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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(MARK ONE)
| þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012
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 | 73-0618660 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
5 Greenway Plaza, Suite 100, Houston, Texas | 77046 | |
| (Address of principal executive offices) | (Zip code) | |
Registrant’s telephone number, including area code:
(281) 406-2000
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered: | |
Common Stock, par value $0.16 2/3 per share | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large accelerated filer ¨ | Accelerated filer þ | Non-accelerated filer ¨ | Smaller reporting company ¨ | |||
| (Do not check if a smaller reporting company) | ||||||
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, 2012 was $519.6 million. At February 26, 2013, there were 118,638,423 shares of common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of our definitive proxy statement for the Annual Meeting of Shareholders to be held on May 8, 2013 are incorporated by reference in Part III.
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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. The Company 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 through the merger of the Oklahoma corporation into its wholly-owned subsidiary Parker Drilling Company, a Delaware corporation. Our principal executive offices are located at 5 Greenway Plaza, Suite 100, Houston, Texas 77046.
We are a provider of contract drilling and drilling-related services and currently operate in 12 countries. We have operated in over 50 foreign countries and the United States since beginning operations in 1934, making us among the most geographically experienced drilling contractors in the world. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. We believe our quality, health, safety and environmental practices are leaders in our industry.
Our business is comprised of six segments: Rental Tools, U.S. Barge Drilling, U.S. Drilling, International Drilling, Technical Services, and Construction Contract.
Our Rental Tools Business
We provide premium rental tools for land and offshore oil and natural gas drilling and provide high-quality, reliable equipment used for drilling, workover and production applications, such as drill pipe, heavy-weight drill pipe, tubing, high-torque connections, blow-out preventers (BOPs), drill collars and more. Our rental tools business is headquartered in New Iberia, Louisiana. We also hold an inventory of rental tools and provide service to our customers from locations in Louisiana, Texas, Wyoming, North Dakota and West Virginia.
Our largest market for rental tools is U.S. land drilling, a cyclical market driven primarily by commodity pricing and availability of project financing. The increase in unconventional lateral drilling, often used in drilling shale formations, has added to the market demand for rental tools, keeping our current market focus in the regions of the primary shale plays. Based on industry information on rig use, we believe that our rental tools were used primarily in drilling for oil and liquids-rich natural gas in 2012. We also have a growing portion of our business that supplies tubular goods and other equipment to international and offshore Gulf of Mexico (GOM) customers.
Our principal customers are major and independent oil and natural gas exploration and production companies operating in the U.S. energy producing markets on land and in the GOM. Generally, rental tools are used for only a portion of a well drilling program and are requested by the customer when they are required. As a result, rental tools are usually rented on a daily or monthly basis, requiring us to keep a broad inventory in stock. For 2012, approximately 18 percent of revenues from our rental tools business were derived from equipment used in offshore and coastal water operations of the GOM. In addition, from our locations within the United States, we have provided rental tools to customers operating internationally. In 2012, we provided rental tools for use in Angola, Russia, Egypt, Mexico, Suriname, Turkey, Trinidad & Tobago, Singapore, Cameroon, Colombia, and Jordan, among others. During each of the years ended December 31, 2012, 2011 and 2010, approximately five percent of rental tools’ segment revenues were derived from equipment used in international applications, respectively.
Our U.S. Barge Drilling Business
Our U.S. Gulf of Mexico barge rig fleet is the largest marketed barge fleet in the GOM region, with rigs ranging from 1,000 to 3,000 horsepower with drilling depth capabilities ranging from 13,000 to over 30,000 feet. Our rigs drill for oil, natural gas, and a combination of oil and natural gas in the shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The barge drilling industry in the GOM is
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characterized by cyclical activity where utilization and dayrates are typically driven by current oil and natural gas prices and our customers’ access to project financing. Contract terms tend to be well-to-well or multi-well programs, with durations typically averaging 45 to 150 days. During periods of strong market demand, contract drilling terms may extend up to twelve months and longer.
We continue to make investments in our barge drilling fleet to increase its efficiency and safety performance. Our rigs are all equipped for zero-discharge operations and are suitable for a variety of drilling programs in coastal waters, particularly for deep shelf drilling.
Our U.S. Drilling Business
Our U.S. Drilling segment primarily consists of two new-design Arctic Alaska Drilling Unit (AADU) land rigs intended to address the challenges presented by the remote location, harsh climate and sensitive environment that characterize the Alaskan North Slope. The rigs include features in use in other applications but not currently available as a drilling package in Alaska and are expected to deliver improved drilling efficiency, operating consistency and safety in this very demanding setting. In early December 2012 we commenced drilling operations with the first rig. The second rig completed client acceptance testing and began drilling in February 2013.
The Alaskan North Slope drilling market is a focus of global and regional exploration and production (E&P) companies with active programs to develop the area’s hydrocarbon resources. In this market, drilling activity, and therefore production, is constrained by the existing limits of the infrastructure in place and the capabilities of existing aged technology. We believe our new-design rigs contribute to expanded drilling capabilities in this market for our customers.
In addition to the two AADU rigs, we have one land rig at our facility in New Iberia, Louisiana, that is currently being marketed for use in international markets.
Our International Drilling Business
Our international drilling business includes operations related to Parker-owned and operated rigs as well as customer-owned rigs. We strive to deploy our fleet of Parker-owned rigs in markets where we expect to have opportunities to keep the rigs regularly at work. In addition, we perform drilling-related activities for operators who own their drilling rigs and who choose to utilize our drilling experience and technical expertise to perform services on a contracted basis, including Operations and Maintenance (O&M) work, and other project management services (e.g., labor, maintenance, and logistics). We have ongoing O&M and project management activities in Sakhalin Island, Russia; Papua New Guinea; China; and Kuwait.
The international drilling markets in which we operate have one or more of the following characteristics:
| Ÿ | customers that typically are major, independent or national oil and natural gas companies or integrated service providers; |
| Ÿ | drilling programs in remote locations with little infrastructure requiring a large inventory of spare parts and other ancillary equipment and self-supported service capabilities; |
| Ÿ | complex wells and/or harsh environments (e.g., high pressure, deep depths, hazardous or geologically challenging conditions) requiring specialized equipment and considerable experience to drill; |
| Ÿ | drilling contracts that generally cover periods of one year or more; and |
| Ÿ | O&M contracts that are typically multi-year drilling programs. |
Our Technical Services Business
Our technical services business primarily includes our engagement in concept development, pre-FEED (Front End Engineering Design), FEED and Engineering, Procurement, Construction and Installation (EPCI) projects that have the potential to evolve into future O&M opportunities. During the EPCI phase, we focus primarily on the drilling systems engineering, procurement, commissioning and installation and typically provide
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customer support during construction. Currently, we provide these services on the Berkut platform project for Exxon Neftegas Limited (ENL). Because these projects are customer-owned and customer-funded, the Technical Services business is non-capital intensive and helps to position the company for future potential growth in O&M work.
Our technical services business is also the Company’s engineering expertise center and provides our ongoing drilling businesses with services similar to those provided to our external customers; including engineering design, retrofitting of existing rigs, modification, upgrades and other technology related advancements.
Our Construction Contract Business
Our construction contract segment includes only the BP-owned Liberty extended-reach drilling rig construction project. In 2008, we commenced the construction phase of the Liberty project. In November 2010, BP suspended construction on the Liberty rig and our construction contract has expired. In addition, our O&M contract with respect to the Liberty rig expired on July 1, 2011.
For more information about the Liberty project, see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations — Other Matters — “Liberty Project Status.”
Our Strategy
Our strategy is to achieve and maintain market leadership in selected global markets as a provider of innovative, efficient and reliable drilling and drilling-related services; to grow our business through select investments in our core businesses, new assets and lines of business; and to achieve consistent execution excellence and exercise financial discipline. We are committed to achieving peak performance for our customers in routine or more conventional settings, as well as extreme and highly challenging environments through:
| ¡ | innovative, fit-for-purpose products and services that deliver reliable results and measurable value; |
| ¡ | safe, efficient and innovative drilling and rental tool performance; and |
| ¡ | highly competent teams, processes and technology that are unmatched for delivering solutions to difficult challenges. |
Achieving and Maintaining Market Leadership. We believe we achieve and sustain the preference for our services by the quality, efficiency and dependability of our performance and its value to the customer. We achieve this by:
| ¡ | providing premium rental tools with premier customer service; |
| ¡ | building, upgrading and maintaining a fleet of barge and land rigs that are preferred by operators because of the value they provide; |
| ¡ | supplying trained and experienced operating crews, rig leadership teams and an array of support services; and |
| ¡ | offering engineering and other technical services that have a record of developing innovative solutions to drilling challenges in difficult, hazardous or environmentally sensitive areas. |
Growing Through Selective Investment. We believe we can improve our competitive position and financial performance through investments in our core businesses and in new assets or lines of business that complement and expand our capabilities. We are focused on:
| ¡ | expanding and broadening our non-capital intensive technical services and O&M activities by leveraging our experience; |
| ¡ | growing our rental tools operation by locating new service facilities in markets with growing demand from new and existing customers; |
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| ¡ | adding new equipment to and upgrading our drilling rig fleet thereby improving our opportunities with operators; and |
| ¡ | entering new markets that we believe present long-term oil and natural gas development opportunities. |
Strive for Execution Excellence and Maintain Financial Discipline. We believe we significantly enhance our operating and financial performance potential by how well we plan, execute and manage. Our operating culture is to align resources, responsibility and accountability with achievable objectives. Our management team has extensive experience in the industry and we work diligently to continue to attract new talent to the Company that can improve our management performance and provide for excellence in leadership in the future. We maintain strong financial controls and disciplines in all aspects of our business to ensure that we adhere to solid financial principles and provide attentive stewardship of our capital. These principles are intended to lead to consistency in operational performance, stronger-than-peer financial performance and value to our shareholders.
In 2013, our focus will be on specific goals that align with these strategies. These are intended to continue to improve our safety performance; manage the geopolitical risks associated with our asset deployment; improve financial returns from operations; improve the predictability and reliability of operational, planning and project management processes; and to continue to strengthen our enterprise talent.
Our Competitive Strengths
We differentiate ourselves from other providers of similar services by focusing on our core competencies and delivering premier and measurable results to our customers. We seek to provide our customers safe, reliable and efficient operations, and innovation in our products and services through these key focus areas:
Safety: We believe industry-leading safety performance is a crucial factor in our status as a preferred drilling contractor and rental tools supplier. We have a portfolio of metrics and processes we utilize to reinforce and drive continuous improvement in safety and environmental performance.
We continue to have an outstanding safety record. In 2013, our Total Recordable Incident Rate (TRIR) was ahead of our targeted goal with more than 70 percent of our facilities reporting zero recordable injuries throughout 2013. Our TRIR has been below the industry average for more than ten years, with rates averaging significantly less than the industry average since 2004. We believe our safety record, along with integrated quality, health, safety, and environmental (HSE), maintenance and supply chain management programs, has contributed to our success in obtaining drilling contracts, as well as contracts to manage and provide labor resources for drilling rigs owned by third parties.
Personnel Development and Training: The challenges of our business are magnified when considering the technological requirements of our work and our customers. We have invested significant resources to provide a full curriculum of standardized training to overcome barriers to working safely and operating efficiently. Our training centers in Louisiana and Alaska provide safety and technical training curricula in four different languages and provide regulatory compliance training throughout the world. We also provide structured training programs and on-site instruction to our customers and clients in the use of equipment we furnish as rental tools. We are committed to ongoing training and to developing best-in-class processes for quickly and effectively developing and deploying the most qualified and highly trained industry workers.
Technology: Applying new technology to create greater efficiencies in the drilling process lies at the heart of our competitive edge. We have a nearly 80-year legacy of applying new technologies for drilling in challenging environments and a demonstrated history of technological leadership within the drilling industry. Our previous contributions to the industry include the patented heli-hoist rig design, winterized rigs on wheels for arctic drilling, and an arctic-class barge rig to explore the Caspian Sea. We have established extended reach drilling depth records on several occasions. Our new-design arctic class land rigs, designed for drilling on the Alaskan North Slope, are intended to increase drilling efficiency, consistency and safety in the extreme climate and harsh conditions of the arctic environment. Our rental tools business focuses on premium equipment, maintained to high standards, that complements advanced drilling technologies like those developed to exploit oil and natural gas deposits in shale.
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Performance: A primary aim is to provide services that benefit both our customers and our company. We strive to achieve this by planning, executing and measuring our performance against our goals and our customers’ expectations. We utilize performance metrics in our business and regularly share them with our customers. Our planned maintenance programs, including preventive maintenance to facilitate dependable operating efficiency and minimize down time, helps to establish us as a contractor of choice. Our management team has extensive experience in the energy services and oil and gas drilling industries and utilizes this experience to set performance standards and assess the performance of our operations and individual employees.
Customers
Our customer base consists of major, independent and national oil and natural gas companies and integrated service providers. We depend on a limited number of significant customers. In 2012, our two largest customers, Exxon Neftegas Limited (ENL) and Schlumberger, accounted for approximately 11.8 percent and 10.4 percent, respectively, of our total revenues.
Competition
We operate in highly competitive businesses characterized by high capital requirements, continuously rigorous technological challenges, evolving regulatory requirements and challenges in securing and retaining qualified field personnel.
In international land markets, we compete with a number of international drilling contractors as well as local contractors. Most contracts are awarded on a competitive bidding basis and operators often consider technical expertise and quality of equipment in addition to price. Although local drilling contractors typically 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, planned maintenance and experience. In international markets, our experience in operating in challenging environments has been a significant factor in securing contracts. We believe the market for drilling contracts will continue to be highly competitive with continued focus on efficiency and quality.
In the GOM barge drilling markets, we are awarded most contracts through a competitive bidding process. We have achieved some success in differentiating ourselves from competitors through our drilling performance, upgraded fleet, planned maintenance programs, well-trained and experienced crews and safety record. This strategy has resulted in safer and more efficient operations and we believe these are important factors in contract awards.
In the U.S. rental tools market we compete with suppliers both larger and smaller than our own business, some of which are parts of larger enterprises. We believe our rental tools business is one of the leading rental tools companies in the U.S. oil and natural gas drilling markets. Our rental tools business, competes against other rentals tool companies based on its breadth of inventory, the availability and price of its product and its quality of service.
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, 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, adverse weather or other conditions, and no payment when certain conditions continue beyond contractually established parameters. When a rig mobilizes to or demobilizes from an operating area, the contract typically provides for a different dayrate or specified fixed payments during the mobilization or demobilization. The terms of most of our contracts are based on either a specified period of time or the time required to drill 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
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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. Certain of our contracts require the customer to pay an early termination fee if the customer terminates a contract before the end of the term without cause, but in the remainder of the contracts the customer has the discretion to terminate the contract without cause prior to the end of the term without penalty.
Rental tools contracts are typically on a dayrate basis with rates based on type of equipment, investment and competitive conditions. Rental rates generally apply from the time the equipment leaves our facility until it is returned. Rental contracts generally require the customer to pay for lost, lost-in-hole or damaged equipment.
Technical Services contracts include engineering, consulting, and project management scopes of work and are typically on a time and materials basis.
Seasonality
Our rigs in 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 the conditions are deemed unsafe to operate in.
Insurance and Indemnification
Our operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, craterings, fires, explosions, pollution, and damage or loss during transportation. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment and pollution damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. 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.
Our contracts provide for varying levels of indemnification between ourselves and our customers, including with respect to well control and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks. Our insurance policies are typically 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 contract, for liability due to control-of-well 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 program provides liability coverage up to $200 million, with a retention of $1 million or less.
Control-of-well events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., a BOP), 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 pollution from a control-of-well event up to $200 million per occurrence. A separate limit of $10 million exists to cover the costs of re-drilling of the well and control-of-well costs under a Contingent Operators Extra Expense policy. Remediation plans are in place to prevent the spread of pollutants and our insurance program provides coverage for removal, response and remedial actions. Our insurance program also provides coverage for liability resulting from pollution events originating from our rigs up to $200 million per occurrence. We retain the risk for liability not indemnified by the customer below the retention and in excess of our insurance coverage. In addition, our insurance program covers only sudden and accidental pollution.
Based upon a Company risk assessment and due to the high cost, high self-insured retention and limited coverage insurance for windstorms in the GOM, we do not purchase windstorm insurance for our barge rigs in the GOM. We elected not to purchase such insurance. 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.
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Our contracts provide for varying levels of indemnification from our customers and may require us to indemnify our customers. Under our contracts liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers customarily assume liability for our respective personnel and property regardless of fault. However, in certain contracts we may assume liability for damage to our customer’s property and other third-party property on the rig resulting from our negligence, subject to negotiated caps per occurrence, 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. 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.
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 as a result of blow-outs or cratering of the well. In some contracts, however, we may have liability for damages resulting from such pollution or contamination caused by our negligence, 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 (sometimes called “mud”) 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 contracts may change in the future. In addition, the indemnification provisions of our contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.
If any of the aforementioned operating hazards results in substantial liability and our insurance and contractual indemnification provisions are unavailable or insufficient, our financial condition, operating results or cash flows may be materially adversely affected.
Employees
The following table sets forth the composition of our employee base:
| December 31, | ||||||||
| 2012 | 2011 | |||||||
Rental Tools | 279 | 253 | ||||||
U.S. Barge Drilling | 387 | 387 | ||||||
U.S. Drilling | 144 | 153 | ||||||
International Drilling | 1,019 | 1,301 | ||||||
Technical Services, Construction Contract and Corporate | 256 | 223 | ||||||
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Total employees | 2,085 | 2,317 | ||||||
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Environmental Considerations
Our operations are subject to numerous federal, state, local and foreign laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous foreign and domestic governmental agencies, such as the U.S. Environmental Protection Agency (EPA), issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain
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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 the Federal Water Pollution Control Act (commonly known as the Clean Water Act (CWA), as amended by the Oil Pollution Act of 1990 (OPA); the Clean Air Act (CAA); the Outer Continental Shelf Lands Act (OCSLA); the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA); the Resource Conservation and Recovery Act (RCRA); Emergency Planning and Community Right to Know Act (EPCRA); Hazardous Materials Transportation Act (HMTA) and comparable state laws, each as may be amended from time to time. In addition, we may also be subject to applicable state law and other civil claims arising out of any such incident.
The OPA and regulations promulgated pursuant thereto impose a variety of regulations on “responsible parties” related to the prevention of spills of oil or other hazardous substances and liability for damages resulting from such spills. “Responsible parties” include the owner or operator of a vessel, pipeline or onshore facility, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability of oil removal costs and a variety of public and private damages to each responsible party.
The OPA liability for a mobile offshore drilling rig is determined by whether the unit is functioning as a vessel or is in place and functioning as an offshore facility. If operating as a vessel, liability limits of $1,000 per gross ton or $854,400, whichever is greater, apply. If functioning as an offshore facility, the mobile offshore drilling rig is considered a “tank vessel” for spills of oil or hazardous substances on or above the water surface, with liability limits of $3,200 per gross ton or $23.5 million, whichever is greater. To the extent damages and removal costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will be responsible up to higher liability limits for all removal costs plus $75.0 million. The party must reimburse all removal costs actually incurred by a governmental entity for actual or threatened oil or hazardous substance discharges associated with any Outer Continental Shelf facilities, without regard to the limits described above. A party also cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.
Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility, for offshore facilities and vessels in excess of 300 gross tons (to cover at least some costs in a potential spill) and preparation of an oil spill contingency plan for offshore facilities and vessels. The OPA requires owners and operators of offshore facilities that have a worst case oil or hazardous substance spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10.0 million in specified state waters to $35.0 million in federal Outer Continental Shelf waters, with higher amounts, up to $150.0 million, in certain limited circumstances where the Bureau of Ocean Energy Management (BOEM) believes such a level is justified by the risks posed by the quantity or quality of oil or hazardous substance that is handled by the facility. For “tank vessels,” as our offshore drilling rigs are typically classified, the OPA requires owners and operators to demonstrate financial responsibility in the amount of their largest vessel’s liability limit, as those limits are described in the preceding paragraph. 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. Violations of environmentally related
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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 can result from either governmental or citizen prosecution.
Our operating U.S. barge drilling rigs are designed to achieve zero-discharge as required by law, such as CWA. In addition, in recognition of environmental concerns regarding dredging of inland waters and permitting requirements, we conduct negligible dredging operations, with approximately two-thirds of our offshore drilling contracts involving directional drilling, which minimizes the need for dredging. However, the existence of such laws and regulations (e.g., Section 404 of the CWA, Section 10 of the Rivers and Harbors Act, etc.) has had and will continue to have a restrictive effect on us and our customers.
Our operations are also governed by laws and regulations related to workplace safety and worker health, primarily the Occupational Safety and Health Act and regulations promulgated thereunder. In addition, various other governmental and quasi-governmental agencies require us to obtain certain miscellaneous permits, licenses and certificates with respect to our operations. The kind of permits, licenses and certificates required by our operations depend upon a number of factors. We believe we have the necessary permits, licenses and certificates that are material to the conduct of our existing business.
CERCLA (also known as “Superfund”) and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” 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. Few defenses exist to the liability imposed by CERCLA.
RCRA and comparable state laws regulate the management of wastes. Current RCRA regulations specifically excludes 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 may be regulated by EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, spent solvents, laboratory wastes, and used oils, may be regulated as hazardous waste. Although the costs of managing solid and hazardous wastes may be significant, we do not expect to experience more burdensome costs than similarly situated companies involved in drilling operations in the Gulf Coast market.
The CAA, comparable state laws, and implementing regulations restrict the emission of air pollutants from various sources, and may require us to obtain permits for the construction, modification, or operation of certain projects or facilities and utilize 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.
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) and which include carbon dioxide and methane, may be contributing to the warming of the atmosphere resulting in climate change. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, are attracting increasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at international, national, regional and state levels.
In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2020. In the United States, federal legislation imposing restrictions on GHGs is under consideration. Proposed legislation has been introduced that would establish an economy-wide cap on emissions of GHGs and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their
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annual emissions. Legislation has also been considered that would establish taxes tied to GHG emissions. In addition, the EPA is taking steps to regulate GHGs as pollutants under the CAA. To-date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, which establishes a new comprehensive scheme requiring operators of stationary sources (including certain oil and natural gas production systems) in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; (ii) an “Endangerment Finding” final rule, effective January 14, 2010 which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, which allowed the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (PSD) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.
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.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS
We operate in six segments: Rental Tools, U.S. Barge Drilling, U.S. Drilling, International Drilling, Technical Services and Construction Contract. Information about our reportable segments and operations by geographic areas for the years ended December 31, 2012, 2011 and 2010 is set forth in Note 12 in the notes to the consolidated financial statements included in Item 8 of this report.
EXECUTIVE OFFICERS
Officers are elected each year by the board of directors following the annual meeting for a term of one year and until the election and qualification of their successors. The current executive officers of the Company and their ages, positions with the Company and business experience are presented below:
| Ÿ | Robert L. Parker Jr., 64, is the executive chairman of the board of directors. Mr. Parker joined the Company in 1973 as a contract representative, and was appointed manager of U.S. operations and a vice president later in 1973. He was elected executive vice president in 1976, and president and chief operating officer in 1977. In 1991, he was elected chief executive officer, was appointed chairman in 2006, and was appointed executive chairman in 2009 when he stepped down as chief executive officer. In the first quarter of 2012, Mr. Parker resumed the duties of president and chief executive officer until the Company hired Gary Rich as president and chief executive officer, effective October 1, 2012. Mr. Parker has been a director since 1973. |
| Ÿ | Gary Rich, 53,is the president and chief executive officer, effective October 1, 2012. Mr. Rich also serves as a member of the company’s board of directors. He is an industry veteran with over 30 years of global technical, commercial and operations experience. Mr. Rich came to Parker Drilling after a 25-year career with Baker Hughes Incorporated. Most recently, he served as vice president of global sales for Baker Hughes, and prior to this role, he served as president of that company’s European operations. Previously, Mr. Rich was president of Hughes Christensen Company (HCC), a division of Baker Hughes primarily focused on the production and distribution of drilling bits for the petroleum industry. |
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| Ÿ | W. Kirk Brassfield, 57, was elected senior vice president and chief financial officer in 2005. Mr. Brassfield joined the Company in 1998 as controller and principal accounting officer, and was appointed vice president, finance and accounting in 2004. From 1991 through 1998, Mr. Brassfield served in various positions, including subsidiary controller and director of financial planning of MAPCO Inc., a diversified energy company. From 1979 through 1991, Mr. Brassfield was employed at the public accounting firm KPMG. On February 11, 2013, we announced the departure of Mr. Brassfield, to be effective April 30, 2013. Mr. Brassfield will assist the Company in identifying his successor and will continue his duties as senior vice president and chief financial officer during a transition period extending through April 30, 2013, unless his successor is identified and the transition period is completed before that date. |
| Ÿ | Jon-Al Duplantier, 45,is the senior vice president and general counsel. Mr. Duplantier joined the Company in 2009 as vice president and general counsel. From 1995 to 2009, Mr. Duplantier served in several legal and business roles at ConocoPhillips, including senior counsel – Exploration and Production, managing counsel – Indonesia, executive assistant – Exploration and Production, and counsel – Dubai. Prior to joining ConocoPhillips, he served as a patent attorney for DuPont from 1992 to 1995. |
| Ÿ | David Farmer, 51, joined the Company in 2011 as vice president of operations. Mr. Farmer has over 20 years experience in the upstream oilfield services business working in executive, engineering, operational, marketing, account management, planning, and general management roles in Europe, the Middle East, and North and South America. From 1991 to 2011, Mr. Farmer served in various positions at Schlumberger, including vice president and global account director – Schlumberger Ltd. The Netherlands, vice president and general manager – Schlumberger Oilfield Service Qatar, global marketing manager – Schlumberger Drilling & Measurement Division, Houston, Texas. Most recently, Mr. Farmer was responsible for Demand Planning management and the development of long term tactical resource plans for Schlumberger’s Drilling & Measurement division. |
| Ÿ | Philip Agnew, 44, joined the Company in December 2010 as vice president of technical services. Mr. Agnew has more than 20 years’ experience in design, construction and project management. From 2003 to 2010, Mr. Agnew held the position of President at Aker MH, Inc., a business unit of Aker Solutions AS. From 1998 to 2003, Mr. Agnew served as Project Manager and then vice president – Project Development at Signal International (previously Friede Goldman Offshore; TDI-Halter LP; Texas Drydock, Inc.). Prior to his career at Signal International, Mr. Agnew served a variety of leadership roles at Schlumberger Sedco Forex International Resources, Interface Consulting International, Inc., and Brown & Root, Inc. |
Other Parker Drilling Company Officers
| Ÿ | J. Daniel Chapman, 42, joined the Company in 2009 as chief compliance officer and counsel. Prior to joining the Company, Mr. Chapman was employed by Baker Hughes from 2002 to 2009 where he served in several legal counsel positions including compliance counsel, international trade counsel, division counsel (drilling fluids), and global ethics and compliance director. Prior to 2002, Mr. Chapman was employed as a securities and mergers and acquisitions lawyer with the law firms of Freshfields (London) and King & Spalding (Atlanta and Houston). |
| Ÿ | Philip A. Schlom, 48, joined the Company in 2009 as principal accounting officer and corporate controller. From 2008 to 2009, he held the position of vice president and corporate controller for Shared Technologies Inc. From 1997 to 2008, Mr. Schlom held several senior financial positions at Flowserve Corporation, a leading manufacturer of pumps, valves and seals for the energy sector. From 1988 through 1997, Mr. Schlom worked at the public accounting firm PricewaterhouseCoopers. |
| Ÿ | David W. Tucker, 57, treasurer, joined the Company in 1978 as a financial analyst and served in various financial and accounting positions before being named chief financial officer of the Company’s wholly-owned subsidiary, Hercules Offshore Corporation, in February 1998. Mr. Tucker was named treasurer of the Company in 1999. |
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Available Information
We make available free of charge on our website atwww.parkerdrilling.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission (SEC). Additionally, these reports are available on an Internet website maintained by the SEC at www.sec.gov.
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, 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, you should know that 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 Business
Volatile oil and natural gas prices impact demand for our services. A decrease in demand for crude oil and natural gas or other factors may reduce demand for our services and substantially reduce our profitability or result in losses.
The success of our operations is significantly dependent upon the exploration and development activities of the major, independent and national oil and natural gas companies and large integrated service companies that comprise our customer base. Oil and natural gas prices and market expectations regarding potential changes in these prices can be extremely volatile. 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. Higher commodity prices do not necessarily result immediately in increased drilling activity because our customers’ expectations of future commodity prices typically drive demand for our drilling services.
Commodity prices and demand for our services also depends upon numerous factors which are beyond our control, including:
| Ÿ | the demand for oil and natural gas; |
| Ÿ | the cost of exploring for, producing and delivering oil and natural gas; |
| Ÿ | expectations regarding future energy prices; |
| Ÿ | advances in exploration, development and production technology; |
| Ÿ | the adoption or repeal of laws and government regulations, both in the United States and other countries; |
| Ÿ | the imposition or lifting of economic sanctions against certain countries, persons and other entities; |
| Ÿ | the number of ongoing and recently completed rig construction projects which may create overcapacity; |
| Ÿ | local and worldwide military, political and economic events, including events in the oil producing countries of Africa, the Middle East, Russia, Central Asia, Southeast Asia and Latin America; |
| Ÿ | the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain production levels and prices; |
| Ÿ | the level of production by non-OPEC countries; |
| Ÿ | weather conditions; |
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| Ÿ | expansion or contraction of worldwide economic activity, which affects levels of consumer and industrial demand; |
| Ÿ | the rate of discovery of new oil and natural gas reserves; |
| Ÿ | domestic and foreign tax policies; |
| Ÿ | acts of terrorism in the United States or elsewhere; |
| Ÿ | the development and use of alternative energy sources; and |
| Ÿ | the policies of various governments regarding exploration and development of their oil and natural gas reserves. |
The 2010 drilling rig accident in the U.S. Gulf of Mexico and its consequences may continue to adversely affect our operations.
On April 22, 2010, the Deepwater Horizon, a deepwater drilling rig that was operating in the U.S. GOM, sank after an apparent blowout and fire (Macondo well blowout). The Macondo well blowout resulted in a temporary moratorium on certain drilling activities in the GOM, drilling delays after the lifting of the moratorium and increased federal regulation. For example, the Bureau of Safety and Environmental Enforcement (BSEE) has issued regulations that require each operator to conduct a specific review of its operations and to certify compliance to the BSEE that mandate independent third-party verifications, that impose blowout preventer capability, testing and documentation obligations, and that outline standards for specific well control training for deepwater operations. The BSEE has noted that it may impose additional regulations and has stated that it has the legal authority to extend its regulatory reach to include contractors in addition to operators.
The Macondo well blowout and the resulting moratorium and increased regulation resulted in longer times to obtain required permits and significantly reduced offshore drilling operations in the GOM, which negatively affected our Rental Tools segment. Significant continuing delay in the issuance of drilling permits, the possibility of additional regulations and government oversight and the possibility of increased legal liability could cause additional floating rigs to depart the GOM, with fewer customers operating in the region. If this were to occur, the market for our rental tools and other services could be further adversely affected.
A slow recovery from an economic recession or 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 slow recovery from an economic recession in the United States or abroad, or a slowdown in economic activity 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. Our business depends to a significant extent on the level of international onshore drilling activity and GOM inland and offshore drilling activity for oil and natural gas. Depressed oil and natural gas prices from lower demand as a result of slow or negative economic growth would reduce the level of exploration, development and production activity, all of which could cause our revenues and margins to decline, decrease day rates and utilization of our rigs and limit our future growth prospects. Any significant decrease in dayrates or utilization of our rigs or use of our rental tools could materially reduce our revenue and profitability. In addition, current and potential customers who depend on financing for their drilling projects may be forced to curtail or delay projects and may also experience an inability to pay suppliers and service providers, including us. Likewise, a slow recovery from an economic recession in the United States or abroad could also 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.
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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:
| Ÿ | shortages of equipment or skilled labor; |
| Ÿ | unforeseen engineering problems; |
| Ÿ | unanticipated change orders; |
| Ÿ | work stoppages; |
| Ÿ | adverse weather conditions; |
| Ÿ | unexpectedly long delivery times for manufactured rig components; |
| Ÿ | unanticipated repairs to correct defects in construction not covered by warranty; |
| Ÿ | failure or delay of third-party equipment vendors or service providers; |
| Ÿ | unforeseen increases in the cost of equipment, labor or raw materials, particularly steel; |
| Ÿ | disputes with customers, shipyards or suppliers; |
| Ÿ | latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions; |
| Ÿ | financial or other difficulties with current customers at shipyards and suppliers; |
| Ÿ | loss of revenue associated with downtime to remedy malfunctioning equipment not covered by warranty; |
| Ÿ | unanticipated cost increases; |
| Ÿ | loss of revenue and payments of liquidated damages for downtime to perform repairs associated with defects, unanticipated equipment refurbishment and delays in commencement of operations; and |
| Ÿ | 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 revenue to us, and may also cause our customer to renegotiate the drilling contract for the rig or terminate or shorten the term of the contract under applicable late delivery clauses, if any. If one of these contracts is terminated, we may not be able to secure a replacement contract on as favorable terms, if at all. Additionally, actual expenditures for required upgrades or to refurbishment or construct rigs could exceed our planned capital expenditures, impairing our ability to service our debt obligations.
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
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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.
Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2012, we had:
| Ÿ | $479.2 million of long-term debt; |
| Ÿ | $27.8 million of operating lease commitments; and |
| Ÿ | $4.5 million of standby letters of credit. |
Our ability to meet our debt service obligations depends on our ability to generate positive cash flows from operations. We have in the past, and may in the future, incur negative cash flows from one or more segments of our operating activities. Our future cash flows from operating activities will be influenced by the demand for our drilling services, the utilization of our rigs, the dayrates that we receive for our rigs, demand for our rental tools, general economic conditions and financial, business 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:
| Ÿ | delay spending on capital projects, including maintenance projects and the acquisition or construction of additional rigs, rental tools and other assets; |
| Ÿ | sell equity securities, or assets; or |
| Ÿ | restructure or refinance our debt. |
Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, or if available, such additional indebtedness or equity financing may not be available on a timely basis, or on terms acceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale. Our ability to generate sufficient cash flow from operating activities to pay the principal of and interest on our indebtedness is subject to certain market conditions and other factors which are beyond our control.
Increases in the level of our debt and restrictions in the covenants contained in the instruments governing our debt could have important consequences to you. For example, they could:
| Ÿ | result in a reduction of our credit rating, which would make it more difficult for us to obtain additional financing on acceptable terms; |
| Ÿ | require us to dedicate a substantial portion of our cash flows from operating activities to the repayment of our debt and the interest associated with our debt; |
| Ÿ | limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, and create liens on our properties; |
| Ÿ | place us at a competitive disadvantage compared with our competitors that have relatively less debt; and |
| Ÿ | make us more vulnerable to downturns in our business. |
Our current operations and future growth may require significant additional capital, and the amount of our indebtedness could impair our ability to fund our capital requirements.
Our business requires substantial capital. Currently, we anticipate that our capital expenditures in 2013 will be between $150 to $175 million, including between $90 to $105 million for maintenance projects and investments in rental tools equipment. We may require additional capital in the event of growth opportunities, unanticipated maintenance requirements or significant departures from our current business plan.
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Additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in the indentures governing the 9.125% Senior Notes and the documentation governing our senior secured credit 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.
Certain of our contracts are subject to cancellation or delay by our customers without penalty and with little or no notice.
Certain of our contracts are subject to cancellation by our customers without penalty and with relatively little or no notice. When drilling market conditions are depressed, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower dayrate. 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 drilling contracts if we experience operational problems. If our equipment fails to function properly and cannot be repaired promptly, we will not be able to engage in drilling operations, and customers may have the right to terminate the drilling contracts. If a rig 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. Even 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 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 drilling contracts could materially reduce our revenue and profitability.
We rely on a small number of customers and 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 2012, our two largest customers, Exxon Neftegas Limited (ENL) and Schlumberger, accounted for approximately 11.8 percent and 10.4 percent, respectively of our total revenues. 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. 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 refuse to award new contracts to us.
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 business may possess greater financial resources than we do. Some of our competitors also are incorporated in countries that may provide them with significant tax advantages that are not available to us as a U.S. company and which may impair our ability to compete with them for many projects.
Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Many drilling and workover rigs can be moved from one region to another in response to changes in levels of activity, provided market conditions warrant, which may result in an oversupply of rigs in an area. Many competitors have constructed numerous rigs during periods of high energy prices and, consequently, the number of rigs available in some of the markets in which we operate has exceeded the demand for rigs for extended periods of time, resulting in intense price competition. Most drilling and workover 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 rig supply and high dayrates often followed by periods of low demand, excess rig supply and low dayrates. Periods of low demand and excess rig supply intensify the competition in the industry and often result in rigs 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 from one geographic location to
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another location; the cost of which may be substantial. If we experience reductions in dayrates or if we cannot keep our rigs operating, 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.
Our international operations are subject to governmental regulation and other risks.
We derive a significant portion of our revenues from our international operations. In 2012, we derived approximately 43 percent of our revenues from operations in countries outside the United States. Our international operations are subject to the following risks, among others:
| Ÿ | political, social and economic instability, war, terrorism and civil disturbances; |
| Ÿ | limitations on insurance coverage, such as war risk coverage, in certain areas; |
| Ÿ | expropriation, confiscatory taxation and nationalization of our assets; |
| Ÿ | 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; |
| Ÿ | increases in governmental royalties; |
| Ÿ | import-export quotas or trade barriers; |
| Ÿ | hiring and retaining skilled and experienced workers, many of whom are represented by foreign labor unions; |
| Ÿ | work stoppages; |
| Ÿ | damage to our equipment or violence directed at our employees, including kidnapping; |
| Ÿ | piracy of vessels transporting our people or equipment; |
| Ÿ | unfavorable changes in foreign monetary and tax policies; |
| Ÿ | solicitation by government officials for improper payments or other forms of corruption; |
| Ÿ | foreign currency fluctuations and restrictions on currency repatriation; |
| Ÿ | repudiation, nullification, modification or renegotiation of contracts; and |
| Ÿ | other forms of governmental regulation and economic conditions that are beyond our control. |
We currently have operations in 12 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 revenue and damage to equipment due to political violence. Civil and political disturbances in Syria, Tunisia, Egypt, Libya and other North African countries may affect our operations. During the fourth quarter of 2012 we began the process of moving two rigs out of Algeria and repositioning them for work in other markets. 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 justifiable.
Our international operations are subject to the laws and regulations of a number of foreign countries whose political, regulatory and judicial systems and regimes may differ significantly from those in the United States. Our ability to compete in international contract drilling 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 often results in disputes between us and
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governing authorities. The ultimate outcome of these disputes is never certain, and it is possible that the outcomes could have an adverse effect on our financial performance.
A portion of the workers we employ in our international operations are members of labor unions or otherwise subject to collective bargaining. We may not be able to hire and retain a sufficient number of skilled and experienced workers for wages and other benefits that we believe are commercially reasonable.
We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not take protective measures against exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. Given the international scope of our operations, we are exposed to risks of currency fluctuation and restrictions on currency repatriation. We attempt to limit the risks of currency fluctuation and restrictions on currency repatriation where possible by obtaining contracts payable in U.S. dollars or freely convertible foreign currency. In addition, some parties with which we do business could require that all or a portion of our revenues be paid in local currencies. Foreign currency fluctuations, therefore, could have a material adverse effect upon our results of operations and financial condition.
The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by the unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments may also impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. 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 and unscheduled operational downtime. Moreover, any failure to comply with applicable legal and regulatory trading obligations could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from governmental contracts, seizure of shipments and loss of import and export privileges.
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 do not purchase windstorm insurance for our inland barges in the GOM. We elected not to purchase such insurance. 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 well control, cratering, oil and natural gas well fires and explosions, natural disasters, pollution and mechanical failure. Our offshore operations also are subject to hazards inherent in marine operations, such as capsizing, sinking, grounding, collision and damage from severe weather conditions. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage. We have had accidents in the past demonstrating some of these hazards. We may not be able to insure against these risks or to obtain indemnification agreements 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 or for which we are not indemnified against, 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
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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, so to make the cost of such insurance prohibitive. For a description of our indemnification obligations and insurance, please read 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 damages can be repaired. In addition, our rigs in arctic regions can be affected by seasonal weather so severe, conditions are deemed unsafe to operate in.
Although not a hazard specific to our drilling operations, we could incur significant liability in the event of loss or damage to proprietary data of operators or third parties during our transmission of this valuable data.
Government regulations and environmental risks, which reduce our business opportunities and increase our operating costs, might become more stringent in the future.
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, may discourage our customers’ activities, reducing demand for our products and services. We may be liable for damages resulting from pollution of offshore waters and, under United States regulations, must establish financial responsibility in order to drill offshore. See Part I, 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 certain gases, commonly referred to as “greenhouse gases” (GHGs) and including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.
In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on the countries that had ratified it. International discussions are underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2020. In the United States, federal legislation imposing restrictions on GHGs is under consideration. In addition, the EPA is taking steps to regulate GHGs as pollutants under the Clean Air Act (the CAA). To date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, which establishes a new comprehensive scheme requiring operators of stationary sources (including certain oil and natural gas production systems) in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; (ii) an “Endangerment Finding” final rule, effective January 14, 2010, which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, which allowed the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (PSD) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.
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
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to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations.
We are regularly involved in litigation, some of which may be material.
We are regularly involved in litigation, claims and disputes incidental to our business, which at times may involve claims for significant monetary amounts, some of which would not be covered by insurance. We undertake all reasonable steps to defend ourselves in such lawsuits. Nevertheless, we cannot predict the ultimate outcome of such lawsuits and any resolution which is adverse to us could have a material adverse effect on our financial condition. See Note 13, “Commitments and Contingencies,” in Item 8 of this Form 10-K for a discussion of the material legal proceedings affecting us.
The proposed agreement in principle with the Department of Justice and the Securities and Exchange Commission relating to investigations of our possible violations of the Foreign Corrupt Practices Act may not become final in its proposed form and could be materially more adverse to us than currently anticipated.
As previously disclosed, we have engaged in settlement discussions with the United States Department of Justice (DOJ) and the United States Securities and Exchange Commission (SEC) related to parallel investigations that they conducted regarding possible violations of U.S. law, including the Foreign Corrupt Practices Act (FCPA), by us. We have reached an agreement in principle with the DOJ and the staff of the SEC to settle these matters. The agreement in principle is contingent upon the parties’ preparation and agreement on the language of the settlement documents, approval of the SEC’s civil settlement by its governing Commission and approval by a United States District Court. There can be no assurance that this proposed settlement will be finalized, or finalized on the terms currently agreed in principle, and we cannot provide assurances regarding if and when the court and/or the SEC’s governing Commission will approve the settlement.
If one or both of these approvals do not occur, the Company may enter further discussions with the DOJ and/or the SEC to resolve the investigated matters on different terms and conditions; such terms and conditions could include any of a broad range of civil and criminal sanctions under the FCPA and other laws and regulations, which they may seek to impose against corporations and individuals in appropriate circumstances. These include, but are not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. Any such disgorgement, fines, penalties, interest and other associated costs could be materially higher than the amounts that we have currently accrued. The DOJ and the SEC have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed. Recent civil and criminal settlements have included multi-million dollar fines, deferred prosecution agreements, guilty pleas, and other sanctions, including the requirement that the relevant corporation retain a monitor to oversee its compliance with the FCPA. In addition, corporations may have to end or modify existing business relationships. The Company could also face fines, sanctions and other penalties imposed by other regulatory authorities or in other legal actions. Any such fines, sanctions or penalties could impact the Company’s business operations and assets, particularly in jurisdictions outside the United States, and could have a material adverse impact on our business, results of operations, financial condition and liquidity.
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, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to
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a lesser extent, 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. For example, several state governments now require the disclosure of chemicals used in the fracturing process. The U.S. EPA has taken the position that some hydraulic fracturing operations are subject to permitting requirements under the Safe Drinking Water Act; has proposed new air emissions standards that would apply to well completion activities; is developing new standards for wastewater discharges associated with hydraulic fracturing; and has commenced a study on the impacts of hydraulic fracturing on groundwater. The Bureau of Land Management is also in the process of developing regulations for hydraulic fracturing activities that would be unique to federal lands. In addition, some jurisdictions have imposed an express or de facto ban on hydraulic fracturing. These and other developments could cause operational delays or increased costs in exploration and production, which could adversely affect the demand for our rental tools.
A cybersecurity incident could negatively impact our business and our relationships with customers.
If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data, having our business operations interrupted, and increased costs to prevent, respond to, or mitigate cybersecurity attacks. These risks could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition.
Risks Related to Our Common Stock
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, most of which are beyond our control, including the following:
| Ÿ | the other risk factors described in this Form 10-K, including changes in oil and natural gas prices; |
| Ÿ | a shortfall in rig utilization, operating revenue or net income from that expected by securities analysts and investors; |
| Ÿ | 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; |
| Ÿ | changes in actual or market expectations with respect to the amounts of exploration and development spending by oil and natural gas companies; |
| Ÿ | general conditions in the economy and in energy-related industries; |
| Ÿ | general conditions in the securities markets; |
| Ÿ | political instability, terrorism or war; and |
| Ÿ | the outcome of pending and future legal proceedings, investigations, tax assessments and other claims. |
A hostile takeover of our company would be difficult.
Some of the provisions of our Restated Certificate of Incorporation and of the Delaware General Corporation Law may make it difficult for a hostile suitor to acquire control of our company and to replace our incumbent management. For example, our Restated Certificate of Incorporation provides for a staggered Board of Directors and permits the Board of Directors, without stockholder approval, to issue additional shares of common stock or a new series of preferred stock.
Risks Related to our Debt Securities
We may not be able to repurchase our 9.125% Senior Notes upon a change of control.
Upon the occurrence of specific change of control events affecting us, the holders of our 9.125% Senior Notes will have the right to require us to repurchase our notes at 101 percent of their principal amount, plus
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accrued and unpaid interest. Our ability to repurchase our notes upon such a change of control event would be limited by our access to funds at the time of the repurchase and the terms of our other debt agreements. Upon a change of control event, we may be required immediately to repay the outstanding principal, any accrued interest on and any other amounts owed by us under our senior secured credit facilities, our notes and other outstanding indebtedness. The source of funds for these repayments would be our available cash or cash generated from other sources. However, we may not have sufficient funds available upon a change of control to make any required repurchases of this outstanding indebtedness.
In addition, the change of control provisions in the indenture governing our 9.125% Senior Notes may not protect the holders of our notes from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction, unless such a transaction constitutes a “Change of Control” under the indenture. Such a transaction may not involve a change in voting power or beneficial ownership or, even if it does, may not involve a change that constitutes a “Change of Control” as defined in the indenture that would trigger our obligation to repurchase the notes. Therefore, if an event occurs that does not constitute a “Change of Control” as defined in the indenture, we will not be required to make an offer to repurchase the notes and the holders may be required to continue to hold their notes despite the event.
The indenture for our 9.125% Senior Notes and our senior secured credit agreement impose significant operating and financial restrictions, which may prevent us from capitalizing on business opportunities and taking some actions.
The indenture governing our 9.125% Senior Notes and the agreement governing our senior secured credit facility impose significant operating and financial restrictions on us. These restrictions limit our ability to:
| Ÿ | make investments and other restricted payments, including dividends; |
| Ÿ | incur additional indebtedness; |
| Ÿ | create liens; |
| Ÿ | engage in sale leaseback transactions; |
| Ÿ | sell our assets or consolidate or merge with or into other companies; and |
| Ÿ | engage in transactions with affiliates. |
These limitations are subject to a number of important qualifications and exceptions. Our senior secured credit agreement also requires us to maintain ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage. These covenants may adversely affect our ability to finance our future operations and capital needs and to pursue available business opportunities. A breach of any of these covenants could result in a default with respect to the related indebtedness. If a default were to occur, the holders of our 9.125% Senior Notes and the lenders under our senior secured credit facility could elect to declare the indebtedness, together with accrued interest, immediately due and payable. If the repayment of the indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness.
DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements contained in this Form 10-K, other than statements of historical facts, are forward-looking statements for purposes of these provisions, including any statements regarding:
| Ÿ | stability of prices and demand for oil and natural gas; |
| Ÿ | levels of oil and natural gas exploration and production activities; |
| Ÿ | demand for contract drilling and drilling-related services and demand for rental tools; |
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| Ÿ | our future operating results and profitability; |
| Ÿ | our future rig utilization, dayrates and rental tools activity; |
| Ÿ | entering into new, or extending existing, drilling contracts and our expectations concerning when our rigs will commence operations under such contracts; |
| Ÿ | growth through acquisitions of companies or assets; |
| Ÿ | organic growth of our operations; |
| Ÿ | construction or upgrades of rigs and expectations regarding when these rigs will commence operations; |
| Ÿ | capital expenditures for acquisition of rigs, construction of new rigs or major upgrades to existing rigs; |
| Ÿ | entering into joint venture agreements; |
| Ÿ | our future liquidity; |
| Ÿ | the outcome of pending or future legal proceedings, investigations, tax assessments and other claims; |
| Ÿ | the availability of insurance coverage for pending or future claims; |
| Ÿ | the enforceability of contractual indemnification in relation to pending or future claims; |
| Ÿ | availability and sources of funds to reduce our debt and expectations of when debt will be reduced; and |
| Ÿ | compliance with covenants under our debt agreements. |
In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certain assumptions and analyses made by our management in light of their experience and perception of historical trends, current conditions, expected future developments and other factors they believe are relevant. Although our management believes that their assumptions are reasonable based on information currently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. The following factors, as well as any other cautionary language included in this Form 10-K, provide examples of risks, uncertainties and events that may cause our actual results to differ materially from the expectations we describe in our forward-looking statements:
| Ÿ | worldwide economic and business conditions that adversely affect market conditions and/or the cost of doing business including Euro country failures and downgrades; |
| Ÿ | our inability to access the credit or bond markets; |
| Ÿ | U.S credit market volatility resulting from the U.S national debt and potential further downgrades of the U.S. credit rating; |
| Ÿ | the U.S. economy and the demand for natural gas; |
| Ÿ | low U.S. natural gas prices could adversely affect U.S. drilling and our barge rig and rental tools businesses; |
| Ÿ | worldwide demand for oil; |
| Ÿ | fluctuations in the market prices of oil and natural gas, including the inability or unwillingness of our customers to fund drilling programs in low price cycles; |
| Ÿ | imposition of unanticipated trade restrictions; |
| Ÿ | unanticipated operating hazards and uninsured risks; |
| Ÿ | political instability, terrorism or war; |
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| Ÿ | governmental regulations, including changes in accounting rules or tax laws or ability to remit funds to the U.S., that adversely affect the cost of doing business; |
| Ÿ | changes in the tax laws that would allow double taxation on foreign sourced income; |
| Ÿ | the outcome, including the finalization of a proposed settlement, related to our investigation and the parallel investigations by the SEC and the DOJ into possible violations of U.S. law, including the FCPA; |
| Ÿ | adverse environmental events; |
| Ÿ | adverse weather conditions; |
| Ÿ | global health concerns; |
| Ÿ | changes in the concentration of customer and supplier relationships; |
| Ÿ | ability of our customers and suppliers to obtain financing for their operations; |
| Ÿ | ability of our customers to fund drilling plans with low commodity prices; |
| Ÿ | unexpected cost increases for new construction and upgrade and refurbishment projects; |
| Ÿ | delays in obtaining components for capital projects and in ongoing operational maintenance and equipment certifications; |
| Ÿ | shortages of skilled labor; |
| Ÿ | unanticipated cancellation of contracts by operators; |
| Ÿ | breakdown of equipment; |
| Ÿ | other operational problems including delays in start-up or commissioning of rigs; |
| Ÿ | changes in competition; |
| Ÿ | the effect of litigation and contingencies; and |
| Ÿ | other similar factors, some of which are discussed in documents referred to or incorporated by reference into this Form 10-K and our other reports and filings with the SEC. |
Each forward-looking statement speaks only as of the date of this Form 10-K, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Before you decide to invest in our securities, you should be aware that the occurrence of the events described in these risk factors and elsewhere in this Form 10-K could have a material adverse effect on our business, results of operations, financial condition and cash flows.
| ITEM | 1B. UNRESOLVED STAFF COMMENTS |
None.
| ITEM | 2. PROPERTIES |
We lease corporate headquarters office space in Houston, Texas and own our Rental Tools headquarters office in New Iberia, Louisiana. Additionally, we own and/or lease office space and operating facilities in various locations including facilities where we hold an inventory of rental tools and locations with close proximity to where we provide service 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 following table shows, as of December 31, 2012, the locations and drilling depth ratings of our rigs available for service:
Name | Type (4) | Year entered into service/ upgraded | Drilling depth rating (in feet) | Location | ||||||||
International | ||||||||||||
Eastern Hemisphere (1) | ||||||||||||
Rig 231 | L | 1981/1997 | 13,000 | Indonesia | ||||||||
Rig 253 | L | 1982/1996 | 15,000 | Indonesia | ||||||||
Rig 188 | L | 1979/2003 | 18,000 | New Zealand | ||||||||
Rig 246 | L | 1981/1998 | 18,000 | New Zealand | ||||||||
Rig 226 | HH | 1989/2010 | 18,000 | Papua New Guinea | ||||||||
Rig 264(3) | L | 2007 | 20,000 | Algeria | ||||||||
Rig 265(3) | L | 2007 | 20,000 | Algeria | ||||||||
Rig 107 | L | 1983/2009 | 15,000 | Kazakhstan | ||||||||
Rig 216 | L | 2001/2009 | 25,000 | Kazakhstan | ||||||||
Rig 247 | L | 1981/2008 | 18,000 | Kazakhstan | ||||||||
Rig 249 | L | 2000/2009 | 25,000 | Kazakhstan | ||||||||
Rig 257 | B | 1999/2010 | 30,000 | Kazakhstan | ||||||||
Rig 258 | L | 2001/2009 | 25,000 | Kazakhstan | ||||||||
Rig 269 | L | 2008 | 21,000 | Kazakhstan | ||||||||
Latin America | ||||||||||||
Rig 268 | L | 1978/2009 | 30,000 | Colombia | ||||||||
Rig 271 | L | 1982/2009 | 30,000 | Colombia | ||||||||
Rig 121 | L | 1980/2007 | 18,000 | Colombia | ||||||||
Rig 53 | B | 1978/2007 | 25,000 | Mexico | ||||||||
Rig 122 | L | 1980/2008 | 18,000 | Mexico | ||||||||
Rig 165 | L | 1978/2007 | 30,000 | Mexico | ||||||||
Rig 221 | L | 1982/2007 | 30,000 | Mexico | ||||||||
Rig 256 | L | 1978/2007 | 25,000 | Mexico | ||||||||
Rig 266 | L | 2008 | 20,000 | Mexico | ||||||||
Rig 267 | L | 2008 | 20,000 | Mexico | ||||||||
U.S. Land and Barge Drilling(1)(2) | ||||||||||||
Rig 8 | B | 1978/2007 | 14,000 | GOM | ||||||||
Rig 20 | B | 1981/2007 | 13,000 | GOM | ||||||||
Rig 21 | B | 1979/2012 | 14,000 | GOM | ||||||||
Rig 12 | B | 1979/2006 | 18,000 | GOM | ||||||||
Rig 15 | B | 1978/2007 | 15,000 | GOM | ||||||||
Rig 50 | B | 1981/2006 | 20,000 | GOM | ||||||||
Rig 51 | B | 1981/2008 | 20,000 | GOM | ||||||||
Rig 54 | B | 1980/2006 | 25,000 | GOM | ||||||||
Rig 55(5) | B | 1981/2001 | 25,000 | GOM | ||||||||
Rig 72 | B | 1982/2005 | 30,000 | GOM | ||||||||
Rig 76 | B | 1977/2009 | 30,000 | GOM | ||||||||
Rig 77 | B | 2006/2006 | 30,000 | GOM | ||||||||
Rig 270 | L | 2011 | 21,000 | Louisiana | ||||||||
Rig 273 | L | 2012 | 18,000 | Alaska | ||||||||
| 1) | Excludes five rigs classified for accounting purposes as assets held for sale located in the Eastern Hemisphere as of December 31, 2012, and one rig previously located in GOM, sold in December 2012. |
| 2) | Excludes Land Rig 272 in Alaska which began drilling in late February. |
| 3) | These rigs were in the process of relocation out of Algeria at the end of 2012. |
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| 4) | Type is defined as: L — land rig; B — barge rig; HH — heli-hoist land rig. |
| 5) | This rig requires additional investment to make it available for service. |
The following table presents our utilization rates and rigs available for service for the years ended December 31, 2012 and 2011:
| December 31, | ||||||||
| 2012 | 2011 | |||||||
U.S. Land & Barge Rigs (4) | ||||||||
U.S. Barge Drilling Rigs | ||||||||
Rigs available for service (1) | 13.0 | 13.0 | ||||||
Utilization rate of rigs available for service (2) | 78 | % | 72 | % | ||||
U.S. Drilling Rigs | ||||||||
Rigs available for service (1) | 1.1 | 1.0 | ||||||
Utilization rate of rigs available for service (2) | 5 | % | 0 | % | ||||
International Land & Barge Rigs | ||||||||
Eastern Hemisphere Region | ||||||||
Rigs available for service (1)(3) | 15.5 | 16.0 | ||||||
Utilization rate of rigs available for service (2) | 37 | % | 35 | % | ||||
Latin America Region | ||||||||
Rigs available for service (1) | 10.0 | 10.0 | ||||||
Utilization rate of rigs available for service (2) | 67 | % | 70 | % | ||||
Total International Land & Barge Rigs | ||||||||
Rigs available for service (1) | 25.5 | 26.0 | ||||||
Utilization rate of rigs available for service (2) | 49 | % | 48 | % | ||||
| 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 365 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. |
| 3) | As of December 31, 2012 five rigs are excluded from the marketable rig count and classified as assets held for sale. |
| 4) | As of December 31, 2012 the Company has one-new build rig undergoing commissioning and construction completion in Alaska. The rig completed client acceptance testing and began drilling in February 2013. This rig is not included in rigs available for service in the table above. |
| ITEM | 3. LEGAL PROCEEDINGS |
For information on Legal Proceedings, see Note 13, Commitments and Contingencies, in the notes to the consolidated financial statements included in Item 8 of this annual report on Form 10-K, 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 is listed for trading on the New York Stock Exchange under the symbol “PKD.” The following table sets forth the high and low sales prices per share of our common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:
| 2012 | 2011 | |||||||||||||||
Quarter | High | Low | High | Low | ||||||||||||
First | $ | 7.62 | $ | 5.69 | $ | 7.10 | $ | 3.98 | ||||||||
Second | $ | 6.27 | $ | 4.19 | $ | 7.45 | $ | 5.36 | ||||||||
Third | $ | 4.91 | $ | 4.00 | $ | 6.95 | $ | 4.17 | ||||||||
Fourth | $ | 4.60 | $ | 3.61 | $ | 7.48 | $ | 3.60 | ||||||||
Most of our stockholders maintain their shares as beneficial owners in “street name” accounts and are not, individually, stockholders of record. As of February 26, 2013, our common stock was held by 1,634 holders of record and we had an estimated 19,518 beneficial owners.
Our existing senior secured revolving credit agreement and the indenture for the 9.125% Senior Notes restrict the payment of dividends. We have not in the past paid dividends on our common stock and 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. When restricted stock awarded by the Company becomes taxable compensation to personnel, shares may be withheld to satisfy the associated withholding tax liabilities. Information on our purchases of equity securities by means of such share withholdings is provided in the table below:
| Issuer Purchases of Equity Securities | ||||||||
Period | Total Number of Shares Purchased | Average Price Paid Per Share | ||||||
October 1-31, 2012 | 52,768 | $ | 4.36 | |||||
November 1-30, 2012 | 3,527 | $ | 4.28 | |||||
December 1-31, 2012 | 7,645 | $ | 4.34 | |||||
|
| |||||||
Total | 63,940 | $ | 4.35 | |||||
|
| |||||||
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| ITEM 6. | SELECTED FINANCIAL DATA |
The following table presents selected historical consolidated financial data derived from the audited financial statements of Parker Drilling Company for each of the five years in the period ended December 31, 2012. The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes appearing elsewhere in this Form 10-K.
| Year Ended December 31, | ||||||||||||||||||||
| 2012 | 2011(1) | 2010 | 2009 | 2008(2) | ||||||||||||||||
| (Dollars in Thousands, Except Per Share Amounts) | ||||||||||||||||||||
Income Statement Data | ||||||||||||||||||||
Total revenues | $ | 677,982 | $ | 686,646 | $ | 659,475 | $ | 752,910 | $ | 829,842 | ||||||||||
Total operating income (loss) | 106,823 | (42,639 | ) | 45,107 | 39,322 | 59,180 | ||||||||||||||
Equity in loss of unconsolidated joint venture, net of tax | — | — | — | — | (1,105 | ) | ||||||||||||||
Other expense, net | (35,846 | ) | (22,773 | ) | (33,602 | ) | (29,495 | ) | (28,405 | ) | ||||||||||
Income tax expense (benefit) | 33,879 | (14,767 | ) | 26,213 | 560 | 6,942 | ||||||||||||||
Net income (loss) | 37,098 | (50,645 | ) | (14,708 | ) | 9,267 | 22,728 | |||||||||||||
Net income (loss) attributable to controlling interest | 37,313 | (50,451 | ) | (14,461 | ) | 9,267 | 22,728 | |||||||||||||
Basic earnings per share: | ||||||||||||||||||||
Income (loss) from continuing operations | $ | 0.32 | $ | (0.43 | ) | $ | (0.13 | ) | $ | 0.08 | $ | 0.20 | ||||||||
Net income (loss) | $ | 0.32 | $ | (0.43 | ) | $ | (0.13 | ) | $ | 0.08 | $ | 0.20 | ||||||||
Diluted earnings per share: | ||||||||||||||||||||
Income (loss) from continuing operations | $ | 0.31 | $ | (0.43 | ) | $ | (0.13 | ) | $ | 0.08 | $ | 0.20 | ||||||||
Net income (loss) | $ | 0.31 | $ | (0.43 | ) | $ | (0.13 | ) | $ | 0.08 | $ | 0.20 | ||||||||
Balance Sheet Data | ||||||||||||||||||||
Cash and cash equivalents | $ | 87,886 | $ | 97,869 | $ | 51,431 | $ | 108,803 | $ | 172,298 | ||||||||||
Property, plant and equipment, net | 786,158 | 719,809 | 816,147 | 716,798 | 675,548 | |||||||||||||||
Assets held for sale | 11,550 | 5,315 | 5,287 | — | — | |||||||||||||||
Total assets | 1,255,733 | 1,216,246 | 1,274,555 | 1,243,086 | 1,205,720 | |||||||||||||||
Total long-term debt including current portion of long-term debt | 479,205 | 482,723 | 472,862 | 423,831 | 441,394 | |||||||||||||||
Total equity | 590,633 | 544,050 | 588,066 | 595,899 | 582,172 | |||||||||||||||
| 1) | The 2011 results reflect a $170.0 million ($109.1 million, net of taxes of $60.9 million) non-cash pretax impairment charge related to our two AADUs located in Alaska. See Note 2 to the Consolidated Financial Statements in Item 8 of this Form 10-K. |
| 2) | The 2008 results reflect a $100.3 million non-cash pretax charge for impairment of goodwill. |
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
OVERVIEW AND OUTLOOK
Overview
We made significant progress in 2012 on several important projects aimed at improving the competitive position of some of our key operations, while sustaining our operating performance under challenging market conditions.
By mid-year 2012, we had achieved significant growth in revenues and earnings, with contributions from our domestic drilling, rental tools, and international drilling operations. This was primarily driven by the expansion of drilling activity in the U.S. land and GOM markets and steady and uninterrupted work for the portion of our international rig fleet that was under contract. During the second half of the year, drilling activity in the U.S. land and GOM markets underwent a slow and steady decline. This led to reduced demand and increased competitive conditions for our rental tools and barge drilling businesses. At the same time, international and local operators reduced their drilling programs in several of the international markets we serve, providing fewer opportunities to maintain our rig fleet utilization.
As we worked on operational responses to the changes in market conditions, we also were focused on completing or progressing several projects that are important to our future success. Included among these were: completing construction of our new AADU rigs, initiating the repositioning of our international rig fleet for more sustainable and profitable performance, and maximizing the organic growth opportunities of our rental tools business.
| Ÿ | By year-end 2012, we had successfully commissioned Rig 273, the first of our two AADU rigs developed to safely and efficiently perform in environmentally sensitive, harsh arctic environments. Rig 273 commenced operating in mid-December. Our second rig completed client acceptance testing and began drilling in February 2013. Both AADU rigs are expected to be cash flow contributors during 2013. The successful development of the AADU rigs marks an important milestone in our history of supporting responsible arctic drilling through innovative technologies and reliable performance. We believe this level of arctic expertise is unique in our industry and are committed to leveraging this knowledge to benefit our clients going forward. |
| Ÿ | Actions to achieve sustainable improvement in our international drilling rig fleet utilization continued throughout 2012. Of particular focus was the group of nine rigs serving the Kazakhstan market. At one point in 2012, only two of those rigs were under contract. By year-end, three rigs were under contract in Kazakhstan, a contract for a fourth rig to work in Kazakhstan was being negotiated, and several rigs were under consideration for work in other markets. In February, 2013, we contracted two of the rigs in Kazakhstan for work in the Kurdistan region of Iraq and began preparing them for mobilization. |
| Ÿ | Our efforts to improve overall fleet utilization included consideration of the strategic value of the geographic position of all our rigs. During 2012, we undertook the relocation of our rigs in North Africa, moving our two rigs out of Algeria to reposition them for work other markets. In addition, we worked to expand our business opportunities in the Latin America region, a key market we believe can provide long-term profitable growth. |
| Ÿ | In 2012, we continued to make investments in our Rental Tools segment. This included purchases of drill pipe and related products to meet the increased demand for drilling activity in several oil and natural gas liquids-rich plays in the U.S. land market, and building our capacity to participate in the growing GOM offshore drilling market by purchasing more of the tubular products unique to that market. We invested $62.0 million of capital in the rental tools business in 2012, most of which was for new equipment to serve these two opportunities. |
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Other achievements in 2012 that contributed to our results and are expected to have an impact on future performance were:
| • | We continued to hold the lead position in the U.S. GOM barge drilling market, measured by barge drilling rigs working. According to industry compiled information, over 62 percent of all wells drilled by barge rigs in the inland waters of the GOM during 2012 were drilled by Parker rigs. |
| • | We continued our involvement in the development of the ENL Berkut platform, providing construction oversight of the drilling package during the platform’s shipyard construction phase, with expectation that the rig will move to Sakhalin Island, Russia for operations. |
Outlook
Our markets are highly cyclical, driven by, among other things, our customers’ responses to price trends in oil and natural gas, the level of energy exploration and resource development spending (E&P spending) in the domestic and international markets in which we operate, and technological advancements in energy exploration and production. We expect oil and natural gas prices to remain near current levels or improve modestly in 2013. Recent industry surveys project worldwide E&P spending to rise, with the greatest increases in offshore exploration and development and the Middle East land market. Meanwhile, enhanced production in the U.S. of oil natural gas liquids and natural gas, brought about by the technological advancements accompanying the application of horizontal drilling and hydraulic fracturing, is expected to lead to continued drilling activity in the U.S. land market.
Based on recent market trends, competitive conditions and the state of our operations, we anticipate to see improvements in operating results as the year progresses. The growing level of drilling activity in the deep water U.S. GOM should provide expanding business opportunities for our rental tools operations that will offset some of the impact of slowing activity and more competitive conditions in the U.S. land drilling market. We expect to continue to lead in the GOM barge drilling market and to use our performance-driven customer focus to maintain strong utilization and dayrates.
Our two AADU rigs are operating under contract on the Alaskan North Slope and they are projected to generate reliable cash flow during the year. We have been transforming our international drilling activities, focused both on enhancing the deployment of the assets we have in the field and on leveraging our drilling expertise through O&M contracts. As we execute this transformation and develop opportunities to employ our international rig fleet further repositioning of rigs may lead to uneven operating results. As we make progress in expanding our contract drilling business, we expect the contribution to Parker’s results to improve.
RESULTS OF OPERATIONS
Year Ended December 31, 2012 Compared with Year Ended December 31, 2011
Revenues of $678.0 million for the year ended December 31, 2012 decreased $8.7 million, or 1.3%, from the comparable 2011 period. The years ended December 31, 2012 and 2011 included construction contract revenues of zero and $9.6 million, respectively, for the Liberty rig construction project that was suspended by BP in November 2010. Excluding that individual project, revenues from ongoing operations for the year ended December 31, 2012 would have been approximately the same as in 2011. Operating gross margin, including depreciation and amortization decreased 3.5% to $150.9 million for the year ended December 31, 2012 as compared to $156.4 million for the year ended December 31, 2011.
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The following is an analysis of our operating results for the comparable periods:
| Year Ended December 31, | ||||||||||||||||
| 2012 | 2011 | |||||||||||||||
| (Dollars in Thousands) | ||||||||||||||||
Revenues: | ||||||||||||||||
Rental Tools | $ | 246,900 | 36 | % | $ | 237,068 | 35 | % | ||||||||
U.S. Barge Drilling | 123,672 | 18 | % | 93,763 | 14 | % | ||||||||||
U.S. Drilling | 1,387 | 1 | % | — | 0 | % | ||||||||||
International Drilling | 291,772 | 43 | % | 318,482 | 46 | % | ||||||||||
Technical Services | 14,251 | 2 | % | 27,695 | 4 | % | ||||||||||
Construction Contract | — | 0 | % | 9,638 | 1 | % | ||||||||||
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Total revenues | 677,982 | 100 | % | 686,646 | 100 | % | ||||||||||
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Operating gross margin: | ||||||||||||||||
Rental Tools gross margin excluding depreciation and amortization | 158,016 | 64 | % | 162,577 | 69 | % | ||||||||||
U.S Barge Drilling gross margin excluding depreciation and amortization | 54,267 | 44 | % | 28,620 | 31 | % | ||||||||||
U.S. Drilling gross margin excluding depreciation and amortization | (8,151 | ) | n/a | (1,692 | ) | n/a | ||||||||||
International Drilling gross margin excluding depreciation and amortization | 59,995 | 21 | % | 72,891 | 23 | % | ||||||||||
Technical Services gross margin | (209 | ) | n/a | 5,335 | 19 | % | ||||||||||
Construction Contract gross margin | — | n/a | 771 | 8 | % | |||||||||||
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Total operating gross margin excluding depreciation and amortization | 263,918 | 39 | % | 268,502 | 39 | % | ||||||||||
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Depreciation and amortization | (113,017 | ) | (112,136 | ) | ||||||||||||
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Total operating gross margin | 150,901 | 156,366 | ||||||||||||||
General and administrative expense | (46,052 | ) | (31,314 | ) | ||||||||||||
Impairments and other charges | — | (170,000 | ) | |||||||||||||
Provision for reduction in carrying value of certain assets | — | (1,350 | ) | |||||||||||||
Gain on disposition of assets, net | 1,974 | 3,659 | ||||||||||||||
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Total operating income | $ | 106,823 | $ | (42,639 | ) | |||||||||||
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Operating gross margins, excluding depreciation and amortization, are computed as revenues less direct operating expenses, excluding 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 amounts and operating gross margin percentages should not be used as a substitute for those amounts reported under generally accepted accounting principles in the U.S. (U.S. GAAP). However, we monitor our business segments based on several criteria, including operating gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by segment. Such operating gross margin amounts are reconciled to our most comparable U.S. GAAP measure as follows:
| Rental Tools | U.S. Barge Drilling | U.S. Drilling | International Drilling | Technical Services | Construction Contract(2) | |||||||||||||||||||
| (Dollars in Thousands) | ||||||||||||||||||||||||
Year Ended December 31, 2012 | ||||||||||||||||||||||||
Operating gross margin(1) | $ | 113,899 | $ | 39,774 | $ | (15,168 | ) | $ | 12,642 | $ | (246 | ) | $ | — | ||||||||||
Depreciation and amortization | 44,117 | 14,493 | 7,017 | 47,353 | 37 | — | ||||||||||||||||||
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Operating gross margin excluding depreciation and amortization | $ | 158,016 | $ | 54,267 | $ | (8,151 | ) | $ | 59,995 | $ | (209 | ) | $ | — | ||||||||||
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Year Ended December 31, 2011 | ||||||||||||||||||||||||
Operating gross margin(1) | $ | 120,822 | $ | 11,116 | $ | (3,915 | ) | $ | 22,237 | $ | 5,335 | $ | 771 | |||||||||||
Depreciation and amortization | 41,755 | 17,504 | 2,223 | 50,654 | — | — | ||||||||||||||||||
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Operating gross margin excluding depreciation and amortization | $ | 162,577 | $ | 28,620 | $ | (1,692 | ) | $ | 72,891 | $ | 5,335 | $ | 771 | |||||||||||
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| (1) | Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense. |
| (2) | The Construction Contract segment does not incur depreciation and amortization. |
Operations
Rental Tools
Rental Tools segment revenues increased $9.8 million, or 4.1%, to $246.9 million for the year ended December 31, 2012 compared to revenues for the year ended December 31, 2011. The increase is primarily due to an increase in rentals to offshore GOM customers and greater tool sales and repair revenues. This was partially offset by the impact of soft U.S. natural gas prices that led to reduced demand from the U.S. land drilling market and lower rental tools utilization in key operating areas.
Rental Tools segment operating gross margin, excluding depreciation and amortization, decreased by $4.6 million, or 2.8%, for the year ended December 31, 2012 compared with operating gross margin, excluding depreciation and amortization, for the year ended December 31, 2011, primarily due to increased price competition in key U.S. land drilling markets, and the impact of an increase in lower-margin tools sales and repair revenues.
U.S. Barge Drilling
U.S. Barge Drilling segment revenues increased $29.9 million, or 31.9%, to $123.7 million for the year ended December 31, 2012, compared with revenues for the year ended December 31, 2011. The increase in revenues was primarily due to an increase in rig fleet utilization and overall higher average dayrates for 2012. Both of these factors reflect a general increase in overall drilling activity in the U.S. GOM shallow water drilling market. Additionally, our dayrates benefit from our ability to renegotiate day rates during multi-well contracts based on our ability to deliver higher levels of performance.
U.S. Barge Drilling segment operating gross margin, excluding depreciation and amortization, increased $25.6 million or 89.6% to $54.3 million for the year ended December 31, 2012, compared with segment
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operating gross margin, excluding depreciation and amortization, for the year ended December 31, 2011. This increase is primarily a result of overall improved rig fleet utilization and average dayrates and the continued control of operating costs.
U.S. Drilling
U.S. Drilling segment began generating revenue in early December 2012 as the first of the two AADU rigs commenced drilling operations. The second rig completed client acceptance testing and began drilling in February 2013. Revenues were $1.4 million and zero for the years ended December 31, 2012 and 2011, respectively. The introduction of these rigs to the Alaskan North Slope is expected to improve drilling efficiency, operating consistency and safety in this remote and challenging environment.
U.S. Drilling segment operating gross margin, excluding depreciation and amortization, was a loss of $8.2 million and $1.7 million for the years ended December 31, 2012 and 2011, respectively. Operating expenses include start-up costs associated with re-entering the Alaskan market, such as salaries and employee hiring-related expenditures, training and rental of facilities in Alaska to support our operations. Additionally, early in the third quarter of 2012 we began incurring depreciation expense and ceased capitalizing interest costs related to one of the rigs when it was presented to the customer to begin the acceptance testing process.
International Drilling
International Drilling segment revenues decreased $26.7 million, or 8.4%, to $291.8 million for the year ended December 31, 2012, compared with the year ended December 31, 2011. The lower revenues are primarily due to a decrease in revenue generated by our O&M contracts and a decline in our drilling revenues generated through the operation of rigs that we own.
O&M revenues decreased to $108.3 million, or 14.7% for the year ended December 31, 2012 compared to $127.0 million for the year ended December 31, 2011. The decrease in revenues was primarily due to the completion in 2011 of a drilling rig relocation project in Sakhalin Island, Russia and lower rates associated with our services contracts in Sakhalin Island. This was partially offset by increased operating and reimbursable revenues associated with the Orlan platform contract as it moved from warm-stack mode to fully-operational mode during 2012, the benefits of a new one-rig service contract in China, and the operation during much of 2012 of a customer-owned rig in Papua New Guinea. O&M projects included $31.3 million and $51.9 million of reimbursable costs for the years ended December 31, 2012 and 2011. Reimbursable costs add to revenues but have little direct impact on operating margins.
Revenues related to Parker-owned rigs decreased to $183.5 million or 4.2% for the year ended December 31, 2012 compared with $191.5 million for the year ended December 31, 2011. Revenues declined in the Eastern Hemisphere region primarily due to lower utilization of our arctic-class barge rig in the Caspian Sea and reduced dayrates on our rig in Papua New Guinea. The decrease was partially offset by increased revenues in Algeria as a result of the mobilization and start-up of two rigs during 2012 and a contribution from demobilization fees in the Latin America region as two rigs completed work during the year.
International Drilling operating gross margin, excluding depreciation and amortization, decreased $12.9 million, or 17.7%, to $60.0 million for the year ended December 31, 2012, compared with $72.9 million for the year ended December 31, 2011. The decrease in operating gross margin for the year ended December 31, 2012 was due to decreased margins for both our O&M operations and our Parker-owned rig operations. Operating margins generated by our O&M operations were $20.7 million and $25.3 million for the years ended December 31, 2012 and 2011, respectively. The decrease is primarily due to a decrease in handling fees associated with lower reimbursable costs charged back to customers and lower project management fees related to the drilling rig relocation project in Sakhalin Island, Russia that was completed prior to December 31, 2011 and lower rates associated with our service contracts in Sakhalin Island as we transitioned from higher value operating contracts to cost-plus contracts during 2012. This was partially offset by the gross margins associated with the Orlan platform contract as it moved from warm-stack mode to fully-operational mode during 2012 and the benefits of a new one-rig service contract in China.
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Our margins related to Parker-owned rigs were $39.2 million and $47.6 million for the years ended December 31, 2012 and 2011, respectively. The decrease in operating gross margins was primarily the result of lower rig utilization related to our arctic-class barge rig in the Caspian Sea and a non-cash charge to reserve certain value-added tax assets resulting from a strategic decision to move two rigs out of the Kazakhstan market. Partially offsetting this decrease were increased operating gross margins resulting from the start-up of two rigs in Algeria during 2012 and increased utilization and demobilization revenues with minimal demobilization costs in Latin America. In addition, results for 2011 included $1.9 million of expense related to equity tax assessments in Latin America.
Technical Services
Technical Services segment revenues decreased $13.4 million, or 48.5%, to $14.3 million for the year ended December 31, 2012, compared with $27.7 million for the year ended December 31, 2011. This decrease was primarily due to expiration of the “pre-operations” phase of the Liberty project at the end of the second quarter of 2011 and the transition of the Berkut platform project from its engineering phase to a less revenue-intensive construction oversight and assistance phase. Also contributing to the decrease was the completion of a pre-FEED project at the end of the second quarter of 2012.
Operating gross margin for this segment decreased by $5.5 million to a loss of $0.2 million for the year ended December 31, 2012, compared with the year ended December 31, 2011. The decrease in operating gross margin was primarily due to the completion of a pre-FEED project at the end of the second quarter of 2012, the transition of the Berkut platform project into a less revenue-intensive construction oversight and assistance phase, and the costs to retain technical capabilities as we transition between projects. The Technical Services segment incurs minimal depreciation and amortization primarily related to office furniture and fixtures.
Construction Contract
This segment includes only the Liberty extended-reach drilling rig construction project. Construction Contract segment revenues were zero for the year ended December 31, 2012 compared with $9.6 million for the year ended December 31, 2011. This segment reported zero and $0.8 million operating gross margin for the years ended December 31, 2012 and December 31, 2011, respectively. The operating gross margin generated during the year ended December 31, 2011 resulted from the preliminary close-out of the Liberty project and recognition of final percentage of completion revenues. The Construction Contract segment does not incur depreciation and amortization.
The Liberty rig construction contract was a fixed fee and reimbursable contract that we accounted for on a percentage of completion basis. As of December 31, 2011, we had recognized $335.5 million in project-to-date revenues. Over the life of the contract, we recognized $11.7 million of margin on the contract.
For more information about the Liberty project, see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations — Other Matters — “Liberty Project Status.”
Other Financial Data
During the fourth quarter of 2011 we recorded a non-cash pre-tax impairment charge of $170.0 million ($109.1 million, net of taxes of $60.9 million) to adjust our AADU rigs to their fair value from the existing net book value (see Note 2 to the Consolidated Financial Statements). In 2011, we recognized a $1.4 million reduction in carrying value of assets related to a final settlement of a customer bankruptcy matter as it was deemed that the Company’s rights to mineral reserves no longer supported the outstanding receivable.
Gain on asset dispositions for the year ended December 31, 2012 and 2011 was $2.0 million and $3.7 million, respectively. We periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.
Interest expense increased $10.9 million for the year ended December 31, 2012 compared with the year ended December 31, 2011. The increase primarily resulted from a $5.2 million increase in interest on the additional $125.0 million of 9.125% Notes, which have a higher interest rate than our 2.125% Notes that were
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repaid during 2012, and a $9.0 million decrease in interest capitalized on major projects, resulting from a reduction in the value of the AADU rigs following the impairment charge recorded during the fourth quarter of 2011 and the placement of one of the AADU rigs into service during the third quarter of 2012. The net increase was partially offset by a decrease in amortization of the debt discount on the 2.125% Notes as they were tendered or matured during 2012 and amortization of the debt premium related to the additional $125.0 million of 9.125% Notes. Interest income was $0.2 million and $0.3 million for the years ended December 31, 2012 and 2011, respectively.
Loss on extinguishment of debt of $2.1 million resulted from the repurchase prior to maturity of $122.9 million of the 2.125% Notes pursuant to a tender offer on May 9, 2012 and the write-off of debt issuance costs related to refinancing our Credit Facility in December 2012. The loss included a $0.4 million premium paid to repurchase the 2.125% Notes prior to maturity, $1.4 million accelerated amortization of the related debt discount and debt issuance costs of the 2.125% Notes, and $0.3 million accelerated amortization of the debt issuance costs related to our Credit Facility.
General and administration expense increased $14.7 million for the year ended December 31, 2012, compared with general and administrative expense for the year ended December 31, 2011. The general and administrative cost increase was due primarily to a proposed settlement with the DOJ and SEC recorded during the fourth quarter of 2012, offset by a decrease in legal fees associated with the related SEC and DOJ investigations (see further discussion in Note 13 in the Notes to the Company’s financial statements).
Income tax expense was $33.9 million for the year ended December 31, 2012, compared with an income tax benefit of $14.8 million for the year ended December 31, 2011. The 2012 tax expense was primarily due to the mix of our domestic and international pretax earnings and losses, the mix of international tax jurisdictions in which we operate, and adjustments related to the settlement of our examination with the U.S. Internal Revenue Service for tax periods through 2010 including carryover adjustments impacting the 2011 period. The 2011 period tax benefit is driven primarily by the $170.0 million non-cash pretax charge for our AADU rigs in Alaska resulting in a $60.9 million federal and state tax benefit, offset by operating income (excluding the impairment), differences in the mix of our domestic and international pretax earnings and losses, as well as the mix of international tax jurisdictions in which we operate. Included in tax expense for the year ended December 31, 2012 is an expense of $1.5 million related to an uncertain tax position and a benefit of $7.0 million related to the effective settlement of uncertain tax positions.
Year Ended December 31, 2011 Compared with Year Ended December 31, 2010
Revenues of $686.6 million for the year ended December 31, 2011 increased $27.2 million, or 4.1%, from the comparable 2010 period. The years ended December 31, 2011 and 2010 included construction contract revenues of $9.6 million and $91.1 million, respectively, for the Liberty rig construction project. Excluding that individual project, revenues for the year ended December 31, 2011 would have been $108.6 million or 19.1%, higher than 2010 from ongoing operations. Operating gross margin including depreciation and amortization increased 113.7% to $156.4 million for the year ended December 31, 2011 as compared to $73.2 million for the year ended December 31, 2010. We recorded a net loss attributable to controlling interest of $50.5 million for the year ended December 31, 2011, as compared to a net loss of $14.5 million for the year ended December 31, 2010. During the fourth quarter of 2011 we recorded a non-cash pre-tax impairment charge of $170.0 million ($109.1 million, net of taxes of $60.9 million) to adjust our AADU rigs to their fair value from the existing net book value (see Note 2 to the Consolidated Financial Statements). Excluding this non-cash charge, net income attributable to controlling interest for the year ended December 31, 2011 would have been $58.7 million.
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The following is an analysis of our operating results for the comparable periods:
| Year Ended December 31, | ||||||||||||||||
| 2011 | 2010 | |||||||||||||||
| (Dollars in Thousands) | ||||||||||||||||
Revenues: | ||||||||||||||||
Rental Tools | $ | 237,068 | 35 | % | $ | 172,598 | 26 | % | ||||||||
U.S. Barge Drilling | 93,763 | 14 | % | 64,543 | 10 | % | ||||||||||
U.S. Drilling | — | 0 | % | — | 0 | % | ||||||||||
International Drilling | 318,482 | 46 | % | 294,821 | 45 | % | ||||||||||
Technical Services | 27,695 | 4 | % | 36,423 | 5 | % | ||||||||||
Construction Contract | 9,638 | 1 | % | 91,090 | 14 | % | ||||||||||
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Total revenues | 686,646 | 100 | % | 659,475 | 100 | % | ||||||||||
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Operating gross margin: | ||||||||||||||||
Rental Tools gross margin excluding depreciation and amortization | 162,577 | 69 | % | 112,562 | 65 | % | ||||||||||
U.S Barge Drilling gross margin excluding depreciation and amortization | 28,620 | 31 | % | 11,209 | 17 | % | ||||||||||
U.S. Drilling gross margin excluding depreciation and amortization | (1,692 | ) | n/a | (217 | ) | n/a | ||||||||||
International Drilling gross margin excluding depreciation and amortization | 72,891 | 23 | % | 59,389 | 20 | % | ||||||||||
Technical Services gross margin | 5,335 | 19 | % | 5,052 | 14 | % | ||||||||||
Construction Contract gross margin | 771 | 8 | % | 202 | 0 | % | ||||||||||
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Total operating gross margin excluding depreciation and amortization | 268,502 | 39 | % | 188,197 | 29 | % | ||||||||||
Depreciation and amortization | (112,136 | ) | (115,030 | ) | ||||||||||||
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Total operating gross margin | 156,366 | 73,167 | ||||||||||||||
General and administrative expense | (31,314 | ) | (30,728 | ) | ||||||||||||
Impairments and other charges | (170,000 | ) | — | |||||||||||||
Provision for reduction in carrying value of certain assets | (1,350 | ) | (1,952 | ) | ||||||||||||
Gain on disposition of assets, net | 3,659 | 4,620 | ||||||||||||||
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Total operating income | $ | (42,639 | ) | $ | 45,107 | |||||||||||
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Segment gross margins, excluding depreciation and amortization, are computed as revenues less direct operating expenses, and less depreciation and amortization expense, where applicable; segment operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin amounts and operating gross margin percentages should not be used as a substitute for those amounts reported under U.S. GAAP. However, we monitor our business segments based on several criteria, including operating gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by segment. Such operating gross margin amounts are reconciled to our most comparable U.S. GAAP measure as follows:
| Rental Tools | U.S. Barge Drilling | U.S. Drilling | International Drilling | Technical Services(2) | Construction Contract(2) | |||||||||||||||||||
| (Dollars in Thousands) | ||||||||||||||||||||||||
Year Ended December 31, 2011 | ||||||||||||||||||||||||
Operating gross margin(1) | $ | 120,822 | $ | 11,116 | $ | (3,915 | ) | $ | 22,237 | $ | 5,335 | $ | 771 | |||||||||||
Depreciation and amortization | 41,755 | 17,504 | 2,223 | 50,654 | — | — | ||||||||||||||||||
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Operating gross margin excluding depreciation and amortization | $ | 162,577 | $ | 28,620 | $ | (1,692 | ) | $ | 72,891 | $ | 5,335 | $ | 771 | |||||||||||
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Year Ended December 31, 2010 | ||||||||||||||||||||||||
Operating gross margin(1) | $ | 74,541 | $ | (11,503 | ) | $ | (217 | ) | $ | 5,092 | $ | 5,052 | $ | 202 | ||||||||||
Depreciation and amortization | 38,021 | 22,712 | — | 54,297 | — | — | ||||||||||||||||||
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Operating gross margin excluding depreciation and amortization | $ | 112,562 | $ | 11,209 | $ | (217 | ) | $ | 59,389 | $ | 5,052 | $ | 202 | |||||||||||
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| (1) | Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization expense. |
| (2) | The Technical Services segment and the Construction Contract segment do not incur depreciation and amortization. |
Operations
Rental Tools
Rental Tools segment revenues increased $64.5 million, or 37.4%, to $237.1 million for the year ended December 31, 2011 compared to revenues for the year ended December 31, 2010. The increase was primarily due to the growth in demand for rental tools, higher utilization of our rental tools inventory and better pricing. The growing use of lateral drilling and longer well-bores to exploit both shale deposits and conventional oil and natural gas reservoirs continued to lead to greater demand for rental tools. Our 2011 investments in rental tools inventory of approximately $61.5 million expanded our ability to serve this growing demand.
Rental Tools segment operating gross margin, excluding depreciation and amortization, increased by $50.0 million, or 44.4%, for the year ended December 31, 2011 compared with operating gross margin, excluding depreciation and amortization, for the year ended December 31, 2010, primarily due to higher revenues and the ability to leverage costs across the increased revenue stream.
U.S. Barge Drilling
U.S. Barge Drilling segment revenues increased $29.2 million, or 45.3%, to $93.8 million for the year ended December 31, 2011, compared with revenues for the year ended December 31, 2010. The increase in revenues was primarily due to higher rig fleet utilization and a higher average dayrate for 2011. The market’s continued shift to more oil-focused drilling supported the demand for drilling throughout the year.
U.S. Barge Drilling segment operating gross margin, excluding depreciation and amortization, increased $17.4 million or 155.3% to $28.6 million for the year ended December 31, 2011, compared with segment operating gross margin, excluding depreciation and amortization, for the year ended December 31, 2010. The increase reflects the impact of improved utilization and the continued control of operating costs.
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U.S. Drilling
As of December 31, 2011, the U.S. Drilling segment had not begun generating revenue. We re-entered the Alaska drilling market in late 2012 with two new-design land rigs intended to deliver improved drilling efficiency, operating consistency and safety to address the challenges presented by the remote location, harsh climate and sensitive environment that characterize the Alaskan North Slope. Operating gross margin, excluding depreciation and amortization, was a loss of $1.7 million and $0.2 million for the years ended December 31, 2011 and 2010, respectively, and includes expenditures associated with re-entering the Alaskan market. The start-up costs include salaries and employee hiring-related expenditures, training and rental of facilities in Alaska to support our operations.
International Drilling
International Drilling segment revenues increased $23.7 million, or 8.0%, to $318.5 million for the year ended December 31, 2011, compared with the year ended December 31, 2010. The higher revenues were primarily due to an increase in revenue generated by our O&M contracts offset by a decline in our drilling revenues generated through the operation of rigs that we own.
O&M revenues increased to $127.0 million, or 70.5% for the year ended December 31, 2011 compared to $74.5 million for the year ended December 31, 2010. The increase in revenues generated through our O&M contracts was primarily due to a drilling rig relocation project which began during the fourth quarter of 2010 and a shipyard refurbishment and operations project which began during the first quarter of 2011. The projects included approximately $50.3 million of reimbursable costs for the year ended December 31, 2011, which added to revenues but have little direct impact on operating margins. The increase in O&M revenues was partially offset by a lower average dayrate associated with our services on the Orlan Platform in Sakhalin Island, Russia as the rig was in warm stack mode in 2011 compared with workover mode in 2010.
Revenues related to Parker-owned rigs decreased to $191.5 million or 13.1% for the year ended December 31, 2011 compared to $220.4 million for the year ended December 31, 2010. Revenues declined in the Eastern Hemisphere operations due to reduced average utilization and lower reimbursable revenues, partially offset by a higher average dayrate for our rigs in this region. The decrease in revenues in the Latin America operations was primarily due to reduced average utilization and lower reimbursables partially offset by higher average dayrates for rigs in certain locations in this region.
International Drilling operating gross margin, excluding depreciation and amortization, increased $13.5 million, or 22.7%, to $72.9 million for the year ended December 31, 2011, compared with $59.4 million for the year ended December 31, 2010. The increase in operating gross margin for the year ended December 31, 2011 was due to increased margins for our O&M operations in addition to increased margins for our Parker-owned rig operations. Operating margins generated by our O&M operations were $25.3 million and $16.6 million for the years ended December 31, 2011 and 2010, respectively. The increase was primarily due to the Yastreb drilling rig move and the Coral Sea refurbishment program. Our margins related to Parker-owned rigs were $47.6 million and $42.8 million for the years ended December 31, 2011 and 2010, respectively. The increase was due to the inclusion in 2010 of $6.4 million of expense related to a non-cash charge to write-off certain value added tax (VAT) assets and expense for property tax assessments and other tax matters. In addition to the impacts from lower utilization and higher average dayrates in both the Eastern Hemisphere and Latin American regions, we achieved benefits from lower labor costs in our operations in the Eastern Hemisphere region. The increase in operating margins was partially offset by a $2.3 million non-cash charge to write-off certain VAT assets and the recording of expenses related to the estimated salvage cost of a barge rig that was stranded in Nigeria. We have no ongoing operations in Nigeria.
Technical Services
Technical Services segment revenues decreased $8.7 million, or 24.0%, to $27.7 million for the year ended December 31, 2011, compared with $36.4 million for the year ended December 31, 2010. This decrease was primarily due to the transition of the Berkut platform project from its engineering phase to a less revenue-intensive construction oversight phase and the expiration at the end of the second quarter of 2011 of the “pre-operations” phase of the Liberty rig contract. This was partially offset by revenues related to two front-end engineering projects that are in the early development stages.
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Operating gross margin for this segment increased by $0.3 million, or 5.6%, to $5.3 million for the year ended December 31, 2011, compared with the year ended December 31, 2010. The increase in operating gross margin was primarily due to revenues related to two front-end engineering projects that are in the early development stages and an increase in operating margin on the Liberty project resulting from increased margin for resources contracted to BP to support and maintain the Liberty rig. This was partially offset by a decrease due to the transition in the work content of the Berkut platform project. The Technical Services segment does not incur depreciation and amortization.
Construction Contract
This segment includes only the Liberty extended-reach drilling rig construction project for use in the Alaskan Beaufort Sea. Construction Contract segment revenues were $9.6 million for the year ended December 31, 2011 compared with $91.1 million for the year ended December 31, 2010. This segment reported $0.8 million operating gross margin for the year ended December 31, 2011 resulting from preliminary close-out of the Liberty project and recognition of final percentage of completion revenues. The segment reported a $0.2 million operating gross margin for the year ended December 31, 2010 due to an increase in total estimated construction costs and a longer construction period. The Construction Contract segment does not incur depreciation and amortization.
The Liberty rig construction contract was a fixed fee and reimbursable contract that we accounted for on a percentage of completion basis. As of December 31, 2011 and 2010, we had recognized $335.5 million and $325.9 million in project-to-date revenues, respectively. Over the life of the contract we recognized $11.7 million margin on the contract.
For more information about the Liberty project, see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations — Other Matters — “Liberty Project Status.”
Other Financial Data
During 2011 we recorded a provision for reduction in the carrying value of assets of $1.4 million related to a final settlement of a customer bankruptcy proceeding. In 2010, the Company recognized a $2.0 million provision for reduction in carrying value related to this same bankruptcy matter as it was deemed that the Company’s rights to mineral reserves no longer supported the outstanding receivable.
Gain on asset dispositions for the year ended December 31, 2011 and 2010 was $3.7 million and $4.6 million, respectively, and resulted from the sale of equipment deemed to be excess or not currently required for operations.
Interest expense decreased $4.2 million for the year ended December 31, 2011 compared with the year ended December 31, 2010, due to a $5.8 million increase in capitalized interest on major projects (primarily the two rigs being built in Alaska) which reduced overall interest expense This was partially offset by a $0.9 million increase in debt-related interest expense and $0.7 million increase in debt amortization costs. Interest income was $0.3 million for each of the years ended December 31, 2011 and 2010.
General and administration expense increased $0.6 million for the year ended December 31, 2011, compared with general and administrative expense for the year ended December 31, 2010. The general and administrative cost increase was due primarily to an increase in legal expenses and salaries and wages, partially offset by a decrease in professional and consulting fees and other corporate administrative expenses.
Income tax benefit was $14.8 million for the year ended December 31, 2011, compared with income tax expense of $26.2 million for the year ended December 31, 2010. The 2011 period tax benefit was driven primarily by the $170.0 million non-cash pretax charge for our AADU rigs in Alaska resulting in a $60.9 million federal and state tax benefit, offset by operating income (excluding the impairment), differences in the mix of our domestic and international pretax earnings and losses, as well as the mix of international tax jurisdictions in which we operate. Included in tax benefit for the year ended December 31, 2011 was an expense of $0.8 million related to an uncertain tax position and a benefit of $0.8 million related to the effective settlement of an uncertain tax position.
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LIQUIDITY AND CAPITAL RESOURCES
We periodically evaluate our liability requirements, capital needs and availability of resources in view of expansion plans, debt service requirements, and other operational cash needs. To meet our short and long term liquidity requirements, including payment of operating expenses and repaying debt, we rely primarily on cash from operations. However, we have recently, as well as in the past, sought, and may in the future seek, to raise additional capital. We expect that, for the foreseeable future, cash generated from operations will be sufficient to provide us the ability to fund our operations, provide the working capital necessary to support our strategy, and fund planned capital expenditures.
We amended and restated our Credit Agreement on December 14, 2012, extending the maturity date to December 2017. The $50.0 million Term Loan borrowed under the facility amortizes at $2.5 million per quarter beginning with the first payment due on March 31, 2013, thus $10.0 million is classified as a current obligation on our consolidated balance sheet at December 31, 2012. As a result of amending and extending the Credit Agreement, we recorded debt extinguishment costs of $0.4 million during the twelve months ended December 31, 2012. Based on the current amortization schedule, we believe we could repay the Term Loan over the remaining term of the Credit Agreement utilizing existing cash and cash generated from operations.
On April 25, 2012, we issued an additional $125.0 million aggregate principal amount of our existing 9.125% Notes at a price of 104.0% of par, resulting in gross proceeds of $130.0 million. Substantially all of the net proceeds from the offering of $124.1 million were utilized to repurchase $122.9 million aggregate principal amount of 2.125% Notes pursuant to a tender offer on May 9, 2012. The tender offer price was $1,003.27 for each $1,000 principal amount of 2.125% Notes, plus accrued and unpaid interest. As a result of the repurchase, we recorded debt extinguishment costs of $1.8 million during the twelve months ended December 31, 2012. The $2.1 million aggregate principal amount of remaining non-tendered 2.125% Notes were paid off at their stated maturity on July 15, 2012.
Liquidity
As of December 31, 2012, we had cash and cash equivalents of $87.9 million, a decrease of $10.0 million from December 31, 2011. The following table provides a summary for the last three years:
| 2012 | 2011 | 2010 | ||||||||||
| (Dollars in thousands) | ||||||||||||
Operating Activities | $ | 189,699 | $ | 225,885 | $ | 123,550 | ||||||
Investing Activities | (187,606 | ) | (184,614 | ) | (212,709 | ) | ||||||
Financing Activities | (12,076 | ) | 5,167 | 31,787 | ||||||||
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Net change in cash and cash equivalents | $ | (9,983 | ) | $ | 46,438 | $ | (57,372 | ) | ||||
Operating Activities
Cash flows from operating activities were $189.7 million in 2012, compared with $225.9 million in 2011. Before changes in operating assets and liabilities, cash from operating activities was impacted primarily by net income of $37.1 million plus non-cash charges of $151.6 million. Non-cash charges primarily consisted of $113.0 million of depreciation expense and deferred tax benefit of $15.8 million. Net changes in operating assets and liabilities provided $1.0 million and $32.2 million of cash in 2012 and 2011 respectively.
Cash flows from operating activities were $225.9 million in 2011, compared with $123.6 million in 2010. Before changes in operating assets and liabilities, cash from operating activities was impacted primarily by a net loss of $50.6 million plus non-cash charges of $244.3 million. Non-cash charges primarily consisted of the impairment charge of $170.0 million and $112.1 million of depreciation expense, partially offset by deferred tax expense of $48.4 million. Net changes in operating assets and liabilities provided $32.2 million of cash in 2011, compared to $5.2 million provided in 2010.
Investing Activities
Cash flows used in investing activities were $187.6 million for 2012. Our primary use of cash was $191.5 million for capital expenditures. Major capital expenditures for the period included $86.0 million, including capitalized interest, for the construction of our two AADU rigs, $62.0 million for tubular and other
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products for Rental Tools, and $13.8 million in a new enterprise resource planning system. Capital incurred to support ongoing drilling activities was $29.7 million. Sources of cash included $3.9 million of proceeds from asset sales.
Cash flows used in investing activities were $184.6 million for 2011. Our primary use of cash was $190.4 million for capital expenditures. Major capital expenditures for the period included $77.9 million for the construction of our two AADU rigs, including capitalized interest, and $61.5 million for tubular and other products for Rental Tools. Capital expenditures to support ongoing drilling activities was $51.0 million. Sources of cash included $5.5 million of proceeds from asset sales.
Capital expenditures for 2013 are estimated to range from $150.0 million to $175.0 million and will primarily be directed to our Rental Tools inventory and maintenance capital. Any discretionary spending will be evaluated based upon adequate return requirements and available liquidity. We believe that our operating cash flows and borrowings under our revolving credit facility (Revolver), will provide us sufficient cash and available liquidity to sustain operation and fund our capital expenditures for 2013, though there can be no assurance that we will continue to generate cash flows at sufficient levels or be able to obtain additional financing if necessary. See “Item 1A. Risk Factors” for a discussion of additional risks related to our business.
Financing Activities
Cash flows used in financing activities were $12.1 million for 2012. Our primary financing activities included the repayment of $125.0 million of 2.125% Senior Notes and $18.0 million in quarterly payments against our Term Loans. In addition, we received proceeds from the issuance of an additional $125.0 million aggregate principal amount of 9.125% Notes at a price of 104.0%, resulting in gross proceeds of $130.0 million, less $4.9 million of associated debt issuance costs. We also made a $7.0 million draw on our Revolver.
Cash flows provided by financing activities were $5.2 million for 2011. Our primary financing activities included a $50.0 million draw on the accordion feature of our Credit Agreement in the form of a Term Loan, offset by the repayment of the $25.0 million outstanding balance on our Revolver and $21.0 million in quarterly payments against our Term Loans.
9.125% Senior Notes, due April 2018
On March 22, 2010, we issued $300.0 million aggregate principal amount of 9.125% Senior Notes (9.125% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 9.125% Notes offering were primarily used to redeem the $225.0 million aggregate principal amount of our 9.625% Senior Notes due 2013 and to repay $42.0 million of borrowings under our senior secured revolving credit facility (Revolver).
On April 25, 2012, we issued an additional $125.0 million aggregate principal amount of 9.125% Notes under the same indenture at a price of 104.0% of par, resulting in gross proceeds of $130.0 million. Net proceeds from the offering were utilized to refinance $125.0 million aggregate principal amount of the 2.125% Convertible Senior Notes due July 2012 (2.125% Notes). We repurchased $122.9 million aggregate principal amount of the 2.125% Notes tendered pursuant to a tender offer on May 9, 2012 and paid off the remaining $2.1 million at their stated maturity on July 15, 2012.
The 9.125% 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 9.125% Notes are jointly and severally guaranteed by substantially all of our material domestic subsidiaries other than subsidiaries generating revenues primarily outside the United States. Interest on the 9.125% Notes is payable on April 1 and October 1 of each year. Debt issuance costs related to the 9.125% Notes of approximately $11.6 million ($7.6 million, net of amortization) are being amortized over the term of the notes using the effective interest rate method.
At any time prior to April 1, 2013, we may redeem up to 35 percent of the aggregate principal amount of the 9.125% Notes at a redemption price of 109.125 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. On and after April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of
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104.563 percent of the principal amount, and beginning April 1, 2016 at redemption prices decreasing each year thereafter to par. If we experience certain changes in control, we must offer to repurchase the 9.125% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.
2.125% Convertible Senior Notes, due July 2012
On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125% Notes. As noted above, on May 9, 2012, we repurchased $122.9 million aggregate principal amount of the 2.125% Notes pursuant to a tender offer. The tender offer price was $1,003.27 for each $1,000 principal amount of 2.125% Notes, plus accrued and unpaid interest. This repurchase resulted in the recording of debt extinguishment costs of $1.8 million related to the accelerated amortization of both the unamortized debt issuance costs and debt discount associated with the 2.125% Notes. The remaining $2.1 million aggregate principal amount of non-tendered 2.125% Notes was subsequently paid off at their stated maturity on July 15, 2012.
Concurrently with the issuance of the 2.125% Notes, we purchased a convertible note hedge (note hedge) and sold warrants in private transactions with counterparties that were different than the ultimate holders of the 2.125% Notes. The note hedge allowed us to receive shares of our common stock from the counterparties to the transaction equal to the amount of common stock related to the excess conversion value that we would issue and/or pay to the holders of the 2.125% Notes upon conversion. The warrants allowed us to sell 9,027,713 common shares at a strike price of $18.29 per share. The note hedge expired on July 15, 2012, the maturity date of the 2.125% Notes. The warrants expired ratably from October 15, 2012 to February 22, 2013.
Because we had the choice of settling the call options and the warrants in cash or shares of our common stock and these contracts met all of the applicable criteria for equity classification, the cost of the call options and proceeds from the sale of the warrants were classified in stockholders’ equity in the consolidated condensed balance sheets. In addition, because both of these contracts are classified in stockholders’ equity and were indexed solely to our common stock, they were not accounted for as derivatives.
Debt issuance costs related to the 2.125% Notes of approximately $3.6 million were amortized over the five year term of the 2.125% Notes using the effective interest method.
Amended and Restated Credit Agreement
On December 14, 2012, we entered into an Amended and Restated Credit Agreement (Credit Agreement) consisting of a senior secured $80.0 million revolving credit facility (Revolver) and a senior secured term loan facility (Term Loan) of $50.0 million. The Credit Agreement amended and restated our existing credit agreement dated May 15, 2008 (Existing Credit Agreement). We entered into the Credit Agreement to extend its maturity from May 14, 2013 to December 14, 2017 and to decrease the range of Applicable Rates under our Revolver. The Credit Agreement provides that, subject to certain conditions, including the approval of the Administrative Agent and the lenders’ acceptance (or additional lenders being joined as new lenders), the amount of the Term Loan or Revolver can be increased by an additional $50.0 million, so long as after giving effect to such increase, the Aggregate Commitments shall not be in excess of $180.0 million.
Our obligations under the Credit Agreement are guaranteed by substantially all of our material domestic subsidiaries, each of which has executed guaranty agreements; and are secured by first priority liens on our accounts receivable, specified barge rigs and rental equipment. The Credit Agreement contains customary affirmative and negative covenants with which we were in compliance as of December 31, 2012 and December 31, 2011. The Credit Agreement terminates on December 14, 2017.
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Revolver
Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Under the Credit Agreement, the Applicable Rate varies from a rate per annum ranging from 2.50 percent to 3.00 percent for LIBOR rate loans and 1.50 percent to 2.00 percent for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the Credit Agreement). Under the previously Existing Credit Agreement, the Applicable Rate varied from a rate per annum ranging from 2.75 percent to 3.25 percent for LIBOR rate loans and 1.75 percent to 2.25 percent for base rate loans. Revolving loans are available subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and rental equipment of the Company and its subsidiary guarantors. There were no revolving loans outstanding at December 31, 2012 and December 31, 2011. Letters of credit outstanding as of December 31, 2012 and December 31, 2011 totaled $4.5 million and $2.7 million, respectively.
Term Loan
The Term Loan originated at $50.0 million on December 14, 2012 and requires quarterly principal payments of $2.5 million beginning March 31, 2013. Interest on the Term Loan accrues at a Base Rate plus 2.00 percent or LIBOR plus 3.00 percent. The Existing Credit Agreement required quarterly principal payments of $6.0 million, and interest accrued at a Base Rate plus 2.25 percent or LIBOR plus 3.25 percent. The outstanding balance on the Term Loans at December 31, 2012 was $50.0 million under the Credit Agreement. The outstanding balance under the Existing Credit Agreement as of December 31, 2011 was $61.0 million.
Other Liquidity
Our principal amount of long-term debt, including current portion, was $475.0 million as of December 31, 2012, which consists of:
| Ÿ | $425.0 million aggregate principal amount of 9.125% Senior Notes, due April 1, 2018; and |
| Ÿ | $50.0 million under our Term Loan, $10.0 million of which is classified as current. |
As of December 31, 2012, we had approximately $163.4 million of liquidity, which consisted of $87.9 million of cash and cash equivalents on hand and $75.5 million of availability under the Revolver. We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. We have no energy, commodity, or foreign currency derivative contracts at December 31, 2012.
The following table summarizes our future contractual cash obligations as of December 31, 2012:
| Total | Less than 1 Year | Years 1 - 3 | Years 3 - 5 | More than 5 Years | ||||||||||||||||
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Contractual cash obligations: | ||||||||||||||||||||
Long-term debt — principal(1) | $ | 475,000 | $ | 10,000 | $ | 20,000 | $ | 20,000 | $ | 425,000 | ||||||||||
Long-term debt — interest(1) | 217,623 | 40,342 | 79,598 | 78,292 | 19,391 | |||||||||||||||
Operating leases(2) | 27,762 | 6,734 | 7,985 | 4,834 | 8,209 | |||||||||||||||
Purchase commitments(3) | 9,645 | 9,645 | — | — | — | |||||||||||||||
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Total contractual obligations | $ | 730,030 | $ | 66,721 | $ | 107,583 | $ | 103,126 | $ | 452,600 | ||||||||||
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Standby letters of credit(4) | 4,527 | 4,527 | — | — | — | |||||||||||||||
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| 1) | Long-term debt includes the principal and interest cash obligations of the 9.125% Notes. The remaining unamortized premium of $4.2 million on the additional $125.0 million of 9.125% Notes is not included in the contractual cash obligations schedule. |
| 2) | Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property. |
| 3) | We have purchase commitments outstanding as of December 31, 2012, related to rig upgrade projects and new rig construction. |
| 4) | We have an $80.0 million Revolver. As of December 31, 2012, there were no borrowings and $4.5 million of availability has been used to support letters of credit that have been issued, resulting in an estimated $ 75.5 million of availability. The Revolver expires December 14, 2017. |
OTHER MATTERS
Business Risks
See Item 1A, Risk Factors, for a discussion of risks related to our business.
Liberty Project Status
In November 2010, BP informed us that it was suspending construction on the project to review the rig’s engineering and design, including its safety systems. The Liberty rig construction contract expired on February 8, 2011 prior to completion of the rig. Before expiration of the construction contract, BP identified several areas of concern relating to design, construction and invoicing for which it asked us to provide explanations and documentation, and we did so. Although we provided BP with the requested information, we do not know when or how these issues will be resolved with our client.
The Liberty rig construction contract was a fixed fee and reimbursable contract that we accounted for on a percentage of completion basis. Costs of the project were reimbursed without markup, except for costs associated with changes in work scope, for which we were entitled to a markup. As of December 31, 2011, we had recognized $335.5 million in project-to-date revenues and the entire $11.7 million fixed fee margin on the contract.
After expiration of the construction contract, the Company and BP continued activities to preserve and maintain the rig under the “pre-operations” phase of an O&M contract, which was entered into in August 2009 and expired on July 1, 2011. A new consulting services agreement was reached between the Company and BP effective July 1, 2011. Under the consulting services agreement, we assisted BP in a review of the rig’s design, the creation of a new statement of requirements for the rig, and the transition of documentation and materials to BP. All work under the consulting agreement has been completed and we are engaged with BP on construction contract close-out resolution. In June 2012, BP publicly announced that it had made the decision to suspend the Liberty project indefinitely. We do not know whether or how that decision may impact our discussions with BP related to contract close-out.
Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate our estimates, including those related to fair value of assets, bad debt, materials and supplies obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.
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We believe the following are our most critical accounting policies as they are 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 in the notes to 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 review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or circumstances change that indicate the carrying value 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, or 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.
Insurance Reserves. Our operations are subject to many hazards inherent to the drilling industry, including blowouts, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these 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 record reserves for these amounts in our consolidated financial statements. Reserves 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 reserves are critical.
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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 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 the expiration of our net operating loss (NOL) and foreign tax credit (FTC) carryforwards. In the event that our earnings performance projections do not indicate that we will be able to benefit from our NOL and FTC carryforwards, valuation allowances are established. We periodically evaluate our ability to utilize our NOL and FTC carryforwards 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 U.S. deferred taxes on unremitted earnings of our foreign subsidiaries as such earnings are deemed to be permanently reinvested. If such earnings were to be distributed, we would be subject to U.S. taxes, which may have a material impact on our results of operations. We periodically 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 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. Technical Services contracts include engineering, consulting, and project management scopes of work and revenue is typically recognized on a time and materials basis. Construction contract revenues and costs are recognized on a percentage of completion basis utilizing the cost-to-cost method.
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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 Notes to Consolidated Financial Statements — Note 18 — Recent Accounting Pronouncements.
| 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, which is our functional currency, 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 foreign currency exchange rate risk forward contracts, or spot purchases, may be used to mitigate foreign exchange rate currency risk. A foreign currency exchange rate risk forward contract obligates us to exchange predetermined amounts of specified foreign currencies at specified exchange rates on specified dates or to make an equivalent U.S. dollar payment equal to the value of such an exchange. We do not enter into derivative transactions for speculative purposes. At December 31, 2012, we had no open foreign currency exchange rate risk derivative contracts.
Interest Rate Risk
We are exposed to changes in interest rates through our fixed rate long-term debt. Typically, the fair market value of fixed rate long-term debt will increase as prevailing interest rates decrease and will decrease as prevailing interest rates increase. The fair value of our long-term debt is estimated based on quoted market prices where applicable, or based on the present value of expected cash flows relating to the debt discounted at rates currently available to us for long-term borrowings with similar terms and maturities. The estimated fair value of our $425.0 million principal amount of 9.125% Senior Notes due 2018, based on quoted market prices, was $453.7 million at December 31, 2012. A hypothetical 100 basis point increase in interest rates relative to market interest rates at December 31, 2012 would decrease the fair market value of our 9.125% Senior Notes by approximately $47.5 million.
The Company entered into two variable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on the Term Loan borrowings under the Credit Agreement. The two agreements fix the interest rate on a notional amount of $73.0 million of borrowings at 3.878% for the period beginning June 27, 2011 and terminating May 14, 2013. The notional amount of the swap agreements decreases correspondingly with amortization of the Term Loan. We do not apply hedge accounting to the agreements and, accordingly, the Company reports the mark-to-market change in the fair value of the interest rate swaps in earnings. For the years ended December 31, 2012 and 2011, the Company recognized in earnings a $0.1 million gain and $0.1 million loss, respectively on interest rate swaps.
Impact of Fluctuating Commodity Prices
We are exposed to fluctuations that arise from economic or political risks that have, and will, impact underlying commodity prices for natural gas, oil and natural gas/oil mixtures. The Company’s business is subject to price fluctuations in commodities, and may be impacted by prolonged pricing reductions. Currently, the price of natural gas has been depressed due in some part to high levels of natural gas inventory. Drilling for natural gas has been negatively impacted; however, drilling activity and our rental tools business has remained active with the focus on oil/liquids-rich shale plays.
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| ITEM 8. FINANCIAL | STATEMENTS AND SUPPLEMENTARY DATA |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Parker Drilling Company:
We have audited Parker Drilling Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Parker Drilling 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 Report on Internal Control over Financial Reporting in Item 9A. Controls and Procedures. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 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.
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.
In our opinion, Parker Drilling Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework 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), the consolidated balance sheets of Parker Drilling Company and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated March 1, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
March 1, 2013
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Parker Drilling Company:
We have audited the accompanying consolidated balance sheets of Parker Drilling Company and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2012. In connection with our audits of the consolidated financial statements, we also have audited financial statement Schedule II – Valuation and Qualifying Accounts. These consolidated financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Parker Drilling Company and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Parker Drilling Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 1, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
March 1, 2013
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PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Dollars in Thousands, Except Per Share Data)
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
Revenues | $ | 677,982 | $ | 686,646 | $ | 659,475 | ||||||
Expenses: | ||||||||||||
Operating expenses | 414,064 | 418,144 | 471,278 | |||||||||
Depreciation and amortization | 113,017 | 112,136 | 115,030 | |||||||||
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| |||||||
| 527,081 | 530,280 | 586,308 | ||||||||||
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Total operating gross margin | 150,901 | 156,366 | 73,167 | |||||||||
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General and administration expense | (46,052 | ) | (31,314 | ) | (30,728 | ) | ||||||
Impairments and other charges | — | (170,000 | ) | — | ||||||||
Provision for reduction in carrying value of certain assets | — | (1,350 | ) | (1,952 | ) | |||||||
Gain on disposition of assets, net | 1,974 | 3,659 | 4,620 | |||||||||
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Total operating income (loss) | 106,823 | (42,639 | ) | 45,107 | ||||||||
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Other income and (expense): | ||||||||||||
Interest expense | (33,542 | ) | (22,594 | ) | (26,805 | ) | ||||||
Interest income | 153 | 256 | 257 | |||||||||
Loss on extinguishment of debt | (2,130 | ) | — | (7,209 | ) | |||||||
Change in fair value of derivative positions | 55 | (110 | ) | — | ||||||||
Other | (382 | ) | (325 | ) | 155 | |||||||
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Total other expense | (35,846 | ) | (22,773 | ) | (33,602 | ) | ||||||
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Income (loss) before income taxes | 70,977 | (65,412 | ) | 11,505 | ||||||||
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Income tax expense (benefit): | ||||||||||||
Current tax expense | 18,042 | 33,608 | 27,521 | |||||||||
Deferred tax expense (benefit) | 15,837 | (48,375 | ) | (1,308 | ) | |||||||
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Total income tax expense (benefit) | 33,879 | (14,767 | ) | 26,213 | ||||||||
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Net income (loss) | 37,098 | (50,645 | ) | (14,708 | ) | |||||||
Less: Net (loss) attributable to noncontrolling interest | (215 | ) | (194 | ) | (247 | ) | ||||||
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Net income (loss) attributable to controlling interest | $ | 37,313 | $ | (50,451 | ) | $ | (14,461 | ) | ||||
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Basic earnings per share: | $ | 0.32 | $ | (0.43 | ) | $ | (0.13 | ) | ||||
Diluted earnings per share: | $ | 0.31 | $ | (0.43 | ) | $ | (0.13 | ) | ||||
Number of common shares used in computing earnings per share: | ||||||||||||
Basic | 117,721,135 | 116,081,590 | 114,258,965 | |||||||||
Diluted | 119,093,590 | 116,081,590 | 114,258,965 | |||||||||
See accompanying notes to the consolidated financial statements.
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PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Dollars in Thousands)
| December 31, | ||||||||
| 2012 | 2011 | |||||||
| ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 87,886 | $ | 97,869 | ||||
Accounts and notes receivable, net of allowance for bad debts of $8,117 in 2012 and $1,544 in 2011 | 168,562 | 183,923 | ||||||
Rig materials and supplies | 28,860 | 29,947 | ||||||
Deferred costs | 1,089 | 3,249 | ||||||
Deferred income taxes | 8,742 | 6,650 | ||||||
Other tax assets | 33,524 | 25,358 | ||||||
Assets held for sale | 11,550 | 5,315 | ||||||
Other current assets | 12,821 | 15,302 | ||||||
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Total current assets | 353,034 | 367,613 | ||||||
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Property, plant and equipment, at cost: | ||||||||
Drilling equipment | 1,165,924 | 1,094,366 | ||||||
Rental tools | 337,874 | 310,429 | ||||||
Buildings, land and improvements | 38,736 | 33,817 | ||||||
Other | 56,819 | 57,111 | ||||||
Construction in progress | 190,445 | 194,362 | ||||||
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| 1,789,798 | 1,690,085 | |||||||
Less accumulated depreciation and amortization | 1,003,640 | 970,276 | ||||||
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Property, plant and equipment, net | 786,158 | 719,809 | ||||||
Other assets: | ||||||||
Rig materials and supplies | 8,980 | 10,395 | ||||||
Debt issuance costs | 8,863 | 7,025 | ||||||
Deferred income taxes | 95,295 | 108,311 | ||||||
Other assets | 3,403 | 3,093 | ||||||
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Total other assets | 116,541 | 128,824 | ||||||
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Total assets | $ | 1,255,733 | $ | 1,216,246 | ||||
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| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 10,000 | $ | 145,723 | ||||
Accounts payable | 62,090 | 76,706 | ||||||
Accrued liabilities | 75,656 | 58,544 | ||||||
Accrued income taxes | 4,120 | 4,837 | ||||||
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Total current liabilities | 151,866 | 285,810 | ||||||
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Long-term debt | 469,205 | 337,000 | ||||||
Other long-term liabilities | 23,182 | 33,452 | ||||||
Long-term deferred tax liability | 20,847 | 15,934 | ||||||
Commitments and contingencies (Note 13) | — | — | ||||||
Stockholders’ equity: | ||||||||
Preferred stock, $1 par value, 1,942,000 shares authorized, no shares outstanding | — | — | ||||||
Common stock, $0.16 2/3 par value, authorized 280,000,000 shares, issued and outstanding, 118,968,396 shares (117,061,203 shares in 2011) | 19,818 | 19,508 | ||||||
Capital in excess of par value | 646,217 | 637,042 | ||||||
Accumulated deficit | (74,631 | ) | (111,944 | ) | ||||
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Total controlling interest stockholders’ equity | 591,404 | 544,606 | ||||||
Noncontrolling interest | (771 | ) | (556 | ) | ||||
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Total equity | 590,633 | 544,050 | ||||||
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Total liabilities and stockholders’ equity | $ | 1,255,733 | $ | 1,216,246 | ||||
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See accompanying notes to the consolidated financial statements.
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PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
Net income (loss) | $ | 37,098 | $ | (50,645 | ) | $ | (14,708 | ) | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 113,017 | 112,136 | 115,030 | |||||||||
Impairment of property, plant and equipment | — | 170,000 | — | |||||||||
Loss on extinguishment of debt | 2,130 | — | 7,209 | |||||||||
Gain on disposition of assets | (1,974 | ) | (3,659 | ) | (4,620 | ) | ||||||
Deferred tax expense (benefit) | 15,837 | (48,375 | ) | (1,308 | ) | |||||||
Provision for reduction in carrying value of certain assets | — | 1,350 | 1,952 | |||||||||
Expenses not requiring cash | 22,600 | 12,833 | 14,829 | |||||||||
Change in assets and liabilities: | ||||||||||||
Accounts and notes receivable | 15,241 | (6,841 | ) | 20,752 | ||||||||
Rig materials and supplies | 344 | (913 | ) | (856 | ) | |||||||
Other current assets | (4,313 | ) | 63,816 | (2,969 | ) | |||||||
Accounts payable and accrued liabilities | (2,657 | ) | (24,908 | ) | (10,868 | ) | ||||||
Accrued income taxes | (6,102 | ) | 2,141 | (4,124 | ) | |||||||
Other assets | (1,522 | ) | (1,050 | ) | 3,231 | |||||||
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Net cash provided by operating activities | 189,699 | 225,885 | 123,550 | |||||||||
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CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
Capital expenditures | (191,543 | ) | (190,399 | ) | (219,184 | ) | ||||||
Proceeds from the sale of assets | 3,937 | 5,535 | 6,475 | |||||||||
Proceeds from insurance claims | — | 250 | — | |||||||||
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Net cash used in investing activities | (187,606 | ) | (184,614 | ) | (212,709 | ) | ||||||
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CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
Proceeds from issuance of debt | 130,000 | 50,000 | 300,000 | |||||||||
Proceeds from draw on revolver credit facility | 7,000 | — | 25,000 | |||||||||
Repayments of senior notes | (125,000 | ) | — | (225,000 | ) | |||||||
Repayments of term loan | (18,000 | ) | (21,000 | ) | (12,000 | ) | ||||||
Repayments of revolver | — | (25,000 | ) | (42,000 | ) | |||||||
Payments of debt issuance costs | (4,859 | ) | (504 | ) | (7,976 | ) | ||||||
Payments of debt extinguishment costs | (555 | ) | — | (7,466 | ) | |||||||
Proceeds from stock options exercised | — | 183 | 26 | |||||||||
Excess tax benefit (expense) from stock-based compensation | (662 | ) | 1,488 | 1,203 | ||||||||
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Net cash provided by (used in) financing activities | (12,076 | ) | 5,167 | 31,787 | ||||||||
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Net increase (decrease) in cash and cash equivalents | (9,983 | ) | 46,438 | (57,372 | ) | |||||||
Cash and cash equivalents at beginning of year | 97,869 | 51,431 | 108,803 | |||||||||
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Cash and cash equivalents at end of year | $ | 87,886 | $ | 97,869 | $ | 51,431 | ||||||
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Supplemental cash flow information: | ||||||||||||
Interest paid | $ | 37,405 | $ | 32,785 | $ | 30,377 | ||||||
Income taxes paid | $ | 40,234 | $ | 21,742 | $ | 41,024 | ||||||
See accompanying notes to the consolidated financial statements.
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PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Dollars and Shares in Thousands)
| Shares | Common Stock | Capital in Excess of Par Value | Accumulated Deficit | Total Controlling Stockholders’ Equity | Noncontrolling Interest | Total Stockholders’ Equity | ||||||||||||||||||||||
Balances, December 31, 2009 | 116,239 | $ | 19,374 | $ | 623,557 | $ | (47,032 | ) | $ | 595,899 | — | $ | 595,899 | |||||||||||||||
Activity in employees’ stock plans | 130 | 23 | 114 | — | 137 | 137 | ||||||||||||||||||||||
Excess tax benefit from stock based compensation | — | — | 1,203 | — | 1,203 | 1,203 | ||||||||||||||||||||||
Amortization of restricted stock plan compensation | — | — | 5,535 | — | 5,535 | 5,535 | ||||||||||||||||||||||
Net income (total comprehensive income of $14,708) | — | — | — | (14,461 | ) | (14,461 | ) | (247 | ) | (14,708 | ) | |||||||||||||||||
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Balances, December 31, 2010 | 116,369 | $ | 19,397 | $ | 630,409 | $ | (61,493 | ) | $ | 588,313 | $ | (247 | ) | $ | 588,066 | |||||||||||||
Activity in employees’ stock plans | 692 | 111 | (343 | ) | — | (232 | ) | (232 | ) | |||||||||||||||||||
Excess tax benefit from stock options exercised | — | — | 988 | — | 988 | 988 | ||||||||||||||||||||||
Amortization of restricted stock plan compensation | — | — | 5,988 | — | 5,988 | 5,988 | ||||||||||||||||||||||
Net income (total comprehensive net loss of $50,645) | — | — | — | (50,451 | ) | (50,451 | ) | (194 | ) | | (50,645 | ) ` | ||||||||||||||||
Other, net | (115 | ) | (115 | ) | ||||||||||||||||||||||||
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Balances, December 31, 2011 | 117,061 | $ | 19,508 | $ | 637,042 | $ | (111,944 | ) | $ | 544,606 | $ | (556 | ) | $ | 544,050 | |||||||||||||
Activity in employees’ stock plans | 1,907 | 310 | 2,620 | — | 2,930 | 2,930 | ||||||||||||||||||||||
Excess tax benefit from stock options exercised | — | — | (662 | ) | — | (662 | ) | (662 | ) | |||||||||||||||||||
Amortization of restricted stock plan compensation | — | — | 7,217 | — | 7,217 | 7,217 | ||||||||||||||||||||||
Net income (total comprehensive net income of $37,098) | — | — | — | 37,313 | 37,313 | (215 | ) | 37,098 | ||||||||||||||||||||
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Balances, December 31, 2012 | 118,968 | $ | 19,818 | $ | 646,217 | $ | (74,631 | ) | $ | 591,404 | $ | (771 | ) | $ | 590,633 | |||||||||||||
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See accompanying notes to the consolidated financial statements.
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Summary of Significant Accounting Policies
Nature of Operations — Parker Drilling, together with its subsidiaries (the Company), is a worldwide provider of contract drilling and drilling-related services and currently we operate in 12 countries. We have operated in over 50 foreign countries and the United States since beginning operations in 1934, making us among the most geographically experienced drilling contractors in the world. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. We believe our quality, health, safety and environmental practices are leaders in our industry. Our rental tools subsidiary specializes in oil and natural gas drilling rental tools providing high-quality, reliable equipment, such as drill pipe, heavy-weight drill pipe, tubing, high-torque connections, BOPs and drill collars used for drilling, workover and production applications.
Our U.S. barge drilling business operates barge rigs drill for natural gas, oil, and a combination of oil and natural gas in the shallow waters in and along the inland waterways of Louisiana, Alabama, and Texas. Our international drilling business provides extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. Additionally, our international drilling business includes operations and maintenance and other project management services, such as labor, maintenance, and logistics for operators who own their own drilling rigs, but choose Parker Drilling to operate the rigs for them. At December 31, 2012, our marketable rig fleet consisted of 14 barge drilling rigs and 24 land rigs located in the United States, Latin America and the Eastern Hemisphere regions. Our Technical services business includes engineering and related project services during the concept development, pre-FEED, and FEED (Front End Engineering Design) phases of our customer owned drilling facility projects. As these projects mature, we continue providing the same services during the Engineering, Procurement, Construction and Installation (EPCI) phase.
Consolidation — The consolidated financial statements include the accounts of the Company and subsidiaries in which we exercise control or have a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s losses or returns, regardless of ownership percentage. If a subsidiary of Parker Drilling has a 50 percent interest in an entity but Parker Drilling’s interest in the subsidiary or the entity does not meet the consolidation criteria described above, then that interest is accounted for under the equity method.
Noncontrolling Interest — We apply the accounting standards related to noncontrolling interests for ownership interests in our subsidiaries held by parties other than Parker Drilling. The entities that comprise the noncontrolling interest include Parker SMNG Drilling Limited Liability Company and Primorsky Drill Rig Services B.V. 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 with the current period presentation. These reclassifications did not have a material effect on our consolidated statements of operations, consolidated balance sheets or statements of cash flows.
Revenue Recognition— Contract drilling revenues and expenses, comprised of daywork drilling contracts 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. Construction contract revenues and costs are recognized on a percentage of completion basis utilizing the cost-to-cost method.
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Reimbursable Costs — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $44.9 million, $64.2 million, and $40.1 million during the years ended December 31, 2012, 2011, and 2010, respectively.
Use of Estimates — The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of the financial statements, and our revenue and expenses during the periods reported. Estimates are typically used when accounting for certain significant items such as legal or contractual liability accruals, mobilization and deferred mobilization, revenue and cost accounting for projects that follow the percentage of completion method, self-insured medical/dental plans, 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.
During the third quarter of 2010, we corrected an accounting error relating to value added taxes (VAT) in our Western Kazakhstan branch (PDKBV). The cumulative effect of the error and related foreign currency translation impact overstated net income and retained earnings by $6.4 million over the period 2007 through 2009. The impact of the error was determined not to be material to our results of operations and financial position for any previously reported periods. Consequently, during the third quarter of 2010, the cumulative effect of this correction was recorded in operating expenses and is reflected in year to date operating expenses for the year ended December 31, 2010.
Cash and Cash Equivalents — For purposes of the consolidated balance sheets and the consolidated statements of cash flows, the Company considers cash equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.
Accounts Receivable and Allowance for Doubtful Accounts — Trade accounts receivable are recorded at the invoice amount and generally do not bear interest. The allowance for doubtful accounts is our best estimate 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 exist 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.
| December 31, | ||||||||
| 2012 | 2011 | |||||||
| (Dollars in Thousands) | ||||||||
Trade | $ | 176,029 | $ | 184,817 | ||||
Notes receivable | 650 | 650 | ||||||
Allowance for doubtful accounts(1) | (8,117 | ) | (1,544 | ) | ||||
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Total accounts and notes receivable, net of allowance for bad debt | $ | 168,562 | $ | 183,923 | ||||
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| 1) | Additional information on the allowance for doubtful accounts for the years ended December 31, 2012, 2011 and 2010 is reported on Schedule II — Valuation and Qualifying Accounts. |
Property, Plant and Equipment — We account for depreciation of property, plant and equipment on the straight line method over the estimated useful lives of the assets after provision for salvage value. Depreciation, for tax purposes, utilizes several methods of accelerated depreciation. Depreciable lives for different categories of property, plant and equipment are as follows:
Land drilling equipment | 3 to 20 years | |
Barge drilling equipment | 3 to 20 years | |
Drill pipe, rental tools and other | 4 to 7 years | |
Buildings and improvements | 15 to 30 years |
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Annual Impairment Review — We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourth quarter, or when events occur or circumstances change that indicate the carrying value of such assets may not be recoverable. 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 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.
Capitalized Interest — Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets. Capitalized interest costs reduce net interest expense in the consolidated statements of operations. During 2012, 2011 and 2010, we capitalized interest costs related to the construction of rigs of $10.2 million, $19.3 million and $13.5 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. At December 31, 2012 and 2011, we had net assets held for sale, included in current assets, in the amounts of $11.6 million and $5.3 million, respectively. For further information, see Note 4.
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. Rig materials and supplies are valued at the lower of cost or market value.
Deferred Costs — We defer costs related to rig mobilization and amortize such costs over the 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 debt financings and refinancing, and amortize those costs over the term of the related debt.
Income Taxes —Income taxes are accounted for under the asset and liability method and have been provided based upon tax laws and rates in effect in the countries in which operations are conducted and income is earned. There is little or no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes as the countries in which we operate have taxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits, and other benefits. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which the temporary differences are expected to be recovered or settled and the effect of changes in tax rates is recognized in income in the period in which the change is enacted. Accordingly, the impact of the American Taxpayer Relief Act of 2012, which was enacted January 2, 2013, will be recognized in 2013, not 2012. 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% likely of being realized and changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
Earnings (Loss) Per Share (EPS) —Basic earnings (loss) per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock and convertible debt are included in the diluted EPS calculation, when applicable.
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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.
At December 31, 2012 and 2011, we had deposits in domestic banks in excess of federally insured limits of approximately $12.2 million and $10.2 million, respectively. In addition, we had deposits in foreign banks, which were not insured at December 31, 2012 and 2011 of $34.5 million and $38.4 million, respectively.
Our customer base consists of major, independent and national oil and natural gas companies and integrated service providers. We depend on a limited number of significant customers. Our two largest customers, Exxon Neftegas Limited (ENL) and Schlumberger, constituted 11.8 percent and 10.4 percent, respectively of our revenues for 2012.
Construction Contract —For the periods reported, our construction contract business included only the drilling rig construction project for BP. In November 2010, our customer, BP, informed us that it was suspending construction on the project to review the rig’s engineering and design, including its safety systems. The Liberty rig construction contract was a fixed fee and reimbursable contract that we accounted for on a percentage of completion basis. As of December 31, 2011 and 2010, we had recognized $335.5 million and $325.9 million in project-to-date revenues, respectively. We have recognized the entire $11.7 million fixed fee margin on the contract.
The Liberty rig construction contract expired on February 8, 2011 prior to completion of the rig. Before expiration of the construction contract, BP identified several areas of concern relating to design, construction and invoicing for which it asked us to provide explanations and documentation, and we have done so. Although we provided BP with the requested information, we do not know when or how these issues will be resolved with our client.
After expiration of the construction contract, the Company and BP continued activities to preserve and maintain the rig under the “pre-operations” phase of our contract, which was entered into in August 2009 and expired on July 1, 2011. A new consulting services agreement was reached between the Company and BP effective July 1, 2011. Under the consulting services agreement, we assisted BP in a review of the rig’s design, the creation of a new statement of requirements for the rig, and the transition of documentation and materials to BP. All work under the consulting agreement has been completed and we are engaged with BP on construction contract close-out resolution. In June 2012, BP publicly announced that it had made the decision to suspend the Liberty project indefinitely. We do not know whether or how that decision may impact our discussions with BP related to contract close-out.
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.
Derivative Financial Instruments — We use derivative instruments to manage risks associated with interest rate fluctuations in connection with our Credit Agreement (see Note 7). These derivative instruments, which consist of variable-to-fixed interest rate swaps, are not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps is recognized in earnings at each reporting period.
Stock-Based Compensation — Under our long term incentive plans, we grant restricted stock awards (RSA), restricted stock units (RSU) and performance units (PU). For service-based awards and performance-based awards with graded vesting conditions, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. For market-based awards that vest at the end of the service period, we recognize compensation expense on a straight-line basis through the end of the service period. Share-based awards generally vest over three years.
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Share-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. The fair value of nonvested RSA’s and RSU’s is determined based on the closing trading price of the company’s shares on the grant date. Our RSA’s and RSU’s are settled in stock upon vesting. Our PU awards can be settled in cash or stock at the discretion of the compensation committee of the board of directors and are, therefore, accounted for as liability awards under the stock compensation rules of U.S. GAAP.
We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to the respective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow.
Note 2 — Asset Impairment
During the fourth quarter of 2011, we evaluated the present value of the future cash flows related to our AADU rigs in accordance with the impairment or disposal of long-lived assets subsections of ASC 360-10, Property, Plant and Equipment. The evaluation was performed as a result of the delay in completion of the rigs to allow the Company to modify the rigs to meet their design and functional requirements and an increase in the cost of the rigs. The need for the modifications was determined as a result of comprehensive safety, technical and operational reviews during commissioning activities of these prototype drilling rigs. The modification work extended the commissioning activities and increased the rigs’ total costs. At the time of the impairment evaluation, the two rigs’ cost at completion was estimated to be $385 million, which included capitalized interest estimates of approximately $50.7 million. This cost exceeded the estimated fair value of the rigs based on their projected cash flows. Based on this evaluation, the Company determined that the long-lived assets with a carrying amount of $339.5 million as of December 31, 2011, were no longer recoverable and were in fact impaired and recorded a charge in the 2011 fourth quarter of $170.0 million ($109.1 million, net of taxes) to reflect their estimated fair value of $169.5 million. Fair value was based on expected future cash flows using Level 3 inputs under the fair value measurement requirements. The cash flows are those expected to be generated by the market participants, discounted at the 10 percent rate of interest. In December 2012 we commenced drilling operations with the first AADU rig. The second rig completed client acceptance testing and began drilling in February 2013. The AADU rigs are reported as part of the U.S. Drilling segment.
Note 3 — Disposition of Assets
Disposition of Assets — In December 2012, we sold a 33 year old posted barge drilling rig for proceeds of $0.2 million, resulting in a $0.5 million loss. There were no individually significant asset dispositions in 2011 and 2010.
Provision for Reduction in Carrying Value of an Asset — In 2011 and 2010, we recognized a charge of $1.4 million, and $2.0 million respectively related to a final settlement of a bankruptcy proceeding. The 2010 reduction resulted from the conclusion that the Company’s rights to mineral reserves no longer supported the outstanding receivable. In 2011, the Company and the bankruptcy trustee settled claims through this final settlement. In 2012, we did not incur any provision for reduction in carrying value of an asset.
Note 4 — Assets Held for Sale
Assets held for sale of $11.6 million as of December 31, 2012 was comprised of the net book value of five land rigs and related inventory. For three rigs comprising $5.3 million of the assets held for sale balance, we have received $1.6 million in down payment and deposits on these assets and associated inventories. The sale of these assets is expected to be finalized in 2013. Prior to being classified as assets held for sale, these assets were included in the International Drilling segment. We expect the carrying amount of the assets, less costs to sell, will be fully recoverable through sale of the assets.
Additionally, during the third quarter of 2012, we determined that two of our rigs located in Kazakhstan met the criteria for classification as assets held for sale. As of September 30, 2012, we reclassified the $6.4 million net book value of these assets and associated inventories to assets held for sale. Prior to being classified as assets held for sale, these assets were included in the International Drilling segment. We expect the carrying amount of the assets, less costs to sell, will be fully recoverable through sale of the assets.
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Note 5 — Income Taxes
Income (loss) before income taxes is summarized below:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| (Dollars in Thousands) | ||||||||||||
United States | $ | 52,422 | $ | (61,434 | ) | $ | 1,865 | |||||
Foreign | 18,555 | (3,978 | ) | 9,640 | ||||||||
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| $ | 70,977 | $ | (65,412 | ) | $ | 11,505 | ||||||
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Income tax expense (benefit) is summarized as follows:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| (Dollars in Thousands) | ||||||||||||
Current: | ||||||||||||
United States: | ||||||||||||
Federal | $ | 7,791 | $ | 17,168 | $ | (273 | ) | |||||
State | 733 | 1,264 | 184 | |||||||||
Foreign | 9,518 | 15,176 | 27,610 | |||||||||
Deferred: | ||||||||||||
United States: | ||||||||||||
Federal | 15,612 | (46,694 | ) | (3,981 | ) | |||||||
State | 4,296 | 1,864 | 1,459 | |||||||||
Foreign | (4,071 | ) | (3,545 | ) | 1,214 | |||||||
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| $ | 33,879 | $ | (14,767 | ) | $ | 26,213 | ||||||
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Total income tax expense differs from the amount computed by multiplying income before income taxes by the U.S. federal income tax statutory rate. The reasons for this difference are as follows:
| Year Ended December 31, | ||||||||||||||||||||||||
| 2012 | 2011 | 2010 | ||||||||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||||||
| Amount | % of Pre-Tax Income | Amount | % of Pre-Tax Income | Amount | % of Pre-Tax Income | |||||||||||||||||||
Computed Expected Tax Expense | $ | 24,842 | 35 | % | $ | (22,894 | ) | 35 | % | $ | 4,027 | 35 | % | |||||||||||
Foreign Taxes | 13,428 | 19 | % | 15,644 | -24 | % | 18,951 | 165 | % | |||||||||||||||
Tax Effect Different From Statutory Rates | (8,080 | ) | -11 | % | (1,571 | ) | 2 | % | (7,996 | ) | -70 | % | ||||||||||||
State Taxes, net of federal benefit | 4,757 | 7 | % | 2,689 | -4 | % | 1,579 | 14 | % | |||||||||||||||
Foreign Tax Credits | (1,867 | ) | -3 | % | (14,595 | ) | 22 | % | (15,442 | ) | -134 | % | ||||||||||||
Kazakhstan Tax Settlement | — | 0 | % | (536 | ) | 1 | % | 13,304 | 116 | % | ||||||||||||||
Mexico Tax Settlement | — | 0 | % | — | 0 | % | 1,022 | 9 | % | |||||||||||||||
Change in Valuation Allowance | (1,662 | ) | -2 | % | 2,542 | -4 | % | 506 | 4 | % | ||||||||||||||
Uncertain Tax Positions | (6,814 | ) | -10 | % | 1,348 | -2 | % | 983 | 9 | % | ||||||||||||||
Permanent Differences | 5,477 | 8 | % | 6,356 | -10 | % | 6,003 | 52 | % | |||||||||||||||
Prior Year Return to Provision Adjustments | 2,948 | 4 | % | 835 | -1 | % | 1,775 | 15 | % | |||||||||||||||
Other | 850 | 1 | % | 899 | -1 | % | 1,501 | 13 | % | |||||||||||||||
Unremitted Foreign Earnings-Current Year Adjustment | — | 0 | % | (5,484 | ) | 8 | % | — | 0 | % | ||||||||||||||
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Actual Tax Expense | $ | 33,879 | 48 | % | $ | (14,767 | ) | 22 | % | $ | 26,213 | 228 | % | |||||||||||
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The components of the Company’s deferred tax assets and liabilities as of December 31, 2012 and 2011 are shown below:
| December 31, | ||||||||
| 2012 | 2011 | |||||||
| (Dollars in Thousands) | ||||||||
Deferred tax assets | ||||||||
Current deferred tax assets: | ||||||||
Reserves established against realization of certain assets | $ | 1,634 | $ | 3,284 | ||||
Accruals | 6,747 | 3,065 | ||||||
Other | 361 | 301 | ||||||
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Gross current deferred tax assets | 8,742 | 6,650 | ||||||
Valuation allowance | — | — | ||||||
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Current deferred tax assets | 8,742 | 6,650 | ||||||
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Non-current deferred tax assets: | ||||||||
Federal net operating loss carryforwards | — | 361 | ||||||
State net operating loss carryforwards | 3,095 | 6,393 | ||||||
Other state deferred tax asset, net | 914 | 656 | ||||||
Foreign Tax Credits | 25,977 | 28,146 | ||||||
Note Hedge Interest | — | 1,318 | ||||||
Uncertain tax positions | 8,015 | 8,188 | ||||||
Foreign tax | 5,838 | 9,824 | ||||||
Impairment of long-lived assets | 56,190 | 59,500 | ||||||
Other | 71 | 392 | ||||||
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Gross long-term deferred tax assets | 100,100 | 114,778 | ||||||
Valuation Allowance | (4,805 | ) | (6,467 | ) | ||||
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Non-current deferred tax assets, net of valuation allowance | 95,295 | 108,311 | ||||||
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Net deferred tax assets | 104,037 | 114,961 | ||||||
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Deferred tax liabilities: | ||||||||
Non-current deferred tax liabilities: | ||||||||
Property, Plant and equipment | (19,139 | ) | (8,986 | ) | ||||
Accruals | (1,066 | ) | — | |||||
Foreign tax | — | (6,379 | ) | |||||
Convertible Debt | — | (31 | ) | |||||
Deferred compensation | 2,001 | 1,243 | ||||||
Other state deferred tax liability, net | (2,643 | ) | ||||||
Other | — | (630 | ) | |||||
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Gross non-current deferred tax liabilities | (20,847 | ) | (15,934 | ) | ||||
|
|
|
| |||||
Net deferred tax asset | $ | 83,190 | $ | 99,027 | ||||
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As part of the process of preparing the consolidated financial statements, the Company is required to determine its provision for income taxes. This process involves estimating the annual effective tax rate and the nature and measurements of 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 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. Based upon the factors considered by management in assessing the realizability of the deferred tax assets, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 2012. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.
The 2012 results include income tax expenses of $1.7 million related to the effective settlement of our US Federal Internal Revenue Service examination for the 2006 through 2010 periods and $7.7 million for depreciation and amortization relating to our AADU rigs in Alaska. In addition, we decreased our valuation allowance by $1.7 million primarily related to foreign NOLs.
The 2011 results include an income tax benefit of $60.9 million (federal and state combined) related to the $170.0 million non-cash pretax impairment charge relating to our AADU rigs in Alaska. In addition, we increased our valuation allowance by $2.5 million primarily related to foreign NOL’s.
The 2010 results include income tax expense primarily related to an unfavorable ruling by the Atyrau Oblast Court. The Kazakhstan tax matter increased tax expense by approximately $14.5 million ($6.8 million net of anticipated tax benefits), which includes approximately $6.5 million in tax, $4.8 million in interest and $3.2 million in penalties. PKD Kazakhstan intends to submit a further discretionary appeal to the Supreme Court of the Republic of Kazakhstan. In addition, tax expense increased from our settlement of a foreign tax audit for one of our subsidiaries for $1.2 million, which includes approximately $0.6 million of tax, $0.1 million in interest, and $0.5 million in penalties.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| In Thousands | ||||
Balance at January 1, 2012 | $ | (15,492 | ) | |
Additions based on tax positions taken during a prior period | (1,495 | ) | ||
Reductions based on tax positions taken during a prior period | 4,102 | |||
Reductions related to a lapse of applicable statute of limitations | 2,855 | |||
|
| |||
Balance at December 31, 2012 | $ | (10,030 | ) | |
|
| |||
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, 2012:
Colombia | 2008-present | |||
Kazakhstan | 2007-present | |||
Mexico | 2007-present | |||
Papua New Guinea | 2010-present | |||
Russia | 2009-present | |||
United States — Federal | 2011-present |
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At December 31, 2012, we had a liability for unrecognized tax benefits of $10.0 million ($3.2 million of which, if recognized, would favorably impact our effective tax rate).
The Company recognized interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2012 and December 31, 2011 we had approximately $7.0 million and $8.4 million of accrued interest and penalties related to uncertain tax positions, respectively. We recognized a decrease of $0.2 million of interest and a decrease of $1.1 million of penalties on unrecognized tax benefits for the year ended December 31, 2012.
As of December 31, 2012, 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 would likely be subject to US income taxes and foreign withholding taxes. It is not practicable to determine precisely the amount of taxes that may be payable on the eventual remittance of these earnings because of the application of US foreign tax credits. While we currently claim foreign tax credits, we may not be in a credit position if and when future remittances of foreign earnings occur, or the limitation imposed by the Internal Revenue Code and regulations thereunder may not allow the credits to be utilized during the applicable carryback and carryforward periods.
Note 6 — Long-Term Debt
The following table illustrates the Company’s current debt portfolio as of December 31, 2012 and December 31, 2011:
| December 31, | ||||||||
| 2012 | 2011 | |||||||
| (Dollars in Thousands) | ||||||||
Senior Notes—payable in April 2018; fixed interest at 9.125% payable | $ | 300,000 | $ | 300,000 | ||||
semi-annually in April and October (Issued March 22, 2010). | ||||||||
Senior Notes—payable in April 2018; fixed interest at 9.125% payable | 129,205 | — | ||||||
semi-annually in April and October (Issued April 25, 2012). | ||||||||
$125.0 million aggregate principal Convertible Senior Notes—payable in | — | 121,723 | ||||||
July 2012; interest at 2.125% payable semi-annually in January and | ||||||||
July, net of unamortized discount of $3,277 at December 31, 2011. | ||||||||
Term Note—amortizes $2.5 million per quarter beginning March 31, 2013 | 50,000 | 61,000 | ||||||
($6.0 million per quarter prior to March 31, 2013); interest at prime, plus an applicable margin or LIBOR, plus an applicable margin. (Effective interest rate of 3.21% and 3.55% at December 31, 2012 and December 31, 2011, respectively) | ||||||||
Total debt | 479,205 | 482,723 | ||||||
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| |||||
Less current portion | 10,000 | 145,723 | ||||||
Total long-term debt | $ | 469,205 | $ | 337,000 | ||||
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| |||||
The aggregate maturities of long-term debt, including unamortized premiums of $4.2 million, as of December 31, 2012 are as follows:
| Ÿ | 2013 — $11.0 million |
| Ÿ | 2014 — $10.9 million |
| Ÿ | 2015 — $10.8 million |
| Ÿ | 2016 — $10.7 million |
| Ÿ | 2017 and thereafter — $435.8 million |
9.125% Senior Notes, due April 2018
On March 22, 2010, we issued $300.0 million aggregate principal amount of 9.125% Senior Notes (9.125% Notes) pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company,
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N.A., as trustee. Net proceeds from the 9.125% Notes offering were primarily used to redeem the $225.0 million aggregate principal amount of our 9.625% Senior Notes due 2013 and to repay $42.0 million of borrowings under our senior secured revolving credit facility.
On April 25, 2012, we issued an additional $125.0 million aggregate principal amount of 9.125% Notes under the same indenture at a price of 104.0% of par, resulting in gross proceeds of $130.0 million. Net proceeds from the offering were utilized to refinance $125.0 million aggregate principal amount of the 2.125% Convertible Senior Notes due July 2012 (2.125% Notes). We repurchased $122.9 million aggregate principal amount of the 2.125% Notes tendered pursuant to a tender offer on May 9, 2012 and paid off the remaining $2.1 million at their stated maturity on July 15, 2012.
The 9.125% 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 9.125% Notes are jointly and severally guaranteed by substantially all of our direct and indirect subsidiaries other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States. Interest on the 9.125% Notes is payable on April 1 and October 1 of each year. Debt issuance costs related to the 9.125% Notes of approximately $11.6 million ($7.6 million, net of amortization) are being amortized over the term of the notes using the effective interest rate method.
At any time prior to April 1, 2013, we may redeem up to 35 percent of the aggregate principal amount of the 9.125% Notes at a redemption price of 109.125 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds of certain equity offerings by us. On and after April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of 104.563 percent of the principal amount, and beginning April 1, 2016 at redemption prices decreasing each year thereafter to par. If we experience certain changes in control, we must offer to repurchase the 9.125% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.
The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Events of Default. These covenants are subject to a number of important exceptions and qualifications.
2.125% Convertible Senior Notes, due July 2012
On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125% Notes. As noted above, on May 9, 2012, we repurchased $122.9 million aggregate principal amount of the 2.125% Notes pursuant to a tender offer. The tender offer price was $1,003.27 for each $1,000 principal amount of 2.125% Notes, plus accrued and unpaid interest. This repurchase resulted in the recording of debt extinguishment costs of $1.8 million related to the accelerated amortization of both the unamortized debt issuance costs and debt discount associated with the 2.125% Notes. The remaining $2.1 million aggregate principal amount of non-tendered 2.125% Notes was subsequently paid off at their stated maturity on July 15, 2012.
Concurrently with the issuance of the 2.125% Notes, we purchased a convertible note hedge (note hedge) and sold warrants in private transactions with counterparties that were different than the ultimate holders of the 2.125% Notes. The note hedge allowed us to receive shares of our common stock from the counterparties to the transaction equal to the amount of common stock related to the excess conversion value that we would issue and/or pay to the holders of the 2.125% Notes upon conversion. The warrants allowed us to sell 9,027,713 common shares at a strike price of $18.29 per share. The note hedge expired on July 15, 2012, the maturity date of the 2.125% Notes. The warrants expired ratably from October 15, 2012 to February 22, 2013.
Because we had the choice of settling the call options and the warrants in cash or shares of our common stock and these contracts met all of the applicable criteria for equity classification, the cost of the call options and proceeds from the sale of the warrants were classified in stockholders’ equity in the consolidated condensed balance sheets. In addition, because both of these contracts are classified in stockholders’ equity and were indexed solely to our common stock, they were not accounted for as derivatives.
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Debt issuance costs related to the 2.125% Notes of approximately $3.6 million were amortized over the five year term of the 2.125% Notes using the effective interest method.
Amended and Restated Credit Agreement
On December 14, 2012, we entered into an Amended and Restated Credit Agreement (Credit Agreement) consisting of a senior secured $80.0 million Revolver and senior secured term loan facility (Term Loan) of $50.0 million. The Credit Agreement amended and restated our existing credit agreement dated May 15, 2008 (Existing Credit Agreement). We entered into the Credit Agreement to extend its maturity from May 14, 2013 to December 14, 2017 and to decrease the range of Applicable Rates under our Revolver. The Credit Agreement provides that, subject to certain conditions, including the approval of the Administrative Agent and the lenders’ acceptance (or additional lenders being joined as new lenders), the amount of the Term Loan or Revolver can be increased by an additional $50.0 million, so long as after giving effect to such increase, the Aggregate Commitments shall not be in excess of $180.0 million.
Our obligations under the Credit Agreement are guaranteed by substantially all of our domestic subsidiaries, each of which has executed guaranty agreements; and are secured by first priority liens on our accounts receivable, specified barge rigs and rental equipment. The Credit Agreement contains customary affirmative and negative covenants with which we were in compliance as of December 31, 2012 and December 31, 2011. The Credit Agreement terminates on December 14, 2017.
Revolver
Our Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Under the Credit Agreement, the Applicable Rate varies from a rate per annum ranging from 2.50 percent to 3.00 percent for LIBOR rate loans and 1.50 percent to 2.00 percent for base rate loans, determined by reference to the consolidated leverage ratio (as defined in the Credit Agreement). Under the Existing Credit Agreement, the Applicable Rate varied from a rate per annum ranging from 2.75 percent to 3.25 percent for LIBOR rate loans and 1.75 percent to 2.25 percent for base rate loans. Revolving loans are available subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and rental equipment of the Company and its subsidiary guarantors. There were no revolving loans outstanding at December 31, 2012 and December 31, 2011. Letters of credit outstanding as of December 31, 2012 and December 31, 2011 totaled $4.5 million and $2.7 million, respectively.
Term Loan
The Term Loan originated at $50.0 million on December 14, 2012 and requires quarterly principal payments of $2.5 million beginning March 31, 2013. Interest on the Term Loan accrues at a Base Rate plus 2.00 percent or LIBOR plus 3.00 percent. The Existing Credit Agreement required quarterly principal payments of $6.0 million, and interest accrued at a Base Rate plus 2.25 percent or LIBOR plus 3.25 percent. The outstanding balance on the Term Loans at December 31, 2012 was $50.0 million under the Credit Agreement. The outstanding balance under the then existing Credit Agreement as of December 31, 2011 was $61.0 million.
Note 7—Derivative Financial Instruments
The Company entered into two variable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on the Term Loan borrowings under the Credit Agreement. The two agreements fix the interest rate on a notional amount of $73.0 million of borrowings at 3.878% for the period beginning June 27, 2011 and terminating May 14, 2013. The notional amount of the swap agreements decrease correspondingly with amortization of the Term Loan. We will not apply hedge accounting to the agreements and, accordingly, mark-to-market change in the fair value of the interest rate swaps are recognized in earnings. As of December 31, 2012, the fair value of the interest rate swap was a liability of $0.1 million and is recorded in accrued liabilities in our consolidated balance sheets. For the year ended December 31, 2012, the Company recognized in earnings a $0.1 million loss relating to these contracts.
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Note 8—Fair Value of Financial Instruments
Certain of our assets and liabilities are required to be measured at fair value on a recurring basis. For purposes of recording fair value adjustments for certain financial and non-financial assets and liabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.
The fair value measurement and disclosure requirements of FASB Accounting Standards Codification Topic No. 820, Fair Value Measurement and Disclosures (ASC 820) 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 inactive 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 measurement even though we may have also utilized significant inputs that are more readily observable. The amounts reported in our consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. The carrying amount of our interest rate swap agreements represents the estimated fair value, measured using Level 2 inputs. At each year ended December 31, 2012 and 2011, the carrying amount of our interest rate swap agreements was a liability of $0.1 million, recorded in accrued liabilities and other long-term liabilities, respectively on our consolidated balance sheets.
Fair value of our debt instruments is determined using Level 2 inputs. Fair values and related carrying values of our debt instruments are as follows:
| December 31, 2012 | December 31, 2011 | |||||||||||||||
| Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
| (in thousands) | ||||||||||||||||
Long-term Debt | ||||||||||||||||
9.125% Notes | $ | 300,000 | $ | 320,250 | $ | 300,000 | $ | 315,000 | ||||||||
9.125% Notes | $ | 125,000 | $ | 133,438 | ||||||||||||
2.125% Notes | — | — | 125,000 | 123,204 | ||||||||||||
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|
|
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|
|
| |||||||||
Total | $ | 425,000 | $ | 453,688 | $ | 425,000 | $ | 438,204 | ||||||||
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| |||||||||
As discussed in Note 2, in accordance with the impairment or disposal of long-lived assets subsections of ASC 360-10, Property, Plant and Equipment, during the fourth quarter of 2011, our AADU assets with a carrying value as of December 31, 2011 of $339.5 million were written down to their estimated fair value of $169.5 million, resulting in a pretax non-cash charge of $170.0 million which is included in earnings for the period. The fair value was based on expected future cash flows using Level 3 inputs.
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, 2012.
Note 9 — Common Stock and Stockholders’ Equity
Stock Plans — The Company’s employee and non-employee director stock plans are summarized as follows:
The 2010 Long-Term Incentive Plan (2010 Plan) was approved by the stockholders at the Annual Meeting of Stockholders on May 7, 2010. The 2010 Plan authorizes the compensation committee or the board of directors to issue stock options, stock appreciation rights, RSAs, RSUs, performance-based awards and other types of
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awards in cash or stock to key employees, consultants, and directors. The maximum number of shares of our common stock that may be delivered pursuant to the awards granted under the 2010 Plan is 5,800,000 shares of common stock.
On September 17, 2012, Gary Rich was elected as President and Chief Executive Officer of the company. As part of his employment agreement, he was granted 349,651 restricted stock units, which were granted outside of the Company’s 2010 Plan but are subject to substantially the same terms and conditions of other service-based restricted stock units granted by the Company to its executive officers.
The 2005 Long-Term Incentive Plan (2005 Plan) was approved by the stockholders at the Annual Meeting of Stockholders on April 27, 2005. The 2005 Plan authorizes the compensation committee or the board of directors to issue stock options, stock grants and various types of incentive awards in cash or stock to key employees, consultants and directors. During 2008, we obtained stockholder’s approval to increase the total number of common shares available for future awards under the 2005 Plan. This amendment to the 2005 Plan was approved by stockholders at our Annual Meeting on March 21, 2008. No further grants can be made under this plan.
Information regarding the Company’s Long-Term Incentive plans is summarized below:
Nonvested Shares | Shares | Weighted Average Grant-Date Fair Value | ||||||
Nonvested at January 1, 2012 | 2,813,409 | $ | 6.91 | |||||
Granted | 1,558,347 | 5.37 | ||||||
Vested | (1,472,233 | ) | 4.86 | |||||
Forfeited | (505,626 | ) | 5.44 | |||||
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Nonvested at December 31, 2012 | 2,393,897 | $ | 5.22 | |||||
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In 2012 and 2011, we issued 1,558,347 and 1,457,039, respectively, of restricted shares to selected key personnel. Total stock-based compensation expense recognized for the years ended December 31, 2012, 2011, and 2010 was $7.2 million, $5.9 million, and $5.5 million, respectively, all of which was related to nonvested stock. The total fair value of the shares vested during the years ended December 31, 2012, 2011, and 2010 was $7.2 million, $6.9 million, and $4.1 million, respectively. The fair value of RSA’s and RSU’s is determined based on the closing trading price of the company’s shares on the grant date. The weighted-average grant-date fair value of shares granted during the years 2012, 2011, and 2010 was $5.37, $5.61, and $4.54, respectively. Stock-based compensation expense is included in our consolidated statements of operations in both “General and administration expense” and “Operating expenses.”
Nonvested RSAs and RSUs at December 31, 2012 totaled 2,393,897 shares and total unrecognized compensation cost related to unamortized nonvested stock awards was $6.8 million as of December 31, 2012. The remaining unrecognized compensation cost related to non-vested stock awards will be amortized over a weighted-average vesting period of approximately 20.1 months.
During the year ended December 31, 2012, we granted to certain of our officers and key employees a total of 38,429 performance units under the 2010 Long Term Incentive Plan. Subsequent to the award of these performance units, 3,955 units were forfeited during 2012. During the year ended December 31, 2011, we granted to certain of our officers and key employees a total of 44,500 performance units under the 2010 Long Term Incentive Plan. Subsequent to the award of these performance units, 2,424 units were forfeited during 2011. Incentive grants included in this issuance were based on the attainment of pre-established performance goals. Each performance unit has a nominal value of $100.00. Awards are dependent upon our total stockholder return and return on capital employed relative to a peer group of companies over a three-year performance period. A maximum of 200 percent of the number of performance units granted may be earned if performance at the maximum level is achieved. Performance units can be settled in cash or stock at the discretion of the compensation committee of the board of directors and are, therefore, accounted for as liability awards and remeasured at each reporting date until settlement. Compensation expense recognized related to the performance units for the years ended December 31, 2012, 2011, and 2010 was $0.5 million, $2.1 million, and $2.7 million, respectively.
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As of December 31, 2012 and 2011, we had 7,657,479 and 8,669,723, respectively, common stock shares reserved for issuance. As of December 31, 2012 and 2011, we had no stock options outstanding or exercisable and we had 1,411,371 and 1,709,963 shares held in treasury stock, respectively.
Note 10 — Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings per Share (EPS)
| For the Year Ended December 31, 2012 | ||||||||||||
| Income (Numerator) | Shares (Denominator) | Per-Share Amount | ||||||||||
Basic EPS | $ | 37,313,000 | 117,721,135 | $ | 0.32 | |||||||
Effect of dilutive securities: | ||||||||||||
Stock options and restricted stock | 1,372,455 | $ | (0.01 | ) | ||||||||
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Diluted EPS | $ | 37,313,000 | 119,093,590 | $ | 0.31 | |||||||
| For the Year Ended December 31, 2011 | ||||||||||||
| Income (Numerator) | Shares (Denominator) | Per-Share Amount | ||||||||||
Basic EPS | $ | (50,451,000 | ) | 116,081,590 | $ | (0.43 | ) | |||||
Effect of dilutive securities: | ||||||||||||
Stock options and restricted stock | — | $ | — | |||||||||
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Diluted EPS: | $ | (50,451,000 | ) | 116,081,590 | $ | (0.43 | ) | |||||
| For the Year Ended December 31, 2010 | ||||||||||||
| Income (Numerator) | Shares (Denominator) | Per-Share Amount | ||||||||||
Basic EPS | $ | (14,461,000 | ) | 114,258,965 | $ | (0.13 | ) | |||||
Effect of dilutive securities: | ||||||||||||
Stock options and restricted stock | — | $ | — | |||||||||
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Diluted EPS: | $ | (14,461,000 | ) | 114,258,965 | $ | (0.13 | ) | |||||
For the year ended December 31, 2012, weighted-average shares outstanding used in our computation of diluted EPS includes the dilutive effect of potential common shares. For the years ended December 31, 2011, and 2010, all potential common shares have been excluded from the calculation of weighted-average shares outstanding used in our computation of diluted EPS as the company incurred a loss for each year, and therefore, inclusion of potential common shares in the calculation of diluted EPS would be anti-dilutive.
Note 11 — Employee Benefit Plan
The Company sponsors a defined contribution 401(k) plan (Plan) in which substantially all U.S. employees are eligible to participate. The Company matches 100 percent of the first 4 percent and 50 percent of the next 2 percent of an employee’s pre-tax contributions. The costs of our matching contributions to the Plan were $2.8 million, $2.4 million and $2.4 million in 2012, 2011 and 2010, respectively. Employees become 100 percent vested in the employer match contributions immediately upon participation in the Plan. Coverage for office based employees begins on the date of hire. For rig-based and rental tools employees, coverage begins on the first of the month following completion of 30 calendar days of continuous full-time employment.
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Note 12 — Reportable Segments
We report our business activities in six business segments: (1) Rental tools, (2) U.S. barge drilling, (3) U.S. drilling, (4) International drilling, (5) Technical services, and (6) Construction contract. We eliminate inter-segment revenue and expenses. The following table represents the results of operations by reportable segment:
| Year Ended December 31, | ||||||||||||
Operations by Reportable Industry Segment: | 2012 | 2011 | 2010 | |||||||||
| (Dollars in Thousands) | ||||||||||||
Revenues: | ||||||||||||
Rental Tools(1) | $ | 246,900 | $ | 237,068 | $ | 172,598 | ||||||
U.S. Barge Drilling(1) | 123,672 | 93,763 | 64,543 | |||||||||
U.S. Drilling(1)(3) | 1,387 | — | — | |||||||||
International Drilling(1) | 291,772 | 318,482 | 294,821 | |||||||||
Technical Services(1) | 14,251 | 27,695 | 36,423 | |||||||||
Construction Contract(1) | — | 9,638 | 91,090 | |||||||||
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Total revenues | 677,982 | 686,646 | 659,475 | |||||||||
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Operating income: | ||||||||||||
Rental Tools(2) | 113,899 | 120,822 | 74,541 | |||||||||
U.S. Barge Drilling(2) | 39,774 | 11,116 | (11,503 | ) | ||||||||
U.S. Drilling(2) | (15,168 | ) | (3,915 | ) | (217 | ) | ||||||
International Drilling(2) | 12,642 | 22,237 | 5,092 | |||||||||
Technical Services(2) | (246 | ) | 5,335 | 5,052 | ||||||||
Construction Contract(2) | — | 771 | 202 | |||||||||
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Total operating gross margin | 150,901 | 156,366 | 73,167 | |||||||||
General and administrative expense | (46,052 | ) | (31,314 | ) | (30,728 | ) | ||||||
Impairments and other charges | — | (170,000 | ) | — | ||||||||
Provision for reduction in carrying value of certain assets | — | (1,350 | ) | (1,952 | ) | |||||||
Gain on disposition of assets, net | 1,974 | 3,659 | 4,620 | |||||||||
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Total operating income (loss) | 106,823 | (42,639 | ) | 45,107 | ||||||||
Interest expense | (33,542 | ) | (22,594 | ) | (26,805 | ) | ||||||
Changes in fair value of derivative positions | 55 | (110 | ) | — | ||||||||
Loss on extinguishment of debt | (2,130 | ) | — | (7,209 | ) | |||||||
Other | (229 | ) | (69 | ) | 412 | |||||||
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Income (loss) from continuing operations before income taxes | $ | 70,977 | $ | (65,412 | ) | $ | 11,505 | |||||
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| 2012 | 2011 | |||||||||||
Identifiable assets: | ||||||||||||
Rental Tools | $ | 194,600 | $ | 188,520 | ||||||||
U.S. Barge Drilling | 99,409 | 108,396 | ||||||||||
U.S. Drilling | 374,794 | 265,166 | ||||||||||
International Drilling | 414,546 | 426,490 | ||||||||||
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Total identifiable assets | 1,083,349 | 988,572 | ||||||||||
Corporate and other assets(4) | 172,384 | 227,674 | ||||||||||
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Total assets | $ | 1,255,733 | $ | 1,216,246 | ||||||||
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| 1) | In 2012, our two largest customers, Exxon Neftegas Limited (ENL) and Schlumberger, constituted approximately 12 percent and 10 percent, respectively, of our total consolidated revenues and approximately 27 percent and 24 percent of our International Drilling segment, respectively. In 2011, our largest customer, ENL constituted approximately 16 percent of our total revenues and approximately 34 percent of our International Drilling segment. In 2010, our two largest customers BP and ExxonMobil both accounted for approximately 12 percent of the Company’s total revenues. In 2010, BP accounted for 90 percent of our construction contract segment revenues and ExxonMobil accounted for approximately 22 percent of our International Drilling segment and 7 percent of our Rental Tools segment. |
| 2) | Operating income is calculated as revenues less direct operating expenses, including depreciation and amortization expense. |
| 3) | As of December 31, 2011, this segment had not begun generating revenue. |
| 4) | This category includes corporate assets as well as minimal assets for our Technical Services segment primarily related to office furniture and fixtures. |
| Year ended December 31, | ||||||||||||
Operations by Reportable Industry Segment: | 2012 | 2011 | 2010 | |||||||||
| (Dollars in Thousands) | ||||||||||||
Capital expenditures: | ||||||||||||
Rental Tools | $ | 61,958 | $ | 61,702 | $ | 48,872 | ||||||
U.S. Barge Drilling | 8,808 | 7,339 | 5,315 | |||||||||
U.S. Drilling | 86,786 | 99,915 | 113,177 | |||||||||
International Drilling | 15,240 | 15,011 | 50,482 | |||||||||
Corporate | 18,751 | 6,432 | 1,338 | |||||||||
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Total capital expenditures | $ | 191,543 | $ | 190,399 | $ | 219,184 | ||||||
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Depreciation and amortization: | ||||||||||||
Rental Tools | 42,944 | 40,497 | 36,558 | |||||||||
U.S. Barge Drilling | 13,906 | 17,006 | 22,165 | |||||||||
U.S. Drilling | 7,011 | 2,223 | — | |||||||||
International Drilling | 45,967 | 48,965 | 52,429 | |||||||||
Corporate and other (1) | 3,189 | 3,445 | 3,878 | |||||||||
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Total depreciation and amortization | $ | 113,017 | $ | 112,136 | $ | 115,030 | ||||||
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| 1) | This category includes depreciation of corporate assets as well as minimal depreciation for our Technical Services segment primarily related to office furniture and fixtures. |
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| Year Ended December 31, | ||||||||||||
Operations by Geographic Area: | 2012 | 2011 | 2010 | |||||||||
| (Dollars in Thousands) | ||||||||||||
Revenues: | ||||||||||||
Africa and Middle East | $ | 26,528 | $ | 6,774 | $ | 22,621 | ||||||
Asia Pacific | 39,400 | 38,477 | 26,416 | |||||||||
CIS | 122,304 | 176,421 | 149,963 | |||||||||
Latin America | 103,540 | 96,810 | 103,885 | |||||||||
United States | 386,210 | 368,164 | 356,590 | |||||||||
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| |||||||
Total revenues | 677,982 | 686,646 | 659,475 | |||||||||
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Operating gross margin: | ||||||||||||
Africa and Middle East(1) | (2,234 | ) | (6,383 | ) | 659 | |||||||
Asia Pacific(1) | (927 | ) | 1,933 | 2,374 | ||||||||
CIS(1) | 6,840 | 26,402 | 8,139 | |||||||||
Latin America(1) | 8,990 | 377 | 1,210 | |||||||||
United States(1) | 138,232 | 134,037 | 60,785 | |||||||||
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| |||||||
Total operating gross margin | 150,901 | 156,366 | 73,167 | |||||||||
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| |||||||
General and administrative expense | (46,052 | ) | (31,314 | ) | (30,728 | ) | ||||||
Impairments and other charges | — | (170,000 | ) | — | ||||||||
Provision for reduction in carrying value of certain assets | — | (1,350 | ) | (1,952 | ) | |||||||
Gain on disposition of assets, net | 1,974 | 3,659 | 4,620 | |||||||||
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| |||||||
Total operating income (loss) | 106,823 | (42,639 | ) | 45,107 | ||||||||
Interest expense | (33,542 | ) | (22,594 | ) | (26,805 | ) | ||||||
Changes in fair value of derivative positions | 55 | (110 | ) | — | ||||||||
Loss on extinguishment of debt | (2,130 | ) | — | (7,209 | ) | |||||||
Other | (229 | ) | (69 | ) | 412 | |||||||
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| |||||||
Income (loss) from continuing operations before income taxes | $ | 70,977 | $ | (65,412 | ) | $ | 11,505 | |||||
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Long-lived assets:(2) | ||||||||||||
Africa and Middle East | $ | 25,032 | $ | 28,427 | ||||||||
Asia Pacific | 15,723 | 18,300 | ||||||||||
CIS | 106,774 | 119,282 | ||||||||||
Latin America | 63,899 | 57,710 | ||||||||||
United States | 574,730 | 496,090 | ||||||||||
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| |||||||||
Total long-lived assets | $ | 786,158 | $ | 719,809 | ||||||||
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| |||||||||
| 1) | Operating income is calculated as revenues less direct operating expenses, including depreciation and amortization expense. |
| 2) | Long-lived assets primarily consist of property, plant and equipment, net and exclude assets held for sale, if any. |
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Note 13 — Commitments and Contingencies
The Company has various lease agreements for office space, equipment, vehicles and personal property. These obligations extend through 2013 and are typically non-cancelable. Most leases contain renewal options and certain of the leases contain escalation clauses. Future minimum lease payments at December 31, 2012, under operating leases with non-cancelable terms are as follows:
| Year Ended December 31, | ||||
| (Dollars in Thousands) | ||||
2013 | 6,734 | |||
2014 | 4,134 | |||
2015 | 3,851 | |||
2016 | 2,742 | |||
2017 | 2,092 | |||
Thereafter | 8,209 | |||
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| |||
Total | $ | 27,762 | ||
|
| |||
Total rent expense for all operating leases amounted to $11.8 million for 2012, $12.1 million for 2011 and $12.0 million for 2010.
We are self-insured for certain losses relating to workers’ compensation, employers’ liability, general liability (for onshore liability), protection and indemnity (for offshore liability) and property damage. Our exposure (that is, the retention or deductible) per occurrence is $250,000 for worker’s compensation, employer’s liability, general liability, protection and indemnity and maritime employers’ liability (Jones Act). In addition, we assume a $500,000 annual aggregate deductible for protection and indemnity and maritime employers’ liability claims. The annual aggregate deductible is reduced by every dollar that exceeds the $250,000 per occurrence retention. We continue to assume a retention of $250,000 for workers’ compensation, employers’ liability, and general liability losses and a $100,000 deductible for auto liability claims. For all primary insurances mentioned above, the Company has excess coverage for those claims that exceed the retention and annual aggregate deductible. We maintain actuarially-determined accruals in our consolidated balance sheets to cover the self-insurance retentions.
We have self-insured retentions for certain other losses relating to rig, equipment, property, business interruption and political, war, and terrorism risks which vary according to the type of rig and line of coverage. Political risk insurance is procured for international operations. However, this coverage may not adequately protect us against liability from all potential consequences.
As of December 31, 2012 and 2011, our gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $4.7 million and $6.6 million, respectively and the related insurance recoveries/receivables were $1.2 million and $1.9 million, respectively.
We have entered into employment agreements with terms of one to two years 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.
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
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lawsuits and claims, the ultimate outcome may differ significantly from our estimates. In the opinion of management and based on liability accruals provided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on our consolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particular reporting period.
Asbestos-Related Claims
We are from time to time a party to various lawsuits that are incidental to our operations in which the claimants seek an unspecified amount of monetary damages for personal injury, including injuries purportedly resulting from exposure to asbestos on drilling rigs and associated facilities. At December 31, 2012, there were approximately 15 of these lawsuits in which we are one of many defendants. These lawsuits have been filed in the United States in the State of Mississippi.
The subsidiaries named in these asbestos-related lawsuits intend to defend themselves vigorously and, based on the information available to us at this time, we do not expect the outcome to have a material adverse effect on our financial condition, results of operations or cash flows. However, we are unable to predict the ultimate outcome of these lawsuits. No amounts were accrued at December 31, 2012.
Gulfco Site
In 2003, we received an information request under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) designating Parker Drilling Offshore Corporation, a subsidiary of Parker Drilling, as a potentially responsible party with respect to the Gulfco Marine Maintenance, Inc. Superfund Site in Freeport, Texas (EPA No. TX 055144539). We responded to this request and in January 2008 received an administrative order to participate in an investigation of the site and a study of the remediation needs and alternatives. The EPA alleges that our subsidiary is a successor to a party who owned the Gulfco site during the time when chemical releases took place there. In December 2010, we entered into an agreement with two other potentially responsible parties, pursuant to which we agreed to pay 20 percent of past and future costs to study and remediate the site. The EPA also issued notice letters to several other parties who may also participate in funding the site remediation costs. As of December 31, 2012, the Company had made certain participating payments and had accrued $0.7 million for our portion of certain unreimbursed past costs and the estimated future cost of remediation. To date, we believe that all required activity for removal and remediation has been completed, except for ongoing monitoring costs, and we are awaiting a Notice of Completion from the EPA.
Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation
As previously disclosed, we have engaged in settlement discussions with the United States Department of Justice (DOJ) and the United States Securities and Exchange Commission (SEC) related to parallel investigations that they conducted regarding possible violations of U.S. law, including the FCPA, by us. In particular, the DOJ and the SEC investigated certain of our operations relating to countries in which we currently operate or formerly operated, including Kazakhstan and Nigeria. We fully cooperated with the DOJ and SEC investigations and conducted an internal investigation into potential customs and other issues in Kazakhstan and Nigeria. Subject to court and regulatory approvals, we have reached agreement in principle regarding a proposed settlement of these matters with the DOJ and the staff of the SEC.
Under the terms of the proposed resolution with the DOJ, it is expected that the Company would enter into a deferred prosecution agreement (DPA), under which the DOJ would defer for three years prosecuting the Company for criminal violations of the anti-bribery provisions of the FCPA relating to the Company’s retention and use of an individual agent in Nigeria with respect to certain customs-related issues, in return for: (i) the Company’s acceptance of responsibility for, and agreement not to contest or contradict the truthfulness of, the statement of facts and allegations to be filed in a United States District Court concurrently with the DPA; (ii) the Company’s payment of an approximately $11.76 million fine; (iii) the Company’s reaffirming its commitment to compliance with the FCPA and other applicable anti-corruption laws in connection with the Company’s operations, and continuing cooperation with domestic and foreign authorities in connection with the matters that
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are the subject of the DPA; (iv) the Company’s commitment to continue to address any identified areas for improvement in the Company’s internal controls, policies and procedures relating to compliance with the FCPA and other applicable anti-corruption laws if, and to the extent, not already addressed; and (v) the Company’s agreement to report to the DOJ in writing annually during the term of the DPA regarding remediation of the matters that are the subject of the DPA, implementation of any enhanced internal controls, and any evidence of improper payments the Company may have discovered during the term of the agreement. If the Company remains in compliance with the terms of the DPA throughout its effective period, the charge against the Company would be dismissed with prejudice.
Under the terms of the proposed resolution with SEC, the staff of the SEC has agreed to recommend to its governing Commission that the SEC enter into a settlement with the Company, pursuant to which the SEC will file a civil complaint in a United States District Court charging the Company with violations of the anti-bribery, books and records and internal control provisions of the FCPA, and the Company would consent to the entry of a final judgment of permanent injunction barring future violations of the anti-bribery, books and records and internal controls provisions of the FCPA. The Company also would agree to the payment of disgorgement of approximately $3.05 million and prejudgment interest of approximately $1.04 million, for a total of approximately $4.09 million. The proposed agreement with the SEC would not require the payment of a civil monetary fine, and neither the proposed agreement with the DOJ nor the proposed agreement with the SEC would require the appointment of a monitor to oversee the Company’s activities or compliance with applicable laws.
The agreement in principle is contingent upon the parties’ preparation and agreement on the language of the settlement documents, approval of the civil settlement by the SEC’s governing Commission and by a United States District Court. There can be no assurance that this proposed settlement will be finalized, or finalized on the terms currently agreed in principle, and we cannot provide assurances regarding if and when the court and/or the SEC’s governing Commission will approve the settlement.
If one or both of these approvals do not occur, the Company may enter further discussions with the DOJ and/or the SEC to resolve the investigated matters on different terms and conditions; such terms and conditions could include any of a broad range of civil and criminal sanctions under the FCPA and other laws and regulations, which they may seek to impose against corporations and individuals in appropriate circumstances. These include, but are not limited to, injunctive relief, disgorgement, fines, penalties and modifications to business practices and compliance programs. Any such disgorgement, fines, penalties, interest or other associated costs could be materially higher than the amounts that we have currently accrued. The DOJ and the SEC have entered into agreements with, and obtained a range of sanctions against, several public corporations and individuals arising from allegations of improper payments and deficiencies in books and records and internal controls, whereby civil and criminal penalties were imposed. Recent civil and criminal settlements have included multi-million dollar fines, deferred prosecution agreements, guilty pleas, and other sanctions, including the requirement that the relevant corporation retain a monitor to oversee its compliance with the FCPA. In addition, corporations may have to end or modify existing business relationships. The Company could also face fines, sanctions and other penalties imposed by other regulatory authorities or in other legal actions. Any such fines, sanctions or penalties could impact the Company’s business operations and assets, particularly in jurisdictions outside the United States, and could have a material adverse impact on our business, results of operations, financial condition and liquidity.
As previously disclosed, we have taken and continue to take certain steps to enhance our existing anti-bribery compliance efforts, including retaining a full-time Chief Compliance Officer who reports to the Chief Executive Officer and Audit Committee and full-time staff to assist him; adopting revised FCPA policies, procedures, and controls; increasing training and testing requirements; strengthening contractual provisions for our service providers that interface with foreign government officials; improving due diligence and continuing oversight procedures for the review and selection of such service providers; and implementing a compliance awareness improvement initiative that includes issuance of periodic anti-bribery compliance alerts. We will continue to emphasize the importance of compliance and ethical business conduct.
The Company recorded a charge of $15.85 million associated with the proposed settlement with the DOJ and SEC for the fourth quarter of 2012. Such charge, which is included in general and administrative expenses, is subject to change based on the results of any final settlement with DOJ and SEC relating to these matters.
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Demand Letter and Derivative Litigation
In April 2010, we received a demand letter from a law firm representing Ernest Maresca. The letter states that Mr. Maresca is one of our stockholders and that he believes that certain of our current and former officers and directors violated their fiduciary duties related to the issues described above under “Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation.” The letter requests that our Board of Directors take action against the individuals in question. In response to this letter, the Board formed a special committee to evaluate the issues raised by the letter and determine a course of action for the Company, and such committee’s work is ongoing.
On August 31, 2010, Douglas Freuler, a purported stockholder of the Company, filed a derivative action in the United States District Court for the Southern District of Texas against our current directors, select officers, and the Company as a nominal defendant. The lawsuit alleges that the individuals breached their fiduciary duties to the Company related to the issues described above under “Customs Agent and Foreign Corrupt Practices Act (FCPA) Investigation,” as well as abuse of control, gross mismanagement, waste of corporate assets, and unjust enrichment. The damages sought included both compensatory and exemplary damages in an unspecified amount, along with various other forms of relief and an award of attorney fees, other costs, and expenses to the plaintiffs. Defendants’ motions to dismiss the amended complaint were granted on June 30, 2011, and plaintiff was given thirty days to replead. Mr. Freuler filed his second amended complaint on July 20, 2011. Defendants’ motions to dismiss the second amended complaint were granted on March 14, 2012. The matter is now on appeal before the U.S. Court of Appeals for the Fifth Circuit, and oral argument in the matter will be heard on March 5, 2013.
Note 14 — Related Party Transactions
Consulting Agreement
The Company was a party to a consulting agreement with Robert L. Parker Sr., the former Chairman of the Board of Directors of the Company and the father of our current Executive Chairman, Robert L. Parker Jr. The consulting agreement expired on April 30, 2011. Under the agreement, Mr. Parker Sr. was paid consulting fees of $40,000, and $123,750 in the years ending December 31, 2011 and 2010, respectively. For one year after the termination of the consulting agreement, Mr. Parker Sr. was prohibited from soliciting business from any of our customers or individuals with which we have done business, from becoming interested in any business that competes with the Company, and from recruiting any employees of the Company. Under the consulting agreement, Mr. Parker Sr. also represented the Company on the U.S.-Kazakhstan Business Council. In addition, we pay a monthly rental fee to Mr. Parker Sr. for various pieces of artwork which are displayed throughout our corporate office. In 2012, 2011, and 2010 we paid Mr. Parker $36,000, $36,000, and $30,000, respectively for the artwork rental.
Effective January 1, 2012, the Company entered into two separate ranch lease agreements under which the Company agreed to pay a daily usage fee per person for utilization of the Cypress Springs Ranch owned by the Robert L. Parker, Sr. and Catherine M. Parker Family Limited Partnership and the Camp Verde Ranch owned by Robert L. Parker, Jr. During 2012, the Company incurred fees of $39,875 and $1,650 for the Cypress Springs Ranch and Camp Verde Ranch, respectively, pursuant to the ranch lease agreements for the right to utilize the premises of the ranches for the purpose of hosting business meetings.
Other Related Party Agreements
During 2012 and 2011, one of the Company’s directors held executive positions at Apache Corporation (Apache), including the positions of President and Chief Corporate Officer, Executive Vice President and Chief Financial Officer and Chief Corporate Officer. During 2012 and 2011, affiliates of Apache paid affiliates of the Company a total of $31.2 million and $22.7 million, respectively, for performance of drilling services and provision of rental tools. This information is considered and discussed annually in connection with the Board of Directors’ assessment of facts and circumstances that could preclude a determination that such director is independent under the New York Stock Exchange governance listing standards.
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Note 15 — Supplementary Information
At December 31, 2012, accrued liabilities included $1.6 million of deferred mobilization fees, $9.7 million of accrued interest expense, $2.3 million of worker’s compensation liabilities and $26.0 million of accrued payroll and payroll taxes. Other long-term obligations included $2.5 million of workers’ compensation liabilities as of December 31, 2012.
At December 31, 2011, accrued liabilities included $2.2 million of deferred mobilization fees, $8.1 million of accrued interest expense, $3.0 million of worker’s compensation liabilities and $26.8 million of accrued payroll and payroll taxes. Other long-term obligations included $3.6 million of workers’ compensation liabilities as of December 31, 2011.
Note 16 —Parent, Guarantor, Non-Guarantor Unaudited Consolidating Condensed Financial Statements
Set forth on the following pages are the consolidating condensed financial statements of Parker Drilling. The Company’s 9.125% Notes are guaranteed by substantially all of the restricted subsidiaries of Parker Drilling. 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(a)(1) of Regulation S-X, set forth in sub-paragraph (f) of such rule. All guarantor subsidiaries are owned 100 percent by the parent company, all guarantees are full and unconditional and all guarantees are joint and several.
We are providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of December 31, 2012 and December 31, 2011 and for the years ended December 31, 2012, 2011, and 2010. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.
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PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
| Year ended December 31, 2012 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
Total revenues | $ | — | $ | 393,959 | $ | 385,279 | $ | (101,256 | ) | $ | 677,982 | |||||||||
Operating expenses | — | 185,328 | 329,992 | (101,256 | ) | 414,064 | ||||||||||||||
Depreciation and amortization | — | 65,354 | 47,663 | — | 113,017 | |||||||||||||||
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Total operating gross margin | — | 143,277 | 7,624 | — | 150,901 | |||||||||||||||
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|
| |||||||||||
General and administration expense (1) | (182 | ) | (45,433 | ) | (437 | ) | — | (46,052 | ) | |||||||||||
Gain on disposition of assets, net | — | 775 | 1,199 | — | 1,974 | |||||||||||||||
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|
|
|
|
|
| |||||||||||
Total operating income (loss) | (182 | ) | 98,619 | 8,386 | — | 106,823 | ||||||||||||||
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| |||||||||||
Other income and (expense): | ||||||||||||||||||||
Interest expense | (37,326 | ) | (151 | ) | (8,739 | ) | 12,674 | (33,542 | ) | |||||||||||
Changes in fair value of derivative positions | 55 | — | — | — | 55 | |||||||||||||||
Interest income | 9,863 | 5,073 | 41,999 | (56,782 | ) | 153 | ||||||||||||||
Loss on extinguishment of debt | (2,130 | ) | — | — | — | (2,130 | ) | |||||||||||||
Other | — | (370 | ) | (12 | ) | — | (382 | ) | ||||||||||||
Equity in net earnings of subsidiaries | 43,884 | — | — | (43,884 | ) | — | ||||||||||||||
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| |||||||||||
Total other income (expense) | 14,346 | 4,552 | 33,248 | (87,992 | ) | (35,846 | ) | |||||||||||||
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| |||||||||||
Income (benefit) before income taxes | 14,164 | 103,171 | 41,634 | (87,992 | ) | 70,977 | ||||||||||||||
Income tax expense (benefit): | ||||||||||||||||||||
Current | (25,406 | ) | 32,781 | 10,667 | — | 18,042 | ||||||||||||||
Deferred | 2,257 | 15,429 | (1,849 | ) | — | 15,837 | ||||||||||||||
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| |||||||||||
Income tax expense (benefit) | (23,149 | ) | 48,210 | 8,818 | — | 33,879 | ||||||||||||||
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|
|
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|
| |||||||||||
Net income (loss) | 37,313 | 54,961 | 32,816 | (87,992 | ) | 37,098 | ||||||||||||||
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| |||||||||||
Less: Net (loss) attributable to noncontrolling interest | — | — | (215 | ) | — | (215 | ) | |||||||||||||
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| |||||||||||
Net income (loss) attributable to controlling interest | $ | 37,313 | $ | 54,961 | $ | 33,031 | $ (87,992 | ) | $ | 37,313 | ||||||||||
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| (1) | General and administration expenses for field operations are included in operating expenses. |
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PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
| Year ended December 31, 2011 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
Total revenues | $ | — | $ | 376,229 | $ | 426,491 | $ | (116,074 | ) | $ | 686,646 | |||||||||
Operating expenses | — | 175,465 | 358,753 | (116,074 | ) | 418,144 | ||||||||||||||
Depreciation and amortization | — | 62,744 | 49,392 | — | 112,136 | |||||||||||||||
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| |||||||||||
Total operating gross margin | — | 138,020 | 18,346 | — | 156,366 | |||||||||||||||
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|
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|
| |||||||||||
General and administration expense (1) | (218 | ) | (30,859 | ) | (237 | ) | — | (31,314 | ) | |||||||||||
Impairment and other charges | — | (170,000 | ) | — | — | (170,000 | ) | |||||||||||||
Provision for reduction in carrying value of certain assets | — | (1,350 | ) | — | — | (1,350 | ) | |||||||||||||
Gain on disposition of assets, net | — | 2,706 | 953 | — | 3,659 | |||||||||||||||
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|
|
|
|
|
|
|
| |||||||||||
Total operating income (loss) | (218 | ) | (61,483 | ) | 19,062 | — | (42,639 | ) | ||||||||||||
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|
|
|
|
|
|
| |||||||||||
Other income and (expense): | ||||||||||||||||||||
Interest expense | (26,654 | ) | (17,889 | ) | (8,865 | ) | 30,814 | (22,594 | ) | |||||||||||
Changes in fair value of derivative positions | (110 | ) | — | — | — | (110 | ) | |||||||||||||
Interest income | 18,131 | 750 | 12,189 | (30,814 | ) | 256 | ||||||||||||||
Other | — | (345 | ) | 20 | — | (325 | ) | |||||||||||||
Equity in net earnings of subsidiaries | (23,484 | ) | — | — | 23,484 | — | ||||||||||||||
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|
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|
| |||||||||||
Total other income and (expense) | (32,117 | ) | (17,484 | ) | 3,344 | 23,484 | (22,773 | ) | ||||||||||||
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|
| |||||||||||
Income (benefit) before income taxes | (32,335 | ) | (78,967 | ) | 22,406 | 23,484 | (65,412 | ) | ||||||||||||
Income tax expense (benefit): | ||||||||||||||||||||
Current | (13,402 | ) | 27,169 | 19,841 | — | 33,608 | ||||||||||||||
Deferred | 31,518 | (57,030 | ) | (22,863 | ) | — | (48,375 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total income tax expense (benefit) | 18,116 | (29,861 | ) | (3,022 | ) | — | (14,767 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net income (loss) | (50,451 | ) | (49,106 | ) | 25,428 | 23,484 | (50,645 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Less: Net (loss) attributable to noncontrolling interest | — | — | (194 | ) | — | (194 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net income (loss) attributable to controlling interest | $ | (50,451 | ) | $ | (49,106 | ) | $ | 25,622 | $ | 23,484 | $ | (50,451 | ) | |||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
| (1) | General and administration expenses for field operations are included in operating expenses. |
77
Table of Contents
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands)
(Unaudited)
| Twelve months ended December 31, 2010 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
Total revenues | $ | — | $ | 366,947 | $ | 401,617 | $ | (109,089 | ) | $ | 659,475 | |||||||||
Operating expenses | — | 237,584 | 342,783 | (109,089 | ) | 471,278 | ||||||||||||||
Depreciation and amortization | — | 63,402 | 51,628 | — | 115,030 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total operating gross margin | — | 65,961 | 7,206 | — | 73,167 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
General and administration expense (1) | (225 | ) | (30,193 | ) | (310 | ) | — | (30,728 | ) | |||||||||||
Provision for reduction in carrying value of certain assets | — | (1,952 | ) | — | — | (1,952 | ) | |||||||||||||
Gain on disposition of assets, net | — | 2,067 | 2,553 | — | 4,620 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total operating income (loss) | (225 | ) | 35,883 | 9,449 | — | 45,107 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Other income and (expense): | ||||||||||||||||||||
Interest expense | (30,771 | ) | (35,640 | ) | (16,185 | ) | 55,791 | (26,805 | ) | |||||||||||
Interest income | 42,000 | 757 | 23,291 | (65,791 | ) | 257 | ||||||||||||||
Loss on extinguishment of debt | (7,209 | ) | — | — | — | (7,209 | ) | |||||||||||||
Other | — | 88 | 67 | — | 155 | |||||||||||||||
Equity in net earnings of subsidiaries | (22,962 | ) | — | — | 22,962 | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total other income and (expense) | (18,942 | ) | (34,795 | ) | 7,173 | 12,962 | (33,602 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Income (benefit) before income taxes | (19,167 | ) | 1,088 | 16,622 | 12,962 | 11,505 | ||||||||||||||
Income tax expense (benefit): | ||||||||||||||||||||
Current | 139 | (189 | ) | 27,571 | — | 27,521 | ||||||||||||||
Deferred | (4,845 | ) | 2,323 | 1,214 | — | (1,308 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total income tax expense (benefit) | (4,706 | ) | 2,134 | 28,785 | — | 26,213 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net income (loss) | (14,461 | ) | (1,046 | ) | (12,163 | ) | 12,962 | (14,708 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Less: Net (loss) attributable to noncontrolling interest | — | — | (247 | ) | — | (247 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net income (loss) attributable to controlling interest | $ | (14,461 | ) | $ | (1,046 | ) | $ | (11,916 | ) | $ | 12,962 | $ | (14,461 | ) | ||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
| (1) | General and administration expenses for field operations are included in operating expenses. |
78
Table of Contents
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)
| December 31, 2012 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
ASSETS |
| |||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 42,251 | $ | 11,023 | $ | 34,612 | $ | — | $ | 87,886 | ||||||||||
Accounts and notes receivable, net | 289,957 | 98,747 | 292,644 | (512,786 | ) | 168,562 | ||||||||||||||
Rig materials and supplies | — | 2,834 | 26,026 | — | 28,860 | |||||||||||||||
Deferred costs | — | — | 1,089 | — | 1,089 | |||||||||||||||
Deferred income taxes | — | 7,615 | �� | 1,127 | — | 8,742 | ||||||||||||||
Other tax assets | 46,249 | (31,136 | ) | 18,411 | — | 33,524 | ||||||||||||||
Assets held for sale | — | — | 11,550 | — | 11,550 | |||||||||||||||
Other current assets | — | 8,675 | 4,146 | — | 12,821 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total current assets | 378,457 | 97,758 | 389,605 | (512,786 | ) | 353,034 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Property, plant and equipment, net | 60 | 548,794 | 237,304 | — | 786,158 | |||||||||||||||
Investment in subsidiaries and intercompany advances | 780,878 | (233,388 | ) | 1,467,429 | (2,014,919 | ) | — | |||||||||||||
Other noncurrent assets | 43,569 | 59,541 | 13,431 | — | 116,541 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total assets | $ | 1,202,964 | $ | 472,705 | $ | 2,107,769 | $ | (2,527,705 | ) | $ | 1,255,733 | |||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY |
| |||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Current portion of long-term debt | $ | 10,000 | $ | — | $ | — | $ | — | $ | 10,000 | ||||||||||
Accounts payable and accrued liabilities | 65,839 | 93,243 | 205,864 | (227,200 | ) | 137,746 | ||||||||||||||
Accrued income taxes | — | 612 | 3,508 | — | 4,120 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total current liabilities | 75,839 | 93,855 | 209,372 | (227,200 | ) | 151,866 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Long-term debt | 469,205 | — | — | — | 469,205 | |||||||||||||||
Other long-term liabilities | 3,933 | 6,129 | 13,120 | — | 23,182 | |||||||||||||||
Long-term deferred tax liability | — | 36,894 | (16,047 | ) | — | 20,847 | ||||||||||||||
Intercompany payables | 62,583 | 43,657 | 216,320 | (322,560 | ) | — | ||||||||||||||
Contingencies | — | — | — | — | — | |||||||||||||||
Stockholders’ equity: | ||||||||||||||||||||
Common stock | 19,818 | 18,049 | 43,003 | (61,052 | ) | 19,818 | ||||||||||||||
Capital in excess of par value | 646,217 | 733,112 | 1,455,246 | (2,188,358 | ) | 646,217 | ||||||||||||||
Retained earnings (accumulated deficit) | (74,631 | ) | (458,991 | ) | 187,526 | 271,465 | (74,631 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total controlling interest stockholders’ equity | 591,404 | 292,170 | 1,685,775 | (1,977,945 | ) | 591,404 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Noncontrolling interest | — | — | (771 | ) | — | (771 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total Equity | 591,404 | 292,170 | 1,685,004 | (1,977,945 | ) | 590,633 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total liabilities and stockholders’ equity | $ | 1,202,964 | $ | 472,705 | $ | 2,107,769 | $ | (2,527,705 | ) | $ | 1,255,733 | |||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
79
Table of Contents
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED BALANCE SHEET
(Dollars in Thousands)
(Unaudited)
| December 31, 2011 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
| ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 55,670 | $ | 4,212 | $ | 37,987 | $ | — | $ | 97,869 | ||||||||||
Accounts and notes receivable, net | 289,512 | 94,748 | 285,326 | (485,663 | ) | 183,923 | ||||||||||||||
Rig materials and supplies | — | 762 | 29,185 | — | 29,947 | |||||||||||||||
Deferred costs | — | — | 3,249 | — | 3,249 | |||||||||||||||
Deferred income taxes | — | 5,311 | 853 | 486 | 6,650 | |||||||||||||||
Other tax assets | 47,834 | (25,218 | ) | 2,742 | — | 25,358 | ||||||||||||||
Assets held for sale | — | — | 5,315 | — | 5,315 | |||||||||||||||
Other current assets | 788 | 6,381 | 8,133 | — | 15,302 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total current assets | 393,804 | 86,196 | 372,790 | (485,177 | ) | 367,613 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Property, plant and equipment, net | 79 | 474,942 | 244,787 | 1 | 719,809 | |||||||||||||||
Investment in subsidiaries and intercompany advances | 720,214 | (212,883 | ) | 1,347,719 | (1,855,050 | ) | — | |||||||||||||
Other noncurrent assets | 44,962 | 66,660 | 16,839 | 363 | 128,824 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total assets | $ | 1,159,059 | $ | 414,915 | $ | 1,982,135 | $ | (2,339,863 | ) | $ | 1,216,246 | |||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Current portion of long-term debt | $ | 145,723 | $ | — | $ | — | $ | — | $ | 145,723 | ||||||||||
Accounts payable and accrued liabilities | 60,120 | 94,056 | 181,010 | (199,936 | ) | 135,250 | ||||||||||||||
Accrued income taxes | (205 | ) | 921 | 4,121 | — | 4,837 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total current liabilities | 205,638 | 94,977 | 185,131 | (199,936 | ) | 285,810 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Long-term debt | 337,000 | — | — | — | 337,000 | |||||||||||||||
Other long-term liabilities | 8,081 | 9,474 | 15,897 | — | 33,452 | |||||||||||||||
Long-term deferred tax liability | 1,151 | 25,232 | (11,296 | ) | 847 | 15,934 | ||||||||||||||
Intercompany payables | 62,583 | 43,657 | 111,619 | (217,859 | ) | — | ||||||||||||||
Contingencies | — | — | — | — | — | |||||||||||||||
Stockholders’ equity: | ||||||||||||||||||||
Common stock | 19,508 | 18,049 | 43,003 | (61,052 | ) | 19,508 | ||||||||||||||
Capital in excess of par value | 637,042 | 733,120 | 1,444,091 | (2,177,211 | ) | 637,042 | ||||||||||||||
Retained earnings (accumulated deficit) | (111,944 | ) | (509,594 | ) | 194,246 | 315,348 | (111,944 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total controlling interest stockholders’ equity | 544,606 | 241,575 | 1,681,340 | (1,922,915 | ) | 544,606 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Noncontrolling interest | — | — | (556 | ) | — | (556 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total Equity | 544,606 | 241,575 | 1,680,784 | (1,922,915 | ) | 544,050 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total liabilities and stockholders’ equity | $ | 1,159,059 | $ | 414,915 | $ | 1,982,135 | $ | (2,339,863 | ) | $ | 1,216,246 | |||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
80
Table of Contents
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
| Year Ended December 31, 2012 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: | ||||||||||||||||||||
Net income (loss) | $ | 37,313 | $ | 54,961 | $ | 32,816 | $ | (87,992 | ) | $ | 37,098 | |||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||
Depreciation and amortization | — | 65,354 | 47,663 | — | 113,017 | |||||||||||||||
Loss on extinguishment of debt | 2,130 | — | — | — | 2,130 | |||||||||||||||
Gain on disposition of assets | — | (775 | ) | (1,199 | ) | — | (1,974 | ) | ||||||||||||
Deferred income tax expense | 2,257 | 15,429 | (1,849 | ) | — | 15,837 | ||||||||||||||
Expenses not requiring cash | 16,558 | 33,644 | (27,602 | ) | — | 22,600 | ||||||||||||||
Equity in net earnings of subsidiaries | (43,884 | ) | — | — | 43,884 | — | ||||||||||||||
Change in accounts receivable | (445 | ) | (1,788 | ) | 17,474 | — | 15,241 | |||||||||||||
Change in other assets | 1,649 | 2,060 | (9,200 | ) | — | (5,491 | ) | |||||||||||||
Change in accrued income taxes | (4,055 | ) | 220 | (2,267 | ) | — | (6,102 | ) | ||||||||||||
Change in liabilities | 3,914 | (4,158 | ) | (2,413 | ) | — | (2,657 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) operating activities | 15,437 | 164,947 | 53,423 | (44,108 | ) | 189,699 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Cash flows from investing activities: | ||||||||||||||||||||
Capital expenditures | — | (176,333 | ) | (15,210 | ) | — | (191,543 | ) | ||||||||||||
Proceeds from the sale of assets | — | 2,062 | 1,875 | — | 3,937 | |||||||||||||||
Proceeds from insurance settlements | — | — | — | — | — | |||||||||||||||
Intercompany dividend payment | (8,387 | ) | (4,357 | ) | (31,364 | ) | 44,108 | — | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash (used in) investing activities | (8,387 | ) | (178,628 | ) | (44,699 | ) | 44,108 | (187,606 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Cash flows from financing activities: | ||||||||||||||||||||
Proceeds from debt issuance | 130,000 | — | — | — | 130,000 | |||||||||||||||
Proceeds from draw on revolver credit facility | 7,000 | — | — | — | 7,000 | |||||||||||||||
Paydown on senior notes | (125,000 | ) | — | — | — | (125,000 | ) | |||||||||||||
Paydown on term note | (18,000 | ) | — | — | — | (18,000 | ) | |||||||||||||
Paydown on revolver credit facility | — | — | — | — | — | |||||||||||||||
Payment of debt issuance costs | (4,859 | ) | — | — | — | (4,859 | ) | |||||||||||||
Payment of debt extinguishment costs | (555 | ) | — | — | — | (555 | ) | |||||||||||||
Proceeds from stock options exercised | — | — | — | — | — | |||||||||||||||
Excess tax benefit from stock-based compensation | (662 | ) | — | — | — | (662 | ) | |||||||||||||
Intercompany advances, net | (8,393 | ) | 20,492 | (12,099 | ) | — | — | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) financing activities | (20,469 | ) | 20,492 | (12,099 | ) | — | (12,076 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net change in cash and cash equivalents | (13,419 | ) | 6,811 | (3,375 | ) | — | (9,983 | ) | ||||||||||||
Cash and cash equivalents at beginning of year | 55,670 | 4,212 | 37,987 | — | 97,869 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Cash and cash equivalents at end of year | $ | 42,251 | $ | 11,023 | $ | 34,612 | $ | — | $ | 87,886 | ||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
See accompanying notes to unaudited consolidated condensed financial statements.
81
Table of Contents
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
| Year Ended December 31, 2011 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: | ||||||||||||||||||||
Net income (loss) | $ | (50,451 | ) | $ | (49,106 | ) | $ | 25,428 | $ | 23,484 | $ | (50,645 | ) | |||||||
Adjustments to reconcile net income (loss)to net cash provided by operating activities: | ||||||||||||||||||||
Depreciation and amortization | — | 62,744 | 49,392 | — | 112,136 | |||||||||||||||
Loss on extinguishment of debt | — | — | — | — | — | |||||||||||||||
Gain on disposition of assets | — | (2,706 | ) | (953 | ) | — | (3,659 | ) | ||||||||||||
Deferred income tax expense | 31,518 | (57,030 | ) | (22,863 | ) | — | (48,375 | ) | ||||||||||||
Impairment and other charges | — | 170,000 | — | — | 170,000 | |||||||||||||||
Provision for reduction in carrying value of certain assets | — | 1,350 | — | — | 1,350 | |||||||||||||||
Expenses not requiring cash | 16,411 | 376 | (3,954 | ) | — | 12,833 | ||||||||||||||
Equity in net earnings of subsidiaries | 23,484 | — | — | (23,484 | ) | — | ||||||||||||||
Change in accounts receivable | (288,333 | ) | 347,344 | (65,852 | ) | — | (6,841 | ) | ||||||||||||
Change in other assets | 62,173 | (16,724 | ) | 16,404 | — | 61,853 | ||||||||||||||
Change in liabilities | (10,454 | ) | (53,404 | ) | 41,091 | — | (22,767 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) operating activities | (215,652 | ) | 402,844 | 38,693 | — | 225,885 | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Cash flows from investing activities: | ||||||||||||||||||||
Capital expenditures | — | (174,999 | ) | (15,400 | ) | — | (190,399 | ) | ||||||||||||
Proceeds from the sale of assets | — | 4,335 | 1,200 | — | 5,535 | |||||||||||||||
Proceeds from insurance settlements | — | 250 | — | — | 250 | |||||||||||||||
Intercompany dividend payment | — | — | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) investing activities | — | (170,414 | ) | (14,200 | ) | — | (184,614 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Cash flows from financing activities: | ||||||||||||||||||||
Proceeds from debt issuance | 50,000 | — | — | — | 50,000 | |||||||||||||||
Proceeds from draw on revolver credit facility | — | — | — | — | — | |||||||||||||||
Paydown on senior notes | — | — | — | — | — | |||||||||||||||
Paydown on term note | (21,000 | ) | — | — | — | (21,000 | ) | |||||||||||||
Paydown on revolver credit facility | (25,000 | ) | — | — | — | (25,000 | ) | |||||||||||||
Payment of debt issuance costs | (504 | ) | — | — | — | (504 | ) | |||||||||||||
Payment of debt extinguishment costs | — | — | — | — | — | |||||||||||||||
Proceeds from stock options exercised | 183 | — | — | — | 183 | |||||||||||||||
Excess tax benefit from stock-based compensation | 1,488 | — | — | — | 1,488 | |||||||||||||||
Intercompany advances, net | 252,320 | (230,535 | ) | (21,785 | ) | — | — | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) financing activities | 257,487 | (230,535 | ) | (21,785 | ) | — | 5,167 | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net change in cash and cash equivalents | 41,835 | 1,895 | 2,708 | — | 46,438 | |||||||||||||||
Cash and cash equivalents at beginning of year | 13,835 | 2,317 | 35,279 | — | 51,431 | |||||||||||||||
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| |||||||||||
Cash and cash equivalents at end of year | $ | 55,670 | $ | 4,212 | $ | 37,987 | $ | — | $ | 97,869 | ||||||||||
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|
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|
|
|
|
|
| |||||||||||
See accompanying notes to unaudited consolidated condensed financial statements.
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PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
| Year Ended December 31, 2010 | ||||||||||||||||||||
| Parent | Guarantor | Non-Guarantor | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: | ||||||||||||||||||||
Net income (loss) | $ | (14,461 | ) | $ | (1,046 | ) | $ | (12,163 | ) | $ | 12,962 | $ | (14,708 | ) | ||||||
Adjustments to reconcile net income (loss)to net cash provided by operating activities: | ||||||||||||||||||||
Depreciation and amortization | — | 63,402 | 51,628 | — | 115,030 | |||||||||||||||
Loss on extinguishment of debt | 7,209 | — | — | — | 7,209 | |||||||||||||||
Gain on disposition of assets | — | (2,067 | ) | (2,553 | ) | — | (4,620 | ) | ||||||||||||
Deferred income tax expense | (4,845 | ) | 2,323 | 1,214 | — | (1,308 | ) | |||||||||||||
Provision for reduction in carrying value of certain assets | — | 1,952 | — | — | 1,952 | |||||||||||||||
Expenses not requiring cash | 14,829 | — | — | — | 14,829 | |||||||||||||||
Equity in net earnings of subsidiaries | 22,962 | — | — | (22,962 | ) | — | ||||||||||||||
Change in accounts receivable | 16,178 | (14,763 | ) | 19,337 | — | 20,752 | ||||||||||||||
Change in other assets | (2,505 | ) | (13,454 | ) | 15,365 | — | (594 | ) | ||||||||||||
Change in liabilities | (144 | ) | 7,793 | (22,641 | ) | — | (14,992 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) operating activities | 39,223 | 44,140 | 50,187 | (10,000 | ) | 123,550 | ||||||||||||||
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| |||||||||||
Cash flows from investing activities: | ||||||||||||||||||||
Capital expenditures | — | (169,784 | ) | (49,400 | ) | — | (219,184 | ) | ||||||||||||
Proceeds from the sale of assets | — | 4,646 | 1,829 | — | 6,475 | |||||||||||||||
Intercompany dividend payment | — | — | (10,000 | ) | 10,000 | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) investing activities | — | (165,138 | ) | (57,571 | ) | 10,000 | (212,709 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Cash flows from financing activities: | ||||||||||||||||||||
Proceeds from debt issuance | 300,000 | — | — | — | 300,000 | |||||||||||||||
Proceeds from draw on revolver credit facility | 25,000 | — | — | — | 25,000 | |||||||||||||||
Paydown on senior notes | (225,000 | ) | — | — | — | (225,000 | ) | |||||||||||||
Paydown on term note | (12,000 | ) | — | — | — | (12,000 | ) | |||||||||||||
Paydown on revolver credit facility | (42,000 | ) | — | — | — | (42,000 | ) | |||||||||||||
Payment of debt issuance costs | (7,976 | ) | — | — | — | (7,976 | ) | |||||||||||||
Payment of debt extinguishment costs | (7,466 | ) | — | — | — | (7,466 | ) | |||||||||||||
Proceeds from stock options exercised | 26 | — | — | — | 26 | |||||||||||||||
Excess tax benefit from stock-based compensation | 1,203 | — | — | — | 1,203 | |||||||||||||||
Intercompany advances, net | (115,364 | ) | 121,547 | (6,183 | ) | — | — | |||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net cash provided by (used in) financing activities | (83,577 | ) | 121,547 | (6,183 | ) | — | 31,787 | |||||||||||||
|
|
|
|
|
|
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|
|
| |||||||||||
Net change in cash and cash equivalents | (44,354 | ) | 549 | (13,567 | ) | — | (57,372 | ) | ||||||||||||
Cash and cash equivalents at beginning of year | 58,189 | 1,768 | 48,846 | — | 108,803 | |||||||||||||||
|
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|
|
|
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|
|
|
| |||||||||||
Cash and cash equivalents at end of year | $ | 13,835 | $ | 2,317 | $ | 35,279 | $ | — | $ | 51,431 | ||||||||||
|
|
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|
|
|
|
|
| |||||||||||
See accompanying notes to unaudited consolidated condensed financial statements.
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Note 17 — Selected Quarterly Financial Data
| Quarter | ||||||||||||||||||||
Year 2012 | First | Second | Third | Fourth | Total | |||||||||||||||
| (Dollars in Thousands Except Per Share Amounts) | ||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||
Revenues | $ | 176,569 | $ | 178,925 | $ | 165,301 | $ | 157,187 | $ | 677,982 | ||||||||||
Operating gross margin(2) | $ | 54,018 | $ | 46,440 | $ | 34,038 | $ | 16,405 | $ | 150,901 | ||||||||||
Operating income | $ | 49,013 | $ | 40,388 | $ | 25,739 | $ | (8,317 | ) | $ | 106,823 | |||||||||
Net income (loss) attributable to controlling interest | $ | 26,392 | $ | 20,083 | $ | 10,936 | $ | (20,098 | ) | $ | 37,313 | |||||||||
Basic earnings per share — net income (loss)(1) | $ | 0.23 | $ | 0.17 | $ | 0.09 | $ | (0.17 | ) | $ | 0.32 | |||||||||
Diluted earnings per share — net income (loss)(1) | $ | 0.22 | $ | 0.17 | $ | 0.09 | $ | (0.17 | ) | $ | 0.31 | |||||||||
| Quarter | ||||||||||||||||||||
Year 2011 | First | Second | Third | Fourth | Total | |||||||||||||||
| (Dollars in Thousands Except Per Share Amounts) | ||||||||||||||||||||
| (Unaudited) | ||||||||||||||||||||
Revenues | $ | 156,179 | $ | 172,812 | $ | 176,589 | $ | 181,066 | $ | 686,646 | ||||||||||
Operating gross margin(2) | $ | 21,204 | $ | 40,797 | $ | 49,966 | $ | 44,399 | $ | 156,366 | ||||||||||
Operating income | $ | 15,402 | $ | 33,215 | $ | 41,959 | $ | (133,215 | ) | $ | (42,639 | ) | ||||||||
Net income (loss) attributable to controlling interest | $ | 4,827 | $ | 14,173 | $ | 20,725 | $ | (90,176 | ) | $ | (50,451 | ) | ||||||||
Basic earnings per share — net income (loss)(1) | $ | 0.04 | $ | 0.12 | $ | 0.18 | $ | (0.77 | ) | $ | (0.43 | ) | ||||||||
Diluted earnings per share — net income (loss)(1) | $ | 0.04 | $ | 0.12 | $ | 0.18 | $ | (0.77 | ) | $ | (0.43 | ) | ||||||||
| 1) | As a result of shares issued during the year, earnings 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 per share, which is based on the weighted average shares outstanding during the year. Additionally, as a result of rounding to the thousands, revenues, operating gross margin, operating income, and net income (loss) attributable to controlling interest may not equal the 2012 year to date results. |
| 2) | As the Company modified our reporting segments to be consistent with recent organizational changes to improve our drilling organization, expenses related to our U.S. Barge Drilling segment were found to be incorrectly included in our general and administrative expense during the first through third quarters of the current year. These expenses have been appropriately reclassified to be included as part of the segment operating expenses, therefore our operating gross margin for each of the first three quarters will not agree to the respective 10-Q reports for the current year only. |
Note 18 — Recent Accounting Pronouncements
Revenue Recognition — On January 1, 2011, we adopted an update issued by the Financial Accounting Standards Board (FASB) to existing guidance on revenue recognition for arrangements with multiple deliverables. This update allows companies to allocate consideration for qualified separate deliverables using estimated selling price for both delivered and undelivered items when vendor-specific objective evidence or third-party evidence is unavailable. It also requires additional disclosures on the nature of multiple element arrangements, the types of deliverables under the arrangements, the general timing of their delivery, and significant factors and estimates used to determine estimated selling prices. The update is effective for fiscal years beginning after June 15, 2010. The adoption of this update did not have a material impact on our financial position, results of operations, cash flows, or disclosures.
Comprehensive Income — In June 2011, the FASB issued Accounting Standards Update 2011-05, “Presentation of Comprehensive Income.” This update will increase the prominence of comprehensive income in the financial statements. It gives an entity the option to present the components of net income and comprehensive
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income in either a single continuous statement or in two separate but consecutive financial statements and eliminates the option to present other comprehensive income in the statement of changes in equity. This update will be effective for us beginning in the first quarter of 2012. This update did not have a material impact on our financial position, results of operations, cash flows, or disclosures.
Fair value measurements — Effective January 1, 2012, we adopted the accounting standards update that changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements. Some of the amendments included in this update are intended to clarify the applications of existing fair value measurement requirements. The update is effective for annual periods beginning after December 15, 2011. This adoption did not have a material effect on the disclosures contained in our notes to the consolidated financial statements.
Comprehensive Income — On January 1, 2012, we adopted an update issued by the FASB to existing guidance on the presentation of comprehensive income. The update eliminates the option to present the components of other comprehensive income (OCI) as part of the statement of changes in stockholders’ equity. Public entities are required to comply with the new reporting requirements for fiscal years beginning after December 15, 2011 and interim periods within those years. Calendar year-end companies must adopt the requirements for the quarter ended March 31, 2012. The adoption of this update did not have a material impact on our financial position, results of operations, cash flows, or disclosures.
Impairment — In July 2012, the Financial Accounting Standards Board (FASB) issued an update to existing guidance on the impairment assessment of indefinite-lived intangibles. This update simplifies the impairment assessment of indefinite-lived intangibles by allowing companies to consider qualitative factors to determine whether it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount before performing the two step impairment review process. The adoption of this update did not have an impact on our condensed consolidated financial statements.
Note 19 — Subsequent Events
Executive Departure
On February 11, 2013, we announced the departure of W. Kirk Brassfield, senior vice president and chief financial officer to be effective April 30, 2013. Mr. Brassfield will assist the Company in identifying his successor and will continue his duties as senior vice president and chief financial officer during a transition period extending through April 30, 2013, unless his successor is identified and the transition period is completed before that date.
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures — In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, 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, as defined in the Exchange Act Rules 13a-15 and 15d-15, were effective, as of December 31, 2012, 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 (2) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Management’s Report on Internal Control over Financial Reporting — The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). 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:
| Ÿ | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; |
| Ÿ | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States, and that receipts and expenditures of the Company are being made only in accordance with authorization of management and directors of the Company; and |
| Ÿ | 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 that 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, 2012 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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, 2012.
KPMG LLP, our independent registered public accounting firm that audited the consolidated financial statements included in this Annual Report Form 10-K, has issued a report with respect to our internal control over financial reporting as of December 31, 2012.
Changes in Internal Control over Financial Reporting — There were no changes in our internal control over financial reporting during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information with respect to directors can be found under the captions “Item 1 — Election of Directors” and “Board of Directors” in our 2013 Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013. Such information is incorporated herein by reference.
Information with respect to executive officers is shown in Item 1 of this Form 10-K.
Information with respect to our audit committee and audit committee financial expert can be found under the caption “The Audit Committee” of our 2013 Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013 and is incorporated herein by reference.
The information in our 2013 Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013 set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.
We have adopted the Parker Drilling Code of Corporate Conduct (CCC) which includes a code of ethics that is applicable to the chief executive officer, chief financial officer, controller and other senior financial personnel as required by the SEC. The CCC includes provisions that will ensure compliance with the code of ethics required by the SEC and with the minimum requirements under the corporate governance listing standards of the NYSE. The CCC is publicly available on our website at http://www.parkerdrilling.com. If any waivers of the CCC occur that apply to a director, the chief executive officer, the chief financial officer, the controller or senior financial personnel or if the Company materially amends the CCC, we will disclose the nature of the waiver or amendment on the website and in a current report on Form 8-K within four business days.
ITEM 11. EXECUTIVE COMPENSATION
The information under the captions “Executive Compensation,” “Fees and Benefit Plans for Non-Employee Directors,” “2012 Director Compensation Table,” and “Compensation Committee Report” in our 2013 Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013 is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is hereby incorporated by reference to the information appearing under the captions “Security Ownership of Officers, Directors and Principal Stockholders” and “Equity Compensation Plan Information” in our 2013 Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item is hereby incorporated by reference to such information appearing under the captions “Certain Relationships and Related Party Transactions” and “Director Independence Determination” in our 2013 Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item is hereby incorporated by reference to the information appearing under the captions “Audit and Non-Audit Fees” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Registered Public Accounting Firm” in our 2013 Proxy Statement for the Annual Meeting of the Stockholders to be held on May 8, 2013.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
(1) Financial Statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8:
(3) Exhibits:
Exhibit Number |
| Description | ||
| 3.1 | — | Restated Certificate of Incorporation of the Company, as amended on May 16, 2007 (incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007). | ||
| 3.2 | — | Parker Drilling Company By-Laws, effective as amended March 11, 2011 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on March 16, 2011). | ||
| 4.4 | — | Indenture, dated March 22, 2010, among Parker Drilling Company, the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on March 22, 2010). | ||
| 4.5 | — | Form of 9 1 / 8 % Senior Note due 2018 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on March 22, 2010). | ||
| 4.6 | — | Registration Rights Agreement, dated March 22, 2010, by and among Parker Drilling Company, the guarantors named therein, Bank of America Securities LLC, RBS Securities Inc., Barclays Capital Inc., Credit Suisse Securities (USA), Inc., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc., Natixis Bleichroeder LLC and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 22, 2010). | ||
| 10.1 | — | Amended and Restated Credit Agreement dated as of December 14, 2012, among Parker Drilling Company, as Borrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, the several banks and other financial institutions or entities from time to time parties thereto, NATIXIS, New York Branch, Wells Fargo Bank, N.A., and Whitney Bank as Co-Documentation Agents, and Merrill Lynch, Fenner & Smith Incorporated as Sole Lead Arranger and Book Manager | ||
| 10.2 | — | Parker Drilling Company Incentive Compensation Plan, dated December 17, 2008, and as amended and restated effective January 1, 2008 (incorporated by reference to Exhibit 10(b) to the Company’s Annual Report on Form 10-K filed on March 2, 2009).* | ||
| 10.3 | — | Parker Drilling Company Incentive Compensation Plan (as amended and restated effective January 1, 2009) (incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K filed on March 1, 2011)* | ||
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Exhibit Number |
| Description | ||
| 10.4 | — | Parker Drilling Company 2005 Long Term Incentive Plan 2005 LTIP (incorporated by reference to the Annex E to the Company’s Definitive Proxy Statement filed on March 25, 2005).* | ||
| 10.5 | — | Amendment No. 1 to the Parker Drilling Company 2005 LTIP (incorporated by reference to Annex B to the Company’s Definitive Proxy Statement filed on March 21, 2008).* | ||
| 10.6 | — | Second Amendment to the Parker Drilling Company 2005 LTIP, dated December 13, 2008 (incorporated by reference to Exhibit 10(j) to the Company’s Annual Report on Form 10-K filed on March 2, 2009).* | ||
| 10.7 | — | Form of Parker Drilling Company Restricted Stock Agreement under the 2005 LTIP (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 3, 2005).* | ||
| 10.8 | — | Form of Parker Drilling Company Performance Based Restricted Stock Agreement under the 2005 LTIP (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on May 3, 2005).* | ||
| 10.9 | — | Parker Drilling Company 2010 Long-Term Incentive Plan (incorporated by reference to Annex A to the Company’s Definitive Proxy Statement filed on March 16, 2010).* | ||
| 10.10 | — | Form of Parker Drilling Company Restricted Stock Unit Incentive Agreement under the 2010 LTIP (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K filed on March 1, 2011).* | ||
| 10.11 | — | Form of Parker Drilling Company Performance Unit Award Incentive Agreement under the 2010 LTIP (incorporated by reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K filed on March 1, 2011).* | ||
| 10.12 | — | 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).* | ||
| 10.13 | — | Employment Agreement between Mr. Robert L. Parker, Jr. and Parker Drilling Company, effective March 21, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 25, 2011).* | ||
| 10.14 | — | First Amendment dated August 29, 2011 to First Amended and Restated Employment Agreement between Mr. Robert L. Parker Jr. and Parker Drilling Company, effective March 21, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 30, 2011).* | ||
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Exhibit Number | Description | |||
| 10.15 | — | Employment Agreement, dated as of September 17, 2012, by and between Parker Drilling Company and Gary Rich (incorporated by reference to Exhibit 10.23 to the Company’s Current Report on Form 8-K filed on September 24, 2012).* | ||
| 10.16 | — | Form of Restricted Stock Unit Incentive Agreement between Parker Drilling Company and Gary Rich (incorporated by reference to Exhibit 10.23 to the Company’s Current Report on Form 8-K filed on September 24, 2012).* | ||
| 10.17 | — | Employment Agreement, dated as of December 29, 2010, by and between Parker Drilling Company and W. Kirk Brassfield (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 4, 2011).* | ||
| 10.18 | — | First Amendment dated August 29, 2011 to Employment Agreement between Mr. W. Kirk Brassfield and Parker Drilling Company, effective December 29, 2010 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on August 30, 2011).* | ||
| 10.19 | — | 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).* | ||
| 10.20 | — | First Amendment dated August 29, 2011 to Employment Agreement between Mr. Jon-Al Duplantier and Parker Drilling Company, effective March 21, 2011 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on August 30, 2011).* | ||
| 10.21 | — | Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr. dated April 12, 2006 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 12, 2006).* | ||
| 10.22 | — | Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr., effective as of May 1, 2008. (incorporated by reference to Exhibit 10(t) to the Company’s Annual Report on Form 10-K filed on March 2, 2009)* | ||
| 10.23 | — | Second Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr., dated May 1, 2009 (incorporated by reference to Exhibit 10(n)(3) to the Company’s Annual Report on Form 10-K filed on March 3, 2010).* | ||
| 10.24 | — | Third Amendment to Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr. dated May 1, 2010. (incorporated by reference to Exhibit 10.28 to the Company’s Annual Report on Form 10-K filed on March 1, 2011)* | ||
| 10.25 | — | Termination of Split Dollar Life Insurance Agreement between Parker Drilling Company, Robert L. Parker Sr., and Robert L. Parker Sr. and Catherine M. Parker Family Trust dated April 12, 2006 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 12, 2006).* | ||
| 21 | — | Subsidiaries of the Registrant. | ||
| 23.1 | — | Consent of KPMG LLP — Independent Registered Public Accounting Firm. | ||
| 31.1 | — | Gary Rich, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification. | ||
| 31.2 | — | W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification. | ||
| 32.1 | — | Gary Rich, President and Chief Executive Officer, Section 1350 Certification. | ||
| 32.2 | — | W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification. | ||
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Exhibit Number | Description | |||
| 101.INS | — | XBRL Instance Document. | ||
| 101.SCH | — | XBRL Taxonomy Schema Document. | ||
| 101.CAL | — | XBRL Calculation Linkbase Document. | ||
| 101.LAB | — | XBRL Label Linkbase Document. | ||
| 101.PRE | — | XBRL Presentation Linkbase Document. | ||
| 101.DEF | — | XBRL Definition Linkbase Document. | ||
| * | — | Management contract, compensatory plan or agreement. | ||
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PARKER DRILLING COMPANY AND SUBSIDIARIES
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)
Classifications | Balance at beginning of year | Charged to cost and expenses | Charged to other accounts | Deductions | Balance at end of year | |||||||||||||||
Year ended December 31, 2012 | ||||||||||||||||||||
Allowance for doubtful accounts and notes | $ | 1,544 | $ | 4,264 | $ | 3,195 | $ | (886 | ) | $ | 8,117 | |||||||||
Allowance for obsolete rig materials and supplies | $ | 316 | — | $ | — | $ | (4 | ) | $ | 312 | ||||||||||
Deferred tax valuation allowance | $ | 6,467 | $ | (1,662 | ) | $ | — | $ | — | $ | 4,805 | |||||||||
Year ended December 31, 2011 | ||||||||||||||||||||
Allowance for doubtful accounts and notes | $ | 7,020 | $ | 2,258 | $ | (2,034 | ) | $ | (5,700 | ) | $ | 1,544 | ||||||||
Allowance for obsolete rig materials and supplies | $ | 309 | $ | 26 | $ | — | $ | (19 | ) | $ | 316 | |||||||||
Deferred tax valuation allowance | $ | 5,532 | $ | 2,542 | $ | (1,607 | ) | $ | — | $ | 6,467 | |||||||||
Year ended December 31, 2010 | ||||||||||||||||||||
Allowance for doubtful accounts and notes | $ | 4,095 | $ | 3,244 | $ | (211 | ) | $ | (108 | ) | $ | 7,020 | ||||||||
Allowance for obsolete rig materials and supplies | $ | — | $ | 309 | $ | — | $ | — | $ | 309 | ||||||||||
Deferred tax valuation allowance | $ | 5,194 | $ | 338 | $ | — | $ | — | $ | 5,532 | ||||||||||
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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/ W. Kirk Brassfield | |
| W. Kirk Brassfield | ||
| Senior Vice President and Chief Financial Officer | ||
Date: March 1, 2013
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/ Robert L. Parker Jr. Robert L. Parker Jr. | Executive Chairman and Director | March 1, 2013 | |||
By: | /s/ Gary Rich Gary Rich | President, Chief Executive Officer, and Director (Principal Executive Officer) | March 1, 2013 | |||
By: | /s/ W. Kirk Brassfield W. Kirk Brassfield | Senior Vice President and Chief Financial Officer (Principal Financial Officer) | March 1, 2013 | |||
By: | /s/ Philip A. Schlom Philip A. Schlom | Controller (Principal Accounting Officer) | March 1, 2013 | |||
By: | /s/ Jonathan M. Clarkson Jonathan M. Clarkson | Director | March 1, 2013 | |||
By: | /s/ George J. Donnelly George J. Donnelly | Director | March 1, 2013 | |||
By: | /s/ Robert W. Goldman Robert W. Goldman | Director | March 1, 2013 | |||
By: | /s/ Gary R. King Gary R. King | Director | March 1, 2013 | |||
By: | /s/ Robert E. McKee III Robert E. McKee III | Director | March 1, 2013 | |||
| By: | /s/ Richard D. Paterson Richard D. Paterson | Director | March 1, 2013 | |||
| By: | /s/ Roger B. Plank Roger B. Plank | Director | March 1, 2013 | |||
| By: | /s/ R. Rudolph Reinfrank R. Rudolph Reinfrank | Director | March 1, 2013 | |||
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INDEX TO EXHIBITS
Exhibit Number | Description | |||
21 | — | Subsidiaries of the Registrant. | ||
23.1 | — | Consent of KPMG LLP — Independent Registered Public Accounting Firm. | ||
31.1 | — | Gary Rich, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification. | ||
31.2 | — | W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification. | ||
32.1 | — | Gary Rich, President and Chief Executive Officer, Section 1350 Certification. | ||
32.2 | — | W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, 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. | ||
94