporary and permanent differences resulting from differing treatment of items for tax and
accounting purposes. These differences and the operating loss and tax credit carryforwards result in deferred tax assets and liabilities. In
assessing the realizability of deferred tax assets, management considers whether it is more likely than not that all or a portion of the
deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable
income of appropriate character in each taxing jurisdiction during the periods in which those temporary differences become deductible.
Management considers the weight of available evidence, both positive and negative, including the scheduled reversal of deferred tax
liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax planning
strategies in making this assessment. To the extent the Company believes that it does not meet the test that recovery is more likely than not,
it establishes a valuation allowance. To the extent that the Company establishes a valuation allowance or changes this allowance in a
period, it adjusts the tax provision or tax benefit in the consolidated statement of operations. We use our judgment in determining
provisions or benefits for income taxes, and any valuation allowance recorded against previously established deferred tax assets. We have
measured the value of our deferred tax assets for the year ended December 31, 2018 based on the cumulative weight of positive and
negative evidence that exists as of the date of the consolidated financial statements. Should the cumulative weight of all available positive
and negative evidence change in the forecast period, the expectation of realization of deferred tax assets existing as of December 31, 2018
and prospectively may change.
The 2018 results include an increase in our valuation allowance of $28.4 million primarily related to U.S. and certain foreign net
operating losses and other deferred tax assets. Valuation allowances are established based on the weight of available evidence, both positive
and negative, including results of recent and current operations and our estimates of future taxable income or loss by jurisdiction in which
we operate. In order to determine the amount of deferred tax assets or liabilities, as well as the valuation allowances, we must make
estimates and assumptions regarding future taxable income, where rigs will be deployed and other business considerations. Changes in
these estimates and assumptions, including changes in tax laws and other changes impacting our ability to recognize the underlying
deferred tax assets, could require us to adjust the valuation allowances.
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Table of contents
The 2017 results include an increase in our valuation allowance of $14.6 million primarily related to U.S. and certain foreign net
operating losses and other deferred tax assets.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
Dollars in thousands
Balance at January 1, 2018
Reductions based on tax positions taken during a prior period
Additions based on tax positions taken during the current period
Balance at December 31, 2018
$
$
(5,395)
190
(523)
(5,728)
In many cases, our uncertain tax positions are related to tax years that remain subject to examination by tax authorities. The
following describes the open tax years, by major tax jurisdiction, as of December 31, 2018:
Kazakhstan
Mexico
Russia
United States — Federal
United Kingdom
2008-present
2014-present
2014-present
2009-present
2015-present
As of December 31, 2018, we had a liability for unrecognized tax benefits of $5.7 million (all of which, if recognized, would
favorably impact our effective tax rate), on which no payments were made during 2018.
The Company recognized interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2018
and December 31, 2017 we had approximately $2.1 million and $2.1 million of accrued interest and penalties related to uncertain tax
positions, respectively. We recognized a $0.1 million increase in interest and $0.1 million decrease in penalties on unrecognized tax
benefits for the year ended December 31, 2018.
As of December 31, 2018, the Company has permanently reinvested accumulated undistributed earnings of foreign subsidiaries
and, therefore, has not recorded a deferred tax liability related to subject earnings. Upon distribution of additional earnings in the form of
dividends or otherwise, we could be subject to income taxes and withholding taxes. It is not practicable to determine precisely the amount
of taxes that may be payable on the eventual remittance of these earnings due to many factors, including application of foreign tax credits,
levels of accumulated earnings and profits at the time of remittance, and the sources of earnings remitted. The Company generally does not
provide for taxes related to its undistributed earnings because such earnings either would not be taxable when remitted or they are
considered to be indefinitely reinvested. Taxes that would be incurred if the undistributed earnings of other subsidiaries were distributed to
their ultimate parent company would not be material.
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Note 9 - Commitments and Contingencies
The Company has various lease agreements for office space, equipment, vehicles and personal property. These obligations extend
through 2025 and are typically non-cancelable. Most leases contain renewal options and certain of the leases contain escalation clauses.
Future minimum lease payments as of December 31, 2018, under operating leases with non-cancelable terms are as follows:
Dollars in Thousands
2019
2020
2021
2022
2023
Thereafter
Total
Year Ended
December 31,
10,722
7,887
4,193
1,968
1,540
636
26,946
$
$
Total rent expense for all operating leases amounted to $21.2 million, $23.8 million and $21.8 million for the years then ended
December 31, 2018, 2017, and 2016, respectively.
Self-Insurance
We are self-insured for certain losses relating to workers’ compensation, employers’ liability, general liability (for onshore
liability), protection and indemnity (for offshore liability) and property damage. Our exposure (that is, the retention or deductible) per
occurrence is $0.3 million for worker’s compensation and employer’s liability, and $0.5 million for general liability, protection and
indemnity and maritime employers’ liability (Jones Act). There is no annual aggregate deductible for protection and indemnity and
maritime employers’ liability claims. We also assume retention for foreign casualty exposures of $0.1 million for workers’ compensation,
employers’ liability, and $1.0 million for general liability losses. We do not have any deductible for auto liability claims. For all primary
insurances mentioned above, the Company has excess coverage for those claims that exceed the retention and annual aggregate deductible.
We maintain actuarially-determined accruals in our consolidated balance sheets to cover the self-insurance retentions.
We have self-insured retentions for certain other losses relating to rig, equipment, property, business interruption and political,
war, and terrorism risks which vary according to the type of rig and line of coverage. Political risk insurance is procured for international
operations. However, this coverage may not adequately protect us against liability from all potential consequences.
As of December 31, 2018 and 2017, our gross self-insurance accruals for workers’ compensation, employers’ liability, general
liability, protection and indemnity and maritime employers’ liability totaled $2.4 million and $3.2 million, respectively and the related
insurance recoveries/receivables were $1.6 million and $1.9 million, respectively.
Other Commitments
We have entered into employment agreements with certain members of management with automatic one year renewal periods at
expiration dates. The agreements provide for, among other things, compensation, benefits and severance payments. The employment
agreements also provide for lump sum compensation and benefits in the event of termination within two years following a change in
control of the Company.
Contingencies
We are a party to various lawsuits and claims arising out of the ordinary course of business. We estimate the range of our liability
related to pending litigation when we believe the amount or range of loss can be estimated. We record our best estimate of a loss when the
loss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we record
the minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potential
liability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits and
claims, the ultimate outcome may differ significantly from our estimates. In the opinion of management and based on liability accruals
provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our
consolidated balance sheet or consolidated statement of cash flows, although they could have a material adverse effect on our consolidated
statement of operations for a particular reporting period.
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Any claims filed, or to be filed in relation to the Chapter 11 Cases, will be investigated and addressed in connection with the
claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as
necessary.
Note 10 - Related Party Transactions
Consulting Agreement
On December 31, 2013, Robert L. Parker, Jr., our former Executive Chairman, retired as an employee of the Company. Mr. Parker
continued to serve as Chairman of the Company’s board of directors until the annual meeting of stockholders held in 2014, at which time
Mr. Parker was elected to the board for a three-year term. In 2017, he was re-elected to another three-year term and Mr. Parker has
continued to serve as a member Chairman of the Company’s board of directors since then. Mr. Parker was paid $0.3 million in 2017 in
exchange for his agreement to provide additional support to the Company when needed in matters where his historical and industry
knowledge, client relationships and related expertise could be of particular benefit to the Company’s interests. No such payments were
made in 2018.
Other Transactions
During 2015 we purchased the legal rights to certain rental tool software from two employees and a relative of the employees. As
part of the purchase, we paid $0.1 million to each employee in January 2017. No such payments were made in 2018.
In 2015, one of our directors acquired $0.6 million aggregate principal amount of our 7.50% Notes and $0.7 million aggregate
principal amount of our 6.75% Notes.
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Note 11 - Stock-Based Compensation
Stock Plan
Stock-based compensation awards were granted to employees under the Company’s 2010 Long-Term Incentive Plan, as amended
and restated as of May 10, 2016 (the “Stock Plan”). The Stock Plan was approved by the stockholders at the Annual Meeting of
Stockholders on May 10, 2016. The Stock Plan authorizes the compensation committee or the board of directors to issue stock options,
stock appreciation rights, restricted stock awards, restricted stock units, performance-based awards, time-based awards, and other types of
awards in cash or stock to key employees, consultants, and directors. The maximum number of shares that may be delivered pursuant to the
awards granted under the Stock Plan is 1,120,000 shares of common stock. As of December 31, 2018 there were 252,072 shares remaining
available under the Stock Plan. See Note 12 - Stockholders' Equity for details regarding the 1-for-15 reverse stock split.
Stock-Based Awards
Stock-based awards generally vest over three years. Stock-based compensation expense is recognized net of an estimated forfeiture
rate, which is based on historical experience and adjusted, if necessary, in subsequent periods based on actual forfeitures. Stock-based
compensation expense and cash compensation paid to the respective employees is included in our consolidated statements of operations in
general and administrative expense. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a
financing cash flow.
In 2018, we issued three types of stock-based awards:
1. Restricted stock units are service-based awards and entitle a grantee to receive a share of common stock on a specified vesting
date. The grant-date fair value of nonvested units is determined based on the closing trading price of the Company’s shares on the
grant date. These awards vest to the extent earned at the end of a three-year performance period. These awards are expensed
ratably over the applicable vesting period and are settled in shares of our common stock upon vesting. These awards are
considered equity awards.
2. Time-based phantom stock units are service-based awards and represent the equivalent of one share of common stock as of the
grant date. The value of these awards is based on the common stock price. These awards vest when earned at the end of the
performance period which is generally 1 to 3 years. These awards are expensed ratably over the applicable vesting period and are
settled in cash upon vesting. These awards are classified as liability awards.
3. Performance-based phantom stock units are performance-based awards and we issued two types of performance-based
awards:
a.
Performance cash units are performance-based awards that contain payout conditions which are based on our performance
against a group of selected peer companies with regard to relative return on capital employed over a three-year
performance period. Each unit has a nominal value of $100.0. A maximum of 200.0 percent of the number of units
granted may be earned if performance at the maximum level is achieved. These awards vest to the extent earned at the
end of a three-year performance period. These awards are expensed ratably over the applicable vesting period and are
settled in cash upon vesting. These awards are classified as liability awards.
b. Performance-based phantom stock units are performance-based awards denominated in a number of shares which contain
payout conditions based on our performance against a group of selected peer companies with regard to relative total
shareholder return over a three-year performance period. They represent a grant of hypothetical stock to the equivalent
number of shares of common stock but, with the employee receiving cash upon vesting. We used a simulation-based
option pricing approach to determine the fair value of these awards. A maximum of 250.0 percent of the number of units
granted may be earned if performance at the maximum level is achieved. These awards vest to the extent earned at the
end of the three-year performance period. These awards are expensed ratably over the applicable vesting period and are
settled in cash upon vesting. These awards are classified as liability awards.
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Restricted Stock Units
The following table presents restricted stock units granted, vested and forfeited during 2018 under the Stock Plan:
Nonvested at January 1, 2018
Granted
Vested
Forfeited
Nonvested at December 31, 2018
Restricted Stock
Units
Weighted
Average
Grant-Date Fair
Value
302,338 $
107,863 $
(156,524) $
(18,079) $
235,598 $
27.10
12.51
29.87
23.82
18.84
In 2018, 2017 and 2016 we issued 107,863 units, 180,728 units, and 219,742 units, respectively, to select key personnel. The per-
share weighted-average grant-date fair value of units granted during 2018, 2017, and 2016 was $12.51, $21.19, and $31.06, respectively.
Total expense recognized relating to these awards for the years ended December 31, 2018, 2017, and 2016 was $2.8 million, $4.0
million, and $7.5 million, respectively, all of which was related to nonvested units. The total fair value of the units vested during the years
ended December 31, 2018, 2017, and 2016 was $4.7 million, $8.6 million, and $10.0 million, respectively.
Nonvested units as of December 31, 2018 totaled 235,598 and total unrecognized compensation cost related to unamortized units
was $1.4 million as of December 31, 2018. The remaining unrecognized compensation cost related to non-vested units will be amortized
over a weighted-average vesting period of approximately 27 months.
Time-based Phantom Stock Units
The following table presents time-based phantom stock units granted, vested, and forfeited during 2018 under the Stock Plan:
Nonvested at January 1, 2018
Granted
Vested
Forfeited
Nonvested at December 31, 2018
Time-based
Phantom Stock
Units
68,759
106,530
(28,387)
(4,117)
142,785
In 2018, 2017 and 2016 we issued 106,530 units, 43,245 units, and 79,248 units, respectively, to select key personnel.
Total expense recognized relating to these awards for the year ended December 31, 2018 was a gain of $0.3 million, and expense
recognized for the years ended 2017 and 2016 was nominal and $1.4 million, respectively.
Performance Cash Units
The following table presents performance cash units granted, vested, and forfeited during 2018 under the Stock Plan:
Nonvested at January 1, 2018
Granted
Vested
Forfeited
Nonvested at December 31, 2018
Performance
Cash Units
23,021
16,149
(10,771)
(791)
27,608
In 2018, 2017, and 2016 we issued 16,149 units, 14,153 units, and 17,091 units, respectively, to select key personnel.
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Total expense recognized relating to these awards for the years ended December 31, 2018, 2017, and 2016 was $0.2 million, $1.0
million, and $2.3 million, respectively.
Performance-based Phantom Stock Units
The following table presents performance-based phantom stock units granted, vested, and forfeited during 2018 under the Stock
Plan:
Nonvested at January 1, 2018
Granted
Vested
Forfeited
Nonvested at December 31, 2018
Performance-
based Phantom
Stock Units
87,395
107,645
(48,937)
(3,778)
142,325
In 2018, 2017, and 2016 we issued 107,645 units, 44,020 units, and 77,652 units, respectively, to select key personnel.
Total expense recognized relating to these awards for the years ended December 31, 2018, 2017, and 2016 was a gain of $0.6
million, gain of $0.9 million, and an expense of $1.3 million, respectively.
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Note 12 - Stockholders' Equity
Stock Issuance
In February 2017, we issued 800,000 shares (on a post-split basis or 12,000,000 shares on pre-split basis) of common stock, par
value $0.16 2/3 per share, at the public offering price of $2.1 per share, and 500,000 shares of the Convertible Preferred Stock, par value
$1.0 per share, with a liquidation preference of $100.0 per share, for total net proceeds of $72.3 million, after underwriting discount and
offering expenses.
Unless converted earlier, each share of our Convertible Preferred Stock will automatically convert into between 2.8 and 3.2 shares
(on a post-split basis) of our common stock (respectively, the “minimum conversion rate” and “maximum conversion rate”), subject to anti-
dilution adjustments. The number of shares of our common stock issuable on conversion will be determined based on the volume weighted-
average price of our common stock over the 20 consecutive trading day period beginning on, and including, the 23rd scheduled trading day
immediately preceding March 31, 2020. Except in limited circumstances, at any time prior to March 31, 2020, a holder may convert
Convertible Preferred Stock into shares of our common stock at the minimum conversion rate of 2.8 shares (on a post-split basis) of
common stock per share of Convertible Preferred Stock, subject to anti-dilution adjustments.
Dividends
The dividends on our Convertible Preferred Stock are payable on a cumulative basis when, as and if declared by our board of
directors, or an authorized committee of our board of directors, at an annual rate of 7.25 percent of the liquidation preference of $100.0 per
share. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock, or in any combination of
cash and shares of our common stock on March 31, June 30, September 30 and December 31 of each year, commencing on June 30, 2017
and ending on, and including, March 31, 2020.
On February 28, 2018, the Company declared a cash dividend of $1.8125 per share of our Convertible Preferred Stock for the
period beginning on December 31, 2017 and ending on March 30, 2018, which was paid on April 2, 2018 to holders of record of the
Convertible Preferred Stock as of March 15, 2018. On May 10, 2018, the Company declared a cash dividend of $1.8125 per share of our
Convertible Preferred Stock for the period beginning on March 31, 2018 and ending on June 29, 2018, which was paid on July 2, 2018 to
holders of record of the Convertible Preferred Stock as of June 15, 2018. On August 23, 2018, the Company declared a cash dividend of
$1.8125 per share of our Convertible Preferred Stock for the period beginning on June 30, 2018 and ending on September 29, 2018, which
was paid on September 28, 2018 to holders of record of the Convertible Preferred Stock as of September 15, 2018. We have not declared or
made any cash dividend payments on the Convertible Preferred Stock since the commencement of the Chapter 11 Cases.
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 $1.0 per share, at a purchase price of $52.5 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 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
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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.
Reverse Stock Split
On July 27, 2018, the Company’s 1-for- 15 reverse stock split of its common stock became effective. Unless otherwise indicated,
all common share and per common share data have been retroactively restated for all periods presented. The reverse stock split did not
affect the par value of the common stock. Shareholders who otherwise would have been entitled to receive a fractional share of common
stock as a result of the reverse stock split received cash in lieu of such fractional share. The Company’s Convertible Preferred Stock was
not subject to the reverse stock split as proportionate adjustments were made to the minimum and maximum conversion rates of the
Convertible Preferred Stock.
Note 13 - Earnings (Loss) Per Share (EPS)
Basic earnings (loss) per share is computed by dividing net income (loss) available to common stockholders by the weighted
average number of common shares outstanding during the period. The effects of dilutive securities, unvested restricted stock, convertible
debt and equity are included in the diluted EPS calculation, when applicable. Note 12 - Stockholders' Equity for details regarding the 1-
for-15 reverse stock split.
The following table represents the computation of earnings per share for the twelve months ended December 31, 2018, 2017, and
2016 respectively:
Dollars in thousands, except per share amounts
Basic EPS
Numerator
Net income (loss) available to common stockholders (numerator)
Denominator
Weighted average shares outstanding
Number of shares used for basic EPS computation
Basic earnings (loss) per common share
Dollars in thousands, except per share amounts
Diluted EPS
Numerator
Net income (loss) available to common stockholders (numerator)
Denominator
Number of shares used for basic EPS computation
Restricted stock units (1)
Convertible preferred stock (2)
Number of shares used for diluted EPS computation
Year ended December 31,
2018
2017
2016
$
(168,416) $
(121,752) $
(230,814)
9,311,722
9,311,722
9,084,456
9,084,456
$
(18.09) $
(13.40) $
8,275,334
8,275,334
(27.89)
Year ended December 31,
2018
2017
2016
$
(168,416) $
(121,752) $
(230,814)
9,311,722
—
—
9,311,722
9,084,456
—
—
9,084,456
8,275,334
—
—
8,275,334
(27.89)
Diluted earnings (loss) per common share
$
(18.09) $
(13.40) $
(1) For each of the years ended December 31, 2018, 2017, and 2016, all common shares potentially issuable in connection with
outstanding restricted stock unit awards have been excluded from the calculation of diluted EPS as the Company incurred losses
during the periods, therefore, inclusion of such potential common shares would be anti-dilutive.
(2) Weighted average common shares issuable upon the assumed conversion of our Convertible Preferred Stock totaling 1,587,300
shares (on a post-split basis) were excluded from the computation of diluted EPS as such shares would be anti-dilutive.
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Note 14 - Revenue from Contracts with Customers
We adopted the Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) effective
January 1, 2018, using the modified retrospective implementation method. Accordingly, we have applied the five-step method outlined in
Topic 606 for determining when and how revenue is recognized to all contracts that were not completed as of the date of adoption.
Revenues for reporting periods beginning as of January 1, 2018 are presented under Topic 606, while prior period amounts have not been
adjusted and continue to be reported under the previous revenue recognition guidance. For contracts that were modified before the effective
date, we have considered the modification guidance within the new standard and determined that the revenue recognized and contract
balances recorded prior to adoption for such contracts were not impacted. While Topic 606 requires additional disclosure of the nature,
amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact
on the measurement or recognition of our revenues. As part of the adoption, no adjustments were needed to the consolidated balance
sheets, statements of operations and statements of cash flows.
Our business is comprised of two business lines: (1) Drilling Services and (2) Rental Tools Services. See Note 16 - Reportable Segments
for further details on these business lines and revenue disaggregation amounts.
Our drilling and rental tools services provided under each contract is a single performance obligation satisfied over time and
comprised of a series of distinct time increments, or service periods. Total revenue is determined for each individual contract by estimating
both fixed and variable consideration expected to be earned over the contract term. Fixed consideration generally relates to activities that
are not distinct within the context of our contracts and is recognized on a straight-line basis over the contract term. Variable consideration
generally relates to distinct service periods during the contract term and are recognized in the period when the services are performed. Our
contract terms generally range from 2 to 60 months.
The amount estimated for variable consideration may be constrained (reduced) and is only recognized as revenue to the extent that
it is probable that a significant reversal of previously recognized revenue will not occur during the contract term. When determining if
variable consideration should be constrained, management considers whether there are factors outside the Company’s control that could
result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are re-
assessed each reporting period as required. Accounts receivable are recognized when the right to consideration becomes unconditional
based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days.
Drilling Services Business
Dayrate Revenues
Our drilling services contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling
unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed
to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis.
Such dayrate consideration is allocated to the distinct hourly increment to which it relates within the contract term, and therefore,
recognized in line with the contractual rate billed for the services provided for any given hour.
Mobilization Revenues
We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization of our rigs.
These activities are not considered to be distinct within the context of the contract and therefore, the associated revenues are
allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a
contract liability for mobilization fees received, which is amortized ratably to revenue as services are rendered over the initial term of the
related drilling contract. The amortized amount is adjusted accordingly if the term of the initial contract is extended.
Capital Modification Revenues
We may, from time to time, receive fees from our customers for capital improvements to our rigs to meet contractual requirements
(on either a fixed lump-sum or variable dayrate basis).
Such revenues are allocated to the overall performance obligation and recognized ratably over the initial term of the related
drilling contract as these activities are not considered to be distinct within the context of our contracts. We record a contract liability for
such fees and recognize them ratably as revenue over the initial term of the related drilling contract.
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Demobilization Revenues
We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the demobilization of our rigs.
Due to the inherent uncertainty regarding the realization, we have elected to not recognize demobilization revenues until the
uncertainty is resolved. Therefore, demobilization revenues are recognized once the related performance obligations have been completed.
Reimbursable Revenues
We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other
services provided at their request in accordance with a drilling contract or other agreement.
Such reimbursable revenues are variable and subject to uncertainty, as the amounts received and timing thereof is highly
dependent on factors outside of our control. Accordingly, reimbursable revenues are not included in the total transaction price until the
uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a
principal in such transactions and record the associated revenues at the gross amount billed to the customer in our consolidated statements
of operations. Such amounts are recognized once the services have been performed. Such amounts totaled $54.6 million, $57.8 million and
$69.3 million for the year ended December 31, 2018, 2017 and 2016 respectively.
Rental Tools Services Business
Dayrate Revenues
Our rental tools services contracts generally provide for payment on a dayrate basis depending on the rate for the tool defined in
the contract.
Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore,
recognized in line with the contractual rate billed for the services provided for any given hour.
Contract Costs
The following is a description of the different costs that we may incur for our contracts:
Mobilization Costs
These costs include certain direct and incremental costs incurred for mobilization of contracted rigs. These costs relate directly to
a contract, enhance resources of the Company that will be used in satisfying its performance obligations in the future and are expected to be
recovered. These costs are capitalized when incurred as a current or non-current asset (depending on the length of the initial contract term),
and are amortized over the initial term of the related drilling contract. Current and non-current capitalized mobilization costs are included
in other current assets and other non-current assets, respectively, on our consolidated balance sheet.
The balance for capitalized mobilization costs was $5.3 million and $3.1 million as of December 31, 2018 and December 31,
2017, respectively. There was no impairment loss in relation to capitalized costs. Amortization of capitalized mobilization costs was $6.7
million and $1.2 million for the year ended December 31, 2018 and 2017, respectively.
Demobilization Costs
These costs are incurred for the demobilization of rigs at contract completion and are recognized as incurred during the
demobilization process.
Capital Modification Costs
These costs are incurred for rig modifications or upgrades required for a contract, which are considered to be capital
improvements, are capitalized as property, plant and equipment and depreciated over the estimated useful life of the improvement.
Contract Liabilities
The following table provides information about contract liabilities from contracts with customers:
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Dollars in thousands
Contract liabilities - current (Deferred revenue) (1)
Contract liabilities - non-current (Deferred revenue) (1)
Total contract liabilities
December 31, 2018 December 31, 2017
1,581
$
1,568
3,149
4,081 $
2,441
6,522 $
$
(1) Contract liabilities - current and contract liabilities - non-current are included in accounts payable and accrued liabilities and other
long-term liabilities respectively, in our consolidated condensed balance sheet as of December 31, 2018 and December 31, 2017.
Contract liabilities relate to mobilization revenues and capital modification revenues, where, we have unconditional right to cash
or cash has been received but performance obligations have not been fulfilled. These liabilities are reduced and revenue is recognized as
performance obligations are fulfilled.
Significant changes to contract liabilities balances during the year ended December 31, 2018 are shown below:
Dollars in thousands
Balance at December 31, 2017
Decrease due to recognition of revenue
Increase to deferred revenue during current period
Balance at December 31, 2018
Contract
Liabilities
$
$
(3,149)
4,879
(8,252)
(6,522)
Transaction price allocated to the remaining performance obligations
The following table includes deferred revenue expected to be recognized in the future related to performance obligations that are
unsatisfied (or partially unsatisfied) at the end of the reporting period.
Dollars in thousands
Deferred revenue
2019
2020
2021
Beyond 2022
Total
$
4,071 $
898 $
872 $
681 $
6,522
Balance at December 31, 2018
The revenues included above consist of mobilization and capital modification revenues for both wholly and partially unsatisfied
performance obligations, which have been estimated for purposes of allocating across the entire corresponding performance obligations.
The amounts are derived from the specific terms within contracts that contain such provisions, and the expected timing for recognition of
such revenue is based on the estimated start date and duration of each respective contract based on information known at December 31,
2018. The actual timing of recognition of such amounts may vary due to factors outside of our control. We have applied the disclosure
practical expedient in FASB ASC Topic No. 606-10-50-14A(b) and have not included estimated variable consideration related to wholly
unsatisfied performance obligations or to distinct future time increments within our contracts.
Note 15 - Employee Benefit Plan
The Company sponsors a defined contribution 401(k) plan (the “401(k) Plan”) in which substantially all U.S. employees are
eligible to participate. The Company match was suspended in May 2016 and resumed in May 2017. During 2018 and 2017 the Company
matched 25.0 percent of each participant’s pre-tax contributions in an amount not exceeding 6.0 percent of the participant’s compensation,
up to the maximum amount of contributions allowed by law. The costs of matching contributions to the 401(k) Plan were $0.6 million, $0.7
million and $1.1 million in 2018, 2017 and 2016, respectively. 401(k) Plan participants hired prior to July 2017 become 100.0 percent
vested immediately in the Company’s matching contributions, and 401(k) Plan participants hired after July 2017 become vested on a pro-
rata basis over three years.
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Note 16 - Reportable Segments
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.
Within the four reportable segments, we have aggregated our Arctic, Eastern Hemisphere, and Latin America business units under
International & Alaska Drilling, one business unit under U.S. (Lower 48) Drilling, one business unit under U.S. Rental Tools, and one
business unit under International Rental Tools, for a total of six business units. The Company has aggregated each of its business units in
one of the four reporting segments based on the guidelines of the FASB ASC Topic No. 280 - Segment Reporting. We eliminate inter-
segment revenues and expenses. We disclose revenues under the four reportable segments based on the similarity of the use and markets
for the groups of products and services within each segment.
Drilling Services Business
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;
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,
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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.
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The following table represents the results of operations by reportable segment:
Dollars in thousands
Revenues: (1)
U.S. (Lower 48) Drilling
International & Alaska Drilling
Total Drilling Services
U.S. Rental Tools
International Rental Tools
Total Rental Tools Services
Total revenues
Operating gross margin: (2)
U.S. (Lower 48) Drilling
International & Alaska Drilling
Total Drilling Services
U.S. Rental Tools
International Rental Tools
Total Rental Tools Services
Total operating gross margin (loss)
General and administrative expense
Loss on impairment
Provision for reduction in carrying value of certain assets
Gain (loss) on disposition of assets, net
Pre-petition restructuring charges
Reorganization items
Total operating income (loss)
Interest expense
Interest income
Other
Income (loss) before income taxes
Year Ended December 31,
2018
2017
2016
11,729 $
213,411
225,140
176,531
79,150
255,681
480,821 $
(15,720) $
(21,936)
(37,656)
44,512
(11,684)
32,828
(4,828)
(24,545)
(50,698)
—
(1,724)
(21,820)
(9,789)
(113,404)
(42,565)
91
(2,023)
(157,901) $
12,389 $
247,254
259,643
121,937
60,940
182,877
442,520 $
(20,656) $
(6,248)
(26,904)
15,651
(24,087)
(8,436)
(35,340)
(25,676)
—
(1,938)
(2,851)
—
—
(65,805)
(44,226)
244
126
(109,661) $
5,429
287,332
292,761
71,613
62,630
134,243
427,004
(34,353)
9,272
(25,081)
(22,372)
(27,859)
(50,231)
(75,312)
(34,332)
—
—
(1,613)
—
—
(111,257)
(45,812)
58
367
(156,644)
$
$
$
$
(1) For the years ended December 31, 2018, 2017, and 2016, our largest customer, ENL, constituted approximately 25.7 percent, 31.3
percent, and 38.7 percent, respectively, of our total consolidated revenues and approximately 58 percent, 55.9 percent, and 57.5
percent, respectively, of our International & Alaska Drilling segment revenues.
Excluding reimbursable revenues of $47.2 million, $50.8 million, and $67.0 million, ENL constituted approximately 17.9 percent,
22.7 percent, and 27.5 percent, respectively, of our total consolidated revenues and approximately 48.0 percent, 46.1 percent, and
45.0 percent, respectively of our International & Alaska Drilling segment revenues.
(2) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization
expense.
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Other business segment information
The following table represents capital expenditures and depreciation and amortization by reportable segment:
Dollars in thousands
Capital expenditures:
U.S. (Lower 48) Drilling
International & Alaska Drilling
U.S. Rental Tools
International Rental Tools
Corporate
Total capital expenditures
Depreciation and amortization: (1)
U.S. (Lower 48) Drilling
International & Alaska Drilling
U.S. Rental Tools
International Rental Tools
Total depreciation and amortization
Year Ended December 31,
2018
2017
2016
444 $
7,444
55,545
6,275
859
70,567 $
230 $
3,673
39,948
8,584
2,098
54,533 $
264
5,258
10,848
9,725
2,859
28,954
7,758 $
36,072
48,167
15,548
107,545 $
13,521 $
46,950
43,489
18,413
122,373 $
20,049
55,236
43,769
20,741
139,795
$
$
$
$
(1) For presentation purposes, for the years then ended December 31, 2018, 2017 and 2016 depreciation for corporate assets of $8.4
million, $8.7 million, and $8.3 million, respectively, has been allocated to the corresponding reportable segments.
The following table represents identifiable assets by reportable segment:
Dollars in Thousands
U.S. (Lower 48) Drilling
International & Alaska Drilling
U.S. Rental Tools
International Rental Tools
Total identifiable assets
Corporate
Total assets
94
Year Ended December 31,
2018
2017
30,283 $
366,856
216,123
146,471
759,733
68,681
828,414 $
62,980
421,753
198,664
168,511
851,908
138,371
990,279
$
$
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Geographic information
The following table represents selected geographic information :
Dollars in Thousands
Revenues:
United States
Russia
EMEA & Asia
Latin America
Other CIS
Other (1)
Total revenues
Long-lived assets: (1)
United States
EMEA & Asia
Latin America
Other CIS
Russia
Total long-lived assets
(1) Long-lived assets consist of property, plant and equipment,
net.
95
Year Ended December 31,
2018
2017
2016
127,596
142,538
79,870
12,952
33,659
30,389
427,004
$
$
$
$
207,612 $
123,767
92,568
14,631
13,703
28,540
480,821 $
369,106 $
89,696
36,656
21,949
16,964
534,371 $
177,630 $
139,144
64,572
11,594
23,768
25,812
442,520 $
429,374
108,621
38,959
29,402
19,415
625,771
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Note 17 - Selected Quarterly Financial Data (Unaudited)
Year Dollars in thousands, except per share data
Revenues
Operating gross margin (loss)
Operating income (loss)
Net income (loss)
Net income (loss) available to common stockholders
Basic earnings (loss) per common share (1) (2)
Diluted earnings (loss) per common share (1) (2)
Year Dollars in thousands, except per share data
Revenues
Operating gross margin (loss)
Operating income (loss)
Net income (loss)
Net income (loss) available to common stockholders
Basic earnings (loss) per common share (1) (2)
Diluted earnings (loss) per common share (1) (2)
First
Quarter
Second
Quarter
2018
Third
Quarter
109,675 $
(10,408) $
(16,266) $
(28,796) $
(29,702) $
(3.21) $
(3.21) $
118,603 $
(167) $
(8,933) $
(22,877) $
(23,784) $
(2.56) $
(2.56) $
123,395 $
1,932 $
(56,544) $
(70,951) $
(71,857) $
(7.70) $
(7.70) $
First
Quarter
Second
Quarter
2017
Third
Quarter
98,271 $
(19,745) $
(27,137) $
(39,809) $
(39,809) $
(4.59) $
(4.59) $
109,607 $
(11,016) $
(17,632) $
(29,888) $
(31,127) $
(3.39) $
(3.39) $
118,308 $
121 $
(6,815) $
(20,311) $
(21,217) $
(2.30) $
(2.30) $
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Fourth
Quarter
129,148 $
3,815 $
(31,661) $
(43,073) $
(43,073) $
(4.60) $
(4.60) $
Fourth
Quarter
116,334 $
(4,700) $
(14,221) $
(28,693) $
(29,599) $
(3.20) $
(3.20) $
Total
480,821
(4,828)
(113,404)
(165,697)
(168,416)
(18.09)
(18.09)
Total
442,520
(35,340)
(65,805)
(118,701)
(121,752)
(13.40)
(13.40)
(1) As a result of shares issued during the year, earnings (loss) per share for each of the year’s four quarters, which are based on
weighted average shares outstanding during each quarter, may not equal the annual earnings (loss) per share, which is based
on the weighted average shares outstanding during the year. Additionally, as a result of rounding to the thousands, earnings
per share may not equal the year-to-date results.
(2) See Note 12 - Stockholders' Equity for details regarding the 1-for-15 reverse stock
split.
Note 18 - Recent Accounting Pronouncements
Standards recently adopted
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the
revenue recognition requirements in FASB ASC Topic No. 605 - Revenue Recognition and most industry-specific guidance throughout the
Codification. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an
amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Effective
January 1, 2018, we adopted ASU 2014-09 using the modified retrospective approach and it did not have a material impact on our
consolidated balance sheets, statement of operations, and statements of cash flows. See Note 14 - Revenue from Contracts with Customers
for further details.
Standards not yet adopted
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This ASU requires (a) an entity to separate the lease
components from the non-lease components in a contract where the lease component will be accounted for under ASU 2016-02 and the
non-lease component will be accounted for under ASU 2014-09, (b) recognition of lease assets and lease liabilities by lessees and
derecognition of the leased asset and recognition of a net investment in the lease by the lessor and (c) additional disclosure requirements for
both lessees and lessors. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within
those fiscal years, although early adoption is permitted. Under the updated accounting standard, we have determined that our drilling
contracts contain a lease component. In July 2018, the FASB issued ASU 2018-11 which 1) provides for a new transition method whereby
entities may elect to adopt the update using a prospective with cumulative catch-up approach and 2) provides lessors with an option to not
separate non-lease components from the associated lease components when certain criteria are met and requires them to account for the
combined component in accordance with the new revenue standard if the associated non-lease components are the predominant
components. We adopted ASU 2016-02 on January 1, 2019 using modified retrospective transition method applied at the beginning of the
period of adoption. We have elected certain available practical expedients. Our adoption, and the ultimate effect on our consolidated
financial statements, will be based on an evaluation
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of the contract-specific facts and circumstances, and such effect could introduce variability to the timing of our revenue recognition relative
to current accounting standards. We are evaluating the requirements to determine the effect such requirements may have on our
consolidated balance sheets, statements of operations, statements of cash flows and on the disclosures contained in our notes to the
consolidated financial statements upon the adoption of ASU 2016-02. While, the Company continues to evaluate all of the effects of the
adoption of this ASU, the Company believes the most significant effects relate to (i) the recognition of new right-of-use assets and lease
liabilities on the condensed consolidated balance sheet for the Company’s operating leases and (ii) providing significant new disclosures
about the Company’s leasing activities. Depending on the results of the evaluation, our ultimate conclusions may vary. With respect to
leases whereby we are the lessee, we expect to recognize lease liabilities and offsetting right of use assets of between $15 million and $25
million. However, we are still finalizing our evaluation of the overall impact.
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Note 19 - Parent, Guarantor, Non-Guarantor Unaudited Consolidating Financial Statements (Unaudited)
Set forth on the following pages are the consolidating condensed financial statements of Parker Drilling. The Company’s 2015
Secured Credit Agreement and Senior Notes are fully and unconditionally guaranteed by substantially all of our direct and indirect
domestic subsidiaries other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, subject
to the following customary release provisions:
•
•
•
•
•
in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of
merger or consolidation) to a person that is not (either before or after giving effect to such transaction) a subsidiary of the
Company;
in connection with any sale of such amount of capital stock as would result in such guarantor no longer being a subsidiary to a
person that is not (either before or after giving effect to such transaction) a subsidiary of the Company;
if the Company designates any restricted subsidiary that is a guarantor as an unrestricted
subsidiary;
if the guarantee by a guarantor of all other indebtedness of the Company or any other guarantor is released, terminated or
discharged, except by, or as a result of, payment under such guarantee; or
upon legal defeasance or covenant defeasance (satisfaction and discharge of the
indenture).
There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of
cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate
financial statements for each guarantor company are not provided as the Company complies with the exception to Rule 3-10(f) of
Regulation S-X. All guarantor subsidiaries are owned 100.0 percent by the parent company.
We are providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the
non-guarantor subsidiaries as of December 31, 2018 and December 31, 2017 and for the years ended December 31, 2018, 2017, and 2016.
The consolidating condensed financial statements present investments in both the consolidated and unconsolidated subsidiaries using the
equity method of accounting.
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)
Parent
Guarantor
ASSETS
December 31, 2018
Non-Guarantor
Eliminations
Consolidated
Current assets:
Cash and cash equivalents
Restricted cash
Accounts and notes receivable, net
Rig materials and supplies
Deferred costs
Other tax assets
Other current assets
Total current assets
Property, plant and equipment, net
Intangible assets, net
Rig materials and supplies
Deferred income taxes
Investment in subsidiaries and intercompany
advances
Other non-current assets
Total assets
$
5,905 $
10,389
—
—
—
—
8,088
24,382
(19)
—
—
1,918
9,321 $
—
48,598
1,650
975
—
10,241
70,785
369,529
4,821
7,036
(14,806)
33,376 $
—
87,839
34,002
3,378
2,949
9,600
171,144
164,861
—
5,935
15,031
— $
—
—
593
—
—
—
593
—
—
—
—
2,871,807
(277,183)
2,620,905 $
3,024,736
257,204
3,719,305 $
4,264,747
507,932
(10,161,290)
(480,749)
5,129,650 $ (10,641,446) $
$
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Debtor in possession financing
Accounts payable
Accrued liabilities
Accrued income taxes
Total current liabilities
Other long-term liabilities
Long-term deferred tax liability
Intercompany payables
Total liabilities not subject to compromise
Liabilities subject to compromise
Total stockholder's equity
Total liabilities and stockholders’
equity
$
10,000 $
— $
— $
— $
(200,977)
69,961
88,494
(32,522)
2,867
—
1,918,709
1,889,054
600,996
130,855
222,903
11,934
(67,333)
167,504
4,128
—
1,487,904
1,659,536
—
2,059,769
511,770
76,947
(17,776)
570,941
4,549
510
2,719,884
3,295,884
—
1,833,766
(494,018)
(123,457)
—
(617,475)
—
—
(6,126,497)
(6,743,972)
—
(3,897,474)
$
2,620,905 $
3,719,305 $
5,129,650 $ (10,641,446) $
828,414
99
48,602
10,389
136,437
36,245
4,353
2,949
27,929
266,904
534,371
4,821
12,971
2,143
—
7,204
828,414
10,000
39,678
35,385
3,385
88,448
11,544
510
—
100,502
600,996
126,916
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)
Parent
Guarantor
ASSETS
December 31, 2017
Non-Guarantor
Eliminations
Consolidated
Current assets:
Cash and cash equivalents
Accounts and notes receivable, net
Rig materials and supplies
Deferred costs
Other tax assets
Other current assets
Total current assets
Property, plant and equipment, net
Goodwill
Intangible assets, net
Rig and materials and supplies
Deferred income taxes
Investment in subsidiaries and intercompany
advances
Other non-current assets
Total assets
$
75,342 $
—
—
—
—
—
75,342
(19)
—
—
—
15,144
20,655 $
32,338
(3,025)
17
—
6,345
56,330
429,999
6,708
7,128
7,256
(26,623)
45,552 $
90,173
34,440
3,128
4,889
7,982
186,164
195,791
—
—
11,532
12,763
— $
—
—
—
—
—
—
—
—
—
—
—
2,955,050
(276,375)
2,769,142 $
2,970,220
257,121
3,708,139 $
3,956,747
512,870
(9,882,017)
(480,852)
4,875,867 $ (10,362,869) $
$
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable
Accrued liabilities
Accrued income taxes
Total current liabilities
Long-term debt, net
Other long-term liabilities
Long-term deferred tax liability
Intercompany payables
Total stockholders' equity
$
(137,047) $
85,987
76,883
25,823
577,971
2,867
—
1,865,810
296,671
162,505 $
16,742
(56,870)
122,377
—
5,741
—
1,465,745
2,114,276
510,083 $
78,452
(15,583)
572,952
—
3,825
78
2,430,339
1,868,673
(494,018) $
(123,458)
—
(617,476)
—
—
—
(5,761,894)
(3,983,499)
141,549
122,511
31,415
3,145
4,889
14,327
317,836
625,771
6,708
7,128
18,788
1,284
—
12,764
990,279
41,523
57,723
4,430
103,676
577,971
12,433
78
—
296,121
Total liabilities and stockholders’
equity
$
2,769,142 $
3,708,139 $
4,875,867 $ (10,362,869) $
990,279
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PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
Revenues
Expenses:
Operating expenses
Depreciation and amortization
Total operating gross margin (loss)
General and administrative expense (1)
Loss on impairment
Gain (loss) on disposition of assets, net
Pre-petition restructuring charges
Reorganization items
Total operating income (loss)
Other income (expense):
Interest expense
Interest income
Other
Equity in net earnings of subsidiaries
Total other income (expense)
Income (loss) before income taxes
Income tax expense (benefit):
Current tax expense
Deferred tax expense (benefit)
Total income tax expense (benefit)
Net income (loss)
Less: Convertible preferred stock dividend
Net income (loss) available to common
stockholders
Parent
Guarantor
$
—
$
204,319
Year ended December 31, 2018
Non-Guarantor
327,266
$
$
—
—
—
—
23,568
—
—
(21,820)
(9,789) —
(8,041)
(45,696)
572
—
(87,548)
(132,672)
(140,713)
11,758
13,226
24,984
(165,697)
2,719
115,291
76,353
191,644 —
12,675
(47,819)
(40,917)
(1,347)
—
— —
(77,408)
67
721
6
—
794
(76,614)
(10,241)
(11,865)
(22,106)
(54,508)
—
313,577
31,192
344,769 —
(17,503)
(294)
(9,781)
(377)
—
— —
(27,955)
(9,214)
11,076
(2,029)
—
(167)
(28,122)
6,708
(1,790)
4,918
(33,040)
—
Eliminations
(50,764)
Consolidated
480,821
$
(50,764)
—
(50,764) —
—
—
—
—
—
—
—
12,278
(12,278)
—
87,548
87,548
87,548
—
—
—
87,548
—
378,104
107,545
485,649
(4,828)
(24,545)
(50,698)
(1,724)
(21,820)
(9,789)
(113,404)
(42,565)
91
(2,023)
—
(44,497)
(157,901)
8,225
(429)
7,796
(165,697)
2,719
$
(168,416)
$
(54,508)
$
(33,040)
$
87,548
$
(168,416)
(1)
General and administration expenses for field operations are included in operating expenses.
101
Table of contents
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
Parent
Guarantor
Year ended December 31, 2017
Non-Guarantor
Eliminations
Revenues
Expenses:
Operating expenses
Depreciation and amortization
Total operating gross margin (loss)
General and administrative expense (1)
Loss on impairment
Provision for reduction in carrying value of
certain assets
Gain (loss) on disposition of assets, net
Total operating income (loss)
Other income (expense):
Interest expense
Interest income
Other
Equity in net earnings of subsidiaries
Total other income (expense)
Income (loss) before income taxes
Income tax expense (benefit):
Current tax expense
Deferred tax expense (benefit)
Total income tax expense (benefit)
Net income (loss)
Less: Convertible preferred stock dividend
Net income (loss) available to common
stockholders
$
— $
167,675 $
355,859 $
(81,014) $
Consolidated
442,520
—
—
—
—
(323)
—
—
(323)
(47,135)
831
—
(40,752)
(87,056)
(87,379)
26,537
4,785
31,322
(118,701)
3,051
93,834
81,248
175,082
(7,407)
(24,887)
—
(243)
(32,537)
(220)
744
71
—
595
(31,942)
(22,524)
(7,763)
(30,287)
(1,655)
—
342,667
41,125
383,792
(27,933)
(466)
(1,938)
(2,608)
(32,945)
(7,906)
9,704
55
—
1,853
(31,092)
5,251
2,754
8,005
(39,097)
—
(81,014)
—
(81,014)
—
—
—
—
—
11,035
(11,035)
—
40,752
40,752
40,752
—
—
—
40,752
—
355,487
122,373
477,860
(35,340)
(25,676)
(1,938)
(2,851)
(65,805)
(44,226)
244
126
—
(43,856)
(109,661)
9,264
(224)
9,040
(118,701)
3,051
$
(121,752) $
(1,655) $
(39,097) $
40,752
$
(121,752)
(1)
General and administration expenses for field operations are included in operating expenses.
102
Table of contents
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
Parent
Guarantor
Year ended December 31, 2016
Non-Guarantor
Eliminations
Revenues
Expenses:
Operating expenses
Depreciation and amortization
Total operating gross margin (loss)
General and administrative expense (1)
Gain (loss) on disposition of assets, net
Total operating income (loss)
Other income (expense):
Interest expense
Interest income
Other
Equity in net earnings of subsidiaries
Total other income (expense)
Income (loss) before income taxes
Income tax expense (benefit):
Current tax expense
Deferred tax expense (benefit)
Total income tax expense (benefit)
Net income (loss)
Less: Convertible preferred stock dividend
Net income (loss) available to common
stockholders
$
— $
151,100 $
382,094 $
(106,190) $
Consolidated
427,004
—
—
—
—
(410)
—
(410)
(48,160)
758
—
(94,469)
(141,871)
(142,281)
40,562
47,971
88,533
(230,814)
—
100,751
90,197
190,948
(39,848)
(29,356)
(565)
(69,769)
(642)
695
483
—
536
(69,233)
(35,251)
14,940
(20,311)
(48,922)
—
367,960
49,598
417,558
(35,464)
(4,566)
(1,048)
(41,078)
(6,434)
8,029
(116)
—
1,479
(39,599)
(203)
6,151
5,948
(45,547)
—
(106,190)
—
(106,190)
—
—
—
—
9,424
(9,424)
—
94,469
94,469
94,469
—
—
—
94,469
—
362,521
139,795
502,316
(75,312)
(34,332)
(1,613)
(111,257)
(45,812)
58
367
—
(45,387)
(156,644)
5,108
69,062
74,170
(230,814)
—
$
(230,814) $
(48,922) $
(45,547) $
94,469 $
(230,814)
(1) General and administration expenses for field operations are included in operating
expenses.
103
Table of contents
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
(Unaudited)
Net income (loss)
Other comprehensive income (loss), net of tax:
Currency translation difference on related
borrowings
Currency translation difference on foreign
currency net investments
Total other comprehensive income (loss), net of
tax:
Comprehensive income (loss)
Parent
(165,697) $
$
Year Ended December 31, 2018
Non-Guarantor
Guarantor
Eliminations
Consolidated
(54,508) $
(33,040) $
87,548 $
(165,697)
—
—
—
—
—
—
$
(165,697) $
(54,508) $
(646)
— $
(646)
(2,721)
— $
(2,721)
(3,367)
(36,407) $
—
87,548 $
(3,367)
(169,064)
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
(Unaudited)
Net income (loss)
Other comprehensive income (loss), net of tax:
Currency translation difference on related
borrowings
Currency translation difference on foreign
currency net investments
Total other comprehensive income (loss), net of
tax:
Comprehensive income (loss)
Parent
(118,701) $
$
—
—
—
$
(118,701) $
Year Ended December 31, 2017
Non-Guarantor
Guarantor
Eliminations
Consolidated
(1,655) $
(39,097) $
40,752 $
(118,701)
—
—
643
2,689
—
—
643
2,689
—
(1,655) $
3,332
(35,765) $
—
40,752 $
3,332
(115,369)
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(Dollars in Thousands)
(Unaudited)
Net income (loss)
Other comprehensive gain (loss), net of tax:
Currency translation difference on related
borrowings
Currency translation difference on foreign
currency net investments
Total other comprehensive gain (loss), net of
tax:
Comprehensive income (loss)
Parent
(230,814) $
$
Year ended December 31, 2016
Non-Guarantor
Guarantor
Eliminations
Consolidated
(48,922) $
(45,547) $
94,469 $
(230,814)
—
—
—
—
—
—
$
(230,814) $
(48,922) $
(691)
(4,265)
—
—
(691)
(4,265)
(4,956)
(50,503) $
—
94,469 $
(4,956)
(235,770)
104
Table of contents
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Parent
Guarantor
Eliminations
Consolidated
Year Ended December 31, 2018
Non-Guarantor
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss):
Depreciation and amortization
Gain (loss) on disposition of assets, net
Deferred tax expense (benefit)
Loss on impairment
Reorganization items
Expenses not requiring cash
Equity in net earnings (losses) of
subsidiaries
Change in assets and liabilities:
Accounts and notes receivable
Rig materials and supplies
Other current assets
Other non-current assets
Accounts payable and accrued liabilities
Accrued income taxes
Net cash provided by (used in) operating
activities
Cash flows from investing activities:
Capital expenditures
Proceeds from the sale of assets
Net cash provided by (used in) investing
activities
Cash flows from financing activities:
Proceeds from borrowing under DIP facility
Payment of DIP facility costs
Convertible preferred stock dividend
Payments of debt issuance costs
Shares surrendered in lieu of tax
Intercompany advances, net
Net cash provided by (used in) financing
activities
Net increase (decrease) in cash, cash equivalents
and restricted cash
Cash, cash equivalents and restricted cash at
beginning of period
Cash, cash equivalents and restricted cash at end
of period
$
(165,697) $
(54,508) $
(33,040) $
87,548 $
(165,697)
—
—
13,226
—
7,538
4,526
76,353
1,347
(11,865)
40,917
—
(302)
31,192
377
(1,790)
9,781
—
(8,498)
—
—
—
—
—
—
9,425
107,545
1,724
(429)
50,698
7,538
5,151
87,548
—
—
(87,548)
—
—
—
(8,088)
1,042
(63,054)
11,611
(16,244)
(4,454)
(4,854)
3,315
57,305
(10,415)
1,009
5,296
2,082
8,763
7,207
(2,460)
—
(593)
—
(101)
(10,947)
—
(15,235)
249
(10,860)
13,019
(9,489)
(1,264)
(111,348)
76,595
19,919
(2,216)
(17,050)
—
—
—
10,000
(975)
(3,625)
(1,443)
(251)
48,594
(56,897)
87
(13,670)
1,266
(56,810)
(12,404)
—
—
—
—
—
(31,119)
—
—
—
—
—
(19,691)
—
—
—
—
—
—
—
—
2,216
(70,567)
1,353
(69,214)
10,000
(975)
(3,625)
(1,443)
(251)
—
52,300
(31,119)
(19,691)
2,216
3,706
(59,048)
(11,334)
(12,176)
—
(82,558)
75,342
20,655
45,552
—
141,549
$
16,294 $
9,321 $
33,376 $
— $
58,991
105
Table of contents
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss):
Depreciation and amortization
Gain (loss) on disposition of assets, net
Deferred tax expense (benefit)
Provision for reduction in carrying value of
certain assets
Expenses not requiring cash
Equity in net earnings (losses) of
subsidiaries
Change in assets and liabilities:
Accounts and notes receivable
Rig materials and supplies
Other current assets
Other non-current assets
Accounts payable and accrued liabilities
Accrued income taxes
Net cash provided by (used in) operating
activities
Cash flows from investing activities:
Capital expenditures
Proceeds from the sale of assets
Net cash provided by (used in) investing
activities
Cash flows from financing activities:
Proceeds from the issuance of common stock
Proceeds from the issuance of convertible
preferred stock
Payment of equity issuance costs
Convertible preferred stock dividend
Shares surrendered in lieu of tax
Intercompany advances, net
Net cash provided by (used in) financing
activities
Net increase (decrease) in cash, cash equivalents
and restricted cash
Cash and cash equivalents at beginning of
period
Cash and cash equivalents at end of period
$
Parent
Guarantor
Eliminations
Consolidated
Year Ended December 31, 2017
Non-Guarantor
$
(118,701) $
(1,655) $
(39,097) $
—
—
4,785
—
5,651
81,248
243
(7,763)
—
4,793
41,125
2,608
2,754
1,938
4,869
40,752
—
—
—
—
—
(11,062)
40,752
—
—
(40,752)
—
—
(50,296)
361
(41,885)
79,319
(16,552)
(1,869)
34,096
(1,542)
30,359
(61,233)
13,495
6,579
14,881
3,234
(7,925)
(17,548)
(6,571)
—
—
6,605
10,737
—
(118,701)
122,373
2,851
(224)
1,938
4,251
—
(9,628)
4,710
(1,319)
8,658
(8,714)
538
(80,014)
60,125
26,913
(291)
6,733
—
—
—
(42,990)
68
(11,543)
335
(42,922)
(11,208)
—
—
—
(54,533)
403
(54,130)
25,200
—
—
—
25,200
50,000
(2,864)
(2,145)
(936)
21,101
—
—
—
—
(10,753)
—
—
—
—
(10,639)
—
—
—
—
291
50,000
(2,864)
(2,145)
(936)
—
90,356
(10,753)
(10,639)
291
69,255
10,342
6,450
5,066
—
21,858
65,000
75,342 $
14,205
20,655 $
40,486
45,552 $
—
— $
119,691
141,549
106
Table of contents
PARKER DRILLING COMPANY AND SUBSIDIARIES (DEBTOR IN POSSESSION)
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
Parent
Guarantor
Eliminations
Consolidated
Year Ended December 31, 2016
Non-Guarantor
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss):
Depreciation and amortization
(Gain) loss on debt modification
Accretion of contingent consideration
Gain (loss) on disposition of assets, net
Deferred tax expense (benefit)
Expenses not requiring cash
Equity in net earnings of subsidiaries
Change in assets and liabilities:
Accounts and notes receivable
Rig materials and supplies
Other current assets
Other non-current assets
Accounts payable and accrued liabilities
Accrued income taxes
Net cash provided by (used in) operating
activities
Cash flows from investing activities:
Capital expenditures
Proceeds from the sale of assets
Net cash provided by (used in) investing
activities
Cash flows from financing activities:
Payment for noncontrolling interest
Payment of contingent consideration
Shares surrendered in lieu of tax
Intercompany advances, net
Net cash provided by (used in) financing
activities
Net increase (decrease) in cash and cash
equivalents
Cash and cash equivalents at beginning of
period
Cash and cash equivalents at end of period
$
(230,814) $
(48,922) $
(45,547) $
94,469 $
(230,814)
—
1,088
—
—
47,971
9,545
94,469
—
—
50,296
(299)
(121,016)
(10,381)
90,197
—
419
565
14,940
(4,900)
—
25,848
(361)
(34,479)
441
99,511
(1,134)
49,598
—
—
1,048
6,151
(2,127)
—
34,543
(1,391)
(13,677)
3,755
2,011
5,093
(159,141)
142,125
39,457
—
—
—
(15,384)
437
(13,570)
2,004
(14,947)
(11,566)
(3,375)
—
(1,156)
—
(6,000)
—
—
154,687
(120,659)
(34,028)
150,156
(126,659)
(34,028)
(8,985)
519
(6,137)
—
—
—
—
—
—
(94,469)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
139,795
1,088
419
1,613
69,062
2,518
—
60,391
(1,752)
2,140
3,897
(19,494)
(6,422)
22,441
(28,954)
2,441
(26,513)
(3,375)
(6,000)
(1,156)
—
(10,531)
(14,603)
73,985
65,000 $
13,686
14,205 $
46,623
40,486 $
$
—
— $
134,294
119,691
107
Table of contents
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended (the Exchange Act), we carried
out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief
Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on
that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were
effective as of December 31, 2018 to provide reasonable assurance that information required to be disclosed in our reports filed or
submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and
our Chief Financial Officer, to allow timely decisions regarding required disclosure and is (2) recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Management’s Annual Report on Internal Control over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as
defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those
policies and procedures that:
•
•
•
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the
assets of the Company;
provide reasonable assurance transactions are recorded as necessary to permit preparation of financial statements in accordance
with accounting principles generally accepted in the United States,
provide reasonable assurance that receipts and expenditures of the Company are being made only in accordance with authorization
of management and directors of the Company; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the
Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections
of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in
conditions, or the degree of compliance with the policies or procedures may deteriorate.
The Company’s management with the participation of the chief executive officer and chief financial officer assessed the effectiveness
of our internal control over financial reporting as of December 31, 2018 based on criteria established in Internal Control — Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management’s
assessment included evaluation of the design and testing of the operational effectiveness of our internal control over financial reporting.
Management reviewed the results of its assessment with the audit committee of the board of directors.
Based on that assessment and those criteria, management has concluded that our internal control over financial reporting was effective
as of December 31, 2018.
KPMG LLP, our independent registered public accounting firm that audited the consolidated financial statements included in this
Annual Report on Form 10-K, has issued a report with respect to our internal control over financial reporting as of December 31, 2018.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the
Exchange Act) during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
108
Table of contents
Item 9B. Other Information
None.
109
Table of contents
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A.
Item 11. Executive Compensation
The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A.
Item 12. Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters
The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A.
Item 14. Principal Accounting Fees and Services
The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A.
110
Table of contents
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as part of this report:
(1) Consolidated financial statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8.
Financial Statements and Supplementary Data:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Stockholders’ Equity
Notes to the Consolidated Financial Statements
(2) Financial Statement Schedule:
Schedule II — Valuation and qualifying accounts
(3) Exhibits:
Page
54
56
57
55
58
59
60
115
Exhibit
Number
2.1
—
Description
Sale and Purchase Agreement, dated April 22, 2013, among ITS Tubular Services (Holdings) Limited, as Seller, Ian
David Green, John Bruce Cartwright and Graham Douglas Frost, as joint administrators of the Seller, ITS Holdings,
Inc. and PD International Holdings C.V., Parker Drilling Offshore Corporation and Parker Drilling Company
(incorporated by reference to Exhibit 2.1 to Parker Drilling Company’s Current Report on Form 8-K filed on April
23, 2013).
2.2
—
Amended Joint Chapter 11 Plan of Reorganization of Parker Drilling Company and its Debtor Affiliates
(incorporated by reference to Exhibit A of the Order Confirming the Amended Joint Chapter 11 Plan of
Reorganization, filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on March 11, 2019).
3.1
3.2
3.3
3.4
—
—
—
—
Restated Certificate of Incorporation of the Company, as amended on May 16, 2007 (incorporated by reference to
Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).
Certificate of Amendment of the Restated Certificate of Incorporation of Parker Drilling Company, dated as of July
12, 2018 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on July 13,
2018).
By-laws of Parker Drilling Company, as amended and restated as of March 9, 2017 (incorporated by reference to
Exhibit 3.1 to Parker Drilling Company’s Current Report on Form 8-K filed on March 14, 2017).
Certificate of Designations of 7.25% Series A Mandatory Convertible Preferred Stock of Parker Drilling Company,
dated February 27, 2017 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K
filed on February 27, 2017).
3.5
—
Certificate of Designations of Series A Junior Participating Preferred Stock of Parker Drilling Company, dated July
12, 2018 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on July 13,
2018).
4.1
—
Indenture, dated July 30, 2013, between Parker Drilling Company, the subsidiary guarantors from time to time
parties thereto, as, collectively, Guarantors, and The Bank of New York Mellon Trust Company, N.A. as Trustee
(incorporated by reference to Exhibit 4.1 to Parker Drilling Company’s Current Report on Form 8-K filed on July
31, 2013).
4.2
—
Form of 7.500% Senior Note due 2020 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report
on Form 8-K filed on July 31, 2013).
111
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4.3
—
4.4
4.5
10.1
10.2
10.3
—
—
—
—
—
Indenture, dated January 22, 2014, among Parker Drilling Company, the Guarantors and The Bank of New York
Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report
on Form 8-K filed on January 28, 2014).
Form of 6.750% Senior Note due 2022 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report
on Form 8-K filed on January 28, 2014).
Section 382 Rights Agreement, dated as of August 23, 2018, between Parker Drilling Company and Equiniti Trust
Company, as Rights Agent (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K
filed on August 24, 2018).
Parker Drilling Company Incentive Compensation Plan (as amended and restated effective January 1, 2009)
(incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K filed on March 1, 2011).*
Parker Drilling Company 2010 Long-Term Incentive Plan (as amended and restated effective May 8, 2013)
(incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement filed on March 28, 2013).*
Form of Parker Drilling Company Restricted Stock Unit Incentive Agreement under the 2010 LTIP (as amended and
restated effective May 8, 2013) (incorporated by reference to Exhibit 10.6 to the Company’s Annual Report on Form
10-K filed on February 25, 2015).*
10.4
—
Form of Parker Drilling Company Performance Cash Unit Award Incentive Agreement under the 2010 LTIP (as
amended and restated effective May 8, 2013) (incorporated by reference to Exhibit 10.8 to the Company’s Annual
Report on Form 10-K filed on February 25, 2015).*
10.5
—
Form of Parker Drilling Company Performance-Based Phantom Stock Unit Award Incentive Agreement under the
2010 LTIP (as amended and restated effective May 8, 2013) (incorporated by reference to Exhibit 10.9 to the
Company’s Annual Report on Form 10-K filed on February 25, 2016).*
10.6
—
Form of Parker Drilling Company Time-Based Phantom Stock Unit Award Incentive Agreement under the 2010
LTIP (as amended and restated effective May 8, 2013) (incorporated by reference to Exhibit 10.7 to the Company’s
Annual Report on Form 10-K filed on February 21, 2017).*
10.7
—
Parker Drilling Company 2010 Long-Term Incentive Plan (as amended and restated as of May 10, 2016)
(incorporated by reference to Appendix A of the Company’s Notice of Annual Meeting of Stockholders and Proxy
Statement filed on March 31, 2016).*
10.8
—
Form of Parker Drilling Company Restricted Stock Unit Incentive Agreement under the 2010 LTIP (as amended as
of May 10, 2016) (incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K filed on
February 21, 2017).*
10.9
—
Parker Drilling Company 2018 Annual Incentive Cash Compensation Plan (incorporated by reference to Exhibit 10.1
to the Company’s Current Report on Form 8-K filed on June 26, 2018).*
10.10
—
Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executive
officer of Parker Drilling Company (incorporated by reference to Exhibit 10(g) to the Company’s Annual Report on
Form 10-K filed on March 20, 2003).*
10.11
—
Employment Agreement between Mr. Jon-Al Duplantier and Parker Drilling Company, effective March 21, 2011
(incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 25,
2011).*
10.12
—
First Amendment dated August 29, 2011 to Employment Agreement between Mr. Jon-Al Duplantier and Parker
Drilling Company, effective March 21, 2011 (incorporated by reference to Exhibit 10.4 to the Company’s Current
Report on Form 8-K filed on August 30, 2011).*
112
Table of contents
10.13
—
Employment Agreement, dated as of September 17, 2012, by and between Parker Drilling Company and Gary Rich
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 24,
2012).*
10.14
—
Employment Agreement, dated as of January 1, 2017, by and between Parker Drilling Company and Bryan R.
Collins (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed on May 2,
2018).*
10.15
—
Employment Agreement dated September 21, 2017 by and between Parker Drilling Company and Michael W.
Sumruld (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on
September 26, 2017).*
10.16
—
Employment Agreement, dated as of April 2, 2018, by and between Parker Drilling Company and Jennifer F. Simons
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 3, 2018).*
10.17
—
Retirement and Separation Agreement, dated November 1, 2013, between Parker Drilling Company and Robert L.
Parker, Jr. (incorporated by reference to Exhibit 10.1 to Parker Drilling Company’s Current Report on Form 8-K
filed on November 4, 2013).*
10.18
—
Second Amended and Restated Credit Agreement, dated January 26, 2015, among Parker Drilling Company, as
Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank, National Association,
as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and L/C issuers from time
to time party thereto (incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K
filed on February 25, 2015).
10.19
—
First Amendment to the Second Amended and Restated Credit Agreement, dated June 1, 2015, among Parker
Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank,
National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and
L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly
Report on Form 10-Q filed on August 6, 2015).
10.20
—
Second Amendment to the Second Amended and Restated Credit Agreement, dated September 29, 2015, among
Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells
Fargo Bank, National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the
other lenders and L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the
Company’s Quarterly Report on Form 10-Q filed on November 4, 2015).
10.21
—
Third Amendment to the Second Amended and Restated Credit Agreement, dated May 27, 2016, among Parker
Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank,
National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and
L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly
Report on Form 10-Q filed on August 3, 2016).
10.22
—
Fourth Amendment to the Second Amended and Restated Credit Agreement, dated February 21, 2017, among Parker
Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, Wells Fargo Bank,
National Association, as Syndication Agent, Barclays Bank PLC, as Documentation Agent, and the other lenders and
L/C issuers from time to time party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current
Report on Form 8-K filed on February 27, 2017).
10.23
—
Fifth Amendment to the Second Amended and Restated Credit Agreement, dated February 14, 2018, among Parker
Drilling Company, as Borrower, and Bank of America, N.A., as Administrative Agent and L/C Issuer (incorporated
by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K filed on February 21, 2018).
10.24
—
Sixth Amendment to the Second Amended and Restated Credit Agreement, dated July 12, 2018, among Parker
Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 13, 2018).
113
Table of contents
10.25
—
Restructuring Support Agreement, dated December 12, 2018 (incorporated by reference to Exhibit 10.1 to the
Company’s Current Report on Form 8-K filed on December 12, 2018).
10.26
—
Amended and Restated Backstop Commitment Agreement, dated January 28, 2019 (incorporated by reference to
Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 2, 2019).
10.27
—
First Amendment to the Restructuring Support Agreement, dated January 28, 2019 (incorporated by reference to
Exhibit 10.2 to the Company’s Report on Form 8-K filed on February 2, 2019).
21
— Subsidiaries of the Registrant.
23.1
— Consent of KPMG LLP — Independent Registered Public Accounting Firm.
31.1
— Gary G. Rich, Chairman, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.
31.2
— Michael W. Sumruld, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.
32.1
— Gary G. Rich, Chairman, President and Chief Executive Officer, 18 U.S.C. Section 1350 Certification.
32.2
— Michael W. Sumruld, Senior Vice President and Chief Financial Officer, 18 U.S.C. Section 1350 Certification.
101.INS — XBRL Instance Document.
101.SCH — XBRL Taxonomy Schema Document.
101.CAL — XBRL Calculation Linkbase Document.
101.LAB — XBRL Label Linkbase Document.
101.PRE — XBRL Presentation Linkbase Document.
101.DEF — XBRL Definition Linkbase Document.
____________________________
* — Management contract, compensatory plan or agreement.
114
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PARKER DRILLING COMPANY AND SUBSIDIARIES
Schedule II—Valuation and Qualifying Accounts
Classifications
Dollars in Thousands
Year Ended December 31, 2018
Allowance for bad debt
Allowance for obsolete rig materials and supplies
Deferred tax valuation allowance
Year Ended December 31, 2017
Allowance for bad debt
Allowance for obsolete rig materials and supplies
Deferred tax valuation allowance
Year Ended December 31, 2016
Allowance for bad debt
Allowance for obsolete rig materials and supplies
Deferred tax valuation allowance
Balance at
beginning
of year
Charged to
cost and
expenses
Charged
to other
accounts
Deductions
Balance at
end of
year
$
$
$
$
$
$
$
$
$
7,564
809
157,914
8,259
1,166
171,133
309
1,041
28,353
444
65
(14,625)
8,694
626
51,105
1,483
978
117,707
(47)
—
—
(414)
—
1,406
4
(3)
2,321
(59) $
(303) $
— $
7,767
1,547
186,267
(725) $
(422) $
— $
7,564
809
157,914
(1,922) $
(435) $
— $
8,259
1,166
171,133
115
Table of contents
Item 16. Form 10-K Summary
None.
116
Table of contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned hereunto duly authorized.
PARKER DRILLING COMPANY
By:
/s/ Michael W. Sumruld
Michael W. Sumruld
Senior Vice President and Chief Financial Officer
Date: March 11, 2019
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on
behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Title
Date
By:
/s/ Gary G. Rich
Gary G. Rich
Chairman, President, and Chief Executive Officer
(Principal Executive Officer)
By:
/s/ Michael W. Sumruld
Michael W. Sumruld
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
By:
/s/ Nathaniel C. Dockray
Nathaniel C. Dockray
By:
/s/ Jonathan M. Clarkson
Jonathan M. Clarkson
By:
/s/ Peter T. Fontana
Peter T. Fontana
By:
/s/ Gary R. King
Gary R. King
By:
/s/ Robert L. Parker Jr.
Robert L. Parker Jr.
By:
/s/ Richard D. Paterson
Richard D. Paterson
By:
/s/ Zaki Selim
Zaki Selim
Principal Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
117
March 11, 2019
March 11, 2019
March 11, 2019
March 11, 2019
March 11, 2019
March 11, 2019
March 11, 2019
March 11, 2019
March 11, 2019
SUBSIDIARIES OF THE REGISTRANT
EXHIBIT 21
The following is a list of significant subsidiaries of the Registrant:
1 Parker Technology, Inc. (Oklahoma, U.S.A.)-100% direct subsidiary.
2 Universal Rig Service LLC (Delaware, U.S.A.)-100% direct subsidiary.
3 Parker North America Operations, LLC (Nevada, U.S.A.)-100% direct subsidiary.
4 Parker Drilling International Holding Company, LLC (Delaware, U.S.A.)-100% direct subsidiary.
5 Parker Drilling Company International Limited (Nevada, U.S.A.)-100% indirect subsidiary -Parker Drilling Eurasia, Inc. (100%).
6 Parker Drilling Company Eastern Hemisphere, Ltd. Co. (Oklahoma, U.S.A.)-100% indirect subsidiary -Parker Drilling Eurasia, Inc. (100%).
7 Parker Drilling Company Kuwait Limited (Bahamas)-100% indirect subsidiary -PD Selective Holdings C.V. (100%).
8 Parker Drilling Company of Sakhalin (Russia)-100% indirect subsidiary -Parker Drilling Netherlands B.V. (100%).
9 Parker Drilling Management Services, Ltd. (Nevada, U.S.A.)-100% indirect subsidiary -Parker North America Operations, LLC (100%).
10 Quail Tools, L.P. (Oklahoma, U.S.A.)-100% indirect subsidiary -Parker Tools, LLC (99.0%), Quail USA, LLC (1.0%).
11 Parker Drilling (Kazakstan), LLC (Delaware, U.S.A.)-100% indirect subsidiary -PD Dutch Holdings C.V. (100%).
12 Parker Drilling Offshore International, Inc. (Cayman Islands)-100% indirect subsidiary -Parker Drilling Offshore Company, LLC (100%).
13 Parker Drilling Offshore USA, L.L.C. (Oklahoma, U.S.A.)-100% indirect subsidiary -Parker Drilling Offshore Company, LLC (100%).
14 Parker Hungary Rig Holdings Limited Liability Company (Hungary)-100% indirect subsidiary -Parker Drillsource LLC (100%).
15 Parker Drilling Overseas B.V. (Netherlands)-100% indirect subsidiary -Parker Drilling Netherlands B.V. (100%).
16 Parker Drilling Netherlands B.V. (Netherlands)-100% indirect subsidiary -PD Selective Holdings C.V. (100%).
17 Parker Drilling Russia B.V. (Netherlands)-100% indirect subsidiary -Parker Drilling Netherlands B.V. (100%).
18
Parker Drilling Eurasia, Inc. (Delaware, U.S.A.)-100% indirect subsidiary -Parker Drilling International Holding Company, LLC (64.8%),
Parker Drilling Offshore Company, LLC (35.2%).
19 Parker Central Europe Rig Holdings LLC (Hungary)-100% indirect subsidiary -Parker Drilling (Kazakstan), LLC (100%).
20 Parker Drilling Arctic Operating, LLC (Delaware, U.S.A.)-100% indirect subsidiary -Parker North America Operations, LLC (100%).
21 Primorsky Drill Rig Services B.V. (Netherlands)-100% indirect subsidiary -Parker Drilling Netherlands B.V. (100%).
22 Parker Drilling Canada Company (Nova Scotia, Canada)-100% indirect subsidiary -Parker Technology, Inc. (100%).
23
Parker Drilling Global Employment Company (Management Office), Ltd. (U.A.E.)-100% indirect subsidiary -Parker Drilling Netherlands
B.V. (100%).
24 International Tubular Services Limited (Scotland, U.K.)-100% indirect subsidiary -PD ITS Holdings C.V. (100%).
25 ITS Netherlands B.V. (Netherlands)-100% indirect subsidiary -International Tubular Services Limited (100%).
26 ITS Energy Services (Cayman Islands)-100% indirect subsidiary -PD ITS Holdings C.V. (100%).
27 International Tubular Services de Mexico, S. de R.I. de C.V. (Mexico)-100% indirect subsidiary -International Tubular Services Limited
(99.74%), ITS Egypt Holdings 2, Ltd. (00.26%).
28 2M-TEK, Inc. (Louisiana, U.S.A.)-100% indirect subsidiary -Parker Drilling Offshore Company, LLC (100%).
29 International Tubulars FZE (U.A.E.)-100% indirect subsidiary -International Tubular Services Limited (100%).
30
International Tubular Services Middle East, WLL (U.A.E.)-100% indirect subsidiary -3rd Party Saleem Abdulla Salem Saeed Al Shamnisi
(51%), International Tubulars FZE (49%).
31 ITS Arabia Limited (Saudi Arabia)-100% indirect subsidiary -PD International Holdings C.V. (70%), ITS Egypt Holdings 1, Ltd. (30%).
32 Parker Drillsource LLC (Delaware, U.S.A.)-100% indirect subsidiary -PD Selective Holdings C.V. (100%).
33
PD International Holdings, C.V. (Netherlands)-100% indirect subsidiary -Parker Drilling Company (00.04%), Parker Intex, LLC (00.04%),
Parker Rigsource, LLC (00.04%), Parker Drilling Pacific Rim, Inc. (99.88%).
Note: Certain subsidiaries have been omitted from the list since they would not, even if considered in the aggregate, constitute a significant
subsidiary. All subsidiaries are included in the consolidated financial statements.
Consent of Independent Registered Public Accounting Firm
EXHIBIT 23.1
The Board of Directors
Parker Drilling Company:
We consent to the incorporation by reference in the registration statement (No. 333-219239) on Form S-3 and (Nos. 333-220764, 333-
188754, 333-184230, and 333-167695) on Form S-8 of Parker Drilling Company of our report dated March 11, 2019, with respect to the
consolidated balance sheets of Parker Drilling Company as of December 31, 2018 and 2017, the related consolidated statements of
operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the years in the three-year period ended
December 31, 2018, and the related notes and financial statement Schedule II - Valuation and Qualifying Accounts, and the effectiveness of
internal control over financial reporting as of December 31, 2018, which report appears in the December 31, 2018 annual report on Form
10-K of Parker Drilling Company.
Our report dated March 11, 2019 contains an explanatory paragraph that states that Parker Drilling Company has suffered recurring losses
from operations and is facing risk and uncertainties surrounding its Chapter 11 proceedings, which raise substantial doubt about its ability to
continue as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of
that uncertainty.
Houston, Texas
March 11, 2019
/s/ KPMG LLP
PARKER DRILLING COMPANY
RULE 13a-14(a)/15d-14(a) CERTIFICATION
EXHIBIT 31.1
I, Gary G. Rich, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K for the period ended December 31, 2018, of Parker Drilling Company (the
registrant);
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to
the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all
material
respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this
report;
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures
(as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on
such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the
equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date: March 11, 2019
/s/ Gary G. Rich
Gary G. Rich
Chairman, President and Chief Executive Officer
PARKER DRILLING COMPANY
RULE 13a-14(a)/15d-14(a) CERTIFICATION
EXHIBIT 31.2
I, Michael W. Sumruld, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K for the period ended December 31, 2018, of Parker Drilling Company (the
registrant);
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to
the period covered by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all
material
respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this
report;
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures
(as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act
Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on
such evaluation; and
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the
equivalent functions):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date: March 11, 2019
/s/ Michael W. Sumruld
Michael W. Sumruld
Senior Vice President and Chief Financial Officer
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
EXHIBIT 32.1
Pursuant to 18 U.S.C. Section 1350, the undersigned officer of Parker Drilling Company (the “Company) hereby certifies, to such officer’s
knowledge, that:
1.
2.
The Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “Report) fully complies with the
requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of the Company.
Dated: March 11, 2019
/s/ Gary G. Rich
Gary G. Rich
Chairman, President and Chief Executive Officer
The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a
separate disclosure statement.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
EXHIBIT 32.2
Pursuant to 18 U.S.C. Section 1350, the undersigned officer of Parker Drilling Company (the “Company) hereby certifies, to such officer’s
knowledge, that:
1.
2.
The Company’s Annual Report on Form 10-K for the year ended December 31, 2018 (the “Report) fully complies with the
requirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and result of
operations of the Company.
Dated: March 11, 2019
/s/ Michael W. Sumruld
Michael W. Sumruld
Senior Vice President and Chief Financial Officer
The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a
separate disclosure statement.