PARKER DRILLING CO /DE/ - FORM 8-K - EX-99.2 - EXHIBIT 99.2

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EX-99.1 - EXHIBIT 99.1 - PARKER DRILLING CO /DE/	pkd-41415xexhibit991.htm

EXHIBIT 99.2

PART I

Item 1. Business

General

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

We are an international provider of drilling services and rental tools. We have operated in over 50 countries since beginning operations in 1934, making us among the most geographically experienced drilling contractors and rental tools providers in the world. We currently have operations in 23 countries. We believe we are an industry leader in quality, health, safety and environmental practices. In our Drilling Services business, we own and operate drilling rigs and drilling-related equipment and also perform drilling-related services, referred to as operations and maintenance (O&M) services, for customer-owned drilling rigs on a contracted basis. In addition, we provide project services including engineering and related project services during concept development, pre-FEED (Front End Engineering Design) and FEED phases of customer-owned drilling facility projects. 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. In our Rental Tools Services business, we provide premium rental equipment and services to exploration and production (E&P) companies, drilling contractors and service companies on land and offshore in the United States (U.S.) and select international markets.

Our business is comprised of two business lines: (1) Rental Tools Services and (2) Drilling Services. We have completed a business review and as a result have aligned our reportable segments with our two core business lines and our current internal organizational structure. We will continue to report our Rental Tools Services business as one reportable segment (Rental Tools); however, effective with the first quarter of 2015, the Company will report its Drilling Services business as two segments: (1) U.S. (Lower 48) Drilling, and (2) International & Alaska Drilling.

Our Rental Tools Services Business

Our Rental Tools Services business provides premium rental tools and services for land and offshore oil and natural gas drilling, workover and production applications. Tools we provide include drill collars, standard and heavy-weight drill pipe, all of which are available with standard or high-torque connections, tubing, and pressure control equipment including blow-out preventers (BOPs). We also provide services including fishing, tubular running, inspection and machine shop support. Our U.S. rental tools business is headquartered in New Iberia, Louisiana and our international rental tools business is headquartered in Dubai, United Arab Emirates (UAE). We maintain an inventory of rental tools and provide services to our customers on land and offshore from facilities in Louisiana, Texas, Oklahoma, Wyoming, North Dakota, West Virginia, as well as in the Middle East, Latin America, U.K., Europe, and Asia-Pacific regions.

Our largest single market for rental tools is U.S. land drilling, a cyclical market driven primarily by oil and gas prices and our customers' access to project financing. A growing portion of our U.S. rental tools business is supplying tubular goods and other equipment to offshore Gulf of Mexico (GOM) customers.

Our principal customers are major and independent E&P companies. Generally, rental tools are used for only a portion of a well drilling program and are requested by the customer when they are needed, requiring us to keep a broad inventory of rental tools in stock. Rental tools are usually rented on a daily or monthly basis.

On April 22, 2013, we completed the acquisition of International Tubular Services Limited (ITS) and related assets (collectively, the ITS acquisition). See Note 2 — Acquisition of ITS in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 for further discussion.

Our Drilling Services Business

U.S. (Lower 48) Drilling

Our U.S. (Lower 48) Drilling segment includes our GOM barge drilling rig fleet and U.S. (Lower 48) based O&M work. Our GOM barge drilling 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 and natural gas in shallow waters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The majority of these wells are drilled in water depths of 6 to 12 feet. Our rigs are all equipped for zero-discharge operations and are suitable for a variety of drilling

programs in inland coastal waters, from along inland waterways requiring shallow draft barges to open water drilling on the continental shelf requiring more robust capabilities. The barge drilling industry in the GOM is characterized by cyclical activity where utilization and dayrates are typically driven by oil and gas prices and our customers’ access to project financing. Contract terms tend to be well-to-well or multi-well programs, most commonly ranging from 45 to 150 days.

We continue to make investments in our barge drilling fleet to increase its efficiency and safety performance. In the second quarter of 2014 we completed the reconstruction of Rig 55B and acquired a 1,500 horsepower posted barge rig for our GOM drilling fleet.

International & Alaska Drilling

Our International & Alaska Drilling segment includes operations related to Parker-owned and customer-owned rigs as well as project related services. We strive to deploy our fleet of Parker-owned rigs in markets where we expect to have opportunities to keep the rigs consistently utilized and build a sufficient presence to achieve efficient operating scale. We provide O&M and other project management services, such as labor, maintenance, technical and logistics support for operators who own their own drilling rigs, but choose Parker Drilling to operate the rigs for them. During the year ended December 31, 2014 we had rigs operating in Mexico, Colombia, Kazakhstan, Papua New Guinea, Indonesia, the Kurdistan Region of Iraq, Sakhalin Island, Russia, and Alaska. In addition, we have O&M and ongoing project management activities for customer-owned rigs in Abu Dhabi, Sakhalin Island, Russia and Kuwait. Additionally, during the year ended December 31, 2014 we provided services under a new FEED contract and provided services related to the vendor services phase of the Berkut platform project.

The drilling markets in which this segment operates have one or more of the following characteristics:


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


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


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


•	drilling contracts that generally cover periods of one year or more; and


•	O&M contracts that are typically in support of multi-year drilling programs.

Our Business Strategy

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


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


•	Investing to improve and grow our existing business lines, and to expand the scope of products and services we offer.

Our Core Competencies

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

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

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

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

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

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

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

Customers and Scope of Operations

Our customer base consists of major, independent and national oil and natural gas E&P companies and integrated service providers. Each of our segments depends on a limited number of key customers and the loss of any one or more key customers could have a material adverse effect on a segment. In 2014, our largest customer, Exxon Neftegas Limited accounted for approximately 18.7 percent of our total revenues.

Competition

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

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

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

In international drilling markets, we compete with a number of international drilling contractors as well as local contractors. Although local drilling contractors often have lower labor and mobilization costs, we are generally able to distinguish ourselves from these companies based on our technical expertise, safety performance, quality of service, and experience. We believe our expertise in operating in challenging environments, such as the harsh environments of Sakhalin Island and the North Slope of Alaska, has been a significant factor in securing contracts. In the GOM barge drilling market, we compete with a small number of contractors. We have the largest number and greatest diversity of rigs available in the market, allowing us to provide equipment and services that are well-matched to customers’ requirements. We believe the market for drilling contracts will continue to be competitive with continued focus on reliability, efficiency and safety, in addition to price.

Contracts

Rental tools contracts are typically on a dayrate basis with rates determined based on type of equipment 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-in-hole or damaged equipment.

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 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 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 contracts require the customer to pay an early termination fee if the customer terminates a contract before the end of the term without cause.

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

Insurance and Indemnification

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

Our contracts provide for varying levels of indemnification between ourselves and our customers, 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 or rental tool contract, for liability due to well control events and liability arising from third-party claims, including wrongful death and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees. Generally, our program provides liability coverage up to $350.0 million, with retentions of $1.0 million or less.

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

Based upon a risk assessment and due to the high cost, high self-insured retention and limited coverage for windstorms in the GOM, we have elected not to purchase windstorm insurance for our barge rigs in the GOM. Although we have retained the risk for physical loss or damage for these rigs arising from a named windstorm, we have procured insurance coverage for removal of a wreck caused by a windstorm.

Our contracts provide for varying levels of indemnification from our customers and may require us to indemnify our customers. 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. In addition, our customers typically indemnify us for damage to our equipment down-hole, and in some cases our subsea equipment, generally based on replacement cost minus some level of depreciation. However, in certain contracts we may assume liability for damage to our customer’s property and other third-party property on the rig and in other contracts we are not indemnified by our customers for damage to their property and, accordingly, could be liable for any such damage under applicable law.

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

We generally indemnify the customer for legal and financial consequences of spills of industrial waste, lubricants, solvents and other contaminants (other than drilling fluid) on the surface of the land or water originating from our rigs or equipment. We typically require our customers to retain liability for spills of drilling fluid (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 drilling and rental tool

contracts may change in the future. In addition, the indemnification provisions of our contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.

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

Employees

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



	December 31,
	2014	2013
Rental Tools	1,110	1,122
U.S. (Lower 48) Drilling	546	534
International & Alaska Drilling	1,571	1,508
Corporate	216	231
Total employees	3,443	3,395

Environmental Considerations

Our operations are subject to numerous U.S. federal, state, and local laws and regulations, as well as the laws and regulations of other jurisdictions in which we operate, pertaining to the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (EPA), issue regulations to implement and enforce laws pertaining to the environment, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas; require remedial action to clean up pollution from former operations; and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect our operations and financial position, as well as those of similarly situated entities operating in the same markets. While our management believes that we comply with current applicable environmental laws and regulations, there is no assurance that compliance can be maintained in the future.

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

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

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

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

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

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

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

Some scientific studies have suggested that emissions of certain gases including carbon dioxide and methane, commonly referred to as “greenhouse gases” (GHGs), may be contributing to the warming of the atmosphere resulting in climate change. There are a variety of legislative and regulatory developments, proposals, requirements, and initiatives that have been introduced in the U.S. and international regions in which we operate that are intended to address concerns that emissions of GHGs are contributing to climate change and these may increase costs of compliance for our drilling services or our customer's operations. Among these developments, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change established a set of emission targets for GHGs that became binding on all those countries that had ratified it.

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

Executive Officers

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

•

Gary G. Rich, 56, joined the Company in October 2012 as the president and chief executive officer. Mr. Rich also serves as Chairman of the Company’s board of directors. He is an industry veteran with over 30 years of global technical, commercial and operations experience. Mr. Rich came to Parker Drilling after a 25-year career with Baker Hughes Incorporated. Mr. Rich served as vice president of global sales for Baker Hughes from August 2011 to October 2012, and prior to that role, he served as president of that company’s European operations from April 2009 to August 2011. Previously, Mr. Rich was president of Hughes Christensen Company (HCC), a division of Baker Hughes primarily focused on the production and distribution of drilling bits for the petroleum industry.

•

Christopher T. Weber, 42, joined the Company in May 2013 as the senior vice president and chief financial officer. Prior to joining the Company, Mr. Weber served as the vice president and treasurer of Ensco plc., a public offshore drilling company, from 2011 to May 2013. From 2009 to 2011, Mr. Weber served as vice president, operations for Pride International, Inc., prior to which he served as director, corporate planning and development from 2006 to 2009.

•

Jon-Al Duplantier, 47, is the senior vice president, chief administrative officer, general counsel, and secretary of the Company, a position held since 2013. Mr. Duplantier has over 19 years' experience in the oil and gas industry. Mr. Duplantier joined the Company in 2009 as vice president and general counsel. From 1995 to 2009, Mr. Duplantier served in several legal and business roles at ConocoPhillips, including senior counsel – Exploration and Production, vice president and general counsel – Conoco Phillips Indonesia, and vice president and general counsel – Dubai Petroleum Company. Prior to joining ConocoPhillips, he served as a patent attorney for DuPont from 1992 to 1995.

•

David R. Farmer, 53, was appointed the senior vice president, Europe, Middle East, and Asia (EMEA) in early 2014. He 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, North America 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.

•

Philip L. Agnew, 46, has served as the Company's senior vice president and chief technical officer since 2013. He 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

•

Leslie K. Nagy, 40, was appointed principal accounting officer and controller on April 1, 2014. Ms. Nagy served as director of finance and assistant controller of the Company from December 2012 through March 2014, as assistant controller of the Company from May 2011 to December 2012, and as manager of external reporting and general accounting of the Company from August 2010 to May 2011. Prior to joining Parker Drilling, Mrs. Nagy worked for Ernst & Young LLP from 1997 to 2010.

•

Philip A. Schlom, 50, was named vice president, global compliance and internal audit, effective December 2014. He 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.


•	David W. Tucker, 59, treasurer, joined the Company in 1978 as a financial analyst and served in various financial and accounting positions before being named chief financial officer of our formerly wholly-owned subsidiary, Hercules Offshore Corporation, in February 1998. Mr. Tucker was named treasurer of the Company in 1999.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available free of charge on our website at http://www.parkerdrilling.com as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission (SEC). The public may read and copy any materials we have filed with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Additionally, our reports, proxy and information statements and our other SEC filings are available on an Internet website maintained by the SEC at http://www.sec.gov.

Item 2. Properties

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

Land and Barge Rigs

The table below shows the locations and drilling depth ratings of our rigs as of December 31, 2014. The table excludes three rigs currently not available for service, which are Rig 140, located in Papua New Guinea, and Rig 225 and Rig 252, located in Indonesia.



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

International & Alaska Drilling
Europe, Middle East, and Asia
Rig 231	L	1981/1997	13,000	Indonesia
Rig 253	L	1982/1996	15,000	Indonesia
Rig 226	HH	1989/2010	18,000	Papua New Guinea
Rig 107	L	1983/2009	15,000	Kazakhstan
Rig 216	L	2001/2009	25,000	Kazakhstan
Rig 249	L	2000/2009	25,000	Kazakhstan
Rig 257	B	1999/2010	30,000	Kazakhstan
Rig 258	L	2001/2009	25,000	Kazakhstan
Rig 247	L	1981/2008	18,000	Iraq, Kurdistan Region
Rig 269	L	2008	21,000	Iraq, Kurdistan Region
Rig 265 ⁽²⁾	L	2007	20,000	Iraq, Kurdistan Region
Rig 264	L	2007	20,000	Tunisia
Rig 270	L	2011	21,000	Russia
Latin America
Rig 121	L	1980/2007	18,000	Colombia
Rig 268	L	1978/2009	30,000	Colombia
Rig 271	L	1982/2009	30,000	Colombia
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
Alaska
Rig 272	L	2013	18,000	Alaska
Rig 273	L	2012	18,000	Alaska
U.S. (Lower 48) Drilling
Rig 8	B	1978/2007	14,000	GOM
Rig 12	B	1979/2006	18,000	GOM
Rig 15	B	1978/2007	15,000	GOM
Rig 20	B	1981/2007	13,000	GOM
Rig 21	B	1979/2012	14,000	GOM
Rig 30	B	2014	20,000	GOM
Rig 50	B	1981/2006	20,000	GOM
Rig 51	B	1981/2008	20,000	GOM
Rig 54	B	1980/2006	25,000	GOM
Rig 55	B	1981/2014	25,000	GOM
Rig 72	B	1982/2005	25,000	GOM
Rig 76	B	1977/2009	30,000	GOM
Rig 77	B	2006/2006	30,000	GOM


1)	Type is defined as: L — land rig; B — barge rig; HH — heli-hoist land rig.


2)	Rig 265 was in transit from Tunisia to Iraq at December 31, 2014.

The following table presents our average utilization rates and rigs available for service for the years ended December 31, 2014 and 2013:



	December 31,
	2014		2013
U.S. (Lower 48) Drilling
Rigs available for service ⁽¹⁾	12.1		11.0
Utilization rate of rigs available for service ⁽²⁾	72	%	91	%
International & Alaska Drilling
Europe, Middle East, and Asia Region
Rigs available for service ⁽¹⁾	13.0		14.0
Utilization rate of rigs available for service ⁽²⁾	77	%	49	%
Latin America Region
Rigs available for service ⁽¹⁾	9.0		9.5
Utilization rate of rigs available for service ⁽²⁾	60	%	75	%
Alaska
Rigs available for service ⁽¹⁾	2.0		1.9
Utilization rate of rigs available for service ⁽²⁾	100	%	100	%
Total International & Alaska Drilling
Rigs available for service ⁽¹⁾	24.0		25.4
Utilization rate of rigs available for service ⁽²⁾	72	%	63	%

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.

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.

PART II

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

Management's discussion and analysis (MD&A) should be read in conjunction with Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Executive Overview

We achieved important operational gains during 2014 in all of our key business areas. The progress we made in 2014 strengthened our ability to provide innovative, reliable and efficient solutions to customers and operate successfully in the current challenging business environment.

Our Drilling Services business achieved increases in revenues and gross margin in 2014, compared with 2013, with contributions from both of our drilling services business segments.

•

Our International & Alaska Drilling segment increased average utilization to 72 percent for the year, up from 63 percent for the prior year. At the end of the year, 20 of our 24 drilling rigs were under contract. Market disruptions in Iraq, regulatory changes in the Latin America region and the year-end decline in oil prices hampered our ability to achieve further utilization gains. Our two arctic-class drilling rigs in Alaska achieved strong financial gains due to solid operational performance. The number of customer-owned rigs under O&M contracts increased as the Berkut platform moved into operation alongside our other O&M activities on Sakhalin Island, Russia and we secured a contract in Abu Dhabi to operate two island-based land rigs drilling extended reach wells.

•

Our U.S. (Lower 48) Drilling segment achieved average utilization of 72 percent in 2014, compared with 91 percent for 2013, and increased its average dayrate by 16 percent compared with 2013. This was the result of a strong first three quarters moderated by the impacts of oil price declines on fourth quarter activity. In addition, we completed the reconstruction of Rig 55B and acquired Rig 30B, broadening the operational capabilities of our diversified barge rig fleet.

Our Rental Tools Services business results reflected a full year’s contribution from the April 2013 acquisition of ITS, a significant addition to the Company's position in the international rental tools market. The average utilization index for our U.S. rental tools tubular goods rose to 91 in 2014, compared with 80 in 2013.


•	We increased our participation in the U.S. GOM offshore drilling market with investments in equipment to service the growth in deepwater drilling activity.


•	Our international rental tools business produced improved results in the second half of the year from strong gains in the Middle East, Europe and Latin America, after being slowed earlier in 2014 by disruptive events in Iraq and delayed development in Mexico.

We further strengthened our financial position by reducing our total debt by $39 million during the year and refinancing $360 million of debt at lower interest rates with extended maturities. In January 2015 we enhanced our liquidity and financial flexibility by increasing our revolving credit facility from $80 million to $200 million, extending its maturity to 2020, and repaying our $30 million Term Loan with a $30 million draw on the increased revolving credit facility.

Executive Outlook

We expect 2015 to be a challenging year. The steep and rapid decline in oil prices has led to a sharp reduction in drilling activities in U.S. land and GOM inland and shallow water markets. This also is putting increased pressure on prices for our services. We anticipate the downturn in our U.S. markets will be severe and expect our international markets to be impacted as well, though with less severity.

As a result, we expect continued softness in rental tool demand and pricing in U.S. land drilling markets, continued low utilization in the U.S. barge drilling market with further declines in dayrates and some weakness in utilization and dayrates to develop in our international drilling markets. We expect the impact on our U.S. rental tools business to be moderated by our growing participation in the U.S. GOM deepwater drilling market. In addition, we anticipate stronger results from our international rental tools business due to our significant presence in the Middle East and recent gains in operating performance. We do not anticipate any significant changes in our international O&M projects or in our Alaska drilling operations.

We do not know how deep this downcycle may go or how long it may last. We are taking actions across the company to lower our cost base, sustain our utilization, manage our cash and liquidity, and preserve our ability to respond as opportunities develop.

Results of Operations

We analyze financial results for each of our reportable segments. We monitor our reporting segments based on several criteria, including operating gross margin and operating gross margin excluding depreciation and amortization. Operating gross margin excluding depreciation and amortization is computed as revenues less direct operating expenses, and excludes depreciation and amortization expense, where applicable; operating gross margin percentages are computed as operating gross margin as a percent of revenues. The operating gross margin excluding depreciation and amortization amounts and percentages should not be used as a substitute for those amounts reported under U.S. GAAP. Management believes this information is useful to our investors as it more accurately reflects the cash flow from operations generated by each segment.

Year ended December 31, 2014 Compared with Year ended December 31, 2013

Revenues of $968.7 million for the year ended December 31, 2014 increased $94.5 million, or 10.8 percent, from the comparable 2013 period. Operating gross margin decreased 8.5 percent to $154.2 million for the year ended December 31, 2014 as compared to $168.4 million for the year ended December 31, 2013.

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



	Year Ended December 31,
	2014					2013
Dollars in Thousands
Revenues:
Rental Tools	$	347,766		36	%	$	310,041		35	%
Drilling Services:
U.S. (Lower 48) Drilling	158,405			16	%	153,624			18	%
International & Alaska Drilling ⁽¹⁾	462,513			48	%	410,507			47	%
Total Drilling Services	620,918			64	%	564,131			65	%
Total revenues	968,684			100	%	874,172			100	%
Operating gross margin excluding depreciation and amortization:
Rental Tools	137,123			39	%	147,017			47	%
Drilling Services:
U.S. (Lower 48) Drilling	68,091			43	%	69,415			45	%
International & Alaska Drilling ⁽¹⁾	94,089			20	%	86,068			21	%
Total Drilling Services	162,180			26	%	155,483			28	%
Total operating gross margin excluding depreciation and amortization	299,303			31	%	302,500			35	%
Depreciation and amortization	(145,121		)			(134,053		)
Total operating gross margin	154,182					168,447
General and administrative expense	(35,016		)			(68,025		)
Provision for reduction in carrying value of certain assets	—					(2,544		)
Gain on disposition of assets, net	1,054					3,994
Total operating income	$	120,220				$	101,872


(1)	Includes the close-out of a construction project and recognition of final percentage of completion revenue. The construction project was canceled in 2011 prior to final completion.

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



Dollars in Thousands	Rental Tools		U.S. (Lower 48) Drilling		International & Alaska Drilling		Total
Year ended December 31, 2014
Operating gross margin⁽¹⁾	$	72,946	$	46,831	$	34,405	$	154,182
Depreciation and amortization	64,177		21,260		59,684		145,121
Segment operating gross margin excluding depreciation and amortization	$	137,123	$	68,091	$	94,089	$	299,303
Year ended December 31, 2013
Operating gross margin⁽¹⁾	$	91,164	$	54,203	$	23,080	$	168,447
Depreciation and amortization	55,853		15,212		62,988		134,053
Segment operating gross margin excluding depreciation and amortization	$	147,017	$	69,415	$	86,068	$	302,500


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

Rental Tools Services Business Line

Rental Tools segment revenues increased $37.7 million, or 12.2 percent, to $347.8 million for the year ended December 31, 2014 compared to $310.0 million for the year ended December 31, 2013. The increase was due to a $26.7 million increase in our international revenues and an $11.0 million increase in our U.S. revenues. The increase in international revenues was primarily due to a full year of revenues from International Tubular Services (ITS), acquired in April of 2013, which contributed an increase of $23.4 million of revenues for the year ended December 31, 2014. The increase in U.S. rental tools revenues was due to increased activity in the offshore Gulf of Mexico (GOM) market and increased activity in the U.S. land drilling market.

Rental Tools segment operating gross margin excluding depreciation and amortization decreased $9.9 million, or 6.7 percent, to $137.1 million for the year ended December 31, 2014 compared with $147.0 million for the year ended December 31, 2013. The decrease was primarily due to a reduction in gross margin excluding depreciation and amortization for our international operations, resulting from lower utilization, increased costs related to relocation of facilities and an increase in the allowance for doubtful accounts. This decline was slightly offset by an increase in gross margin excluding depreciation and amortization for our U.S. operations due to the increase in activity in the offshore GOM and U.S. land drilling markets, despite an increase in competitive conditions that have led to lower product pricing for rental tools and related activities.

Drilling Services Business Line

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues increased $4.8 million, or 3.1 percent, to $158.4 million for the year ended December 31, 2014, as compared with revenues of $153.6 million for the year ended December 31, 2013. The increase in revenues was primarily due to higher average dayrates for the U.S. barge rig fleet, including benefits from the addition to our operating fleet of rigs 55B and 30B in the second and third quarters, respectively, of 2014. Additionally, the O&M contract supporting three platform operations located offshore California generated higher reimbursable revenues and was operating for the full year ended December 31, 2014, compared with 2013, in which this contract commenced in February 2013. The increase was partially offset by lower utilization primarily due to a decline in market opportunities in the offshore GOM as a result of lower oil prices late in 2014.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization decreased $1.3 million, or 1.9 percent, to $68.1 million for the year ended December 31, 2014, compared with $69.4 million for the year ended December 31, 2013. This decrease is primarily due to lower utilization of the U.S. barge rig fleet caused by lower oil prices late in 2014.

International & Alaska Drilling

International & Alaska Drilling segment revenues increased $52.0 million, or 12.7 percent, to $462.5 million for the year ended December 31, 2014, compared with $410.5 million for the year ended December 31, 2013. The increase in revenues is primarily due to higher drilling revenues through the operation of rigs we own resulting from an increase in utilization, coupled with higher revenues generated by our O&M contracts and project related activities.

Revenues related to Parker-owned rigs increased $43.2 million, or 15.5 percent, to $322.7 million for the year ended December 31, 2014 compared with $279.5 million for the year ended December 31, 2013. The increase in revenues was primarily due to an increase in utilization in our Sakhalin Island operations and an increase in our utilization in the Kurdistan Region of Iraq

where we successfully deployed two previously idle rigs. In addition, we experienced a full year of operations in 2014 for our two arctic-class drilling rigs in Alaska, compared with 2013, in which one rig was not operational until February 2013. These increases were partially offset by reduced revenues due to a decline in rig fleet utilization in our Latin America region.

O&M and project related revenues increased $25.6 million, or 16.3 percent, to $183.0 million, for the year ended December 31, 2014 compared to $157.4 million for the year ended December 31, 2013. The increase in revenues from our O&M contracts was primarily due to increased activity and higher dayrates associated with our Sakhalin Island O&M operations, which included the startup of the Berkut platform which began drilling operations in the 2014 fourth quarter. Reimbursable revenues are generated through our purchasing support for the O&M contracts with our customers. Reimbursable revenues add to revenues but have a minimal impact on operating margins. Additionally, project related revenues increased primarily due to a new FEED contract entered into during the fourth quarter of 2013 and increased activity under the vendor services phase of the Berkut platform project. The increase was partially offset by the completion of an O&M project in Papua New Guinea in May 2014. Approximately $51.2 million and $46.4 million of O&M revenues were attributable to reimbursable costs for the years ended December 31, 2014 and 2013, respectively. Project related revenues were $43.2 million and $26.4 million for the years ended December 31, 2014 and 2013, respectively.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization increased $8.0 million, or 9.3 percent, to $94.1 million for the year ended December 31, 2014, compared with $86.1 million for the year ended December 31, 2013. The increase in operating gross margin excluding depreciation and amortization for the year ended December 31, 2014 was primarily from our O&M operations with a slight increase in margins for our Parker-owned rig operations.

Operating gross margin excluding depreciation and amortization related to Parker-owned rigs was $67.9 million and $66.0 million for the years ended December 31, 2014 and 2013, respectively. The increase in operating gross margin excluding depreciation and amortization was primarily due to both arctic-class rigs being fully operational and lower operating expenses in our Alaska operations. This increase was partially offset by the impact of net mobilization costs associated with the redeployment of two Parker-owned rigs from Kazakhstan to the Kurdistan Region of Iraq and their high initial operating costs as well as an increase in operating costs in our Papua New Guinea operations and decline in rig fleet utilization in our Latin America region.

Operating gross margin excluding depreciation and amortization generated by our O&M and project related operations was $29.7 million and $27.0 million for the years ended December 31, 2014 and 2013, respectively. Included in the 2013 operating gross margin excluding depreciation and amortization was $4.7 million related to the close-out of a construction project and recognition of final percentage of completion revenue. The construction project was an extended-reach drilling rig construction contract which our customer canceled in 2011 prior to final completion. The increase in operating gross margin excluding depreciation and amortization is primarily due to increased activity and higher revenues and lower operating costs associated with our Sakhalin Island O&M operations, which included the startup of the Berkut platform project which began drilling operations in the fourth quarter. This increase was partially offset by the completion of an O&M project in Papua New Guinea in May 2014 discussed above. Project related operating gross margin excluding depreciation and amortization was $3.5 million and $2.2 million for the years ended December 31, 2014 and 2013, respectively.

Other Financial Data

General and administrative expense

General and administrative expense decreased $33.0 million to $35.0 million for the year ended December 31, 2014, compared with $68.0 million for the year ended December 31, 2013. The general and administrative expense decrease was due primarily to approximately $22.5 million of costs incurred during 2013 related to the ITS Acquisition that did not recur in 2014. During 2013 we also incurred severance costs related to the departure of our former chief financial officer and our executive chairman, and incurred higher legal costs for matters related to our deferred prosecution agreement and settlements with the DOJ and SEC, neither of which recurred during 2014. General and administrative expense during 2014 also benefited from a $2.75 million reimbursement from escrow related to the ITS Acquisition to reimburse the Company for certain post-acquisition expenditures. See Note 13 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 for further discussion.

Provision for reduction in carrying value of certain assets

During 2014, the provision for reduction in carrying value of certain assets was zero. During 2013, the provision for reduction in carrying value of certain assets was $2.5 million which was comprised of non-cash charges recognized for three rigs reclassified from assets held for sale to assets held and used for which carrying values exceeded fair values. Management concluded, based on the facts and circumstances at the time, it was no longer probable that the sales of the rigs sale would be consummated.

Gain on disposition of assets

Net gains recorded on asset dispositions for the years ended December 31, 2014 and 2013 were $1.1 million and $4.0 million, respectively. The net gains for 2014 were primarily the result of long-lived asset sales, including the sale of two rigs located in Kazakhstan during the fourth quarter. The net gains for 2013 were primarily the result of long-lived asset sales include the sale of two rigs located in New Zealand, a building located in Tulsa, Oklahoma and a barge rig located in Mexico. Additionally, during the normal course of business we periodically sell equipment deemed to be excess or not currently required for operations.

Interest income and expense

Interest expense decreased $3.6 million to $44.3 million for the year ended December 31, 2014 compared with $47.8 million for the year ended December 31, 2013. This decrease was primarily related to a decrease in debt-related interest expense resulting from lower interest rates on our outstanding debt balance and a lower total debt balance, offset by an increase in amortization of debt issuance costs and a decrease in capitalized interest. Interest income decreased $2.3 million to $0.2 million during the 2014, compared with interest income of $2.5 million during 2013 primarily related to interest earned on an IRS refund received during 2013.

Loss on extinguishment of debt

Loss on extinguishment of debt was $30.2 million and $5.2 million for the years ended December 31, 2014 and December 31, 2013, respectively. The loss on extinguishment of debt for 2014 related to the purchase and redemption of the 9.125% Notes during the first six months of 2014. The loss on extinguishment of debt for 2013 is related to the write-off of debt issuance costs resulting from the repayment of a $125 million term loan, fully funded by Goldman Sachs Bank USA as Sole Lead Arranger and Administrative Agent (Goldman Term Loan) in July 2013.

Other income and expense

Other income and expense was $2.5 million of income and $1.5 million of income for the years ended December 31, 2014 and December 31, 2013, respectively. Other income in 2014 was primarily related to earnings from our investment in an unconsolidated subsidiary that was acquired as part of the ITS Acquisition as well as settlements of claims against a vendor. This income was partially offset by losses related to foreign currency fluctuations from our Sakhalin Island operations. Other income in 2013 was primarily related to the recognition of non-refundable deposits from a buyer in connection with the sale of three rigs for which the sales agreement was terminated in the fourth quarter of 2013.

Income tax expense

Income tax expense was $24.1 million for the year ended December 31, 2014, compared with $25.6 million for the year ended December 31, 2013. The decrease was driven primarily by the decrease in pre-tax income and the mix of operations.

Our effective tax rate was 49.6 percent for the year ended December 31, 2014, compared with 48.5 percent for the year ended December 31, 2013. Our tax rate is affected by recurring items, such as tax rates in state and foreign jurisdictions and the relative amounts of income we earn in those jurisdictions. It is also affected by discrete items, such as return-to-accrual adjustments and changes in reserves for uncertain tax positions, which may occur in any given year but are not consistent from year to year.

Year Ended December 31, 2013 Compared with Year Ended December 31, 2012

Revenues of $874.2 million for the year ended December 31, 2013 increased $196.4 million, or 29.0 percent, from the comparable 2012 period. Operating gross margin increased $16.9 million to $168.4 million for the year ended December 31, 2013 as compared to $151.6 million for the year ended December 31, 2012.

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



	Year Ended December 31,
	2013					2012
Dollars in Thousands
Revenues:
Rental Tools	$	310,041		35	%	$	246,900		36	%
Drilling Services:
U.S. (Lower 48) Drilling	153,624			18	%	123,672			18	%
International & Alaska Drilling ⁽¹⁾	410,507			47	%	307,189			45	%
Total Drilling Services	564,131			65	%	430,861			64	%
Total revenues	874,172			100	%	677,761			100	%
Operating gross margin excluding depreciation and amortization:
Rental Tools	147,017			47	%	158,016			64	%
Drilling Services:
U.S. (Lower 48) Drilling	69,415			45	%	54,081			44	%
International & Alaska Drilling ⁽¹⁾	86,068			21	%	52,476			17	%
Total Drilling Services	155,483			28	%	106,557			25	%
Total operating gross margin excluding depreciation and amortization	302,500			35	%	264,573			39	%
Depreciation and amortization	(134,053		)			(113,017		)
Total operating gross margin	168,447					151,556
General and administrative expense	(68,025		)			(46,257		)
Provision for reduction in carrying value of certain assets	—					—
Gain on disposition of assets, net	(2,544		)			—
Gain on disposition of assets, net	3,994					1,974
Total operating income	$	101,872				$	107,273


(1)	Includes the close-out of a construction project and recognition of final percentage of completion revenue. The construction project was canceled in 2011 prior to final completion.

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



Dollars in Thousands	Rental Tools		U.S. (Lower 48) Drilling		International & Alaska Drilling			Total
Year ended December 31, 2013
Operating gross margin⁽¹⁾	$	91,164	$	54,203	$	23,080		$	168,447
Depreciation and amortization	55,853		15,212		62,988			134,053
Segment operating gross margin excluding depreciation and amortization	$	147,017	$	69,415	$	86,068		$	302,500
Year ended December 31, 2012
Operating gross margin⁽¹⁾	$	113,899	$	37,718	$	(61	)	$	151,556
Depreciation and amortization	44,117		16,363		52,537			113,017
Segment operating gross margin excluding depreciation and amortization	$	158,016	$	54,081	$	52,476		$	264,573


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

Rental Tools Services Business Line

Rental Tools segment revenues increased $63.1 million, or 25.6 percent, to $310.0 million for the year ended December 31, 2013 compared to $246.9 million for the year ended December 31, 2012. The increase was due to an $86.3 million increase in our international revenues, partially offset by a $23.2 million decrease in our U.S. revenues. The increase in international revenues was primarily due to revenues from ITS, which contributed an increase of $88.0 million of revenues for the year ended December 31, 2013. The decrease in U.S. rental tools revenues was primarily due to the impact of the continuing competitive conditions in the U.S. land drilling market due to declines in drilling activity in almost all major basins, partially offset by higher revenues from a growing participation in the expanding U.S. GOM offshore drilling market.

Rental Tools segment operating gross margin excluding depreciation and amortization decreased $11.0 million, or 7.0 percent, to $147.0 million for the year ended December 31, 2013 as compared with $158.0 million for the year ended December 31, 2012. The decrease was primarily due to a reduction in gross margin excluding depreciation and amortization for our U.S. operations of $29.4 million, primarily due to the increase in competitive conditions which led to lower product pricing for rental tools and related activities and a decline in rental tool utilization. This decrease was partially offset by an increase for our international operations due to the contribution of $20.5 million of gross margin excluding depreciation and amortization attributable to ITS from the date of acquisition.

Drilling Services Business Line

U.S. (Lower 48) Drilling

U.S. (Lower 48) Drilling segment revenues increased $30.0 million, or 24.2 percent, to $153.6 million for the year ended December 31, 2013, as compared with revenues of $123.7 million for the year ended December 31, 2012. The increase in revenues was primarily due to an increase in rig fleet utilization and higher average dayrates for the U.S. barge rig fleet during 2013. Both of these factors reflect a general increase in overall drilling activity in the U.S. GOM inland waters and an increase in our dayrates for multi-well contracts based on our ability to deliver higher levels of performance compared with our competitors. Additionally, in February 2013 we began an O&M contract supporting three platform operations located offshore California.

U.S. (Lower 48) Drilling segment operating gross margin excluding depreciation and amortization increased $15.3 million, or 28.4 percent, to $69.4 million for the year ended December 31, 2013, compared with $54.1 million for the year ended December 31, 2012. This increase is primarily a result of improved average dayrates and the continued control of operating costs for the U.S. barge rig fleet. Additionally, the California O&M contract described above was not earning revenues or contributing to gross margin during 2012.

International & Alaska Drilling

International & Alaska Drilling segment revenues increased $103.3 million, or 33.6 percent, to $410.5 million for the year ended December 31, 2013, compared with $307.2 million for the year ended December 31, 2012. The increase in revenues is primarily due to higher drilling revenues through the operation of rigs we own coupled with higher revenues generated by our O&M contracts and project related activities.

Revenues related to Parker-owned rigs increased $80.5 million, or 40.5 percent, to $279.4 million for the year ended December 31, 2013 compared with $198.9 million for the year ended December 31, 2012. The increase in revenues was primarily due to the commencement of operations by our two arctic-class drilling rigs in Alaska, one in the fourth quarter of 2012 and the other in the first quarter of 2013. Prior to that, during the first three quarters of 2012, both rigs were under construction and not generating revenues. Additionally, the increase in revenues was due to the contribution of revenues from a previously idle rig added to our Sakhalin Island operations and two previously idle rigs added to our operations in the Kurdistan Region of Iraq, as well as increased revenues related to our arctic-class barge rig in the Caspian Sea and the contribution of revenues from a previously idle rig in the Karachaganak field in Kazakhstan. These increases were partially offset by lower utilization in Algeria.

O&M and project related revenues increased $35.1 million, or 28.7 percent, to $157.4 million, for the year ended December 31, 2013 compared to $122.3 million for the year ended December 31, 2012. The increase in revenues was primarily due to higher reimbursable revenues associated with our O&M services related to the Berkut platform and the Orlan platform on Sakhalin Island. Reimbursable revenues are generated through our purchasing support for the O&M contracts with our customers. Reimbursable revenues add to revenues but have a minimal impact on operating margins. Additionally, revenues increased due to increased activity under the vendor services phase of the Berkut platform project which started during the 2012 third quarter and a new customer FEED project. Approximately $46.4 million and $31.3 million of O&M revenues were attributable to reimbursable costs for the years ended December 31, 2013 and 2012, respectively. Project related revenues were $26.4 million and $14.0 million for the years ended December 31, 2013 and 2012, respectively.

International & Alaska Drilling segment operating gross margin excluding depreciation and amortization increased $33.6 million, or 64.0 percent, to $86.0 million for the year ended December 31, 2013, compared with $52.5 million for the year ended December 31, 2012. The increase in operating gross margin excluding depreciation and amortization for the year ended

December 31, 2013 was from our Parker-owned rig operations coupled with higher project related margins slightly offset by a decrease in O&M margins.

Operating gross margin excluding depreciation and amortization related to Parker-owned rigs was $66.0 million and $31.6 million for the years ended December 31, 2013 and 2012, respectively. The increase in operating gross margin excluding depreciation and amortization for this segment is mainly due to the contributions from the arctic-class drilling rigs in Alaska described above, which were not earning revenues or contributing to gross margin during 2012. Additionally, the increase in operating gross margin excluding depreciation and amortization was due to the contribution of revenues from a previously idle rig in Kazakhstan, in our Karachaganak field operations, and a previously idle rig in our Sakhalin Island operations and increased revenues from higher utilization of our arctic-class barge rig in the Caspian Sea. The increase was partially offset by costs associated with the mobilization and start-up of the two rigs located in the Kurdistan Region of Iraq, decreased utilization resulting from two rigs stacked in Tunisia and lower revenues and higher costs in our Latin America region.

Operating gross margin excluding depreciation and amortization generated by our O&M and project related operations was $27.0 million and $21.1 million for the years ended December 31, 2013 and 2012, respectively. Included in the 2013 operating gross margin excluding depreciation and amortization was $4.7 million related to the close-out of a construction project and recognition of final percentage of completion revenue. The constrcution project was an extended-reach drilling rig construction contract which our customer canceled in 2011 prior to final completion. The increase in operating gross margin excluding depreciation and amortization is primarily due to an increase in labor revenues related to the Berkut platform project in South Korea, in addition to increased activity under the vendor services phase of the Berkut platform project, which started during the 2012 third quarter and a new customer FEED project, noted above. The increase was slightly offset by a decline in O&M margins resulting from the completion of an O&M contract in China that was active during all of 2012, a decrease in revenues from our Coral Sea project in Papua New Guinea, and higher operating costs related to the Orlan platform project on Sakhalin Island. Project related operating gross margin excluding depreciation and amortization was $2.2 million and $0.2 million for the years ended December 31, 2013 and 2012, respectively.

Other Financial Data

General and administrative expense

General and administrative expense increased $21.8 million to $68.0 million for the year ended December 31, 2013, compared with $46.3 million for the year ended December 31, 2012. The general and administrative expense increase was due primarily to approximately $22.5 million of costs incurred during 2013 related to the ITS Acquisition slightly offset by decreased costs relating to the settlement with the DOJ and SEC, and decreased legal fees associated with the related SEC and DOJ investigations. See Note 13 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014 for further discussion.

Provision for reduction in carrying value of certain assets

Provision for reduction in carrying value of certain assets was $2.5 million which was comprised of non-cash charges recognized for three rigs reclassified from assets held for sale to assets held and used for which carrying values exceeded fair values. During 2013, management concluded, based on the facts and circumstances at the time, it was no longer probable that the sales of the rigs sale would be consummated.

Gain on disposition of assets

Net gains recorded on asset dispositions for the years ended December 31, 2013 and 2012 were $4.0 million and $2.0 million, respectively. During 2013, we sold two rigs located in New Zealand, a building located in Tulsa and a barge rig located in Mexico. These sales resulted in gains totaling $1.2 million. Additionally, during the normal course of operations, we periodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest income and expense

Interest expense increased $14.3 million to $47.8 million for the year ended December 31, 2013 compared with $33.5 million for the year ended December 31, 2012. The increase in interest expense primarily resulted from an $11.6 million increase in debt-related interest expense primarily related to the full-year impact of the $125.0 million of 9.125% Notes issued in the second quarter of 2012, the $225.0 million 7.50% Notes issued in July 2013 and the $125.0 million debt incurred in April 2013 used to initially fund the ITS Acquisition. Additionally, we experienced a $7.9 million decrease in interest capitalized on internal construction projects resulting from the completion of the two arctic-class drilling rigs in Alaska, which increased overall interest expense. The increase in interest expense is partially offset by a decrease due to the repayment of our 2.125% Convertible Notes in the 2013 second quarter and a decrease in amortization of debt issuance costs. Interest income was $2.5 million and $0.2 million for the years ended December 31, 2013 and 2012, respectively. Interest income in 2013 primarily related to interest earned on an IRS refund received during the year.

Loss on extinguishment of debt

Loss on extinguishment of debt was $5.2 million and $2.1 million for the years ended December 31, 2013 and December 31, 2012, respectively. The loss on extinguishment of debt for 2013 is related to the extinguishment in July 2013 of the $125 million debt incurred in April 2013 used to initially fund the ITS Acquisition. The loss on extinguishment of debt for 2012 resulted from the repurchase of $122.9 million of outstanding 2.125% Convertible Notes in May 2012.

Other income and expense

Other income and expense was $1.5 million of income and $0.8 million of expense for the years ended December 31, 2013 and December 31, 2012, respectively. Other income in 2013 was primarily related to the recognition of non-refundable deposits from a buyer in connection with the sale of three rigs for which the sales agreement was terminated in the 2013 fourth quarter.

Income tax expense

Income tax expense was $25.6 million for the year ended December 31, 2013, compared with $33.9 million for the year ended December 31, 2012. The 2013 tax expense decrease was primarily due to lower pre-tax earnings in addition to discrete items relating to enactment of new tax legislation in Mexico, research and development tax credits and other less significant items related to return-to-accrual adjustments.

Our effective tax rate was 48.5% for the year ended December 31, 2013, compared with 47.7% for the year ended December 31, 2012. Our tax rate is affected by recurring items, such as tax rates in state and non-U.S. jurisdictions and the relative amounts of income we earn in those jurisdictions, which we expect to be fairly consistent in the near term. It is also affected by discrete items, such as return-to-accrual adjustments and changes in reserves for uncertain tax positions, which may occur in any given year but are not consistent from year to year.

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. When determined necessary we may seek to raise additional capital in the future. We expect that for the foreseeable future, cash on hand and 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 do not pay dividends to our shareholders.

Subsequent to December 31, 2014, we increased our liquidity by entering into the 2015 Secured Credit Agreement on January 26, 2015. This agreement amends and restates the Amended and Restated Credit Agreement (the 2012 Secured Credit Agreement) dated December 14, 2012. The 2015 Secured Credit Agreement is comprised of a $200 million revolving credit facility. The 2012 Secured Credit Agreement consisted of an $80 million revolving credit facility and a $50 million term loan facility (Term Loan). At the closing of the 2015 Secured Credit Agreement we repaid $30.0 million of Term Loan borrowings under the 2012 Secured Credit Agreement with a $30.0 million draw under the 2015 Secured Credit Agreement. At the closing, there were no borrowings under the revolving credit portion of the 2012 Secured Credit Agreement.

Cash Flow Activity

As of December 31, 2014, we had cash and cash equivalents of $108.5 million, a decrease of $40.2 million from cash and cash equivalents of $148.7 million at December 31, 2013. The following table provides a summary of our cash flow activity for the last three years:



Dollars in thousands	2014			2013			2012
Operating Activities	$	202,467		$	161,497		$	189,699
Investing Activities	(173,575		)	(265,418		)	(187,606		)
Financing Activities	(69,125		)	164,724			(12,076		)
Net change in cash and cash equivalents	$	(40,233	)	$	60,803		$	(9,983	)

Operating Activities

Cash flows provided by operating activities were $202.5 million in 2014, compared with $161.5 million in 2013. Changes in working capital during 2014 were a use of cash of $17.1 million and a use of cash of $34.0 million for the years ended December 31, 2014 and December 31, 2013, respectively. Over the past few years we have reinvested a substantial portion of our operating cash flows to expand our business through acquisition and to enhance our fleet of drilling rigs and rental tools

equipment. It is our intention to continue to utilize our operating cash flows to finance further investments into our rental tools inventories, rig purchases or upgrades as well as other strategic investments aligned with our strategies.

Cash flows provided by operating activities were $161.5 million in 2013 and were impacted by our earnings and by non-cash charges such as depreciation expense, gains on asset sales, deferred tax benefit, stock compensation expense, debt extinguishment and amortization of debt issuance costs. Depreciation expense increased due to our two Alaska rigs commencing work in late 2012 and early 2013. Additionally, during 2013, we more aggressively disposed of assets deemed not core to the current strategy resulting in an increase in gain on disposition of assets. Uses of working capital during 2013 primarily related to the ITS Acquisition which resulted in increased receivables, inventory and accounts payable.

Cash flows provided by operating activities were $189.7 million in 2012. 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.

Investing Activities

Cash flows used in investing activities were $173.6 million for 2014, compared with $265.4 million for 2013. Our primary use of cash during 2014 was capital expenditures of $179.5 million. Capital expenditures were primarily for tubular and other products for our Rental Tools Services business and rig-related enhancements and maintenance.

Cash flows used in investing activities were $265.4 million for 2013. Our primary use of cash during 2013 was $118.0 million for the ITS Acquisition and $155.6 million for capital expenditures. Capital expenditures in 2013 were primarily for tubular and other products for our Rental Tools Services business, rig-related enhancements and maintenance and costs related to our new enterprise resource planning system. Sources of cash included $8.2 million of proceeds from asset sales.

Cash flows used in investing activities were $187.6 million for 2012. Our primary use of cash was $191.5 million for capital expenditures. Capital expenditures in 2012 were primarily for the construction of our two arctic-class drilling rigs, tubular and other products for our Rental Tools Services business, and costs related to our new enterprise resource planning system. In addition, we incurred capital to support ongoing drilling activities. Sources of cash included $3.9 million of proceeds from asset sales.

Capital expenditures for 2015 are estimated to range from $100.0 million to $120.0 million and will primarily be directed to our rental tools inventory and maintenance capital on our rigs. Any discretionary spending will be evaluated based upon adequate return requirements and available liquidity.

Financing Activities

Cash flows used in financing activities were $69.1 million for 2014. Cash flows used in financing activities primarily related to the repayment of $425.0 million of our 9.125% Notes, payment of $26.2 million of related tender and consent premiums, and payment of debt issuance costs of $7.6 million. Cash provided by financing activities included proceeds of $360.0 million from the issuance of our 6.75% Notes and reborrowing of a $40.0 million Term Loan under our 2012 Secured Credit Agreement.

Cash flows provided by financing activities for 2013 were $164.7 million. Cash flows provided by financing activities primarily related to the $125 million Goldman Term Loan issued during the 2013 second quarter in connection with the ITS Acquisition and the $225.0 million 7.50% Notes issued during the 2013 third quarter. Cash used in financing activities included pay-off of the Goldman Term Loan in the 2013 third quarter, principal payments made under our Term Loan and payments of debt issuance costs.

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% Convertible Notes and $18.0 million in quarterly payments against our Term Loan then-outstanding. 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 percent, 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 revolving credit facility.

Long-Term Debt Summary

Our principal amount of long-term debt, including current portion, was $615.0 million as of December 31, 2014, which consisted of:

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

•$225.0 million aggregate principal amount of 7.50% Notes; and

•$30.0 million under our Term Loan, $10.0 million of which was classified as current.

6.75% Senior Notes, due July 2022

On January 22, 2014, we issued $360.0 million aggregate principal amount of the 6.75% 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 6.75% Notes offering plus a $40.0 million Term Loan draw under the 2012 Secured Credit Agreement and cash on hand were utilized to purchase $416.2 million aggregate principal amount of our outstanding 9.125% Senior Notes due 2018 pursuant to a tender and consent solicitation offer commenced on January 7, 2014. See further discussion of the tender and consent solicitation offer below entitled "9.125% Senior Notes, due April 2018".

The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and our 7.50% Notes. Interest on the 6.75% Notes is payable on January 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes of approximately $7.6 million ($7.0 million net of amortization as of December 31, 2014) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at a redemption price of 106.75 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 January 15, 2018, we may redeem all or a part of the 6.75% Notes upon appropriate notice, at a redemption price of 103.375 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning January 15, 2020. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture 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.

7.50% Senior Notes, due August 2020

On July 30, 2013, we issued $225.0 million aggregate principal amount of the 7.50% Notes pursuant to an Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 7.50% Notes offering were primarily used to repay the $125.0 million aggregate principal amount of the Goldman Term Loan, to repay $45.0 million of Term Loan borrowings and for general corporate purposes.

The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and future senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guarantee indebtedness under the 2015 Secured Credit Agreement and the 6.75% Notes. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year, beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes of approximately $5.6 million ($4.7 million, net of amortization as of December 31, 2014) are being amortized over the term of the notes using the effective interest rate method.

At any time prior to August 1, 2016, we may redeem up to 35 percent of the aggregate principal amount of the 7.50% Notes at a redemption price of 107.50 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 August 1, 2016, we may redeem all or a part of the 7.50% Notes upon appropriate notice, at a redemption price of 103.750 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning August 1, 2018. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of the aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

9.125% Senior Notes, due April 2018

On March 22, 2010, we issued $300.0 million aggregate principal amount of the 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.

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.

On January 7, 2014, we commenced a tender and consent solicitation with respect to the 9.125% Notes. The tender offer price was $1,061.98, inclusive of a $30.00 consent payment, for each $1,000 principal amount of 9.125% Notes, plus accrued and unpaid interest. On January 22, 2014, we paid $453.7 million for the tendered 9.125% Notes, comprised of $416.2 million of aggregate principal amount of the 9.125% Notes, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. On April 1, 2014, we redeemed the remaining $8.8 million aggregate principal amount of the outstanding 9.125% Notes for a purchase price of $9.6 million, inclusive of a $0.4 million call premium and $0.4 million interest. During the year ended December 31, 2014, we recorded a loss on extinguishment of debt of approximately $30.2 million, which included the tender and consent premiums of $25.8 million, the call premium of $0.4 million and the write-off of unamortized debt issuance costs of $7.7 million, offset by the write-off of the remaining unamortized debt issuance premium of $3.8 million.

2015 Secured Credit Agreement

On January 26, 2015 we entered into the 2015 Secured Credit Agreement, which amended and restated the 2012 Secured Credit Agreement. The 2015 Secured Credit Agreement is comprised of a $200 million revolving credit facility (2015 Revolver). The 2012 Secured Credit Agreement consisted of an $80 million revolving credit facility and a $50 million Term Loan. At the closing of the 2015 Secured Credit Agreement, we repaid $30.0 million of Term Loan borrowings under the 2012 Secured Credit Agreement with a $30.0 million draw under the 2015 Revolver. At the closing date there were no borrowings under the revolving credit portion of the 2012 Secured Credit Agreement.

Our 2015 Revolver is available for general corporate purposes and to support letters of credit. Interest on 2015 Revolver loans accrues at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Under the 2015 Secured 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 2015 Secured Credit Agreement). Revolving loans are available subject to a quarterly Asset Coverage Ratio calculation based on the Orderly Liquidation Value of certain specified rigs including barge rigs in the Gulf of Mexico and land rigs in Alaska, and rental equipment of the Company and its subsidiary guarantors and a percentage of eligible domestic accounts receivable. Upon closing of the 2015 Secured Credit Agreement, there was $30.0 million drawn on the 2015 Revolver and $11.7 million of letters of credit outstanding. The 2015 Secured Credit Agreement matures on January 26, 2020.

2012 Secured Credit Agreement

On December 14, 2012, we entered into the 2012 Secured Credit Agreement consisting of a senior secured $80.0 million revolving facility (2012 Revolver) and the Term Loan. In July 2013, the 2012 Secured Credit Agreement was amended to permit re-borrowing in the form of additional term loans, of up to $45.0 million, decreasing by $2.5 million at the end of each quarter beginning September 30, 2013 and ending March 31, 2014. In January 2014 we re-borrowed $40 million of the Term Loan.

Our obligations under the 2012 Secured Credit Agreement were guaranteed by substantially all of our direct and indirect domestic subsidiaries other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, each of which have executed guaranty agreements, and were secured by first priority liens on our accounts receivable, specified barge rigs and rental equipment. The 2012 Secured Credit Agreement contained customary affirmative and negative covenants with which we were in compliance as of December 31, 2014 and December 31, 2013. The 2012 Secured Credit Agreement would have matured on December 14, 2017.

2012 Revolver

Our 2012 Revolver was available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrued at a Base Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Under the 2012 Secured Credit Agreement, the Applicable Rate varied 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 2012 Secured Credit Agreement). Revolving loans were available subject to an asset coverage ratio determined 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, 2014 and December 31, 2013. Letters of credit outstanding as of December 31, 2014 and December 31, 2013 totaled $11.0 million and $4.6 million, respectively.

Term Loan

The Term Loan originated at $50.0 million on December 14, 2012 and required quarterly principal payments of $2.5 million, which began March 31, 2013. Interest on the Term Loan accrued at a Base Rate plus 2.00 percent or LIBOR plus 3.00 percent. The outstanding balance on the Term Loan at December 31, 2013 was zero. In January 2014 we re-borrowed $40 million of the Term Loan and used the proceeds, along with the proceeds from the issuance of the 6.75% Notes, to repurchase our 9.125% Notes. As of December 31, 2014 the remaining balance on the Term Loan was $30.0 million. At the closing of the 2015 Secured Credit Agreement, we repaid $30.0 million of Term Loan borrowings under the 2012 Secured Credit Agreement with a $30.0 million draw under the 2015 Revolver.

Liquidity

As of December 31, 2014, we had approximately $177.5 million of liquidity, which consisted of $108.5 million of cash and cash equivalents on hand and $69.0 million of availability under the 2012 Revolver.

We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. As of December 31, 2014 we have no energy, commodity, or foreign currency derivative contracts.

The following table summarizes our future contractual cash obligations as of December 31, 2014:



	Total		Less than 1 Year		Years 1 - 3		Years 3 - 5		More than 5 Years
	(Dollars in Thousands)
Contractual cash obligations:
Long-term debt — principal	$	615,000	$	10,000	$	20,000	$	—	$	585,000
Long-term debt — interest	297,216		42,018		83,073		82,350		89,775
Operating leases(1)	47,657		13,188		15,649		10,361		8,459
Purchase commitments(2)	65,195		65,195		—		—		—
Total contractual obligations	$	1,025,068	$	130,401	$	118,722	$	92,711	$	683,234
Commercial commitments:
Standby letters of credit(3)	10,999		10,999		—		—		—
Total commercial commitments	$	10,999	$	10,999	$	—	$	—	$	—


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


2)	We had purchase commitments outstanding as of December 31, 2014, related to rental tools and rig upgrade projects.


3)	We had an $80.0 million Revolver pursuant to our 2012 Secured Credit Agreement. As of December 31, 2014, $11.0 million of availability under the 2012 Revolver had been used to support letters of credit that had been issued.

With the closing of the 2015 Secured Credit Agreement disclosed above, we improved our liquidity, which consisted of current cash and cash equivalents on hand and $158.3 million of availability under the 2015 Revolver. At closing, a $30.0 million loan was borrowed from the 2015 Revolver, the Term Loan was paid with the borrowings and all outstanding letters of credit of $11.7 million were continued.

Other Matters

Business Risks

See Item 1A. Risk Factors, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, for a discussion of risks related to our business.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate our estimates, including those related to fair value of assets, bad debt, materials

and supplies obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.

We believe the following are our most critical accounting policies as they can be complex and require significant judgments, assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

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

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.

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

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

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

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

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

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

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

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

Legal and Investigation Matters - As of December 31, 2014, we have accrued an estimate of the probable and estimable costs for the resolution of certain legal and investigation matters. We have not accrued any amounts for other matters for which the liability is not probable and reasonably estimable. Generally, the estimate of probable costs related to these matters is developed in consultation with our legal advisors. The estimates take into consideration factors such as the complexity of the issues, litigation risks and settlement costs. If the actual settlement costs, final judgments, or fines, after appeals, differ from our estimates, our future financial results may be adversely affected.

Recent Accounting Pronouncements

For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated financial statements, see Note 18 - Recent Accounting Pronouncements in the Notes to the Consolidated Financial Statements of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

PARKER DRILLING CO /DE/ - FORM 8-K - EX-99.2 - EXHIBIT 99.2 - April 14, 2015

Attached files

PARKER DRILLING CO /DE/ Reports