Item 1. Business
Our Company
Oil States International, Inc. (the Company or Oil States), through its subsidiaries, is a leading provider of specialty products and services to natural resources companies throughout the world. We operate in some of the world's most active oil, coal, natural gas and iron ore producing regions, including Canada, onshore and offshore U.S., Australia, West Africa, the North Sea, South America and Southeast and West and Central Asia. Our customers include many national oil companies, major and independent oil and natural gas companies, onshore and offshore drilling companies, other oilfield service companies and mining companies. We operate in three principal business segments - accommodations, offshore products and well site services - and have established a leadership position in certain of our product or service offerings in each segment. In this Annual Report on Form 10-K, references to the "Company" or “Oil States” or to "we," "us," "our," and similar terms are to Oil States International, Inc. and our subsidiaries.
Available Information
The Company maintains a website with the address of www.oilstatesintl.com. The Company is not including the information contained on the Company's website as a part of, or incorporating it by reference into, this Annual Report on Form 10-K. The Company makes available free of charge through its website its Annual Report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and amendments to these reports, as soon as reasonably practicable after the Company electronically files such material with, or furnishes such material to, the Securities and Exchange Commission (the Commission). The filings are also available through the Commission at the Commission's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. The Board of Directors of the Company (the Board) has documented its governance practices by adopting several corporate governance policies. These governance policies, including the Company's Corporate Governance Guidelines, Corporate Code of Business Conduct and Ethics and Financial Code of Ethics for Senior Officers, as well as the charters for the committees of the Board (Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee) may also be viewed at the Company's website. The financial code of ethics applies to our principal executive officer, principal financial officer, principal accounting officer and other senior officers. Copies of such documents will be sent to shareholders free of charge upon written request to the corporate secretary at the address shown on the cover page of this Annual Report on Form 10-K.
Our Business Strategy
We have in past years grown our business lines both organically through capital spending and through strategic acquisitions. Our investments are focused in growth areas and on areas where we expect we can expand market share and where we believe we can achieve an attractive return on our investment. Currently, we see investment opportunities in the oil sands developments in Canada, in shale play regions in North America, in the natural resources market in Australia and in the expansion of our capabilities to manufacture and assemble deepwater capital equipment on a global basis. As part of our long-term growth strategy, we continue to review complementary acquisitions as well as make organic capital expenditures to enhance our cash flows and increase our shareholders’ returns. For additional discussion of our business strategy, please read Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Tubular Services Business Disposition
On September 6, 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu Tubulars America, Inc. (Marubeni-Itochu) for the sale of Sooner, Inc. and its subsidiaries (Sooner), which comprised the entirety of the Company’s tubular services segment. Total consideration received by the Company was $600.0 million in cash, which remains subject to customary post-closing adjustments. We recognized a net gain on disposal of $128.4 million ($84.0 million after-tax) during 2013, which is included within “Net income from discontinued operations, net of tax” in the Consolidated Statements of Income. Operating results for the Company’s tubular services business have been classified as discontinued operations for all periods presented.
Proposed Spin-off of Accommodations Business
On July 30, 2013, we announced that our Board of Directors approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to the Company’s shareholders. The spin-off is subject to market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, the completion of a review by the Commission of a Form 10 filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our Board of Directors, and is expected to be completed in the second quarter of 2014. The Accommodations business will initially be spun-off as a C-Corporation, which offers a faster path to separation. The Accommodations business will continue to assess the feasibility and advisability of a potential future conversion into a real estate investment trust (REIT).
Capital Spending and Acquisitions
Capital spending over the last five years has included both growth and maintenance capital expenditures in each of our businesses. Capital spending totaled $1.4 billion over the three-year period 2011 to 2013, 67% of which was spent in our accommodations segment.
In addition to capital spending, we have invested $144 million over the three-year period 2011 to 2013 for acquisitions of businesses. Acquisitions of other oilfield service and accommodations businesses have been an important aspect of our growth strategy and plan to increase shareholder value. Our acquisition strategy has allowed us to leverage our existing and acquired products and services into new geographic locations, and has expanded our technology and product offerings. We have made strategic acquisitions in each of our business segments.
On December 2, 2013, we acquired all of the equity of Quality Connector Systems, LLC (QCS) for total cash consideration of $42.5 million. Headquartered in Houston, Texas, QCS designs, manufactures and markets a portfolio of proprietary deep and shallow water pipeline connectors for subsea pipeline construction, repair and expansion projects. The operations of QCS have been included in our offshore products segment since the acquisition date.
On December 14, 2012, we acquired all of the equity of Tempress Technologies, Inc. (Tempress) for purchase price consideration of $49.8 million consisting of $32.8 million in cash plus contingent consideration with an estimated fair value of $17.0 million at closing. During 2013, the estimated fair market value of the contingent liability was increased to $20.0 million due to favorable developments related to a patent application by Tempress, resulting in a $3.0 million, or $0.05 per diluted share, charge to other operating expense. The patent was granted in the third quarter of 2013 and the $20.0 million of contingent consideration was paid to the former shareholders of Tempress. The Company’s current escrowed deposits of $5.3 million include other consideration for seller transaction indemnities, are considered restricted cash and are classified as “Other current assets” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for escrowed amounts expected to be paid to the seller also totaled $5.3 million and are classified as “Other current liabilities” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent liabilities” in our December 31, 2012 Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.
On July 2, 2012, we acquired all of the operating assets of Piper Valve Systems, Ltd (Piper) for total cash consideration of $48.0 million. Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects offshore (surface and subsea) and onshore. The operations of Piper have been included in our offshore products segment since the acquisition date.
The Company funded all of its acquisitions with cash on hand and/or amounts available under our credit facilities. See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our senior secured bank facilities.
Our Industry
We principally operate in the oilfield services industry and provide a broad range of products and services to our customers through each of our business segments. In our accommodations segment, we also support the mining industry in Australia. See Note 16 to the Consolidated Financial Statements included in “Part II, Item 8. Financial Statements and Supplementary Data” for financial information by segment and a geographical breakout of revenues and long-lived assets for each of the three years ended December 31, 2013, 2012 and 2011. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers' willingness to spend capital on the exploration for and development of oil, natural gas, coal and mineral reserves. Our customers’ spending plans are generally based on their outlook for near-term and long-term commodity prices. As a result, the demand for our products and services is highly sensitive to current and expected commodity prices.
Our historical financial results reflect the cyclical nature of the oilfield services business. Since 2001, there have been periods of increasing and decreasing activity in each of our operating segments. Due to the acquisition of The MAC Services Group Limited (The MAC), beginning in 2011, our results are also influenced by the level of activity in the natural resource market in Australia. For additional information about activities in each of our segments, please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Our accommodations business segment is significantly influenced by customer activity levels related to oil sands deposits in Alberta, Canada, activity levels in support of natural resources production in Australia and oil and gas production in Canada and the United States. Despite the general economic downturn in 2009 and early 2010 resulting from the global financial crisis, activity in our accommodations business has grown significantly in the last seven years.
As a result of the positive outlook for long-term oil demand, along with continued high oil prices during the last three years, bidding and quoting activity for our offshore products has increased since the latter part of 2010. As a result of this increased activity and our acquisitions, backlog in our offshore products segment has steadily increased from $535 million at December 31, 2011 to $561 million as of December 31, 2012, and to a year-end record of $580 million as of December 31, 2013. We anticipate global deepwater capital spending to continue at robust levels due to new award opportunities coming from Brazil, West Africa, the U.S. Gulf of Mexico and Southeast Asia.
Our well site services business segment is affected by drilling and completion activity primarily in the U.S. and, to a lesser extent, Canada and the rest of the world. As recently as 2008, overall North American drilling and completion activity was primarily driven by spending for natural gas exploration and production, particularly in the shale play regions of the U.S. using horizontal drilling and completion techniques. However, considering higher oil prices and lower natural gas prices, drilling and completion activity in North America has shifted to a greater proportion of oil and liquids-rich drilling. According to rig count data published by Baker Hughes Incorporated, the oil rig count in the U.S. as of February 14, 2014 totals approximately 1,423 rigs, comprising approximately 81% of total U.S. drilling activity.
Accommodations
Overview
During the year ended December 31, 2013, we generated approximately 39% of our revenue and 47% of our operating income, before corporate charges, from our accommodations segment. We are one of North America's and Australia’s largest integrated providers of accommodations services for people working in remote locations. Our scalable modular facilities provide temporary and long-term work force accommodations where traditional infrastructure is not accessible or cost effective. Once facilities are deployed in the field, we also provide catering and food services, housekeeping, laundry, facility management, water and wastewater treatment, power generation, communications and redeployment logistics. Our accommodations support workforces in the Canadian oil sands and in a variety of oil and natural gas drilling, mining and related natural resource applications as well as disaster relief efforts, primarily in Canada, Australia and the United States.
Accommodations Market
Our accommodations business has grown in recent years in large part due to the increasing demand for accommodations to support workers in the oil sands region of Canada. Demand for oil sands accommodations is primarily influenced by the longer-term outlook for crude oil prices rather than current energy prices, given the multi-year production phase of oil sands projects and the costs associated with development of such large scale projects. Utilization of our existing Canadian accommodations capacity and our future expansions will largely depend on continued oil sands spending.
Beginning in 2011, as a result of our acquisition of The MAC, our accommodations business entered into the Australian natural resources market. The Australian natural resources sector plays a vital role in the country’s economy through its position as the largest contributor to exports and a major contributor to the country’s gross domestic product, employment and government revenue. Australia has broad natural resources including metallurgical and thermal coal, conventional and coal seam gas, base metals, iron ore and precious metals such as gold. The growth of Australian commodity exports over the last decade has been largely driven by strong Asian demand for coal, iron ore and liquefied natural gas (LNG). The current activities of our Australian accommodations business are primarily related to supplying accommodations in support of metallurgical (met) coal mining in the Bowen Basin region of Queensland.
Volumes and prices of commodities have historically varied significantly and are difficult to predict. Mineral and commodity prices have fluctuated in recent years and may continue to fluctuate significantly in the future. Economic growth in emerging economies, such as China and India, with associated demand for mineral and natural resources such as coal, iron ore and LNG, has been an important driver of growth for our Australian business and, while having slowed recently, remains a key ingredient for our continued growth in Australia. This commodity demand is expected to underpin continued investment and long-term growth in the Australian natural resources market.
Products and Services
We believe our “Develop, Own, Operate” business model provides consistent service delivery to our customers and provides us a competitive advantage in our accommodations segment. Our integrated model includes site identification, permitting and development, facility design, construction, installation and full site maintenance. We provide a turnkey solution for our customers’ accommodation needs, allowing them to focus their efforts and resources on their core development and production businesses.
Our oil sands lodges support construction and operating personnel for maintenance and expansionary projects as well as ongoing operations associated with surface mining and in-situ oil sands projects generally under medium-term contracts (two to three years). We provide a full service hospitality function at our lodges including reservation management, check in and check out, catering, housekeeping and facilities management. Our lodge guests receive the amenity level of a full-service hotel plus three meals a day. Since mid-year 2006, we have installed over 11,000 rooms in our lodge properties supporting oil sands activities in northern Alberta. Our growth plan for this part of our business includes the expansion of these properties where we believe there is durable long-term demand. During 2013, we added 512 rooms (net of retirements) to our major Canadian oil sands lodges by expanding our Beaver River and Conklin Lodges and by opening Anzac Lodge, which was partially offset by a temporary reduction at Athabasca Lodge, as older rooms were removed to facilitate an expansion in the first quarter of 2014. Our Wapasu Creek Lodge is equivalent in size to the largest hotels in North America. In early 2014, the Company also announced the commencement of construction on a new oil sands lodge, McClelland Lake Lodge.
Our Australian accommodations business operates ten villages with over 9,200 rooms currently, 7,506 rooms of which service the Bowen Basin region of Queensland, one of the premier metallurgical coal basins in the world. We provide accommodations services on a day rate basis to mining and related service companies (including construction contractors) under medium-term contracts (three to five years) with minimum nightly room commitments. Our Australian accommodations villages are strategically located in proximity to long-lived, low-cost mines operated by large mining companies. During 2013, we added 644 rooms (net of retirements) to our Australian accommodations business by expanding existing villages and by constructing and opening one new village, Boggabri Village, to serve the Gunnedah Basin.
More than three-fourths of our accommodations revenue is generated by our large-scale lodge and village facilities. Total rooms deployed at our major Canadian oil sands lodges and Australian villages were as follows:
In addition to our large-scale lodge and village facilities, we offer a broad range of semi-permanent and mobile options to house workers in remote regions. Our fleet of temporary camps is designed to be deployed on short notice and can be relocated as a project site moves. Our camps range in size from a 25-person drilling camp to an 800-person camp supporting varied operations, including pipeline construction, Steam Assisted Gravity Drainage (SAGD) drilling operations and large shale oil projects.
As part of our integrated business model, we utilize a flexible manufacturing strategy that combines internal manufacturing capabilities and outsourced manufacturing partners to allow us to respond quickly to changing customer needs and timing. We own two accommodations manufacturing plants near Edmonton, Alberta, Canada, along with manufacturing facilities in Johnstown, Colorado and Belle Chasse, Louisiana. Additionally, we lease a manufacturing plant in Ormeau, Queensland, Australia. Each of our facilities specializes in the design, engineering, production, transportation and installation of a variety of portable modular buildings, predominately for our own use. We manufacture accommodations facilities to suit the climate, terrain and population of a specific project site.
To a significant extent, the Company's recent capital expenditures have focused on opportunities in the oil sands region in northern Alberta and, beginning in 2011, in our Australian accommodations business. Since the beginning of 2005, we have spent $1.3 billion, or 53%, of our total consolidated capital expenditures on our Canadian and Australian accommodations businesses.
Regions of Operations
Our accommodations business is focused primarily in northern Alberta, Canada and Queensland, Australia, but also operates in Western Australia, New South Wales, the U.S. Rocky Mountain corridor, the Bakken Shale region (Montana, North Dakota and Saskatchewan, Canada), the Fayetteville Shale region of Arkansas, the Eagle Ford Shale region of Texas, the Permian Basin of Texas and offshore locations in the Gulf of Mexico. In the past, we have also served companies operating in international markets including the Middle East, Europe, Asia and South America.
Customers and Competitors
Our customers primarily operate in oil sands mining and development, drilling, exploration and extraction of oil and natural gas and coal and other extractive industries. To a lesser extent, we also support other activities, including pipeline construction, forestry, humanitarian aid and disaster relief, and support for military operations. Our largest customers in 2013 were Imperial Oil Limited (a company controlled by ExxonMobil Corporation) and Fluor Canada Ltd in Canada and BM Alliance Coal Operations Pty Ltd (an alliance between BHP Billiton and Mitsubishi) in Australia.
Our primary competitors in North America include Aramark Corporation, Compass Group, ATCO Structures & Logistics Ltd., Black Diamond Group Limited, Horizon North Logistics Inc., and Clean Harbors, Inc. Our primary competitors in Australia include Ausco Modular (a subsidiary of Algeco Scotsman), Fleetwood Corporation, Aramark Corporation, Sodexo and Compass Group PLC.
Historically, many customers have invested in their own accommodations. Management estimates that our existing and potential customers own approximately 50% of the rooms available in the Canadian oil sands and 60% of the rooms in the Australian coal mining regions. We believe this represents a growth opportunity for us. We believe customers will increasingly outsource accommodations to more efficiently deploy capital for core resource development operations.
Offshore Products
Overview
During the year ended December 31, 2013, we generated approximately 33% of our revenue and 27% of our operating income, before corporate charges, from our offshore products segment. Through this segment, we design and manufacture a number of cost-effective, technologically advanced products for the offshore energy industry. In addition, we supply other lower margin products and services such as fabrication and inspection services. Our products and services are used primarily in deepwater producing regions and include flex-element technology, advanced connector systems, high-pressure riser systems, compact valves, deepwater mooring systems, cranes, subsea pipeline products, blow-out preventer stack integration, specialty welding services, offshore installation services and repair services. We have facilities that support our offshore products segment in Arlington, Houston and Lampasas, Texas; Houma, Louisiana; Oklahoma City and Tulsa, Oklahoma; Scotland; Brazil; England; Singapore, Thailand, Vietnam and India.
Offshore Products Market
The market for our offshore products and services depends primarily upon development of infrastructure for offshore production activities, drilling rig refurbishments and upgrades as well as new rig and vessel construction. Demand for oil and natural gas and related drilling and production in offshore areas throughout the world, particularly in deeper water, drive spending for these activities.
Products and Services
Celebrating over 70 years of operations in 2013, our offshore products segment provides a broad range of products and services for use in offshore drilling and development activities. To a lesser extent, this segment also provides onshore oil and natural gas, defense and general industrial products and services. Our offshore products segment is dependent in part on the industry's continuing innovation and creative applications of existing technologies.
Offshore Development and Drilling Activities. We design, manufacture, fabricate, inspect, assemble, repair, test and market subsea equipment and offshore vessel and rig equipment. Our products are components of equipment used for the drilling and production of oil and natural gas wells on offshore fixed platforms and mobile production units, including floating platforms, such as tension leg platforms, floating production, storage and offloading (FPSO) vessels, Spars, and on other marine vessels, floating rigs and jack-up rigs. Our products and services include:
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flexible bearings and advanced connection systems;
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casing and conductor connections and pipe;
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subsea pipeline products;
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compact ball valves, manifold system components and diverter valves;
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marine winches, mooring systems, cranes and other heavy-lift rig equipment;
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production, workover, completion and drilling riser systems and their related repair services;
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blowout preventer (BOP) stack assembly, integration, testing and repair services; and
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other products and services.
Flexible Bearings and Advanced Connection Systems. We are a significant supplier of flexible bearings, or FlexJoint®, to the offshore oil and gas industry as well as weld-on connectors and fittings that join lengths of large diameter conductor or casing used in offshore drilling and production operations. A FlexJoint® is a flexible bearing that permits the controlled movement of riser or tension leg platform tethers under high tension and pressure. A FlexJoint® or our flex element at the top, bottom and, in some cases, middle of a deepwater riser reduces the stress and tension on the riser compensating for the pitch and rotational forces on the riser as the production facility or drilling rig moves with ocean forces. They are used on drilling, production and export risers and are used increasingly as offshore production moves to deeper water areas. Drilling riser systems provide the vertical conduit between the floating drilling vessel and the subsea wellhead. Through the drilling riser, equipment is guided into the well and drilling fluids are returned to the surface. Production riser systems provide the vertical conduit for the hydrocarbons from the subsea wellhead to the floating production platform. Oil and natural gas flows to the surface for processing through the production riser. Export risers provide the vertical conduit from the floating production platform to the subsea export pipelines. Our FlexJoint® bearings are a critical element in the construction and operation of production and export risers on floating production systems in deepwater.
Floating production systems, including tension leg platforms, Spars and FPSO facilities, are a significant means of producing oil and natural gas, particularly in deepwater environments. We provide many important products for the construction of these facilities. A tension leg platform (TLP) is a floating platform that is moored by vertical pipes, or tethers, attached to both the platform and the sea floor. Our FlexJoint® tether bearings are used at the top and bottom connections of each of the tethers, and our Merlin™ connectors are used to efficiently assemble the tethers during offshore installation. An FPSO is a floating vessel, typically ship shaped, used to produce, and process oil and natural gas from subsea wells. A Spar is a floating vertical cylindrical structure which is approximately six to seven times longer than its diameter and is anchored in place. Our FlexJoint® bearings are also used to attach the steel catenary risers to an FPSO, tension leg platform or Spar, and for use on import or export risers.
Casing and Conductor Connections and Pipe. Our advanced connection systems provide connectors used in various drilling and production applications offshore. These connectors are welded onto pipe to provide more efficient joint to joint connections with enhanced tensile and burst capabilities that exceed those of connections that are cut into plain end pipe. Our connectors are reusable and pliable and in some cases provide metal-to-metal seals. We offer a suite of connectors offering differing specifications depending on the application. Our Merlin™ connectors are our premier connectors combining superior static strength and fatigue life with fast, non-rotational make-up and a slim profile. Merlin™ connectors have been used in sizes up to 60 inches (outside diameter) for applications including open-hole and tie-back casing, offshore conductor casing, pipeline risers and TLP tendons (which moor the TLP to the sea floor).
These flexible bearings and advanced connector systems are primarily manufactured through our Arlington, Texas, U.K. and Singapore locations.
Subsea Pipeline Products. We design and manufacture a variety of equipment used in the construction, maintenance, expansion and repair of offshore oil and natural gas pipelines. New construction equipment includes:
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pipeline end manifolds and pipeline end terminals;
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deep and shallow water pipeline connectors;
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midline tie-in sleds;
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forged steel Y-shaped connectors for joining two pipelines into one;
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pressure-balanced safety joints for protecting pipelines and related equipment from anchor snags or a shifting sea-bottom;
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electrical isolation joints; and
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hot tap clamps that allow new pipelines to be joined into existing lines without interrupting the flow of petroleum product.
We provide diverless connection systems for subsea flowlines and pipelines. Our HydroTech® collet connectors provide a high-integrity, proprietary metal-to-metal sealing system for the final hook-up of deep offshore pipelines and production systems. They also are used in diverless pipeline repair systems and in future pipeline tie-in systems. Our lateral tie-in sled, which is installed with the original pipeline, allows a subsea tie-in to be made quickly and efficiently using proven HydroTech® connectors without costly offshore equipment mobilization and without shutting off product flow.
We provide pipeline repair hardware, including deepwater applications beyond the depth of diver intervention. Our products include:
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repair clamps used to seal leaks and restore the structural integrity of a pipeline;
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mechanical connectors used in repairing subsea pipelines without having to weld;
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misalignment and swivel ring flanges; and
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pipe recovery tools for recovering dropped or damaged pipelines.
Our subsea pipeline products are primarily designed and manufactured at three of our Houston, Texas manufacturing locations.
Compact Ball Valves, Manifold System Components and Diverter Valves. Our Piper division designs and manufactures compact high pressure valves and manifold system components for all environments of the oil and gas industry including onshore, offshore, drilling and subsea applications. Our valve and manifold bores are designed to closely match the inside diameter of the required pipe schedule for the system working pressure. The result is elimination of piping transition areas that minimize erosion and system friction pressure loss, resulting in a more efficient flow path. Our floating ball valve design with its large ball/seat interface has over 30 years of field service experience in upstream unprocessed produced liquids and gasses, assuring reliable service. Oil States Piper Valve Optimum Flow Technology is our way of helping end users maximize space, minimize weight and increase production. These products are designed and manufactured at our Oklahoma City, Oklahoma location.
Marine Winches, Mooring Systems, Cranes and other Heavy-Lift Rig Equipment. We design, engineer and manufacture marine winches, mooring systems, cranes and certain rig equipment. Our Skagit® winches are specifically designed for mooring floating and semi-submersible drilling rigs and positioning pipelay and derrick barges, anchor handling boats and jack-ups, while our Nautilus® marine cranes are used on production platforms throughout the world. We also design and fabricate rig equipment such as automatic pipe racking and blow-out preventer handling equipment. Our engineering teams, manufacturing capability and service technicians who install and service our products provide our customers with a broad range of equipment and services to support their operations. Aftermarket service and support of our installed base of equipment to our customers is also an important source of revenue to us. These products are designed at our Houma, Louisiana location and manufactured at our Houma, Louisiana; Navi Mumbai, India; and Rayong, Thailand locations.
Production, Workover, Completion and Drilling Riser Systems and their related repair services. Utilizing the expertise of our welding technology group, we have again extended the boundaries of our Merlin™ connector technology with the design and manufacture of multiple riser systems. The unique Merlin™ connection has proven to be a robust solution for even the most demanding high-pressure (up to 10,000 psi) riser systems used in high-fatigue, deepwater applications. Our riser systems are designed to meet a range of static and fatigue stresses on a par with those of our Tension Leg Elements (TLE) connectors. The connector can be welded or machined directly onto upset riser pipe and provide sufficient material to perform "re-cuts" after extended service. Our marine riser offers unmatched tension capabilities together with one of the fastest run times in the industry. Auxiliary riser system components and running tools can be provided along with full service inspection and repair of these riser systems by our facilities worldwide.
BOP Stack Assembly, Integration, Testing and Repair Services. While we do not manufacture BOP stack assemblies, we design and fabricate lifting and protection frames and offer system integration of blow-out preventer stacks and subsea production trees. We can provide complete turnkey and design fabrication services. We also design and manufacture a variety of custom subsea equipment, such as riser flotation tank systems, guide bases, running tools and manifolds. In addition, we also offer blow-out preventer and drilling riser testing and repair services. These assembly and testing services are offered through our Houston, Texas, U.K., Singapore and Brazil locations.
Other Products & Services. Our offshore products segment also produces a variety of products for use in applications other than in the offshore oil and gas industry. For example, we provide:
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elastomer consumable downhole products for onshore drilling and production;
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sound and vibration isolation equipment for the U.S. Navy submarine fleet;
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metal-elastomeric FlexJoint® bearings used in a variety of naval and marine applications; and
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drum-clutches and brakes for heavy-duty power transmission in the mining, paper, logging and marine industries.
Backlog. Backlog in our offshore products segment was $580 million at December 31, 2013, compared to $561 million at December 31, 2012 and $535 million at December 31, 2011. We expect approximately 90% of our backlog at December 31, 2013 to be recognized as revenue during 2014. Our offshore products backlog consists of firm customer purchase orders for which contractual commitments exist and delivery is scheduled. In some instances, these purchase orders are cancelable by the customer, subject to the payment of termination fees and/or the reimbursement of our costs incurred. However, backlog cancellations have not been significant in the past. Our backlog is an important indicator of future offshore products shipments and revenues; however, backlog as of any particular date may not be indicative of our actual operating results for any future period. We believe that the offshore construction and development business is characterized by lengthy projects and a long "lead-time" order cycle. The change in backlog levels from one period to the next does not necessarily evidence a long-term trend.
Regions of Operations
Our offshore products segment provides products and services to customers in the major offshore oil and natural gas producing regions of the world, including the Gulf of Mexico, West Africa, Azerbaijan, the North Sea, Brazil, Southeast Asia, India and Australia.
Customers and Competitors
We market our products and services to a broad customer base, including direct end users, engineering and design companies, prime contractors, and at times, our competitors through outsourcing arrangements. Our largest customers in 2013 were Saipem, Halliburton Company, and Heerema Marine Contractors. Our main competitors include Cameron International Corporation, National Oilwell Varco, Inc., GE Oil & Gas, Liebherr Cranes, Inc., FMC Technologies, Inc. and Dril-Quip, Inc.
Well Site Services
Overview
During the year ended December 31, 2013, we generated approximately 28% of our revenue and 26% of our operating income, before corporate charges, from our well site services segment. Our well site services segment includes a broad range of products and services that are used to drill for, establish and maintain the flow of oil and natural gas from a well throughout its lifecycle. In this segment, our operations include completion-focused equipment and services as well as land drilling services. We use our fleet of completion tools and drilling rigs to serve our customers at well sites and project development locations. Our products and services are used both in onshore and offshore applications throughout the drilling, completion and production phases of a well's life.
Well Site Services Market
Historically, demand for our completion services and drilling services has been predominately tied to the level of oil and natural gas exploration and production activity in the United States. The primary driver for this activity is the price of oil and natural gas. Activity levels have been, and we expect will continue to be, highly correlated with hydrocarbon commodity prices.
Services
Completion Services. Our completion services business, which is primarily marketed through the brand names Oil States Energy Services and Tempress, provides a wide range of services for use in the onshore and offshore oil and gas industry, including:
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wellhead isolation services;
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wireline and coiled tubing support services;
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frac valve and flowback services;
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well testing, including separators and line heaters;
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ball launching services;
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pipe recovery systems;
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thru-tubing milling and fishing services;
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hydraulic chokes and manifolds;
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blow out preventers;
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downhole extended-reach technology; and
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gravel pack operations on well bores.
Employees in our completion services business typically rig up and operate our equipment on the well site for our customers. Our completion services equipment is primarily used during the completion and production stages of a well. As of December 31, 2013, we provided completion services at approximately 53 distribution points throughout the United States, Canada, Mexico and Argentina. We continue to consolidate operations in areas where our product lines previously had separate facilities and have closed facilities in areas where operations are marginal in order to streamline operations and enhance our facilities to improve operational efficiency. We typically provide our services and equipment based on daily rates which vary depending on the type of equipment and the length of the job. Billings to our customers typically separate charges for our equipment from charges for our field technicians. We own patents or have patents pending covering some of our technology, particularly in our wellhead isolation equipment and downhole extended-reach technology product lines. Our customers in the completion services business include major, independent and private oil and gas companies and other large oilfield service companies. Our largest customers in 2013 were Anadarko Petroleum Corporation, Devon Energy Corporation and Chevron Corporation. Competition in the completion services business is widespread and includes many smaller companies, although we also compete with the larger oilfield service companies for certain products and services.
Drilling Services. Our drilling services business, which is marketed under the brand name Capstar Drilling, our wholly-owned subsidiary, is located in the United States and provides land drilling services for shallow to medium depth wells of up to 10,000 to 12,000 feet and, under more limited conditions, up to 15,000 feet. We serve two primary markets with our drilling services business: the Permian Basin in West Texas and the Rocky Mountain region. Drilling services are typically used during the exploration and development stages of a field. As of December 31, 2013, we had a total of thirty-four semi-automatic drilling rigs with hydraulic pipe handling booms and lift capacities ranging from 150,000 to 500,000 pounds, fifteen of which were fabricated and/or assembled in our Odessa, Texas facility during the last ten years with components purchased from specialty vendors. Twenty-four of these drilling rigs are based in the Permian Basin and ten are based in the Rocky Mountain region. Utilization of our drilling rigs decreased from an average of 88% in 2012 to an average of 75% in 2013. On December 31, 2013, twenty-nine of our rigs, or 85%, were working or under contract.
We market our drilling services directly to a diverse customer base, consisting of major, independent and private oil and gas companies. We contract on both a footage and a dayrate basis. Under a footage drilling contract, we assume responsibility for certain costs (such as bits and fuel) and assume more risk (such as time necessary to drill) than we would on a daywork contract. Depending on market conditions and availability of drilling rigs, we see changes in pricing, utilization and contract terms. Our largest customers in 2013 were Apache Corporation, Energen Resources Corporation and Crescent Point Energy Corporation. The land drilling business is highly fragmented, and our competition consists of a small number of larger companies and many smaller companies. Our Permian Basin drilling activities target primarily oil reservoirs while our Rocky Mountain drilling activities target oil, liquids-rich and natural gas reservoirs.
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Seasonality of Operations
Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada, Australia, the Rocky Mountain region and the Gulf of Mexico. A portion of our Canadian accommodations operations is conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. The spring thaw in these regions restricts operations in the second quarter of our fiscal year and adversely affects our operations and our ability to provide services. During the Australian rainy season between November and April, our accommodations operations in Queensland and the northern parts of Western Australia can be affected by cyclones, monsoons and resultant flooding. Severe winter weather conditions in the Rocky Mountain region can restrict access to work areas for our well site services and accommodations segment operations. Our operations in the Gulf of Mexico are also affected by weather patterns. Weather conditions in the Gulf Coast region generally result in higher drilling activity in the spring, summer and fall months with the lowest activity in the winter months. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. In addition, summer and fall drilling activity can be interrupted by hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast.
Employees
As of December 31, 2013, the Company employed 9,167 full-time employees on a consolidated basis, 42% of whom are in our accommodations segment, 29% of whom are in our well site services segment, 28% of whom are in our offshore products segment and 1% of whom are in our corporate headquarters. We were party to collective bargaining agreements covering approximately 2,400 employees located in Canada, Australia, the United Kingdom and Argentina as of December 31, 2013. We believe we have healthy labor relations with our employees.
Government Regulation
Our business is significantly affected by foreign and domestic laws and regulations at the federal, provincial, state and local levels relating to the oil, natural gas and mining industries, worker safety and environmental protection. To the extent that these laws and regulations impose more stringent requirements or increased costs or delays upon our customers in the performance of their operations, the resulting demand for our products and services by those customers may be adversely affected, which impact could be significant and long-lasting. Moreover, changes in these laws and regulations, including more restrictive standards and increased levels of enforcement, could significantly affect our business. We cannot predict changes in the level of enforcement of existing laws and regulations or how these laws and regulations may be interpreted or the effect changes in these laws and regulations may have on us or our future operations or earnings. We also are not able to predict the extent to which new laws and regulations will be adopted or whether such new laws and regulations may impose more stringent or costly restrictions on our operations.
We depend on the demand for our products and services from oil and natural gas exploration and production companies. This demand is affected by changing taxes, price controls and laws and regulations relating to the oil and natural gas industry generally, including those specifically directed to oilfield and offshore operations. The adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas in areas where we operate could also adversely affect our operations by limiting demand for our products and services. We cannot determine the extent to which our future operations and earnings may be affected by new legislation or regulations, amendments of existing laws or regulations, or changes in enforcement policies.
Our operations and the operations of our customers for whom we provide our products and services are subject to numerous stringent and comprehensive foreign, federal, provincial, state and local environmental laws and regulations governing the release or discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions to achieve and maintain compliance. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, modification or cessation of operations, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with existing environmental laws and regulations and we do not anticipate that future compliance with existing environmental laws and regulations will have a material adverse effect on our Consolidated Financial Statements. However, there can be no assurance that substantial costs for compliance or penalties for non-compliance with these existing requirements will not be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations and enforcement policies or more stringent enforcement of existing environmental laws and regulations, could result in additional costs or liabilities upon us or our customers that we cannot currently quantify.
For example, in Canada, in February 2012, the governments of Canada and Alberta released the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring that was to be phased in between 2012 and 2015. The costs of implementing this plan are to be funded by industry members, some of whom are our customers. This new monitoring regime is now in the process of being implemented and has increased the levels of monitoring in the Canadian oil sands and may increase costs for us and our customers. This could reduce natural resource extraction activity and, consequently, demand for our services.
Alberta is also in the process of establishing land-use frameworks which will apply to the various regions of Alberta. To date, only the Lower Athabasca Regional Plan has been completed and has the force of law. Several Alberta government initiatives are being implemented through this regional plan including enhancements to the reclamation security policy regarding mine site (including oil sands mines) reclamation, the environmental management framework for cumulative effects to air, surface water and ground water resulting from oil, oil sands and gas extraction activities, and Alberta's Wetland Policy, These initiatives and enhancements may increase costs for us or our clients or may curtail our or our client's future operations.
With regard to our operations in the United States, we generate wastes, including non-hazardous solid wastes and hazardous wastes, which are subject to the federal Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. With authority delegated from the United States Environmental Protection Agency, or “EPA,” most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development or exploration of oil or natural gas exploration and production, if properly handled, are exempt from regulation as hazardous waste under RCRA. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, it is possible that certain of these oil and natural gas exploration and production wastes now classified as non-hazardous could be re-classified as hazardous in the future. Any such re-classification of these currently exempt wastes to hazardous could subject our oil and natural gas exploration and production customers to more rigorous and costly operating and disposal requirements, which could reduce demand for the products and services we provide and result in a material adverse effect on our results of operations and financial position. In the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes.
Also in connection with our operations in the United States, the federal Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the "Superfund" law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that transported, disposed of, or arranged for the transport or disposal of the hazardous substances at the site where the release occurred. Under CERCLA, these persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently have operations in the United States on properties where activities involving the handling of hazardous substances or wastes have been conducted by previous owners or operators whose operations were not under our control. These properties may be subject to CERCLA, RCRA and analogous state laws. Under these laws and related regulations, we could be required to remove or remediate previously discarded hazardous substances and wastes or property contamination that was caused by these third parties.
In the course of our operations in the United States, some of our equipment may be exposed to naturally occurring radiation associated with oil and natural gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or "NORM." NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the domestic properties upon which we operate have been used for oil and natural gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.
The Federal Water Pollution Control Act, as amended, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. Many of the domestic properties upon which we operate require permits for discharges of wastewater and/or storm water, and we have developed a system for securing and maintaining these permits, where required. In addition, the Oil Pollution Act of 1990, as amended, or OPA, imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party under OPA includes the owner or operator of an onshore facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The Federal Water Pollution Control Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the OPA, require the development and implementation of spill prevention and response plans and impose potential liability for the remedial costs and associated damages arising out of any unauthorized discharges.
A certain portion of our completion services business supports other contractors actually performing hydraulic fracturing to enhance the production of natural gas from formations with low permeability, such as shales. Due to concerns raised concerning potential impacts of hydraulic fracturing and fracturing fluids disposal on drinking water and groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated in the United States to render permitting, public disclosure and construction and operational compliance requirements for our oil and natural gas exploration and production customers more stringent for hydraulic fracturing. While hydraulic fracturing typically is regulated in the United States by state oil and natural gas commissions, there have been developments indicating that more federal regulatory involvement may occur. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or SDWA, over certain hydraulic fracturing activities involving the use of diesel fuels and has issued revised permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In addition, from time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing in the United States under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular. In the event that new or more stringent federal, state or local legal restrictions relating to use of the hydraulic fracturing process in the United States are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with requirements relating to permitting, construction, financial assurance, monitoring, recordkeeping, and/or plugging and abandonment, as well as could experience delays or curtailment in the pursuit of production or development activities, any or all of which could reduce demand for our completion services business.
In addition, certain governmental reviews in the United States have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review in 2014. Moreover, the EPA is planning to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. Also, in May 2013, the federal Bureau of Land Management, or BLM, published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These ongoing or any future studies, depending on the results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, which events could delay or curtail production of oil and natural gas by exploration and production operations, some of which are performed by our customers, and thus reduce demand for our North American completion products and services and accommodations services.
In response to an April 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the Macondo well operated by a third party in ultra-deepwater in the Gulf of Mexico, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2013, the federal government, acting through the U.S. Department of the Interior (DOI) and its implementing agencies that have since evolved into the present day Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE), has issued various rules, Notices to Lessees and Operators (NTLs) and temporary drilling moratoria that impose or result in added environmental and safety measures upon exploration and production operators in the Gulf of Mexico. These new regulatory requirements include the following:
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The Environmental NTL, which imposes more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;
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The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes and also requires certifications of compliance from senior corporate officers;
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The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and
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The Workplace Safety Rule, which requires operators to employ a comprehensive safety and environmental management system (SEMS) to reduce human and organizational errors as root causes of work-related accidents and offshore spills, which rule was subsequently amended as published on April 5, 2013 (sometimes referred to as the “SEMS II” rule) to require operators to, among other things, establish procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.
These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements also increase the cost of preparing permit applications and will increase the cost of each new well, particularly for wells drilled in deeper waters on the Outer Continental Shelf. We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Moreover, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere where we conduct operations, the United States or other countries could elect to again issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our volume of business as well as our financial position, results of operations and liquidity.
Some of our operations as well as those of our oil and natural gas customers in the U.S. also result in emissions of regulated air pollutants. The federal Clean Air Act, as amended, or CAA, and analogous state laws require permits for facilities in the United States that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. Failure to obtain a permit or to comply with permit requirements could result in the imposition of substantial administrative, civil and even criminal penalties. In addition, amendment of the CAA or comparable state laws may cause our oil and natural gas exploration and production customers to incur capital expenditures for installation of air pollution control equipment and to encounter construction delays while applying for and receiving new or amended permits, which could have an adverse effect on demand for our products and services. For example, in 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels, beginning as early as October 15, 2012.
Past scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, or GHG, and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere and other climatic changes. In 2010, Canada affirmed its desire to be associated with the Copenhagen Accord that was negotiated in December 2009 as part of the international meetings on climate change regulation in Copenhagen. The Copenhagen Accord, which is not legally binding, allows countries to commit to specific efforts to reduce GHG emissions, although how and when the commitments may be converted into binding emission reduction obligations is currently uncertain. Pursuant to the Copenhagen Accord process, Canada has indicated an economy-wide GHG emissions target that equates to a 17 per cent reduction from 2005 levels by 2020, and the Canadian federal government has also indicated an objective of reducing overall Canadian GHG emissions by 60% to 70% from 2006 levels by 2050. One measure the government of Canada has undertaken in pursuit of this objective is to regulate greenhouse gas emissions on a sector by sector basis. The oil and gas sector has yet to be subject to specific emission targets but when and if such specific emission targets are established, the costs of complying with such emission targets may adversely affect our and our clients' levels of activity in the energy sector and our respective financial results.
Additionally, GHG regulation can take place at the provincial and municipal level. For example, Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specified gas emissions, relative to gross domestic product, to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulation, the Specified Gas Emitters Regulation, effective July 1, 2007, requires mandatory emissions reductions through the use of emissions intensity targets, and a company can meet the applicable emissions limits by making emissions intensity improvements at facilities, offsetting GHG emissions by purchasing offset credits or emission performance credits in the open market, or acquiring “fund credits” by making payments of $15 per ton of GHG emissions to the Alberta Climate Change and Management Fund. The Specified Gas Reporting Regulation imposes GHG emissions reporting requirements if a company has GHG emissions of 100,000 tons or more of carbon dioxide equivalent from a facility in a calendar year. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations in permits and under other environmental regulations. The Canadian federal government currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. The direct and indirect costs of overlapping regulations may adversely affect our operations and financial results as well as those of our customers with whom we conduct business.
The EPA determined in December 2009 that emissions of GHGs present an endangerment to public health and the environment and, based on those findings, adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay or ability to obtain air permits for new or modified sources that are major sources of GHG emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including, among others, offshore and onshore oil and natural gas production facilities, on an annual basis.
While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us or our customers to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas, which could reduce the demand for our products and services. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
Our operations outside of the United States are potentially subject to similar foreign governmental controls relating to protection of the environment. We believe that, to date, our operations outside of the United States have been in substantial compliance with existing requirements of these foreign governmental bodies and that such compliance has not had a material adverse effect on our operations. However, this trend of compliance with existing requirements may not continue in the future or the cost of such compliance may become material. For instance, any future restrictions on emissions of GHGs that are imposed in foreign countries in which we operate, could adversely affect demand for our services.
Our Australian accommodations business is regulated by general statutory environmental controls at both the state and federal level which may result in land use approval and compliance risk. These controls include: land use and urban design controls; the regulation of hard and liquid waste, including the requirement for tradewaste and/or wastewater permits or licenses; the regulation of water, noise, heat, and atmospheric gases emissions; the regulation of the production, transport and storage of dangerous and hazardous materials (including asbestos); and the regulation of pollution and site contamination. Some specified activities, for example, sewage treatment works, may require regulation at a state level by way of environmental protection licenses which also impose monitoring and reporting obligations on the holder. There is an increasing emphasis from state and federal regulators on sustainability and energy efficiency in business operations. Federal requirements are now in place for the mandatory disclosure of energy performance under building rating schemes. These schemes require the tracking of specific environmental performance factors. Carbon reporting requirements currently exist for corporations which meet a reporting threshold for greenhouse gases or energy use or production for a reporting (financial) year under national legislation. The Australian Commonwealth Government’s carbon pricing mechanism (“CPM”) commenced on July 1, 2012. Under the CPM, entities that are responsible for facilities that meet specified emissions thresholds will be required to purchase and surrender permits representing their carbon emissions. The CPM is intended to operate as a carbon trading scheme, commencing with a three year fixed price period, followed by a flexible price cap-and-trade emissions trading scheme. The recently elected Australian federal government introduced a bill to Parliament in late 2013 to repeal the CPM legislation, but does not yet have sufficient support in the upper house for this bill to be passed. Although our Australian accommodations facilities are currently below the emissions thresholds specified by the CPM and are, thus, not affected by the CPM, this could change in the future and the result could have an adverse effect on our Australian operations and financial results.
The federal Endangered Species Act, as amended, or the ESA, restricts activities in the United States that may affect endangered or threatened species or their habitats. If endangered species are located in areas of the United States where our oil and natural gas exploration and production customers operate, such operations could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of numerous species as endangered or threatened under the ESA before the end of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas of the United States where our customers’ oil and natural gas exploration and production operations are conducted could cause them to incur increased costs arising from species protection measures or could result in limitations on their exploration and production activities, which could have an adverse impact on demand for our products and services.
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.
In addition, some of our employees who perform services on offshore platforms and vessels are covered by the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws operate to make the liability limits established under states' workers' compensation laws inapplicable to these employees and permit them or their representatives generally to pursue actions against us for damages or job-related injuries with no limitations on our potential liability.
Disclosure under Section 13® of the Exchange Act
The Iran Threat Reduction and Syria Human Rights Act of 2012, signed into law by President Obama on August 10, 2012, added a new Section 13(r) to the Exchange Act, which requires us to disclose whether the Company or any of its affiliates has engaged in certain Iran-related activities during the reporting period. During the year ended December 31, 2013, our wholly-owned Singaporean subsidiary, Oil States (Asia) Ptd Ltd (“Oil States (Asia)”), made two shipments and received three payments in connection with a prior transaction for the sale of riser pipe and associated material to a United Arab Emirates company, for ultimate use in the South Pars Gas Field. This field is controlled and mandated by Pars Oil & Gas Co, an entity designated in December 2010 by the Office of Foreign Assets Control (OFAC) as being owned or controlled by the Government of Iran. The transaction that is the subject of this disclosure commenced at a time when Oil States (Asia) was not subject to the Iranian Transactions and Sanctions Regulations, 31 C.F.R. Part 560 (ITSR). The total value of Oil States (Asia)’s transaction was approximately $4.2 million, for which it received an estimated net profit of $0.4 million. The three payments that Oil States (Asia) received during the reporting period totaled approximately $4.23 million. Except for the receipt of two final payments from its customer during April 2013, Oil States (Asia) completed the transaction in accordance with and during the validity period of the wind-down general license of ITSR Section 560.555, which expired on March 8, 2013. Oil States (Asia) has wound down its Iran-related business, and voluntary self-disclosures have been submitted to OFAC and the State Department about this transaction.
Item 1A.
Item 1A. Risk Factors
The risks described in this Annual Report on Form 10-K are not the only risks we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.
Our business is subject to a number of economic risks.
Financial markets worldwide experienced extreme disruption in the past five years, including, among other things, extreme volatility in securities prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others. Governments took unprecedented actions intended to address extreme market conditions such as severely restricted credit and declines in real estate values. Such economic events can recur and can potentially affect businesses such as ours in a number of ways. Tightening of credit in financial markets and a slowing economy adversely affects the ability of our customers and suppliers to obtain financing for significant operations, can result in lower demand for our products and services, and could result in a decrease in or cancellation of orders included in our backlog and adversely affect the collectability of our receivables. Additionally, tightening of credit in financial markets coupled with a slowing economy could negatively impact our cost of capital and ability to grow. Our business is also adversely affected when energy demand declines as a result of lower overall economic activity. Typically, lower energy demand negatively affects commodity prices, which reduces the earnings and cash flow of our E&P and mining customers, reducing their spending and demand for our products and services. These conditions could have an adverse effect on our operating results and our ability to recover our assets at their stated values. Likewise, our suppliers may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations. Strengthening of the rate of exchange for the U.S. Dollar against certain major currencies, such as the Euro, the British Pound and the Canadian and Australian Dollar, could also adversely affect our financial results.
Decreased customer expenditure levels will adversely affect our results of operations.
Demand for our products and services is sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and gas and mining companies. If our customers' expenditures decline, our business will suffer. The oil and gas and mining industries’ willingness to explore, develop and produce depends largely upon the availability of attractive resource prospects and the prevailing view of future commodity prices. Prices for oil, coal, natural gas, and other minerals are subject to large fluctuations in response to changes in the supply of and demand for these commodities, market uncertainty, and a variety of other factors that are beyond our control. Accordingly, a sudden or long-term decline in commodity pricing would have material adverse effects on our results of operations. Any prolonged reduction in commodity prices will depress levels of exploration, development, and production activity, often reflected as reductions in rig counts, employees or coal production. Additionally, significant new regulatory requirements, including climate change legislation, could have an impact on the demand for and the cost of producing oil, coal and natural gas. Many factors affect the supply of and demand for oil, coal, natural gas and other minerals and, therefore, influence product prices, including:
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the level of drilling activity;
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the level of production;
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the levels of oil and natural gas inventories;
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depletion rates;
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worldwide demand for oil and natural gas;
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the expected cost of finding, developing and producing new reserves;
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delays in major offshore and onshore oil and natural gas field development timetables;
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the level of activity and developments in the Canadian oil sands;
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the level of activity and development in the Australian mining sector;
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the level of demand, particularly from China, for coal and other natural resources produced in Australia;
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the availability of attractive oil and natural gas field prospects, which may be affected by governmental actions or environmental activists which may restrict development;
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the availability of transportation infrastructure for oil, natural gas and coal, refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
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global weather conditions and natural disasters;
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worldwide economic activity including growth in developing countries, such as China and India;
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national government political requirements, including the ability of the Organization of Petroleum Exporting Companies (OPEC) to set and maintain production levels and prices for oil and government policies which could nationalize or expropriate oil and natural gas exploration, production, refining or transportation assets;
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the level of oil and gas production by non-OPEC countries;
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the impact of armed hostilities involving one or more oil producing nations;
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rapid technological change and the timing and extent of development of energy sources, including LNG or other alternative fuels;
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environmental regulation; and
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domestic and foreign tax policies.
Due to the cyclical nature of the natural resources industry, our business may be adversely affected by extended periods of low oil, coal or natural gas prices or unsuccessful exploration results which may decrease our customers’ spending and therefore our results.
Commodity prices have been and are expected to remain volatile. This volatility causes oil and gas and mining companies and drilling contractors to change their strategies and expenditure levels. Prices of oil, coal and natural gas can be influenced by many factors, including reduced demand due to lower global economic growth, surplus inventory, improved technology such as the hydraulic fracturing of horizontally drilled wells in shale discoveries, access to potentially productive regions and availability of required infrastructure to deliver production to the marketplace. In particular, global demand for both oil and metallurgical coal is, at least partially, dependent on the growth of the Chinese economy. With growth in the Chinese economy, China’s demand for oil and steel increases driving demand for oil and metallurgical coal. Should GDP growth in China slow, demand for these commodities and, correspondingly, our accommodations would fall which would negatively impact our financial results.
A significant portion of our business segments support projects that are capital intensive and require several years to generate first production. The economic analyses conducted by exploration and production companies in deepwater, oil sands, Australian mining and LNG investment areas have historically assumed a relatively conservative longer-term price outlook for production from such projects to determine economic viability. Perceptions of lower longer-term commodity prices by these companies can cause our customers to reduce or defer major expenditures given the long-term nature of many large scale development projects which could adversely affect revenues and profitability. In Canada, Western Canadian Select (WCS) crude is the benchmark price for our oil sands accommodations’ customers. Historically, WCS has traded at a discount to West Texas Intermediate (WTI) crude. Should the price of WTI decline or the WCS discount to WTI widen further, our oil sands customers may delay additional investments or reduce their spending in the oil sands region. Similarly, the volumes and prices of the mineral products of our customers, including coal and gold, have historically varied significantly and are difficult to predict. The demand for, and price of, these minerals and commodities is highly dependent on a variety of factors, including international supply and demand, the price and availability of alternative fuels, actions taken by governments and global economic and political developments. Mineral and commodity prices have fluctuated in recent years and may continue to fluctuate significantly in the future. We expect that a material decline in mineral and commodity prices could result in a decrease in the activity of our customers with the possibility that this would materially adversely affect us. No assurance can be given regarding future volumes and/or prices relating to the activities of our customers. We have experienced in the past, and expect to experience in the future, significant fluctuations in operating results based on these changes.
Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells, which could adversely affect our services.
Hydraulic fracturing is an important and commonly used process for the completion of oil and natural gas wells in formations with low permeabilities, such as shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate production. Due to concerns raised regarding potential impacts of hydraulic fracturing and fracturing fluids disposal on drinking water and groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated in the United States to render permitting, public disclosure and construction and operational compliance requirements for our oil and natural gas exploration and production customers more stringent for hydraulic fracturing. While hydraulic fracturing typically is regulated in the United States by state oil and natural gas commissions, there have been developments indicating that more federal regulatory involvement may occur. For example, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act, or SDWA, over certain hydraulic fracturing activities involving the use of diesel fuels and issued revised permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. In addition, from time to time, Congress has considered legislation to provide for federal regulation of hydraulic fracturing in the United States under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular.
In addition, certain governmental reviews in the United States have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and a draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review in 2014. Moreover, the EPA is planning to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities in 2014. Also, in May 2013, BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. These ongoing, proposed or any future studies, depending on the results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, which events could delay or curtail production of oil and natural gas by exploration and production operators, some of which are performed by our customers, and thus reduce demand for our North American completion products and services. In the event that new or more stringent federal, state or local legal restrictions relating to use of the hydraulic fracturing process in the United States are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with requirements relating to permitting, construction, financial assurance, monitoring, recordkeeping, and/or plugging and abandonment, as well as could experience delays or curtailment in the pursuit of production or development activities, any or all of which could reduce demand for the products and services of each of our business segments.
Our clients in the accommodations business are exposed to a number of unique operating risks which could also adversely affect us.
We could be materially adversely affected by disruptions to our accommodations clients’ operations caused by any one of or all of the following singularly or in combination:
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domestic and international pricing and demand for the natural resource being produced at a given project (or proposed project);
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unexpected problems, higher costs and delays during the development, construction and project start-up which may delay the commencement of production;
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unforeseen and adverse climatic, geological, geotechnical, seismic and mining conditions;
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lack of availability of sufficient water or power to maintain their operations;
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water or food quality or safety issues;
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lack of availability or failure of the required infrastructure necessary to maintain or to expand their operations;
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the breakdown or shortage of equipment and labor necessary to maintain their operations;
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risks associated with the natural resources industry being subject to various regulatory approvals. Such risks may include a Government Agency failing to grant an approval or failing to renew an existing approval, or the approval or renewal not being provided by the Government Agency in a timely manner or the Government Agency granting or renewing an approval subject to materially onerous conditions;
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risks to land titles, mining titles and use thereof as a result of native title claims;
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claims by persons living in close proximity to mining projects, which may have an impact on the consents granted;
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interruptions to the operations of our customers caused by industrial accidents or disputes; and
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delays in or failure to commission new infrastructure in timeframes so as not to disrupt customer operations.
Our accommodations business is exposed to a number of general risks that could materially adversely affect our assets and liabilities, financial position, profits, prospects and share price.
Examples of these general risks which may impact our performance include:
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abnormal stoppages in the production or delivery of the products of our clients due to factors such as industrial disruption, infrastructure failure, war, political or civil unrest;
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cost overruns in the provision of new rooms or in other associated or related capital expenditure;
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higher than budgeted costs associated with the provision of accommodations services;
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our clients not renewing their contracts, renewing them on less favorable terms, or other loss of clients;
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our inability to properly treat and dispose of wastewater at our facilities;
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failure of our clients to meet their obligations under their contracts;
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extreme weather conditions adversely affecting our operations or the operations of our clients; and
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a major disaster at one or more of our large accommodations facilities involving fire, communicable diseases, criminal acts or other events causing significant reputational damage.
Development of permanent infrastructure in the Canadian oil sands region, regions of Australia or various U.S. locations where we locate our accommodations assets could negatively impact our accommodations business.
Our accommodations business specializes in providing housing and personnel logistics for work forces in remote areas which often lack the infrastructure typically available in nearby towns and cities. If permanent towns, cities and municipal infrastructure develop in the oil sands region of northern Alberta, Canada, or regions of Australia where we locate accommodations villages, then demand for our accommodations could decrease as customer employees move to the region and choose to utilize permanent housing and food services.
Construction risks exist in our accommodations business which may adversely affect our results of operations.
There are a number of general risks that might impinge on companies involved in the development, construction, manufacture and installation of facilities as a prerequisite to the management of those assets in an operational sense. We might be exposed to these risks from time to time by relying on these corporations and/or other third parties which could include any and/or all of the following:
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the construction activities of our accommodations business are partially dependent on the supply of appropriate construction and development opportunities;
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development approvals, slow decision making by counterparties, complex construction specifications, changes to design briefs, legal issues and other documentation changes may give rise to delays in completion, loss of revenue and cost over-runs which may, in turn, result in termination of accommodation supply contracts;
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other time delays that may arise in relation to construction and development include supply of labor, scarcity of construction materials, lower than expected productivity levels, inclement weather conditions, land contamination, cultural heritage claims, difficult site access or industrial relations issues;
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objections aired by aboriginal or community interests, environment and/or neighborhood groups which may cause delays in the granting or approvals and/or the overall progress of a project;
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where we assume design responsibility, there is a risk that design problems or defects may result in rectification and/or costs or liabilities which we cannot readily recover; and
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there is a risk that we may fail to fulfill our statutory and contractual obligations in relation to the quality of our materials and workmanship, including warranties and defect liability obligations.
Our financial results could be adversely impacted by changes in the regulation of offshore oil and natural gas exploration and development activity in the U.S. Gulf of Mexico.
In response to an April 2010 fire and explosion aboard the Deepwater Horizon drilling rig and resulting oil spill from the Macondo well operated by a third party in ultra-deepwater in the Gulf of Mexico, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. Beginning in 2010 and continuing through 2013, the federal government, acting through the DOI and its implementing agencies, BOEM and BSEE, has issued various rules, Notices to Lessees or Operators, or NTLs, and temporary drilling moratoria that impose or result in added environmental and safety measures upon exploration and production operators in the Gulf of Mexico. These new regulatory requirements include the following:
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The Environmental NTL, which imposes more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements;
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The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes and also requires certifications of compliance from senior corporate officers;
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The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams; and
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The Workplace Safety Rule, which requires operators to employ a comprehensive SEMS to reduce human and organizational errors as root causes of work-related accidents and offshore spills, which rule was subsequently amended as published on April 5, 2013 (sometimes referred to as the “SEMS II” rule) to require operators to, among other things, establish procedures providing all personnel with “stop work” authority, develop protocols as to whom at the facility has the ultimate operational safety and decision-making authority, and establish an independent auditing regimen whereby facility audits are conducted by a service provider accredited by BSEE that is unaffiliated with the operator.
These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits. These new requirements also increase the cost of preparing permit applications and will increase the cost of each new well, particularly for wells drilled in deeper waters on the Outer Continental Shelf. We could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Moreover, if similar oil spill incidents were to occur in the future in the Gulf of Mexico or elsewhere in areas of the United States or foreign locations where we conduct operations, the United States or other countries could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our volume of business as well as our financial position, results of operations and liquidity.
Due to the significant concentration of our accommodations business in the oil sands region of Alberta, Canada and in the Bowen Basin coal region of Queensland, Australia, adverse events in these areas could negatively impact our accommodations business.
Because of the concentration of our accommodations business in the oil sands region of Alberta, Canada and in the coal producing region of Queensland, Australia, two relatively small geographic areas, we have increased exposure to political, regulatory, environmental, labor, climate or natural disaster events or developments that could negatively impact our operations and financial results. For example, in 2011, major flooding caused by seasonal rain and a cyclone impacted areas near our Australian villages. Also in 2011, forest fires in northern Alberta impacted areas near our Canadian lodges. Due to our geographic concentration, any adverse events or developments in our operating areas may disproportionately affect our financial results.
The cyclical nature of our business and a severe prolonged downturn could negatively affect the value of our goodwill.
As of December 31, 2013, goodwill represented approximately 12% of our total assets. We have recorded goodwill because we paid more for some of our businesses that we acquired than the fair market value of the tangible and separately measurable intangible net assets of those businesses. Current accounting standards require a periodic review of goodwill for each of our reporting units (completion services, drilling services, accommodations and offshore products) for impairment in value and a non-cash charge against earnings with a corresponding decrease in stockholders' equity if circumstances, some of which are beyond our control, indicate that the carrying amount will not be recoverable. It is possible that we could recognize additional goodwill impairment losses in the future if, among other factors:
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global economic conditions deteriorate;
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the outlook for future profits and cash flow for any of our reporting units deteriorate as the result of many possible factors, including, but not limited to, increased or unanticipated competition, technology becoming obsolete, further reductions in customer capital spending plans, loss of key personnel, adverse legal or regulatory judgment(s), future operating losses at a reporting unit, downward forecast revisions, or restructuring plans;
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costs of equity or debt capital increase; or
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valuations for comparable public companies or comparable acquisition valuations deteriorate.
We do business in international jurisdictions whose political and regulatory environments and compliance regimes differ from those in the United States.
A portion of our revenue is attributable to operations in foreign countries. These activities accounted for approximately 50% (7% excluding Canada, the UK and Australia) of our consolidated revenue in the year ended December 31, 2013. Risks associated with our operations in foreign areas include, but are not limited to:
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expropriation, confiscation or nationalization of assets;
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renegotiation or nullification of existing contracts;
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foreign exchange limitations;
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foreign currency fluctuations;
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foreign taxation;
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the inability to repatriate earnings or capital in a tax efficient manner;
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changing political conditions;
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changing foreign and domestic monetary policies;
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social, political, military and economic situations in foreign areas where we do business and the possibilities of war, other armed conflict or terrorist attacks; and
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regional economic downturns.
Additionally, in some jurisdictions we are subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations may adversely affect our ability to compete in such jurisdictions.
Our international business operations also include projects in countries where governmental corruption has been known to exist and where our competitors who are not subject to the same ethics-related laws and regulations such as the Foreign Corrupt Practices Act in the U.S. and the Bribery Act in the U.K., can gain competitive advantages over us by securing business awards, licenses or other preferential treatment in those jurisdictions using methods that certain ethics-related laws and regulations prohibit us from using. For example, our non-U.S. competitors may not be subject to the anti-bribery restrictions of the Foreign Corrupt Practices Act, which make it illegal to give anything of value to foreign officials or employees or agents of nationally-owned oil companies in order to obtain or retain any business or other advantage. While many countries, like the U.S. and the U.K., have adopted anti-bribery statutes, there has not been universal adoption and enforcement of such statutes. Therefore, we may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence.
The regulatory regimes in some foreign countries may be substantially different than those in the United States, and may be unfamiliar to U.S. investors. Violations of foreign laws could result in monetary and criminal penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
Exchange rate fluctuations could adversely affect our U.S. reported results of operations and financial position.
In the ordinary course of our business, we enter into purchase and sales commitments that are denominated in currencies that differ from the functional currency used by our operating subsidiaries. Currency exchange rate fluctuations can create volatility in our consolidated financial position, results of operations and/or cash flows. Although we may enter into foreign exchange agreements with financial institutions in order to reduce our exposure to fluctuations in currency exchange rates, these transactions, if entered into, will not eliminate that risk entirely. To the extent that we are unable to match revenues received in foreign currencies with expenses paid in the same currency, exchange rate fluctuations could have a negative impact on our consolidated financial position, results of operations and/or cash flows. Additionally, because our consolidated financial results are reported in U.S. dollars, if we generate net revenues or earnings in countries whose currency is not the U.S. dollar, the translation of such amounts into U.S. dollars can result in an increase or decrease in the amount of our net revenues and earnings depending upon exchange rate movements. With respect to our potential exposure to foreign currency fluctuations and devaluations, for the year ended December 31, 2013, approximately 50% of our revenues originated from subsidiaries outside of the U.S. and were denominated in currencies including, among others, the Canadian dollar, the Australian dollar and the pound sterling. As a result, a material decrease in the value of these currencies relative to the U.S. dollar may have a negative impact on our reported revenues, net income and cash flows. Any currency controls implemented by local monetary authorities in countries where we currently operate could also adversely affect our business, financial condition and results of operations.
We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.
Our operations are significantly affected by stringent foreign, federal, provincial, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. We could be exposed to liabilities for cleanup costs, natural resource damages and other damages under these laws and regulations, with certain of these legal requirements imposing strict liability for such damages and costs, even though our conduct was lawful at the time it occurred or the conduct resulting in such damage and costs were caused by, prior operators or other third-parties. Environmental laws and regulations are subject to change in the future, possibly resulting in more stringent requirements. If existing regulatory requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.
Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:
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issuance of administrative, civil and criminal penalties;
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denial or revocation of permits or other authorizations;
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reduction or cessation in operations; and
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performance of site investigatory, remedial or other corrective actions.
An accidental release of pollutants into the environment may cause us to incur significant costs and liabilities.
There is inherent risk of environmental costs and liabilities in our business as a result of our handling of petroleum hydrocarbons, because of air emissions and waste water discharges related to our operations, and due to historical industry operations and waste disposal practices. Certain environmental statutes impose joint and several, strict liability for these costs. For example, an accidental release by us in the performance of services at one of our or our customers’ sites could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover some or any of these costs from insurance.
We may be exposed to certain regulatory and financial risks related to climate change.
Climate change is receiving increasing attention from scientists and legislators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of any change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions. Significant focus is being made on companies that are active producers of depleting natural resources.
There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. The outcome of foreign, U.S. federal, regional, provincial and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:
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result in increased costs associated with our operations and our customers' operations;
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increase other costs to our business;
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adversely impact overall drilling activity in the areas in which we operate;
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reduce the demand for carbon-based fuels; and
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reduce the demand for our services.
Any adoption of these or similar proposals by foreign, U.S. federal, regional or state governments mandating a substantial reduction in greenhouse gas emissions or imposing a carbon tax on emission of greenhouse gasses could have far-reaching and significant impacts on the energy industry. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for our services. See "Part I, Item 1. “Business - Government Regulation" for a more detailed description of our climate-change related risks.
Currently proposed legislative changes, including changes to tax laws and regulations, could materially, negatively impact the Company by increasing the costs of doing business and decreasing the demand for our products.
The current U.S. administration and Congress have proposed several new articles of legislation or legislative and administrative changes, including changes to tax laws and regulations, which could have a material negative effect on our Company. Some of the proposed changes that could negatively impact us are:
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cap and trade system for emissions;
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increased environmental limits on exploration and production activities;
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repeal of expensing of intangible drilling costs;
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increase of the amortization period for geological and geophysical costs to seven years;
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repeal of percentage depletion;
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limits on hydraulic fracturing or disposal of hydraulic fracturing fluids;
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repeal of the domestic manufacturing deduction for oil and natural gas production;
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repeal of the passive loss exception for working interests in oil and natural gas properties;
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repeal of the credits for enhanced oil recovery projects and production from marginal wells;
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repeal of the deduction for tertiary injectants;
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changes to the foreign tax credit limitation calculation; and
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changes to healthcare rules and regulations.
We are susceptible to seasonal earnings volatility due to adverse weather conditions in our regions of operations.
Our operations are directly affected by seasonal differences in weather in the areas in which we operate, most notably in Canada, Australia, the Rocky Mountain region of the United States and the Gulf of Mexico. A portion of our Canadian accommodations operations is conducted during the winter months when the winter freeze in remote regions is required for exploration and production activity to occur. The spring thaw in these frontier regions restricts operations in the spring months and, as a result, adversely affects our operations and our ability to provide services in the second and, to a lesser extent, third quarters of our fiscal year. During the Australian rainy season, generally between the months of November and April, our accommodations operations in Queensland and the northern parts of Western Australia can be affected by cyclones, monsoons and resultant flooding. Severe winter weather conditions in the Rocky Mountain region of the United States can restrict access to work areas for our well site services and accommodations segment customers. Our operations in the Gulf of Mexico are also affected by weather patterns. Weather conditions in the Gulf Coast region generally result in higher drilling activity in the spring, summer and fall months with the lowest activity in the winter months. As a result of these seasonal differences, full year results are not likely to be a direct multiple of any particular quarter or combination of quarters. In addition, summer and fall drilling activity can be restricted due to hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast.
We are exposed to risks relating to subcontractors’ performance in some of our projects.
In many cases, we subcontract the performance of portions of our operations to subcontractors. While we seek to obtain appropriate indemnities and guarantees from these subcontractors, we remain ultimately responsible for the performance of our subcontractors. Industrial disputes, natural disasters, financial failure or default or inadequate performance in the provision of services, or the inability to provide services by such subcontractors has the potential to materially adversely affect us.
Our inability to control the inherent risks of identifying, acquiring and integrating businesses that we may acquire, including any related increases in debt or issuances of equity securities, could adversely affect our operations.
Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our growth strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements could impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders.
We expect to gain certain business, financial and strategic advantages as a result of business combinations we undertake, including synergies and operating efficiencies. Our forward-looking statements assume that we will successfully integrate our business acquisitions and realize these intended benefits. An inability to realize expected strategic advantages as a result of the acquisition would negatively affect the anticipated benefits of the acquisition. Additional risks we could face in connection with acquisitions include:
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retaining key employees of acquired businesses;
● retaining and attracting new customers of acquired businesses;
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retaining supply and distribution relationships key to the supply chain;
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increased administrative burden;
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developing our sales and marketing capabilities;
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managing our growth effectively;
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potential impairment resulting from the overpayment for an acquisition;
● integrating operations;
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managing tax and foreign exchange exposure;
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operating a new line of business;
● increased logistical problems common to large, expansive operations; and
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inability to pursue and protect patents covering acquired technology.
Additionally, an acquisition may bring us into businesses we have not previously conducted and expose us to additional business risks that are different from those we have previously experienced. If we fail to manage any of these risks successfully, our business could be harmed. Our capitalization and results of operations may change significantly following an acquisition, and shareholders of the Company may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.
We may not have adequate insurance for potential liabilities and our insurance may not cover certain liabilities, including litigation risks.
Our operations are subject to many hazards. In the ordinary course of business, we become the subject of various claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to the activities of businesses that we have sold, and some relate to the activities of businesses that we have acquired, even though these activities may have occurred prior to our acquisition of such businesses. We maintain insurance to cover many of our potential losses, and we are subject to various self-retentions and deductibles under our insurance policies. It is possible, however, that a judgment could be rendered against us in cases in which we could be uninsured and beyond the amounts that we currently have reserved or anticipate incurring for such matters. Even a partially uninsured or underinsured claim, if successful and of significant size, could have a material adverse effect on our results of operations or consolidated financial position. We also face the following other risks related to our insurance coverage:
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we may not be able to continue to obtain insurance on commercially reasonable terms;
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we may be faced with types of liabilities that will not be covered by our insurance, such as damages from environmental contamination or terrorist attacks;
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the counterparties to our insurance contracts may pose credit risks; and
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we may incur losses from interruption of our business that exceed our insurance coverage.
We depend on several significant customers in each of our business segments, and the loss of one or more such customers or the inability of one or more such customers to meet their obligations to us could adversely affect our results of operations.
We depend on several significant customers in each of our business segments. The majority of our customers operate in the energy or mining industry. For a more detailed explanation of our customers for each of our business segments, see “Item 1. Business.” The loss of any one of our largest customers in any of our business segments or a sustained decrease in demand by any of such customers could result in a substantial loss of revenues and could have a material adverse effect on our results of operations. In addition, the concentration of customers in two industries may impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic and industry conditions. While we perform ongoing credit evaluations of our customers, we do not generally require collateral in support of our trade receivables.
As a result of our customer concentration, risks of nonpayment and nonperformance by our counterparties are a concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. In an economic downturn, commodity prices typically decline, and the credit markets and availability of credit could be constrained. Additionally, many of our customers’ equity values could decline. The combination of lower cash flow due to commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of available debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to pay or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Our common stock price has been volatile, and we expect it to continue to remain volatile in the future.
The market price of common stock of companies engaged in the oil and gas services industry has been highly volatile. Likewise, the market price of our common stock has varied significantly (2013 low sales price of $71.28 per share; 2013 high sales price of $113.64 per share) in the past, and we expect it to continue to remain highly volatile given the cyclical nature of our industry.
We may assume contractual risks in developing, manufacturing and delivering products in our offshore products business segment.
Many of our products from our offshore products segment are ordered by customers under frame agreements or project specific contracts. In some cases these contracts stipulate a fixed price for the delivery of our products and impose liquidated damages or late delivery fees if we do not meet specific customer deadlines. In addition, some customer contracts stipulate consequential damages payable, generally as a result of our gross negligence or willful misconduct. The final delivered products may also include customer and third-party supplied equipment, the delay of which can negatively impact our ability to deliver our products on time at our anticipated profitability.
In certain cases these orders include new technology or unspecified design elements. In some cases we may not be fully or properly compensated for the cost to develop and design the final products, negatively impacting our profitability on the projects. In addition, our customers, in many cases, request changes to the original design or bid specifications for which we may not be fully or properly compensated.
As is customary for our offshore products segment, we agree to provide products under fixed-price contracts, typically assuming responsibility for cost overruns. Our actual costs and any gross profit realized on these fixed-price contracts may vary from the initially expected contract economics. There is inherent risk in the estimation process including significant unforeseen technical and logistical challenges or longer than expected lead times. A fixed-price contract may prohibit our ability to mitigate the impact of unanticipated increases in raw material prices (including the price of steel) through increased pricing. In fulfilling some contracts, we provide limited warranties for our products. Although we estimate and record a provision for potential warranty claims, repair or replacement costs under warranty provisions in our contracts could exceed the estimated cost to cure the claim which could be material to our financial results. We utilize percentage-of-completion accounting, depending on the size and length of a project, and variations from estimated contract performance could have a significant impact on our reported operating results as we progress toward completion of major jobs.
Backlog in our offshore products segment is subject to unexpected adjustments and cancellations and is, therefore, an imperfect indicator of our future revenues and earnings.
The revenues projected in our offshore products segment backlog may not be realized or, if realized, may not result in profits. Because of potential changes in the scope or schedule of our customers’ projects, we cannot predict with certainty when or if backlog will be realized. In addition, even where a project proceeds as scheduled, it is possible that contracted parties may default and fail to pay amounts owed to us. Material delays, cancellations or payment defaults could materially affect our financial condition, results of operations and cash flows.
Reductions in our backlog due to cancellations by customers or for other reasons would adversely affect, potentially to a material extent, the revenues and earnings we actually receive from contracts included in our backlog. Some of the contracts in our backlog are cancelable by the customer, subject to the payment of termination fees and/or the reimbursement of our costs incurred. We typically have no contractual right to the total revenues reflected in our backlog once a project is cancelled. If we experience significant project terminations, suspensions or scope adjustments to contracts included in our backlog, our financial condition, results of operations and cash flows may be adversely impacted.
We might be unable to employ a sufficient number of technical personnel.
Many of the products that we sell, especially in our offshore products segment, are complex and highly engineered and often must perform in harsh conditions. We believe that our success depends upon our ability to employ and retain technical personnel with the ability to design, utilize and enhance these products. In addition, our ability to expand our operations depends in part on our ability to increase our skilled labor force. During periods of increased activity, the demand for skilled workers is high, and the supply is limited. We have already experienced high demand and increased wages for labor forces serving our accommodations businesses in Canada and Australia. When these events occur, our cost structure increases and our growth potential could be impaired.
We might be unable to compete successfully with other companies in our industry.
The markets in which we operate are highly competitive and certain of them have relatively few barriers to entry. The principal competitive factors in our markets are product, equipment and service quality, availability, responsiveness, experience, technology, safety performance and price. In some of our business segments, we compete with the oil and gas industry’s largest oilfield service providers. These large national and multi-national companies have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.
If we do not develop new competitive technologies and products, our business and revenues may be adversely affected.
The market for our offshore products is characterized by continual technological developments to provide better performance in increasingly greater water depths, higher pressure levels and harsher conditions. If we are unable to design, develop and produce commercially competitive products in a timely manner in response to changes in technology, our business and revenues will be adversely affected. In addition, competitors or customers may develop new technologies, which address similar or improved solutions to our existing technology. Should our technologies, particularly in offshore products or in our completion services business, become the less attractive solution, our operations and profitability would be negatively impacted.
During periods of strong demand, we may be unable to obtain critical project materials on a timely basis.
Our operations depend on our ability to procure, on a timely basis, certain project materials, such as forgings, to complete projects in an efficient manner. Our inability to procure critical materials during times of strong demand could have a material adverse effect on our business and operations.
Our oilfield operations involve a variety of operating hazards and risks that could cause losses.
Our operations are subject to the hazards inherent in the oilfield business. These include, but are not limited to, equipment defects, blowouts, explosions, fires, collisions, capsizing and severe weather conditions. These hazards could result in personal injury and loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage and suspension of operations. We may incur substantial liabilities or losses as a result of these hazards as part of our ongoing business operations. We may agree to indemnify our customers against specific risks and liabilities. While we maintain insurance protection against some of these risks, and seek to obtain indemnity agreements from our customers requiring the customers to hold us harmless from some of these risks, our insurance and contractual indemnity protection may not be sufficient or effective enough to protect us under all circumstances or against all risks. The occurrence of a significant event not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition.
Our operations may suffer due to increased industry-wide capacity of certain types of equipment or assets.
The demand for and pricing of certain types of our assets and equipment, particularly our accommodations assets, drilling rigs and completion services assets, is subject to the overall availability of such assets in the marketplace. If demand for our assets were to decrease, or to the extent that we and our competitors increase our capacity in excess of current demand, we may encounter decreased pricing for or utilization of our assets and services, which could adversely impact our operations and profits.
In addition, we have significantly increased our accommodations capacity in the oil sands region over the past eight years and in Australia over the past three years based on our expectation for current and future customer demand for accommodations in these areas. Should our customers build their own facilities to meet their accommodations needs or our competitors likewise increase their available accommodations, or activity in the oil sands or natural resources regions of Australia declines significantly, demand and/or pricing for our accommodations could decrease, negatively impacting the profitability of our accommodations segment.
We might be unable to protect our intellectual property rights.
We rely on a variety of intellectual property rights that we use in our offshore products and completion services businesses, particularly our patents relating to our FlexJoint® and Merlin™ technology and intervention and downhole extended-reach tools utilized in the completion or workover of oil and natural gas wells. The market success of our technologies will depend, in part, on our ability to obtain and enforce our proprietary rights in these technologies, to preserve rights in our trade secret and non-public information, and to operate without infringing the proprietary rights of others. We may not be able to successfully preserve these intellectual property rights in the future and these rights could be invalidated, circumvented or challenged. If any of our patents or other intellectual property rights are determined to be invalid or unenforceable, or if a court limits the scope of claims in a patent or fails to recognize our trade secret rights, our competitive advantages could be significantly reduced in the relevant technology, allowing competition for our customer base to increase. In addition, the laws of some foreign countries in which our products and services may be sold do not protect intellectual property rights to the same extent as the laws of the United States. The failure of our company to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could adversely affect our competitive position.
Loss of key members of our management could adversely affect our business.
We depend on the continued employment and performance of key members of our management. If any of our key managers resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain "key man" life insurance for any of our officers.
Employee and customer labor problems could adversely affect us.
As of December 31, 2013, we are party to collective bargaining agreements covering 1,823 employees in Canada, 543 employees in Australia, 18 employees in Argentina and 16 employees in the United Kingdom. In addition, our accommodations facilities serving oil sands development work in Northern Alberta, Canada and mining operations in Australia house both union and non-union customer employees. We have not experienced strikes, work stoppages or other slowdowns in the past, but we cannot guarantee that we will not experience such events in the future. A prolonged strike, work stoppage or other slowdown by our employees or by the employees of our customers could cause us to experience a disruption of our operations, which could adversely affect our business, financial condition and results of operations.
Provisions contained in our certificate of incorporation and bylaws could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, the ability of our stockholders to sell their shares for a premium.
Provisions contained in our certificate of incorporation and bylaws provide limitations on the removal of directors, on stockholder proposals at meetings of stockholders, on stockholder action by written consent and on the ability of stockholders to call special meetings, which could make it more difficult for a third-party to acquire control of our company. Our certificate of incorporation also authorizes our Board of Directors to issue preferred stock without stockholder approval. If our Board of Directors elects to issue preferred stock, it could increase the difficulty for a third-party to acquire us, which may reduce or eliminate our stockholders' ability to sell their shares of our common stock at a premium.
The proposed spin-off of our accommodations business is contingent upon the satisfaction of a number of conditions, which may not be consummated on the terms or timeline currently contemplated or may not achieve the intended results.
On July 30, 2013, we announced that our Board of Directors approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to our shareholders. We expect that the spin-off can be executed by the end of the second quarter of 2014. Our ability to timely effect the spin-off is subject to several conditions, including among other things, market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, completion of a review by the Commission of a Form 10 filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our Board of Directors. We cannot assure you that we will be able to complete the spin-off in a timely fashion, if at all. For these and other reasons, the spin-off may not be completed on the terms or timeline contemplated. Further, if the spin-off is completed, it may not achieve the intended results. Any such delays or difficulties could adversely affect our business, results of operations or financial condition.
We may be required to refinance our debt in connection with the contemplated spin-off of our accommodations business.
In connection with the proposed spin-off, we will be required to refinance all or a portion of our credit facilities and outstanding 5 1/8% Senior Notes (5 1/8% Notes) and 6 1/2% Senior Notes (6 1/2% Notes) unless we obtain the consent of our lenders under our credit facilities and the holders of the notes. If we are required to refinance our debt, we may be required to pay significant redemption premiums, and the terms of any new indebtedness may not be as favorable as our current debt. In addition, if refinancing opportunities are not available to us, we may be required to delay the consummation of the spin-off of our accommodations business.
Our business could be negatively affected as a result of the actions of activist shareholders.
Publicly traded companies have increasingly become subject to campaigns by investors seeking to increase shareholder value by advocating corporate actions such as financial restructuring, increased borrowing, special dividends, stock repurchases, sales of assets or even sale of the entire company. Given our shareholder composition and other factors, it is possible such shareholders or future activist shareholders may attempt to effect such changes or acquire control over us. Responding to proxy contests and other actions by such activist shareholders or others in the future would be costly and time-consuming, disrupt our operations and divert the attention of our Board of Directors and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of shareholder activism or changes to the composition of the Board of Directors may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our, revenue, earnings and operating cash flows could be adversely affected.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
The following table presents information about our principal properties and facilities. For a discussion about how each of our business segments utilizes its respective properties, please see “Part I, Item 1. Business.” Except as indicated below, we own all of these properties or facilities.
Location
Approximate
Square
Footage/
Acreage
Description
United States:
Houston, Texas (lease)
30,931
Principal executive offices
Arlington, Texas (own and lease)
41 acres
Various contiguous offices, manufacturing and warehouse facilities located in thirteen buildings
Houston, Texas
25 acres
Offshore products office, manufacturing facility and yard
Houston, Texas
22 acres
Offshore products manufacturing facility and yard
Houston, Texas (lease)
58,871
Offshore products service facility and office
Houston, Texas (lease)
50,750
Offshore products service facility and office
Houma, Louisiana
40 acres
Offshore products manufacturing facility and yard
Tulsa, Oklahoma
74,600
Offshore products molding facility
Tulsa, Oklahoma (lease)
57,800
Offshore products molding facility
Oklahoma City, Oklahoma
70,000
Offshore products service facility and office
Lampasas, Texas
48,500
Offshore products molding facility
Lampasas, Texas (lease)
20,000
Offshore products warehouse
Johnstown, Colorado
153 acres
Accommodations manufacturing facility and yard
Killdeer, North Dakota
42 acres
Accommodations facility
Pecos, Texas
35 acres
Accommodations facility
Dickinson, North Dakota (lease)
26 acres
Accommodations facility and yard
Vernal, Utah (lease)
21 acres
Accommodations facility and yard
Carrizo Springs, Texas (lease)
20 acres
Accommodations facility
Casper, Wyoming (lease)
14 acres
Accommodations facility and yard
Belle Chasse, Louisiana (own and lease)
10 acres
Accommodations manufacturing facility and yard
Three Rivers, Texas (lease)
9 acres
Accommodations facility
Big Piney, Wyoming (lease)
7 acres
Accommodations facility and yard
Stanley, North Dakota (lease)
7 acres
Accommodations facility
Englewood, Colorado (lease)
5,480
Accommodations office
Windsor, Colorado (lease)
4,933
Accommodations office
Houston, Texas (lease)
23,441
Completion services office
Alice, Texas
27 acres
Completion services shop
Midland, Texas```
11 acres
Completion services shop
Houma, Louisiana
10 acres
Completion services shop
Rock Springs, Wyoming
10 acres
Completion services shop
Oklahoma City, Oklahoma
3 acres
Completion services shop
Odessa, Texas
22 acres
Well site services office, shop, warehouse and yard
Casper, Wyoming
7 acres
Well site services office, shop and yard
Location
Approximate
Square
Footage/
Acreage
Description
Canada:
Fort McMurray, Alberta (Wapasu Creek and Henday Lodges) (lease)
240 acres
Accommodations facility
Fort McMurray, Alberta (Pebble Beach) (lease)
140 acres
Accommodations facility
Fort McMurray, Alberta (Conklin Lodge)(lease)
135 acres
Accommodations facility
Fort McMurray, Alberta (Beaver River and Athabasca Lodges) (lease)
128 acres
Accommodations facility
Fort McMurray, Alberta (Christina Lake Lodge)
45 acres
Accommodations facility
Acheson, Alberta (lease)
40 acres
Accommodations office, yard and warehouse
Edmonton, Alberta
33 acres
Accommodations manufacturing facility
Grimshaw, Alberta (lease)
20 acres
Accommodations equipment yard
Fort McMurray, Alberta (Anzac Lodge)
18 acres
Accommodations facility
Nisku, Alberta
9 acres
Accommodations manufacturing facility
Edmonton, Alberta (lease)
86,376
Accommodations office and warehouse
Edmonton, Alberta (lease)
71,654
Accommodations manufacturing facility and yard
Edmonton, Alberta (lease)
28,253
Accommodations office
Edmonton, Alberta (lease)
16,130
Accommodations office
Australia:
Coppabella, Queensland, Australia
198 acres
Accommodations facility
Calliope, Queensland, Australia
124 acres
Accommodations facility
Narrabri, New South Wales, Australia
82 acres
Accommodations facility
Boggabri, New South Wales, Australia
52 acres
Accommodations facility
Dysart, Queensland, Australia
50 acres
Accommodations facility
Middlemount, Queensland, Australia
37 acres
Accommodations facility
Karratha, Western Australia, Australia (own and lease)
34 acres
Accommodations facility
Kambalda, Western Australia, Australia
27 acres
Accommodations facility
Nebo, Queensland, Australia
26 acres
Accommodations facility
Moranbah, Queensland, Australia
17 acres
Accommodations facility
Ormeau, Queensland, Australia (lease)
3 acres
Accommodations manufacturing facility
Sydney, New South Wales, Australia (lease)
17,276
Accommodations office
Brisbane, Queensland, Australia (lease)
7,115
Accommodations office
Other International:
Rio de Janeiro, Brazil
31 acres
Offshore products manufacturing facility and yard
Macaé, Brazil
17 acres
Offshore products manufacturing facility and yard
Macaé, Brazil (lease)
6 acres
Offshore products manufacturing facility and yard
Aberdeen, Scotland (lease)
15 acres
Offshore products manufacturing facility and yard
Bathgate, Scotland
3 acres
Offshore products manufacturing facility and yard
Rayong Province, Thailand
11 acres
Offshore products manufacturing and service facility
Singapore (lease)
155,398
Offshore products manufacturing facility
Barrow-in-Furness, England (own and lease)
63,300
Offshore products service facility and yard
District Raigad, Maharashtra, India
3 acres
Offshore products manufacturing facility
We have a total of 53 completion services locations throughout the United States and in Canada, Mexico and Argentina. Most of these office locations are leased and provide sales, technical support and personnel services to our customers. We also have various offices supporting our business segments which are both owned and leased. We believe that our leases are at competitive or market rates and do not anticipate any difficulty in leasing additional suitable space upon expiration of our current lease terms. Leases for our lodge properties in Canada refers to land leased from the Alberta government. We also lease land for our Karratha village from the local provincial government in Australia. Generally, our land leases have an initial term of ten years and will expire between 2015 and 2026.
Item 3.
Item 3. Legal Proceedings
We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses, and in other cases, we have indemnified the buyers of businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock Information
Our authorized common stock consists of 200,000,000 shares of common stock. There were 53,340,650 shares of common stock outstanding as of February 21, 2014. The approximate number of record holders of our common stock as of February 21, 2014 was 24. Our common stock is traded on the New York Stock Exchange under the ticker symbol OIS. The closing price of our common stock on February 19, 2014 was $96.09 per share.
The following table sets forth the range of high and low quarterly sales prices of our common stock:
We have not declared or paid any cash dividends on our common stock since our IPO and do not intend to declare or pay any cash dividends on our common stock in the foreseeable future. Furthermore, our existing credit facilities restrict the payment of dividends. For additional discussion of such restrictions, please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.” Any future determination as to the declaration and payment of dividends will be at the discretion of our Board of Directors and will depend on then existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our Board of Directors considers relevant.
PERFORMANCE GRAPH
The following performance graph and chart compare the cumulative 5-year total stockholder return on the Company's common stock relative to the cumulative total returns of the Standard & Poor's 500 Stock Index, the Philadelphia OSX Index, an index of oil and gas related companies that represent an industry composite of the Company's peer group, and two customized peer groups of fourteen companies (our 2012 Proxy Peer Group) and fifteen companies (our 2013 Proxy Peer Group), respectively, whose individual companies are listed in footnotes (a) and (b) below for the period from December 31, 2008 to December 31, 2013. The graph and chart show the value at the dates indicated of $100 invested at December 31, 2008 and assume the reinvestment of all dividends.
The fourteen companies included in the Company's first customized peer group are: Carbo Ceramics Inc., Core Laboratories, Dresser-Rand Group Inc., Dril-Quip Inc., Exterran Holdings Inc., FMC Technologies Inc., Helix Energy Solutions Group Inc., Helmerich & Payne Inc., Key Energy Services Inc., McDermott International Inc., Oceaneering International Inc., RPC Inc., Superior Energy Services Inc. and Tidewater Inc.
The fifteen companies included in the Company's second customized peer group are: Cameron International Corp., Carbo Ceramics Inc., Core Laboratories, Dresser-Rand Group Inc., Dril-Quip Inc., Exterran Holdings Inc., FMC Technologies Inc., Helix Energy Solutions Group Inc., Helmerich & Payne Inc., Key Energy Services Inc., McDermott International Inc., Oceaneering International Inc., RPC Inc., Superior Energy Services Inc. and Tidewater Inc.
Oil States International - NYSE
*$100 invested on December 31, 2008 in stock or index, including reinvestment of dividends. Fiscal year ending December 31st.
(1)
This graph is not "soliciting material," is not deemed filed with the Commission and is not to be incorporated by reference in any filing by us under the Securities Act, or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
(2)
The stock price performance shown on the graph is not necessarily indicative of future price performance. Information used in the graph was obtained from Research Data Group, Inc., a source believed to be reliable, but we are not responsible for any errors or omissions in such information.
Prepared by Research Data Group, Inc. Used with permission. Copyright© 2014. All rights reserved. (www.researchdatagroup.com/S&P.htm).
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchases
Period
Total Number of Shares
Purchased
Average Price Paid
per Share
Total Number of
Shares Purchased
as Part of Publicly
Announced Program
Approximate
Dollar Value of Shares
That May Yet Be Purchased Under the
Program (1)
October 1, 2013 -
October 31, 2013
6,685(2)
$108.62(3)
--
$ 472,865,339
November 1, 2013 -
November 30, 2013
234,411(4)
$102.37(5)
234,309
$ 448,879,598
December 1, 2013 -
December 31, 2013
790,121(6)
$101.35(7)
789,904
$ 368,822,647
Total
1,031,217
$101.63
1,024,213
$ 368,822,647
(1)
On August 23, 2012, we announced a share repurchase program of up to $200,000,000 to replace the prior share repurchase authorization, which was set to expire on September 1, 2012. On September 6, 2013, we announced an increase in the program from $200,000,000 to $500,000,000. The current share repurchase program expires on September 1, 2014.
(2)
Shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.
(3)
The price paid per share was based on the weighted average closing price of our Company’s common stock on October 4, 2013 and October 31, 2013, which represent the dates the restrictions lapsed on such shares.
(4)
Included in these shares are 102 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.
(5)
The price paid per share was based (a) on the dates in which we repurchased shares under our common stock repurchase program, and (b) on the weighted average closing price of our Company’s common stock on November 3, 2013, which represents the date the restrictions lapsed on such shares.
(6)
Included in these shares are 217 shares surrendered to us by participants in our 2001 Equity Participation Plan to settle the participants’ personal tax liabilities that resulted from the lapsing of restrictions on shares awarded to the participants under the plan.
(7)
The price paid per share was based (a) on the dates in which we repurchased shares under our common stock repurchase program, and (b) on the weighted average closing price of our Company’s common stock on December 14, 2013 and December 15, 2013, which represents the dates the restrictions lapsed on such shares.
Item 6.
Item 6. Selected Financial Data
The selected financial data on the following pages include selected historical financial information of our company as of and for each of the five years ended December 31, 2013. The following data should be read in conjunction with “Part II, Item 7.
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act that are based on management’s current expectations, estimates and projections about our business operations. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of numerous factors, including the known material factors set forth in “Part I, Item 1A. Risk Factors.” You should read the following discussion and analysis together with our Consolidated Financial Statements and the notes to those statements included elsewhere in this Annual Report on Form 10-K.
Macroeconomic Environment
We provide a broad range of products and services to the oil and gas industry through our accommodations, offshore products and well site services business segments, and our accommodations segment also supports the mining industry. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas and mining industries, particularly our customers’ willingness to invest capital in the exploration for and development of oil, natural gas, met coal and other mineral reserves. Our customers’ capital spending programs are generally based on their outlook for near-term and long-term commodity prices, economic growth, commodity demand and estimates of resource production. As a result, demand for our products and services is largely sensitive to expected commodity prices, principally related to crude oil, met coal and natural gas.
In the past few years, crude oil prices in North America have been volatile due to global economic uncertainties as well as inadequate regional take-away pipeline capacity. However, crude oil prices continue to trade at relatively high historic levels. This price volatility moderated in 2013 with some fluctuations in crude oil prices resulting from changing market sentiment regarding the outlook for economic growth in the U.S. and China, decreased crude oil production by Organization of the Petroleum Exporting Countries (OPEC), heightened geopolitical risks in the Middle East and North Africa and increased oil production in the U.S. The price of West Texas Intermediate (WTI) crude oil increased from an average price of $88 per barrel in the fourth quarter of 2012 to $98 per barrel in 2013, finishing 2013 at $98 per barrel. The price of Intercontinental Exchange (ICE) Brent crude decreased modestly from an average price of $110 per barrel in the fourth quarter of 2012 to $109 per barrel in 2013, finishing 2013 at $110 per barrel. As of February 19, 2014, WTI crude traded at approximately $103 per barrel while ICE Brent crude traded at approximately $110 per barrel. The price for WTI will influence our customers’ spending in U.S. shale play developments, such as the Bakken, Niobrara, and Eagle Ford, as well as the Permian Basin of Texas. Spending in these regions will influence the overall drilling and completion activity in the area and, therefore, the activity of our well site services segment.
In Canada, Western Canadian Select (WCS) crude is the benchmark price for our oil sands accommodations’ customers. Pricing for WCS is driven by several factors. A significant factor affecting WCS pricing is the underlying price for WTI. As WTI prices have improved over the past few years with the global economic recovery, WCS prices have also improved. Another significant factor affecting WCS pricing has been transportation. Historically, WCS has traded at a discount to WTI, creating a “WCS Basis Differential”, due to transportation costs and limited capacity to move growing Canadian heavy oil production to U.S. refineries. Depending on the extent of pipeline capacity availability, the WCS Basis Differential has varied. With the increase in global oil prices and increased transportation capacity from the oil sands region due to rail and barge alternatives, the absolute price of WCS has increased and the WCS Basis Differential has decreased. WCS prices in 2013 averaged $73.58 per barrel compared to $71.80 per barrel in 2012. However, the WCS Basis Differential widened substantially from below $15 per barrel to $25 per barrel as of February 19, 2014, as production increased and demand from U.S. refineries declined due to maintenance requirements. Should the price of WTI decline or the WCS Basis Differential widen further, our oil sands customers’ may delay additional investments or reduce their spending in the oil sands region.
Given the historical volatility of crude prices and the WCS discount, there remains a risk that prices could deteriorate going forward due to increased domestic crude oil production or slowing growth rates in China, fiscal and financial uncertainty in the U.S. and various European countries and a prolonged level of relatively high unemployment in the U.S. and other advanced economies. However, if the global supply of oil and global inventory levels were to decrease due to government instability in a major oil-producing nation and energy demand continues to increase in countries such as China, India and the U.S., we could see continued and/or additional increases in WTI crude prices, which, coupled with an improvement in takeaway capacity from the oil sands, could improve WCS pricing. This, in turn, could lead to our oil sands customers increasing their investments in oil sands production. Conversely, if WCS crude prices continue to experience a significant discount to WTI crude, our oil sands customers may have an incentive to delay additional investments in their oil sands assets.
Prices for natural gas in the United States improved during 2013 and early 2014, largely due to above average storage withdrawals in response to colder than normal weather, continued elevated demand for natural gas for electric power generation, lower net imports from Canada and higher industrial demand. However, natural gas prices continue to be weak relative to prices experienced in 2006 through 2008 due to the rise in production from unconventional natural gas resources in North America, specifically, onshore shale production resulting from the broad application of horizontal drilling and hydraulic fracturing techniques. Natural gas prices traded at approximately $6.04 per Mcf as of February 19, 2014. As a result of natural gas production growth outpacing demand in the U.S., the U.S. gas-related working rig count has declined from more than 800 rigs at the beginning of 2012 to less than 341 rigs as of February 14, 2014. Natural gas inventories in the U.S. have declined from being 12% above the 5-year average at the end of 2012 to 9% below the 5-year average at the end of 2013. Any increases in the supply of natural gas, whether the supply comes from conventional or unconventional production or associated gas production from oil wells, could constrain prices for natural gas for an extended period and result in fewer rigs drilling for gas in the near-term.
Our Australian villages in the Bowen Basin primarily serve coal mines in that region. Met coal pricing and growth in production in the Bowen Basin region is influenced by levels of steel production. Because Chinese steel production has been growing at a slower pace than that experienced in 2010 and early 2011, Chinese demand for imported steel inputs such as met coal and iron ore decreased during 2013 compared to 2012. Met coal prices have decreased materially from over $200/metric ton at the beginning of 2012 to approximately $150/metric ton at the end of 2013. Depressed met coal prices have led to the implementation of cost control measures by our customers, some coal mine closures and delays in the start-up of new coal mining projects in Australia. A continued depressed met coal price will impact our customers’ future capital spending programs. However, steel consumption per capita in China is less than one-third of the amount installed in the U.S. economy, suggesting a favorable outlook for Chinese steel production and met coal demand over a longer horizon.
Recent WTI crude, ICE Brent crude, WCS crude, Queensland hard coking coal and natural gas pricing trends are as follows:
__________
(1) Source: WTI crude, ICE Brent crude and natural gas prices from U.S. Energy Information Administration (EIA) and WCS crude prices and Queensland hard coking coal index from Bloomberg.
Overview
Demand for our accommodations and offshore products segments is primarily tied to the long-term outlook for commodity prices. In contrast, demand for our well site services segment responds to shorter-term movements in oil and natural gas prices and, specifically, changes in North American drilling and completion activity. Other factors that can affect our business and financial results include the general global economic environment and regulatory changes in the U.S., Canada, Australia and other international markets.
Generally, our oil sands and mining accommodations’ customers are making multi-billion dollar investments to develop their prospects, which have estimated reserve lives of ten years to in excess of thirty years and, consequently, these investments are dependent on those customers' longer-term view of commodity demand and prices. Oil sands development and production activity has increased over the past several years and has had a positive impact on our Canadian accommodations business. However, the growth rate slowed during 2012 and 2013 due to weaker WCS crude pricing compared to prior years and concerns over a lack of transportation infrastructure given delays by the U.S. government in approving the Keystone XL pipeline. Sanctioning of new and expanded oil sands projects by our customers, if they occur, may create the opportunity for extensions of existing accommodations contracts and incremental accommodations contracts in Canada.
We expanded our Australian accommodations room capacity in 2012 and 2013 to meet increasing demand, notably in the Bowen Basin in Queensland and in the Gunnedah Basin in New South Wales to support coal production, and in Western Australia to support LNG and other energy-related projects. In early 2013, a confluence of low met coal pricing, additional carbon and mining taxes on our Australian accommodations customers and several years of cost inflation caused several of our customers to delay or materially reduce their growth plans. This has negatively affected our ability to expand our room count and has led to a decrease in occupancy levels. It has also caused one of our customers to renegotiate contracts with us to reduce their forward room commitments beginning in March 2014 in return for termination compensation beginning in March 2014.
Our offshore products segment provides highly engineered products for offshore oil and natural gas drilling and production systems and facilities. Sales of our offshore products and services depend primarily upon capital spending for offshore production systems and subsea pipelines, repairs and upgrades of existing offshore drilling rigs and construction of new offshore drilling rigs and vessels. In this segment, we are particularly influenced by global deepwater drilling and production spending, which are driven largely by our customers’ longer-term outlook for oil and natural gas prices.
In our well site services business segment, we predominantly provide completion services and, to a lesser extent, land drilling services. Our completion services business provides equipment and service personnel utilized in the completion and initial production of new and recompleted wells. Activity for the completion services business is dependent primarily upon the level and complexity of drilling, completion and workover activity throughout North America. Well complexity has increased with the continuing transition to multi-well pads and the drilling of longer laterals along with the increased number of frac stages completed. Demand for our drilling services is driven by land drilling activity in our primary drilling markets of West Texas, where we primarily drill oil wells, and the Rocky Mountain area in the U.S., where we drill both liquids-rich and natural gas wells.
We have a diversified product and service offering, which has exposure to activities conducted throughout the oil and gas cycle. Demand for our land drilling and completion services businesses is highly correlated to changes in the drilling rig count in the United States and, to a much lesser extent, Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, for the periods indicated.
The average North American rig count fell precipitously in the first half of 2009 in response to the impact of the global economic downturn which negatively impacted energy prices but has since substantially recovered from its June 2009 low. The average North American rig count for the year ended December 31, 2013 decreased by 168 rigs, or 7.4%, compared to the average for the year ended December 31, 2012 largely due to a decline in natural gas drilling.
Another factor that influences the financial results for our accommodations segment is the exchange rate between the U.S. dollar and the Canadian dollar and between the U.S. dollar and the Australian dollar. Our accommodations segment derives a vast majority of its revenues and operating income in Canada and Australia. These revenues and profits are translated into U.S. dollars for U.S. GAAP financial reporting purposes. The Canadian dollar was valued at an average exchange rate of U.S. $0.97 for the year ended December 31, 2013 compared to U.S. $1.00 for the year ended December 31, 2012, a decrease of 3%. The Australian dollar was valued at an average exchange rate of U.S. $0.97 for the year ended December 31, 2013 compared to U.S. $1.04 for the year ended December 31, 2012, a decrease of 7%. Importantly, exchange rates weakened further by the end of 2013, ending the year at U.S. $0.89 per Australian dollar and U.S. $0.94 per Canadian dollar, respectively, as of December 31, 2013. The Australian and Canadian exchange rates were U.S. $0.90 and U.S. $0.91, respectively, as of February 19, 2014. This weakening of the Canadian and Australian dollars has and may continue to have a proportionately negative impact on the translation of earnings generated from our Canadian and Australian subsidiaries and, therefore, the financial results of our accommodations segment.
While global demand for oil and natural gas are significant factors influencing our business generally, certain other factors also influence our business, such as the pace of worldwide economic growth and the recovery in U.S. Gulf of Mexico drilling following the lifting of the government imposed drilling moratorium.
Although 19% higher than in 2012, the drilling rig count in 2013 in the U.S. Gulf of Mexico remains below peak levels following the April 2010 Macondo well incident and resultant oil spill in the U.S. Gulf of Mexico. Beginning in the third quarter of 2011, however, U.S. Gulf of Mexico drilling activity has shown signs of a slow but steady recovery.
We continue to monitor the global economy, the demand for crude oil, met coal and natural gas and the resultant impact on the capital spending plans and operations of our customers in order to plan our business. Our capital expenditures for our continuing operations in 2013 totaled $457 million compared to 2012 capital expenditures of $483 million. Our 2013 capital expenditures included funding to expand our Canadian oil sands and Australian mining related accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Approximately two-thirds of our total 2013 capital expenditures were spent in our accommodations segment. We expect to spend a total of approximately $600 million to $650 million for capital expenditures during 2014 to expand our accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Whether planned expenditures will actually be spent in 2014 depends on industry conditions, project approvals and schedules and vendor delivery timing. Approximately one-half of our total estimated 2014 capital expenditures are expected to be spent in our accommodations segment. With $160 million estimated to be spent in well site services and $135 million in offshore products, we expect to fund these capital expenditures with available cash, internally generated funds and borrowings under our credit facilities. In our well site services segment, we continue to monitor industry capacity additions and will make future capital expenditure decisions based on an evaluation of both the market outlook and industry fundamentals.
Strategic Actions
On July 30, 2013, we announced that our Board of Directors approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to our shareholders. The spin-off is subject to market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, the completion of a review by the Commission of a Form 10 filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our Board of Directors, and is expected to be completed in the second quarter of 2014. The Accommodations business will initially be spun-off as a C-Corporation, which offers a faster path to separation. The Accommodations business will continue to assess the feasibility and advisability of a potential future conversion into a real estate investment trust (REIT).
On September 6, 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu for the sale of Sooner, which comprised the entirety of the Company’s tubular services segment. Total consideration received by the Company was $600.0 million in cash, which remains subject to customary post-closing adjustments. We recognized a net gain on disposal of $128.4 million ($84.0 million after-tax) during 2013, which is included within “Net income from discontinued operations, net of tax” in the Consolidated Statements of Income. Operating results for the Company’s tubular services business have been classified as discontinued operations for all periods presented.
Recent Acquisitions
On December 2, 2013, we acquired all of the equity of QCS for total cash consideration of $42.5 million. Headquartered in Houston, Texas, QCS designs, manufactures and markets a portfolio of proprietary deep and shallow water pipeline connectors for subsea pipeline construction, repair and expansion projects. The operations of QCS have been included in our offshore products segment since the acquisition date.
On December 14, 2012, we acquired all of the equity of Tempress for purchase price consideration of $49.8 million consisting of $32.8 million in cash plus contingent consideration with an estimated fair value of $17.0 million at closing. During 2013, the estimated fair market value of the contingent liability was increased to $20.0 million due to favorable developments related to a patent application by Tempress, resulting in a $3.0 million, or $0.05 per diluted share, charge to other operating expense. The patent was granted in the third quarter of 2013 and the $20.0 million of contingent consideration was paid to the former shareholders of Tempress. The Company’s current escrowed deposits of $5.3 million include other consideration for seller transaction indemnities, are considered restricted cash and are classified as “Other current assets” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for escrowed amounts expected to be paid to the seller also totaled $5.3 million and are classified as “Other current liabilities” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent liabilities” in our December 31, 2012 Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.
On July 2, 2012, we acquired all of the operating assets of Piper for total cash consideration of $48.0 million. Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects located offshore (both surface and subsea) and onshore. The operations of Piper have been included in our offshore products segment since the acquisition date.
We funded all of our 2013 and 2012 acquisitions with cash on hand and/or amounts available under our credit facilities. See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our senior secured bank facilities.
Consolidated Results of Operations (in millions)
YEAR ENDED DECEMBER 31, 2013 COMPARED TO YEAR ENDED DECEMBER 31, 2012
We reported net income from continuing operations attributable to the Company for the year ended December 31, 2013 of $314.9 million, or $5.63 per diluted share, including a loss on the extinguishment of debt of $7.4 million, or $0.09 per diluted share after tax, a gain on the disposal of land and an associated building of $4.6 million, or $0.06 per diluted share after tax, a gain of $4.0 million, or $0.05 per diluted share after tax, from a decrease to a liability associated with contingent acquisition consideration in our U.S. accommodations business and a charge of $3.0 million, or $0.04 per diluted share, from an increase in contingent acquisition consideration in our completion services business. In addition, the Company incurred $5.7 million, or $0.07 per diluted share after tax, of transaction costs in 2013 which is included in “other operating (income) expense” primarily related to the proposed spin-off of our accommodations segment. These results compare to net income from continuing operations attributable to the Company of $401.5 million, or $7.25 per diluted share, reported for the year ended December 31, 2012, including a gain of $17.9 million, or $0.23 per diluted share after tax, from a favorable contract settlement reported in our U.S. accommodations business and a gain of $2.5 million, or $0.03 per diluted share after tax, related to insurance proceeds received for a land drilling rig lost in a fire that occurred in the first quarter of 2012.
Revenues. Consolidated revenues increased $39.0 million, or 1%, in 2013 compared to 2012.
Our well site services segment revenues increased $32.9 million, or 5%, in 2013 compared to 2012 due to an increase in completion services revenues, partially offset by a decrease in drilling services revenues. Our completion services revenues increased $53.4 million, or 10%, in 2013 compared to 2012, in spite of an 8% decrease in the North American land rig count, as a result of increased service intensity in the active shale basins along with contributions from the Tempress acquisition completed in the fourth quarter of 2012. Our revenue per ticket increased 8% year-over-year (excluding the contribution from the acquisition of Tempress) as the industry favored our higher specification equipment. The number of service tickets issued in 2013 decreased 1% compared to 2012 (also excluding the contribution from the acquisition of Tempress) due primarily to reduced activity, particularly in the Haynesville and Barnett shale regions, resulting from reduced customer spending in dry gas markets, partially offset by increased activity in the Bakken region. Our drilling services revenues decreased $20.5 million, or 11%, in 2013 compared to 2012 primarily as a result of decreased utilization of our rigs from an average of approximately 88% for 2012 to an average of approximately 75% for 2013.
Our accommodations segment reported revenues in 2013 that were $72.4 million, or 7%, lower than 2012. This decrease was primarily due to the weakening of the average exchange rates for Canadian and Australian dollars relative to the U.S. dollar by 3% and 7%, respectively, in 2013 compared to 2012. In addition, the segment experienced a 10% decline in other accommodations revenue, a favorable contract settlement reported in our U.S. accommodations business of $18.3 million in the first quarter of 2012 and a 1% decline in lodge and village revenue. Other accommodations revenue declined in 2013 due to lower mobile camp activity in Canada, lower utilization for our U.S. accommodation assets coupled with lower third-party manufacturing revenues. Lodge and village revenues declined due to a 9% year-over-year decrease in RevPAR related to lower contracted rates in Canada and lower occupancy levels, primarily in Australia as a result of the continued slowdown in mining activity, partially offset by a 12% increase in average available rooms in 2013 compared to 2012. In the U.S., utilization for our accommodations was negatively impacted by poor weather conditions in the Bakken region, a weaker land drilling market in the regions which we serve, as well as a surplus of available room capacity in the U.S. market.
Our offshore products segment revenues increased $78.5 million, or 10%, in 2013 compared to 2012. This increase was primarily the result of increased drilling and subsea product sales along with contributions from the acquisition of Piper, which was acquired in July 2012.
Cost of Sales and Service. Our consolidated cost of sales increased $56.7 million, or 4%, in 2013 compared to 2012 as a result of increased cost of sales at our offshore products and well site services segments of $44.8 million, or 8%, and $14.7 million, or 3%, respectively, due to increased activity and revenues in these segments. Our consolidated gross margin as a percentage of revenues decreased slightly from 39% in 2012 to 38% in 2013 primarily due to the favorable contract settlement reported in our U.S. accommodations business in 2012 and lower margins realized in our Canadian accommodations business in 2013.
Our well site services segment cost of sales increased $14.7 million, or 3%, in 2013 compared to 2012 as a result of a $28.4 million, or 9%, increase in completion services cost of sales, partially offset by a $13.7 million, or 10%, decrease in drilling services cost of sales. Our completion services segment gross margin as a percentage of revenues was 39% in 2013 compared to 38% in 2012. Our drilling services gross margin as a percentage of revenues was 30% in both 2013 and 2012 as the decrease in drilling revenues was mostly offset by a reduction in operating costs.
Our accommodations segment cost of sales decreased $2.8 million, or 1%, in 2013 compared to 2012 primarily due to lower third-party manufacturing costs, partially offset by costs of increased room capacity in Canada. Our accommodations segment gross margin as a percentage of revenues decreased from 50% in 2012 to 47% in 2013 primarily due to lower contracted rates in Canada and the favorable contract settlement reported in our U.S. accommodations business in 2012 which did not recur in 2013.
Our offshore products segment cost of sales increased $44.8 million, or 8%, in 2013 compared to 2012 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues increased modestly from 26% in 2012 to 27% in 2013.
Selling, General and Administrative Expenses (SG&A). SG&A expense increased $29.9 million, or 16%, in 2013 compared to 2012 primarily due to increased employee-related costs, SG&A expense associated with the inclusion of Piper and Tempress, which were acquired in July and December of 2012, respectively, increased professional fees, insurance costs and advertising and trade show expenses, partially offset by the weakening of the Australian and Canadian dollars to U.S. dollar exchange rates in 2013 compared to 2012.
Depreciation and Amortization. Depreciation and amortization expense increased $48.7 million, or 21%, in 2013 compared to 2012 primarily due to capital expenditures made during the previous twelve months largely related to investments in our accommodations segment and completion services business.
Operating Income. Consolidated operating income decreased $98.0 million, or 16%, in 2013 compared to 2012 primarily as a result of a decrease in operating income from our accommodations segment of $96.9 million, or 27%, primarily due to the favorable contract settlement reported in our U.S. accommodations business in 2012, the lower contracted rates in Canada, lower occupancy levels in Australia, increased depreciation expense on accommodations assets and lower utilization for our U.S. accommodations assets, partially offset by the increase in average available rooms in 2013 compared to 2012. In addition, operating income decreased in 2013 compared to 2012 due to an increase in corporate SG&A expense of $11.3 million, or 26%, primarily related to increased stock compensation, and $5.7 million in transaction-related costs. These decreases in operating income were partially offset by an increase in operating income from our offshore products segment of $22.9 million, or 17%, due to increased revenues.
Interest Expense and Interest Income. Net interest expense increased by $6.2 million, or 9%, in 2013 compared to 2012 primarily due to interest expense on our 5 1/8% Notes, issued on December 21, 2012, partially offset by decreased interest expense on our 2 3/8% Notes due 2025 (2 3/8% Notes) due to their conversion in July 2012. The weighted average annual interest rate on the Company’s total outstanding debt was 5.5% in 2013 compared to 4.8% in 2012. Interest income increased as a result of increased cash balances in interest bearing accounts.
Loss on Extinguishment of Debt. During 2013, we wrote off $3.3 million of unamortized deferred financing costs associated with the full repayment of our U.S. and Canadian term loans. Additionally, in the fourth quarter of 2013, we repurchased a portion of our 5 1/8% Notes, resulting in a loss of $4.1 million, including the write-off of $0.4 million of unamortized deferred financing costs.
Income Tax Expense. Our income tax provision for 2013 totaled $120.0 million, or 27.5% of pretax income, compared to income tax expense of $149.0 million, or 27.0% of pretax income, for 2012. The effective tax rates for 2013 and 2012 are comparable, and both are lower than U.S. statutory rates because of lower foreign tax rates.
Discontinued Operations. Exclusive of a $128.4 million pre-tax gain ($84.0 million after tax) recorded on the disposal of our tubular services business, net income from discontinued operations for 2013 was $22.3 million compared to $47.1 million for 2012. Revenues reported within discontinued operations were $1,073.1 million and $1,781.9 million during 2013 and 2012, respectively. The decrease in revenue primarily relates to the disposal of our tubular services business on September 6, 2013. The operating income included within discontinued operations was $40.1 million and $73.5 million for 2013 and 2012, respectively.
Other Comprehensive Income (Loss). Other comprehensive income decreased from other comprehensive income of $32.7 million in 2012 to other comprehensive loss of $192.8 million in 2013 primarily as a result of foreign currency translation adjustments due to decreases in the Canadian and Australian dollar exchange rates compared to the U.S. dollar. The Canadian dollar exchange rate compared to the U.S. dollar decreased 6% in 2013 compared to a 2% increase in 2012. The Australian dollar exchange rate compared to the U.S. dollar decreased 14% in 2013 compared to a 1% increase in 2012.
YEAR ENDED DECEMBER 31, 2012 COMPARED TO YEAR ENDED DECEMBER 31, 2011
We reported net income from continuing operations attributable to the Company for the year ended December 31, 2012 of $401.5 million, or $7.58 per diluted share, including a gain of $17.9 million, or $0.23 per diluted share after-tax, from a favorable contract settlement reported in our U.S. accommodations business and a pre-tax gain of $2.5 million, or $0.03 per diluted share after-tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire that occurred in the first quarter of 2012. These results compare to net income attributable to the Company of $282.2 million, or $5.51 per diluted share, reported for the year ended December 31, 2011.
Revenues. Consolidated revenues increased $526.8 million, or 25%, in 2012 compared to 2011.
Our well site services segment revenues increased $59.7 million, or 9%, in 2012 compared to 2011 primarily due to increases in both completion services revenues and drilling services revenues. Our completion services revenues increased $34.6 million, or 7%, in 2012 compared to 2011 primarily due to increased demand for our completion services supporting the 2% increase in the U.S. rig count, a more favorable mix of higher value rentals and services and greater service intensity. Our drilling services revenues increased $25.1 million, or 15%, in 2012 compared to 2011 primarily as a result of increases in pricing, with average day rates rising to $18,000 per day in 2012, up from $16,400 per day in 2011, and increased utilization of our rigs from an average of approximately 82% in 2011 to an average of approximately 88% in 2012.
Our accommodations segment reported revenues in 2012 that were $248.8 million, or 29%, above 2011. The increase in accommodations revenue primarily resulted from increased revenues from expanded room capacity in Canada and Australia along with $18.3 million in revenue from a favorable contract settlement reported in our U.S. accommodations business during the first quarter of 2012. Revenues, average available rooms and revenue per available room (RevPAR) for our lodges and villages increased 36%, 23% and 11%, respectively, in 2012 compared to 2011.
Our offshore products segment revenues increased $218.3 million, or 37%, in 2012 compared to 2011. This increase was primarily the result of higher levels of manufacturing and service activity, an improved revenue mix favoring our production equipment and connector products along with contributions from the acquisition of Piper which closed in July 2012.
Cost of Sales and Service. Our consolidated cost of sales increased $298.6 million, or 23%, in 2012 compared to 2011. This cost of sales increase was directly related to the increase in revenue. Our consolidated gross margin as a percentage of revenues increased from 38% in 2011 to 39% in 2012.
Our well site services segment cost of sales increased $36.7 million, or 9%, in 2012 compared to 2011 as a result of a $26.2 million, or 9%, increase in completion services cost of sales and a $10.5 million, or 9%, increase in drilling services cost of sales. Our well site services segment gross margin as a percentage of revenues remained constant at 36% in both 2012 and 2011. Our completion services gross margin as a percentage of revenues declined modestly to 38% in 2012 compared to 39% in 2011. Our drilling services gross margin as a percentage of revenues increased from 26% in 2011 to 30% in 2012 primarily due to increased day rates, rig utilization and cost absorption.
Our accommodations segment cost of sales increased $95.9 million, or 21%, in 2012 compared to 2011 primarily due to increased revenues and room capacity in both Canada and Australia. Our accommodations segment gross margin as a percentage of revenues increased from 47% in 2011 to 50% in 2012 primarily due to an 11% increase in RevPAR for lodges and villages in 2012 compared to 2011. The increase in the RevPAR in 2012 compared to 2011 was primarily due to increased occupancy levels.
Our offshore products segment cost of sales increased $165.9 million, or 39%, in 2012 compared to 2011 primarily due to increased revenues. Our offshore products segment gross margin as a percentage of revenues decreased modestly to 26% in 2012 compared to 27% in 2011.
Selling, General and Administrative Expenses. SG&A expense increased $20.1 million, or 12%, in 2012 compared to 2011 primarily due to increased employee-related costs related to a 7% increase in total headcount, commissions and office expenses along with SG&A expense associated with the inclusion of Piper, which was acquired in July 2012.
Depreciation and Amortization. Depreciation and amortization expense increased $41.4 million, or 22%, in 2012 compared to 2011 primarily due to capital expenditures made during 2011 and 2012 largely related to investments in our Canadian and Australian accommodations and completion services businesses.
Operating Income. Consolidated operating income increased $166.0 million, or 37%, in 2012 compared to 2011 primarily as a result of an increase in operating income from our accommodations segment of $115.7 million, or 46%, due to expanded room capacity in Canada and Australia, along with the favorable contract settlement reported in our U.S. accommodations business and an increase in operating income from our offshore products segment of $39.4 million, or 42%. In addition, operating income from our well site services segment increased $15.5 million, or 11%, largely due to increased dayrates and rig utilization in our drilling services business and a more favorable mix of services and increased activity in our completion services business.
Interest Expense and Interest Income. Net interest expense increased by $11.5 million, or 21%, in 2012 compared to 2011 primarily due to interest expense on the 6 1/2% Notes, issued on June 1, 2011, partially offset by decreased interest expense on our 2 3/8% Notes due 2025 (2 3/8% Notes) due to their conversion in July 2012. The weighted average annual interest rate on the Company’s total outstanding debt was 4.8% in 2012 compared to 4.9% in 2011. Interest income decreased as a result of decreased cash balances in interest bearing accounts.
Income Tax Expense. Our income tax provision for 2012 totaled $149.0 million, or 27.0% of pretax income, compared to income tax expense of $107.6 million, or 27.5% of pretax income, for 2011. The effective tax rates for 2012 and 2011 are comparable, and both are lower than U.S. statutory rates because of lower foreign tax rates.
Liquidity and Capital Resources
Our primary liquidity needs are to fund capital expenditures, which in the past have included expanding our accommodations facilities, expanding and upgrading our offshore products manufacturing facilities and equipment, replacing and increasing completion services assets, funding new product development and general working capital needs. In addition, capital has been used to repay debt, fund our stock repurchase program and fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our credit facilities and capital market transactions. In 2013, we also received significant funds as a result of the disposition of our tubular services business. See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our credit facilities and debt offerings.
Cash flows from discontinued operations are combined with cash flows from continuing operations within each cash flow statement category on the Company’s Consolidated Statements of Cash Flows.
Cash totaling $687.3 million was provided by operations during the year ended December 31, 2013 compared to cash totaling $637.2 million provided by operations during the year ended December 31, 2012. During 2013, $87.3 million was provided from net working capital reductions, primarily due to decreased investments in working capital for our tubular services business. During 2012, $74.9 million was used to fund working capital, primarily due to increased investments in receivables and inventory in our offshore products segment coupled with higher OCTG inventory at our tubular services segment due to increased order activity.
Cash was provided by investing activities during the year ended December 31, 2013 in the amount of $108.4 million and cash was used in investing activities during the year ended December 31, 2012 in the amount of $577.0 million. A total of $600 million of cash proceeds was received from the sale of our tubular services business in September 2013. Capital expenditures totaled $457.5 million and $487.9 million during the years ended December 31, 2013 and 2012, respectively. Capital expenditures in both years consisted principally of purchases of assets for our accommodations and well site services segments, and in particular for the construction and installation of assets for our lodges and villages primarily in support of Canadian oil sands projects and Australian mining production and development.
During the year ended December 31, 2013, we spent cash of $44.3 million to acquire all of the equity of QCS. This compares to $80.4 million spent during the year ended December 31, 2012 to acquire all of the operating assets of Piper and all of the equity of Tempress. In addition, in 2012, the Company funded escrow accounts totaling $25.3 million related to contingent consideration and seller transaction indemnities for the Tempress acquisition. We funded the Piper and Tempress acquisitions using amounts available under the Company’s U.S. revolving credit facility. See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information on our credit facilities.
We expect to spend a total of approximately $600 million to $650 million for capital expenditures during 2014 to expand our accommodations facilities, to fund our other product and service offerings, and to upgrade our equipment and facilities. Whether planned expenditures will actually be spent in 2014 depends on industry conditions, project approvals and schedules and vendor delivery timing. Approximately one-half of our total estimated 2014 capital expenditures are expected to be spent in our accommodations segment. We expect to fund these capital expenditures with available cash, internally generated funds and borrowings under our credit facilities. The foregoing capital expenditure forecast does not include any funds for strategic acquisitions, which the Company could pursue depending on the economic environment in our industry and the availability of transactions at prices deemed to be attractive to the Company. If we complete our proposed spin-off of our accommodations business during 2014, any remaining capital expenditures related to our accommodations business will be funded by the new entity. At December 31, 2013, we had cash totaling $274.5 million held by foreign subsidiaries, primarily in Canada and the United Kingdom, where, in the case of Canada, we have assumed permanent reinvestment of earnings and have not recorded a U.S. tax liability upon the assumed repatriation of foreign earnings. Our intent is to utilize these cash balances for future investment outside the United States.
Net cash of $430.6 million was used in financing activities during the year ended December 31, 2013, primarily as a result of the repayment of all amounts outstanding under our U.S. and Canadian term loans, repurchases of our common stock, repayments under our Australian credit facility and repurchases of our 5 1/8% Notes. Net cash of $120.6 million was provided by financing activities during the year ended December 31, 2012, primarily as a result of proceeds from the issuance in the fourth quarter of 2012 of $400 million aggregate principal amount of 5 1/8% Notes, offset by net repayments of outstanding amounts under revolving credit facilities, payments of principal amounts on the conversion of our 2 3/8% Notes and repayments on our U.S. and Canadian term loans. We incurred $0.2 million of costs to secure financings in 2013 compared to $7.9 million in 2012. See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10K for additional information on our credit facilities and debt offerings.
On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025, totaling $175 million in aggregate principal amount, on July 6, 2012 at a redemption price equal to 100% of the principal amount thereof plus accrued interest. The 2 3/8% Notes were convertible by the holders thereof into shares of the Company’s common stock at the conversion rate of 31.496 shares of common stock for each $1,000 principal amount of 2 3/8% Notes converted. In July 2012, rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $175 million aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and 3,012,380 shares of the Company’s common stock valued at $220.6 million.
The Company’s discontinued operations impacted the cash flows of the Company as summarized in the table below (in thousands):
The cash (used in)/from financing activities in 2013 primarily represents the net transfers of cash between the discontinued operations of Sooner and Oil States International, Inc. The absence of cash flows from discontinued operations is not expected to adversely affect the investing or financing activities of the Company.
We believe that cash on hand, cash flow from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. We anticipate the need to replace our existing facility in the U.S. in connection with the announced spin-off of our accommodations business in the second quarter of 2014. We will likely redeem or call all of our senior notes which have a book value of $966 million and a fair value of $1,050 million as of December 31, 2013. We expect to receive a distribution of approximately $650 million to $850 million in connection with the spin-off of our accommodations business. In addition, we also recognize the need to separately capitalize the accommodations business when it is distributed to shareholders in a tax-free spin-off. If our plans or assumptions change, or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. The timing, size or success of any acquisition effort and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets and other factors, many of which are beyond our control. In addition, such additional debt service requirements could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to stockholders.
Proposed Spin-Off of Accommodations Business. On July 30, 2013, we announced that our Board of Directors approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to our shareholders. In connection with the proposed spin-off, we anticipate that we will refinance our existing debt. Specifically, we intend to commence a tender offer for any and all of our outstanding 5 1/8% Notes and 6 1/2% Notes. We intend to fund this tender offer in part with the proceeds of a cash dividend to be paid to us by the accommodations business immediately prior to the consummation of the proposed spin-off. We anticipate that this cash dividend will be within a range of $650.0 million to $850.0 million. In connection with the spin-off, we also plan to refinance our existing credit facilities into a single, U.S. revolving credit facility.
Stock Repurchase Program. On September 6, 2013, the Company announced an increase in its Board-authorized Company stock repurchase program from $200 million to $500 million for the repurchase of the Company’s common stock, par value $.01 per share. As of December 31, 2013, the Company had approximately 54.2 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2014. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. As of December 31, 2013, a total of $131.2 million of our stock (1,385,388 shares) had been repurchased under this program, leaving a total authorization of up to approximately $368.8 million remaining available under the program at year end. Through January 27, 2014, we had purchased an additional 1,009,665 shares for $100.0 million leaving $268.8 million remaining under the program.
Credit Facilities. Our current bank credit facilities include a U.S. revolving credit facility and a Canadian revolving facility. The credit facilities are governed by an Amended and Restated Credit Agreement dated December 10, 2010 (Credit Agreement) by and among the Company, PTI Group Inc., PTI Premium Camp Services, Ltd., the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent and U.S. collateral agent and Royal Bank of Canada, as Canadian administrative agent and Canadian collateral agent. The U.S. and Canadian bank credit facilities currently contain total commitments available of $750 million, including Total U.S. Commitments (as defined in the Credit Agreement) of U.S. $500 million and Total Canadian Commitments (as defined in the Credit Agreement) of U.S. $250 million. We repaid Canadian and U.S. term loan balances previously outstanding in full during 2013, which are permanent reductions of availability under our credit facilities. The maturity date of the Credit Agreement is December 10, 2015. We currently have 19 lenders in our Credit Agreement with commitments ranging from $19.0 million to $107.1 million.
The Credit Agreement contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA, of no greater than 3.25 to 1.0 in 2012 and 3.0 to 1.0 thereafter. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest as defined, exclude goodwill impairments, debt discount amortization and other non-cash charges. As of December 31, 2013, we were in compliance with our debt covenants and expect to continue to be in compliance during 2014. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on our leverage ratio, on the unused commitments under the Credit Agreement. During 2013, our applicable margin over LIBOR was 2.00%. Our weighted average annual interest rate paid under the Credit Agreement was 2.6% during the year ended December 31, 2013 and 2.7% for the year ended December 31, 2012.
As of December 31, 2013, we had no borrowings outstanding under the Credit Agreement and $33.6 million of outstanding letters of credit, leaving $716.4 million available to be drawn under the U.S. and Canadian facilities.
On September 18, 2012, the Company’s Australian accommodations subsidiary, The MAC Services Group Pty Limited (The MAC), entered into a A$300 million revolving loan facility governed by a Syndicated Facility Agreement (The MAC Group Facility Agreement), between The MAC, J.P. Morgan Australia Limited, as Australian agent and security trustee, JPMorgan Chase Bank, N.A., as U.S. agent, and the lenders party thereto, which is guaranteed by the Company and The MAC’s subsidiaries. We currently have 11 lenders in The MAC Group Facility Agreement with commitments ranging from A$14 million to A$35 million. The maturity date of The MAC Group Facility Agreement is December 10, 2015. The MAC Group Facility Agreement replaced The MAC’s previous A$150 million revolving loan facility. As of December 31, 2013, we had no borrowings outstanding under The MAC Group Facility Agreement. Our weighted average annual interest rate paid under the MAC Group Facility Agreement was 5.1% during the year ended December 31, 2013 and 5.4% during the period beginning September 18, 2012 and ending December 31, 2012.
In connection with the proposed spin-off of our accommodations business, we intend to refinance our existing credit facilities and enter into a new U.S. revolving credit facility. Please see “Proposed Spin-off of Accommodations Business” above.
5 1/8% Notes. On December 21, 2012, the Company sold $400 million aggregate principal amount of 5 1/8% Notes through a private placement to qualified institutional buyers.
The 5 1/8% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 5 1/8% per annum and mature on January 1, 2023. At any time prior to January 15, 2016, the Company may redeem up to 35% of the 5 1/8% Notes at a redemption price of 105.125% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
The Company utilized approximately $334 million of the net proceeds of the 5 1/8% Notes to repay borrowings under its U.S. credit facility. The remaining net proceeds of approximately $61 million were utilized for general corporate purposes.
On December 21, 2012, in connection with the issuance of the 5 1/8% Notes, the Company entered into an Indenture (the 5 1/8% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The 5 1/8% Notes Indenture restricts the Company's ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 5 1/8% Notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no Default (as defined in the 5 1/8% Notes Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The 5 1/8% Notes Indenture contains customary events of default. As of December 31, 2013, the Company was in compliance with all covenants of the 5 1/8% Notes Indenture.
In the fourth quarter of 2013, the Company repurchased $34.0 million aggregate principal amount of the 5 1/8% Notes. As a result of this transaction, the Company recognized a loss on extinguishment of debt of $4.1 million.
In connection with the proposed spin-off of our accommodations business, we intend to commence a tender offer for any and all of our outstanding 5 1/8% Notes. We intend to fund this tender offer in part with the proceeds of a cash dividend to be paid to us by the accommodations business immediately prior to the consummation of the proposed spin-off. Please see “Proposed Spin-off of Accommodations Business” above.
6 1/2% Notes. On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% Notes through a private placement to qualified institutional buyers.
The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our Guarantors, bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.5% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
The Company utilized approximately $515 million of the net proceeds of the 6 1/2% Note offering in June 2011 to repay borrowings under credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.
On June 1, 2011, in connection with the issuance of the 6 1/2% Notes, the Company entered into an Indenture (the 6 1/2% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The Indenture restricts the Company's ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 6 1/2% Notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no Default (as defined in the 6 1/2% Notes Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The 6 1/2% Notes Indenture contains customary events of default. As of December 31, 2013, the Company was in compliance with all covenants of the 6 1/2% Notes Indenture.
Our total debt represented 27.0% of our combined total debt and stockholders’ equity at December 31, 2013 compared to 34.7% at December 31, 2012.
In connection with the proposed spin-off of our accommodations business, we intend to commence a tender offer for any and all of our outstanding 6 1/2% Notes. We intend to fund this tender offer in part with the proceeds of a cash dividend to be paid to us by the accommodations business immediately prior to the consummation of the proposed spin-off. Please see “Proposed Spin-off of Accommodations Business” above.
Contractual Obligations. The following summarizes our contractual obligations at December 31, 2013, and the effect such obligations are expected to have on our liquidity and cash flow over the next five years (in thousands):
(1)
Includes interest on fixed-rate debt. Excludes interest on variable-rate debt. Since we cannot predict with any certainty the amount of interest due on our revolving debt due to the expected variability of interest rates and principal amounts outstanding, we do not include this in our obligations. If we assume interest payment amounts are calculated using the outstanding principal balances, interest rates and foreign currency exchange rates as of December 31, 2013 and include applicable commitment fees, estimated interest payments on our variable-rate debt would be $4.4 million “due in less than one year” and $4.1 million “due in one to three years.” See Note 10 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional for additional information on our credit facilities.
(2)
See Note 14 to the Consolidated Financial Statements included in this Annual Report on Form 10-K for additional information.
Our debt obligations at December 31, 2013 are included in our consolidated balance sheet, which is a part of our Consolidated Financial Statements included in this Annual Report on Form 10-K. We have not entered into any material leases subsequent to December 31, 2013.
Due to the uncertainty with respect to the timing of future cash flows associated with our uncertain tax positions at December 31, 2013, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. Therefore, $1.0 million in uncertain tax positions, including interest and penalties, have been excluded from the contractual obligations table above.
Effects of Inflation
Our revenues and results of operations have not been materially impacted by inflation in the past three fiscal years.
Off-Balance Sheet Arrangements
As of December 31, 2013, we had no off-balance sheet arrangements as defined in Item 303(a)(4)(ii) of Regulation S-K.
Tax Matters
Our primary deferred tax assets at December 31, 2013, are related to employee benefit costs for our Equity Participation Plan, deductible goodwill and other intangibles, inventory allowance for obsolescence, and foreign tax credit carryforwards. The foreign tax credits will expire in varying amounts after 2019.
Our income tax provision for the year ended December 31, 2013 totaled $120.0 million, or 27.5% of pretax income, compared to $149.0 million, or 27.0% of pretax income, for the year ended December 31, 2012. The effective tax rates for 2013 and 2012 are comparable, and both are lower than U.S. statutory rates because of lower foreign tax rates.
There are a number of legislative proposals to change the United States tax laws related to multinational corporations. In Australia, proposed changes to tax laws could negatively impact the deductibility of the interest expense on our intercompany debt. These proposals are in various stages of discussion. It is not possible at this time to predict how these proposals would impact our business or whether they could result in increased tax costs.
Critical Accounting Policies
Our Consolidated Financial Statements included in this Annual Report on Form 10-K have been prepared in accordance with accounting principles generally accepted in the United States (GAAP), which require that management make numerous estimates and assumptions. Actual results could differ from those estimates and assumptions, thus impacting our reported results of operations and financial position. The critical accounting policies and estimates described in this section are those that are most important to the depiction of our financial condition and results of operations and the application of which requires management’s most subjective judgments in making estimates about the effect of matters that are inherently uncertain. We describe our significant accounting policies more fully in Note 2 to Consolidated Financial Statements included in this Annual Report on Form 10-K.
Accounting for Contingencies
We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on their fair value or our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include future consideration due sellers as a result of the terms of a business combination, litigation, taxes, interest, insurance claims, warranty claims, contract claims and obligations, asset retirement obligations and discontinued operations.
Asset Retirement Obligations
We recognize initial estimated asset retirement obligations (ARO) related to our properties as liabilities, with an associated increase in property and equipment for the asset’s estimated retirement cost. The obligation is expensed over the estimated productive life of the related assets. If the fair value of the estimated ARO changes, an adjustment is recorded to both the ARO and the capitalized asset. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling the ARO. The Company relieves ARO liabilities when the related obligations are settled. At December 31, 2013 and 2012, $6.1 million and $5.5 million, respectively, of ARO was included in the Consolidated Balance Sheet in “Other noncurrent liabilities.” The ARO liability reflects the estimated present value of the amount of asset removal and site reclamation costs related to the retirement of assets in the Company’s accommodations business. Total expense related to the ARO was $0.3 million in 2013 and 2012. There was no expense related to the ARO in 2011. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties and a risk-adjusted discount rate in order to determine the current present value of the obligation.
Tangible and Intangible Assets, including Goodwill
Our goodwill totaled $513.7 million, or 12.4%, of our total assets, as of December 31, 2013. Our other intangible assets totaled $133.5 million, or 3.2%, of our total assets, as of December 31, 2013. The assessment of impairment of long-lived assets, including intangibles, is conducted whenever changes in the facts and circumstances indicate a loss in value has occurred. Indicators of impairment might include persistent negative economic trends affecting the markets we serve, recurring losses or lowered expectations of future cash flows expected to be generated by our assets. The determination of the amount of impairment would be based on quoted market prices, if available, or upon our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows and our determination of whether a decline in value of our investment has occurred, can have a significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment losses.
We evaluate each reporting unit at least annually or on an interim basis, if an indicator of impairment was determined to occur, as defined in current accounting standards regarding goodwill to assess goodwill for potential impairment. Our reporting units include completion services, drilling services, accommodations and offshore products. There is no remaining goodwill in our drilling services reporting unit subsequent to the full impairment of goodwill for that reporting unit as of December 31, 2008. As part of the goodwill impairment analysis, current accounting standards give us the option to first perform a qualitative assessment to determine whether it is more likely than not (that is, a likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying amount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. Current accounting standards also give us the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. In 2013, we chose to bypass the qualitative assessment for all of our reporting units with goodwill remaining and perform the two-step impairment test. In performing the two-step impairment test, we estimate the implied fair value (IFV) of each reporting unit and compare the IFV to the carrying value of such unit. Because none of our reporting units has a publically quoted market price, we must determine the value that willing buyers and sellers would place on the reporting unit through a routine sale process (a Level 3 fair value measurement). In our analysis, we target an IFV that represents the value that would be placed on the reporting unit by market participants, and value the reporting unit based on historical and projected results throughout a cycle, not the value of the reporting unit based on trough or peak earnings. We utilize, depending on circumstances, trading multiples analyses, discounted projected cash flow calculations with estimated terminal values and acquisition comparables to estimate the IFV. The IFV of our reporting units is affected by future oil, coal and natural gas prices, anticipated spending by our customers, and the cost of capital. As part of our process to assess goodwill for impairment, we also compare the total market capitalization of the Company to the sum of the IFV's of all of our reporting units to assess the reasonableness of the IFV's in the aggregate. If the carrying amount of a reporting unit exceeds its IFV, goodwill is considered to be potentially impaired and additional analysis in accordance with current accounting standards is conducted to determine the amount of impairment, if any. At the date of our goodwill impairment test in 2013, the IFV of our offshore products, accommodations and completion services reporting units each exceeded their carrying values.
As part of our process to assess goodwill for impairment in 2013, we also compared the total market capitalization of the Company to the sum of the IFV’s of all of our reporting units to assess the reasonableness of the IFV’s in the aggregate.
Revenue and Cost Recognition
Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectability is probable and pricing is fixed and determinable. Our product sales terms do not include significant post-delivery obligations. For significant projects, revenues are recognized under the percentage-of-completion method, measured by the percentage of costs incurred to date compared to estimated total costs for each contract (cost-to-cost method). Billings on such contracts in excess of costs incurred and estimated profits are classified as deferred revenue. Costs incurred and estimated profits in excess of billings on percentage-of-completion contracts are recognized as unbilled receivables. Management believes this method is the most appropriate measure of progress on large contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Factors that may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents. These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future reported earnings. Our accommodations segment derives the majority of its revenue from lodging and related ancillary services. Accommodations segment revenue is recognized in the period in which services are provided pursuant to the terms of the contractual relationships with customers. In some contracts, rates may vary over the contract term. In these cases, revenue may be deferred and recognized over a straight-line basis over the contract term. In our well site services segment, revenues are recognized based on a periodic (usually daily) rate or when the services are rendered. Proceeds from customers for the cost of oilfield rental equipment that is damaged or lost downhole are reflected as gains or losses on the disposition of assets after considering the write-off of the remaining net book value of the equipment. For drilling services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.
Cost of goods sold includes all direct material and labor costs and those costs related to contract performance, such as indirect labor, supplies, tools and repairs. In our accommodations segment, cost of services includes labor, food, utility costs, cleaning supplies, and other costs of operating the accommodations facilities. SG&A costs are charged to expense as incurred.
Valuation Allowances
Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required. We have, in past years, recorded a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized.
Estimation of Useful Lives
The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Our judgment in this area is influenced by our historical experience in operating our assets, technological developments and expectations of future demand for the assets. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.
Stock-Based Compensation
Since the adoption of the accounting standards regarding share-based payments, we are required to estimate the fair value of stock compensation made pursuant to awards under our 2001 Equity Participation Plan (Plan). An initial estimate of the fair value of each stock option or restricted stock award determines the amount of stock compensation expense we will recognize in the future. To estimate the value of stock option awards under the Plan, we have selected a fair value calculation model. We have chosen the Black Scholes Merton “closed form” model to value stock options awarded under the Plan. We have chosen this model because our option awards have been made under straightforward vesting terms, option prices and option lives. Utilizing the Black Scholes Merton model requires us to estimate the length of time options will remain outstanding, a risk free interest rate for the estimated period options are assumed to be outstanding, forfeiture rates, future dividends and the volatility of our common stock. All of these assumptions affect the amount and timing of future stock compensation expense recognition. We will continually monitor our actual experience and change assumptions for future awards as we consider appropriate.
Income Taxes
The Company follows the liability method of accounting for income taxes in accordance with current accounting standards regarding the accounting for income taxes. Under this method, deferred income taxes are recorded based upon the differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws in effect at the time the underlying assets or liabilities are recovered or settled.
When the Company's earnings from foreign subsidiaries are considered to be indefinitely reinvested, no provision for U.S. income taxes is made for these earnings. If any of the subsidiaries have a distribution of earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the various foreign countries.
In accordance with current accounting standards, the Company records a valuation allowance in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. Management will continue to evaluate the appropriateness of the valuation allowance in the future based upon the operating results of the Company.
In accounting for income taxes, we are required by the provisions of current accounting standards regarding the accounting for uncertainty in income taxes, to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.
Discontinued Operations
The operating results of a component of our business that either has been disposed of or is classified as held for sale are presented as discontinued operations when both of the following conditions are met: (a) the operations and cash flows of the component have been or will be eliminated from our ongoing operations as a result of the disposal transaction and (b) we will not have any significant continuing involvement in the operations of the disposed component. We consider a component of our business to be one that comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of our business.
Recent Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.
ITEM 7A.
ITEM 7A. Quantitative And Qualitative Disclosures About Market Risk
Our principal market risks are our exposure to changes in interest rates and foreign currency exchange rates.
Interest Rate Risk. We have credit facilities that are subject to the risk of higher interest charges associated with increases in interest rates. As of December 31, 2013, we had no floating-rate obligations outstanding under our credit facilities.
Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world and we receive revenue from these operations in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks in areas outside the U.S. (primarily in our offshore products segment), we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. During 2013, our reported foreign exchange losses were $0.8 million and are included in “Other operating (income) expense” in the Consolidated Statements of Income. Excluding intercompany balances, our Canadian dollar and Australian dollar functional currency net assets total approximately C$983 million and A$957 million, respectively, at December 31, 2013. In order to reduce our exposure to fluctuations in currency exchange rates, we may enter into foreign exchange agreements with financial institutions. As of December 31, 2013 and 2012, we had outstanding foreign currency forward purchase contracts with notional amounts of $7.4 million and $12.4 million, respectively, hedging expected cash flows denominated in Euros. As a result of this contract, we recorded other comprehensive losses of $0.4 million and $1.0 million for the years ended December 31, 2013 and 2012, respectively, and a $0.9 million foreign exchange loss related to amounts reclassified from accumulated other comprehensive income into income for the year ended December 31, 2013.
Item 8.
Item 8. Financial Statements and Supplementary Data
Our Consolidated Financial Statements and supplementary data of the Company appear on pages 75 through 116 of this Annual Report on Form 10-K and are incorporated by reference into this Item 8. Selected quarterly financial data is set forth in Note 18 to our Consolidated Financial Statements, which is incorporated herein by reference.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
There were no changes in or disagreements on any matters of accounting principles or financial statement disclosure between us and our independent auditors during our two most recent fiscal years or any subsequent interim period.
Item 9A.
Item 9A. Controls and Procedures
(i) Evaluation of Disclosure Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) of the Exchange Act. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2013 at the reasonable assurance level.
Pursuant to section 906 of The Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer have provided certain certifications to the Commission. These certifications accompanied this report when filed with the Commission, but are not set forth herein.
(ii) Internal Control Over Financial Reporting
(a) Management's annual report on internal control over financial reporting.
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of management and our directors, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Accordingly, even effective internal control over financial reporting can only provide reasonable assurance of achieving their control objectives.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013 was conducted. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we believe that, as of December 31, 2013, the Company's internal control over financial reporting is effective based on those criteria.
In December 2013, the Company acquired all of the equity of QCS. The Company will begin the process of evaluating QCS's internal controls during 2014. As permitted by the related Securities and Exchange Commission (SEC) staff’s interpretative guidance for newly acquired businesses, the Company excluded QCS from management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2013. QCS represented 1.2% of the total assets and less than 1% of total revenues of the Company as of and for the fiscal year ended December 31, 2013.
(b) Attestation report of the registered public accounting firm.
The attestation report of Ernst & Young LLP, the Company's independent registered public accounting firm, on the Company's internal control over financial reporting is set forth in this Annual Report on Form 10-K on Page 77 and is incorporated herein by reference.
(c) Changes in internal control over financial reporting.
During the Company's fourth fiscal quarter ended December 31, 2013, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2013 that was not reported on a Form 8-K during such time.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
(1)
Information concerning directors, including the Company's audit committee financial expert, appears in the Company's Definitive Proxy Statement for the 2014 Annual Meeting of Stockholders, under "Election of Directors." This portion of the Definitive Proxy Statement is incorporated herein by reference.
(2)
Information with respect to executive officers appears in the Company's Definitive Proxy Statement for the 2014 Annual Meeting of Stockholders, under "Executive Officers of the Registrant." This portion of the Definitive Proxy Statement is incorporated herein by reference.
(3)
Information concerning Section 16(a) beneficial ownership reporting compliance appears in the Company's Definitive Proxy Statement for the 2014 Annual Meeting of Stockholders, under "Section 16(a) Beneficial Ownership Reporting Compliance." This portion of the Definitive Proxy Statement is incorporated herein by reference.
Item 11.
Item 11. Executive Compensation
The information required by Item 11 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2014 Annual Meeting of Stockholders.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by Item 12 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2014 Annual Meeting of Stockholders.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by Item 13 hereby is incorporated by reference to such information as set forth in the Company's Definitive Proxy Statement for the 2014 Annual Meeting of Stockholders.
Item 14.
Item 14. Principal Accounting Fees and Services
Information concerning principal accounting fees and services and the audit committee's preapproval policies and procedures appear in the Company's Definitive Proxy Statement for the 2014 Annual Meeting of Stockholders under the heading "Fees Paid to Ernst & Young LLP" and is incorporated herein by reference.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements: Reference is made to the index set forth on page 75 of this Annual Report on Form 10-K.
(2) Financial Statement Schedules: No schedules have been included herein because the information required to be submitted has been included in the Consolidated Financial Statements or the Notes thereto, or the required information is inapplicable.
(3) Index of Exhibits: See Index of Exhibits, below, for a list of those exhibits filed herewith, which index also includes and identifies management contracts or compensatory plans or arrangements required to be filed as exhibits to this Annual Report on Form 10-K by Item 601 of Regulation S-K.
(b) Index of Exhibits
Exhibit No.
Description
2.1
-
Stock Purchase Agreement by and among Marubeni-Itochu Tubulars America Inc., Sooner, Inc. and Oil States International, Inc. dated September 5, 2013 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 6, 2013 (File No. 001-16337)).
3.1
-
Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
3.2
-
Third Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, as filed with the Commission on March 13, 2009 (File No. 001-16337)).
3.3
-
Certificate of Designations of Special Preferred Voting Stock of Oil States International, Inc. (incorporated by reference to Exhibit 3.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
4.1
-
Form of common stock certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1, as filed with the Commission on November 7, 2000 (File No. 333-43400)).
4.2
-
Amended and Restated Registration Rights Agreement (incorporated by reference to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
4.3
-
First Amendment to the Amended and Restated Registration Rights Agreement dated May 17, 2002 (incorporated by reference to Exhibit 4.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2002, as filed with the Commission on March 13, 2003 (File No. 001-16337)).
4.4
-
Registration Rights Agreement dated as of June 21, 2005 by and between Oil States International, Inc. and RBC Capital Markets Corporation (incorporated by reference to Exhibit 4.4 to Oil States' Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).
4.5
-
Indenture dated as of June 21, 2005 by and between Oil States International, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Oil States' Current Report on Form 8-K as filed with the Commission on June 23, 2005 (File No. 001-16337)).
4.6
-
Global Notes representing $175,000,000 aggregate principal amount of 2 3/8% Contingent Convertible Senior Notes due 2025 (incorporated by reference to Section 2.2 of Exhibit 4.5 to Oil States' Current Reports on Form 8-K as filed with the Commission on June 23, 2005 and July 13, 2005 (File No. 001-16337)).
4.7
-
Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).
4.8
-
Supplemental Indenture dated as of June 1, 2011 among the Company, the Guarantors and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on June 1, 2011 (File No. 001-16337)).
4.9
-
First Supplemental Indenture, dated as of September 10, 2012, among Oil States Energy Services, L.L.C., Oil States International, Inc. (together with its successors and assigns), each other then-existing Guarantor under the Indenture, and Wells Fargo Bank, N.A., as Trustee, paying agent and registrar under such Indenture (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).
4.10
-
Indenture dated as of December 21, 2012 among Oil States International, Inc., the Guarantors named therein, and Wells Fargo Bank, N.A., as trustee, paying agent and registrar (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on December 21, 2012 (File No. 001-16337)).
4.11
-
First Supplemental Indenture, dated as of February 15, 2013, among Tempress Technologies, Inc., Oil States International, Inc. (together with its successors and assigns), each other then-existing Guarantor under the Indenture, and Wells Fargo Bank, N.A., as Trustee, paying agent and registrar under such Indenture.
4.12
-
Second Supplemental Indenture, dated as of February 15, 2013, among Tempress Technologies, Inc., Oil States International, Inc. (together with its successors and assigns), each other then-existing Guarantor under the Indenture, and Wells Fargo Bank, N.A., as Trustee, paying agent and registrar under such Indenture.
10.1
-
Combination Agreement dated as of July 31, 2000 by and among Oil States International, Inc., HWC Energy Services, Inc., Merger Sub-HWC, Inc., Sooner Inc., Merger Sub-Sooner, Inc. and PTI Group Inc. (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1, as filed with the Commission on August 10, 2000 (File No. 333-43400)).
10.2
-
Plan of Arrangement of PTI Group Inc. (incorporated by reference to Exhibit 10.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.3
-
Support Agreement between Oil States International, Inc. and PTI Holdco (incorporated by reference to Exhibit 10.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.4
-
Voting and Exchange Trust Agreement by and among Oil States International, Inc., PTI Holdco and Montreal Trust Company of Canada (incorporated by reference to Exhibit 10.4 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.5**
-
Second Amended and Restated 2001 Equity Participation Plan effective February 19, 2013 (incorporated by reference to Exhibit 10.1 to the Company’s' Quarterly Report on Form 10-Q, as filed with the Commission on July 31, 2013 (File No. 001-16337)).
10.6**
-
Deferred Compensation Plan effective January 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as filed with the Commission on April 25, 2013 (File No. 001-16337)).
10.7**
-
Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.8**
-
Executive Agreement between Oil States International, Inc. and Cindy B. Taylor (incorporated by Reference to Exhibit 10.9 to the Company's Annual Report on Form 10-K for the year ended December 31, 2000, as filed with the Commission on March 30, 2001 (File No. 001-16337)).
10.9**
-
Form of Change of Control Severance Plan for Selected Members of Management (incorporated by reference to Exhibit 10.11 of the Company's Registration Statement on Form S-1, as filed with the Commission on December 12, 2000 (File No. 333-43400)).
10.10
-
Credit Agreement, dated as of October 30, 2003, among Oil States International, Inc., the Lenders named therein and Wells Fargo Bank Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12 to the Company's Quarterly Report on Form 10-Q for the three months ended September 30, 2003, as filed with the Commission on November 12, 2003 (File No. 001-16337)).
10.10A
-
Incremental Assumption Agreement, dated as of May 10, 2004, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12A to the Company's Quarterly Report on Form 10-Q for the three months ended June 30, 2004, as filed with the Commission on August 4, 2004 (File No. 001-16337)).
10.10B
-
Amendment No. 1, dated as of January 31, 2005, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, Texas, National Association, as Administrative Agent and U.S. Collateral Agent; and Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Hibernia National Bank and Royal Bank of Canada, as Co-Syndication Agents and Bank One, NA and Credit Lyonnais New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12B to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.10C
-
Amendment No. 2, dated as of December 5, 2006, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.12C to the Company's Current Report on Form 8-K, as filed with the Commission on December 8, 2006 (File No. 001-16337)).
10.10D
-
Incremental Assumption Agreement, dated as of December 13, 2007, among Oil States International, Inc., Wells Fargo, National Association and each of the other lenders listed as an Increasing Lender (incorporated by reference to Exhibit 10.12D to the Company's Current Report on Form 8-K, as filed with the Commission on December 18, 2007 (File No. 001-16337)).
10.10E
-
Amendment No. 3, dated as of October 1, 2009, to the Credit Agreement among Oil States International, Inc., the lenders named therein and Wells Fargo Bank, N.A., as Lead Arranger, U.S. Administrative Agent and U.S. Collateral Agent; and The Bank of Nova Scotia, as Canadian Administrative Agent and Canadian Collateral Agent; Capital One N.A. and Royal Bank of Canada, as Co-Syndication Agents and JP Morgan Chase Bank, N.A. and Calyon New York Branch, as Co-Documentation Agents (incorporated by reference to Exhibit 10.11E to the Company's Current Report on Form 8-K, as filed with the Commission on October 2, 2009 (File No. 001-16337)).
10.10F
-
Amended and Restated Credit Agreement, dated as of December 10, 2010, among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., as borrowers, the lenders named therein and Wells Fargo Bank, N.A., as Administrative Agent, U.S. Collateral Agent, the U.S. Swing Line Lender and an Issuing Bank; and Royal Bank of Canada, as Canadian Administrative Agent, Canadian Collateral Agent and the Canadian Swing Line Lender; JP Morgan Chase Bank, N.A., as Syndication Agent and Wells Fargo Securities, LLC, RBC Capital Markets and JP Morgan Securities, LLC, as Co-Lead Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, as filed with the Commission on December 20, 2010 (File No. 001-16337)).
10.10G
-
Facility Agreement dated July 13, 2011, between The MAC Services Group Pty Limited and National Australia Bank Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on July 15, 2011 (File No. 001-16337)).
10.10H
-
Syndicated Facility Agreement, dated as of September 18, 2012, among The MAC Services Group Pty Limited, as Borrower, the Lenders named therein, J.P. Morgan Australia Limited, as Australian Agent and Security Trustee, JPMorgan Chase Bank, N.A., as U.S. Agent, Issuing Bank and Swing Line Lender (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).
10.10I
-
Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of September 18, 2012, among Oil States International, Inc., PTI Group Inc., PTI Premium Camp Services Ltd., each of the Guarantors named therein, the Lenders party thereto and Wells Fargo Bank, N.A., as administrative agent for the Lenders (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K, as filed with the Commission on September 18, 2012 (File No. 001-16337)).
10.11**
-
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.14 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, as filed with the Commission on November 5, 2004 (File No. 001-16337)).
10.12**
-
Form of Director Stock Option Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.13**
-
Form of Employee Non Qualified Stock Option Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.19 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.14**
-
Form of Restricted Stock Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.20 to the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Commission on March 2, 2005 (File No. 001-16337)).
10.15**
-
Non-Employee Director Compensation Summary (incorporated by reference to Exhibit 10.21 to the Company's Report on Form 8-K as filed with the Commission on November 15, 2006 (File No. 001-16337)).
10.16**
-
Executive Agreement between Oil States International, Inc. and named executive officer (Mr. Cragg) (incorporated by reference to Exhibit 10.22 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, as filed with the Commission on April 29, 2005 (File No. 001-16337)).
10.17**
-
Form of Non-Employee Director Restricted Stock Agreement under the Company's 2001 Equity Participation Plan (incorporated by reference to Exhibit 10.22 to the Company's Report on Form 8-K, as filed with the Commission on May 24, 2005 (File No. 001-16337)).
10.18**
-
Executive Agreement between Oil States International, Inc. and named executive officer (Bradley Dodson) effective October 10, 2006 (incorporated by reference to Exhibit 10.24 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, as filed with the Commission on November 3, 2006 (File No. 001-16337)).
10.19**
-
Executive Agreement between Oil States International, Inc. and named executive officer (Ron R. Green) effective May 17, 2007 (incorporated by reference to Exhibit 10.25 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, as filed with the Commission on August 2, 2007 (File No. 001-16337)).
10.20**
-
Amendment to the Executive Agreement of Cindy Taylor, effective January 1, 2009 (incorporated by reference to Exhibit 10.21 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.21**
-
Amendment to the Executive Agreement of Bradley Dodson, effective January 1, 2009 (incorporated by reference to Exhibit 10.22 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.22**
-
Amendment to the Executive Agreement of Christopher Cragg, effective January 1, 2009 (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.23**
-
Amendment to the Executive Agreement of Ron Green, effective January 1, 2009 (incorporated by reference to Exhibit 10.25 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.24**
-
Amendment to the Executive Agreement of Robert Hampton, effective January 1, 2009 (incorporated by reference to Exhibit 10.26 to the Company's Annual Report on Form 10-K for the year ended December 31, 2008, as filed with the Commission on February 20, 2009 (File No. 001-16337)).
10.25**
-
Executive Agreement between Oil States International, Inc. and named executive officer (Charles Moses), effective March 4, 2010 (incorporated by reference to Exhibit 10.26 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, as filed with the Commission on April 30, 2010 (File No. 001-16337)).
10.26**
-
Call Option Agreement, dated October 15, 2010, by and between Marley Holdings Pty Limited and PTI Holding Company 2 Pty Limited (incorporated by reference to Exhibit 10.1 to Oil States’ Current Report on Form 8-K, as filed with the Commission on October 5, 2010 (File No. 001-16337)).
10.27**
-
Assignment Letter between the Company and Ron Green effective May 3, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on May 6, 2011 (File No. 001-16337)).
10.28**
-
Deferred Stock Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, as filed with the Commission on February 23, 2012 (File No. 001-16337)).
10.29**
-
Deferred Stock Agreement effective February 19, 2013 (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as filed with the Commission on April 25, 2013 (File No. 001-16337)).
10.30**
-
Canadian Long Term Incentive Plan effective February 19, 2013 (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, as filed with the Commission on April 25, 2013 (File No. 001-16337)).
10.31***
-
Executive Agreement between Oil States International, Inc. and named executive officer (Lloyd A. Hajdik) effective December 9, 2013.
21.1*
-
List of subsidiaries of the Company.
23.1*
-
Consent of Independent Registered Public Accounting Firm.
24.1*
-
Powers of Attorney for Directors.
31.1***
-
Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
31.2***
-
Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934.
32.1***
-
Certification of Chief Executive Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
32.2***
-
Certification of Chief Financial Officer of Oil States International, Inc. pursuant to Rules 13a-14(b) or 15d-14(b) under the Securities Exchange Act of 1934.
101.INS*
-
XBRL Instance Document
101.SCH*
-
XBRL Taxonomy Extension Schema Document
101.CAL*
-
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*
-
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*
-
XBRL Taxonomy Extension Label Linkbase Document
101.PRE*
-
XBRL Taxonomy Extension Presentation Linkbase Document
---------
* Filed herewith
** Management contracts or compensatory plans or arrangements
*** Furnished herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on February 24, 2014.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on February 24, 2014.
Signature
Title
/s/ STEPHEN A. WELLS*
Chairman of the Board
Stephen A. Wells
/s/ CINDY B. TAYLOR
Director, President & Chief Executive Officer
Cindy B. Taylor
(Principal Executive Officer)
/s/ LLOYD A. HAJDIK
Senior Vice President, Chief Financial Officer
Lloyd A. Hajdik
and Treasurer
(Principal Financial Officer)
/s/ ROBERT W. HAMPTON
Senior Vice President -Accounting and Corporate Secretary
Robert W. Hampton
(Principal Accounting Officer)
/s/ MARTIN A. LAMBERT*
Director
Martin A. Lambert
/s/ S. JAMES NELSON, JR.*
Director
S. James Nelson, Jr.
/s/ MARK G. PAPA*
Director
Mark G. Papa
/s/ GARY L. ROSENTHAL*
Director
Gary L. Rosenthal
/s/ CHRISTOPHER T. SEAVER*
Director
Christopher T. Seaver
/s/ DOUGLAS E. SWANSON*
Director
Douglas E. Swanson
/s/ WILLIAM T. VAN KLEEF*
Director
William T. Van Kleef
*By:
/s/ LLOYD A. HAJDIK
Lloyd A. Hajdik, pursuant to a power of
attorney filed as Exhibit 24.1 to this
Annual Report on Form 10-K
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Oil States International, Inc.:
We have audited the accompanying consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oil States International, Inc. and subsidiaries at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 Framework) and our report dated February 24, 2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 24, 2014
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Oil States International, Inc.:
We have audited Oil States International, Inc. and subsidiaries’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Oil States International, Inc. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s annual report on internal control over financial reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As indicated in the accompanying Management's annual report on internal control over financial reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the business acquired from Quality Connector Systems, LLC, which is included in the 2013 consolidated financial statements of Oil States International, Inc. and subsidiaries and constituted 1.2 percent of total assets as of December 31, 2013 and less than 1 percent of revenues for the year then ended. Our audit of internal control over financial reporting of Oil States International, Inc. and subsidiaries’ also did not include an evaluation of the internal control over financial reporting of the business acquired from Quality Connector Systems, LLC.
In our opinion, Oil States International, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Oil States International, Inc. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013 and our report dated February 24, 2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, Texas
February 24, 2014
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In Thousands, Except Per Share Amounts)
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In Thousands)
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Amounts)
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In Thousands)
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
The accompanying notes are an integral part of these financial statements.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
The Consolidated Financial Statements include the accounts of Oil States International, Inc. (Oil States or the Company) and its consolidated subsidiaries. Investments in unconsolidated affiliates, in which the Company is able to exercise significant influence, are accounted for using the equity method. All significant intercompany accounts and transactions between the Company and its consolidated subsidiaries have been eliminated in the accompanying Consolidated Financial Statements.
In September 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu Tubulars America, Inc. (Marubeni-Itochu) for the sale of Sooner, Inc. and its subsidiaries (Sooner), which comprised the entirety of the Company’s tubular services segment. The applicable assets and liabilities of this business have been classified as held for sale in the Consolidated Balance Sheet as of December 31, 2012. The Consolidated Statements of Income for all periods presented have been reclassified to reflect the presentation of discontinued operations. Unless otherwise indicated, all disclosures and amounts in the Notes to Consolidated Financial Statements relate to the Company’s continuing operations.
The Company, through its subsidiaries, is a leading provider of specialty products and services to natural resources companies throughout the world. We operate in a substantial number of the world's active oil, natural gas and coal producing regions, including Canada, onshore and offshore U.S., Australia, West Africa, the North Sea, South America and Southeast and Central Asia. The Company operates in three principal reportable business segments - accommodations, offshore products and well site services.
2. Summary of Significant Accounting Policies
Cash and Cash Equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Fair Value of Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, investments, receivables, payables, bank debt and foreign currency forward contracts. The Company believes that the carrying values of these instruments on the accompanying consolidated balance sheets approximate their fair values.
The fair values of the Company’s 6 1/2% Notes and 5 1/8% Notes are estimated based on quoted prices and analysis of similar instruments (Level 2 fair value measurements). The carrying values and fair values of these notes are as follows for the periods indicated (in thousands):
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Restricted Cash
At December 31, 2013, cash of $5.3 million was held in escrow in accounts and were subject to terms of acquisition agreements providing for contingent consideration and seller representation and warranty provisions and are included in “Other noncurrent assets” in our Consolidated Balance Sheets.
Inventories
Inventories consist of oilfield products, manufactured equipment, spare parts for manufactured equipment, work-in-process, raw materials and supplies and materials for the construction and operation of remote accommodation facilities. Inventories also include food, raw materials, labor, subcontractor charges, manufacturing overhead and catering and other supplies. Inventories are carried at the lower of cost or market. The cost of inventories is determined on a standard cost, average cost or specific-identification method. A reserve for excess, damaged and/or obsolete inventory is maintained based on the age, turnover or condition of the inventory.
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost or at estimated fair market value at acquisition date if acquired in a business combination, and depreciation is computed, for assets owned or recorded under capital lease, using the straight-line method, after allowing for salvage value where applicable, over the estimated useful lives of the assets. We use the component depreciation method for our drilling services and Australian accommodations assets. Leasehold improvements are capitalized and amortized over the lesser of the life of the lease or the estimated useful life of the asset.
Expenditures for repairs and maintenance are charged to expense when incurred. Expenditures for major renewals and betterments, which extend the useful lives of existing equipment, are capitalized and depreciated. Upon retirement or disposition of property and equipment, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is recognized in the statements of income.
Asset Retirement Obligations
We recognize initial estimated asset retirement obligations (ARO) related to our properties as liabilities, with an associated increase in property and equipment for the asset’s estimated retirement cost. The obligation is expensed over the estimated productive life of the related assets. If the fair value of the estimated ARO changes, an adjustment is recorded to both the ARO and the capitalized asset. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling the ARO. The Company relieves ARO liabilities when the related obligations are settled. At December 31, 2013 and 2012, $6.1 million and $5.5 million, respectively, of ARO was included in the Consolidated Balance Sheet in “Other noncurrent liabilities.” The ARO liability reflects the estimated present value of the amount of asset removal and site reclamation costs related to the retirement of assets in the Company’s accommodations business. Total expense related to the ARO was $0.3 million in 2013 and 2012. There was no expense related to the ARO in 2011. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties and a risk-adjusted discount rate in order to determine the current present value of the obligation.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price paid for acquired businesses over the allocated fair value of the related net assets after impairments, if applicable. Goodwill is stated net of accumulated amortization of $11 million as of December 31, 2013 and 2012.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
We evaluate goodwill for impairment annually and when an event occurs or circumstances change to suggest that the carrying amount may not be recoverable. Our reporting units with goodwill include accommodations, offshore products and completion services. In accordance with current accounting standards, we are given the option to test for impairment of our goodwill by first performing a qualitative assessment to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carryingamount, including goodwill. If it is determined that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing the currently prescribed two-step impairment test is unnecessary. In developing a qualitative assessment to meet the “more-likely-than-not” threshold, each reporting unit with goodwill on its balance sheet is assessed separately and different relevant events and circumstances are evaluated for each unit. If it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then the prescribed two-step impairment test is performed. Current accounting standards also give us the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test. In 2013, the Company chose to bypass the qualitative assessment for all of its reporting units with goodwill remaining and perform the two-step impairment test. In performing the two-step impairment test, we compare the reporting unit's carrying amount, including goodwill, to the implied fair value (IFV) of the reporting unit. The IFV of the reporting units are estimated using an analysis of trading multiples of comparable companies to our reporting units. We also utilize discounted projected cash flows and acquisition multiples analyses in certain circumstances. We discount our projected cash flows using a long-term weighted average cost of capital for each reporting unit based on our estimate of investment returns that would be required by a market participant. If the carrying amount of the reporting unit exceeds its fair value, goodwill is considered impaired, and a second step is performed to determine the amount of impairment, if any. We conduct our annual impairment test as of December of each year. In 2011, 2012 and 2013, our goodwill impairment tests indicated that the fair value of each of our reporting units is greater than its carrying amount.
For intangible assets that we amortize, we review the useful life of the intangible asset and evaluate each reporting period whether events and circumstances warrant a revision to the remaining useful life. We evaluate the remaining useful life of an intangible asset that is not being amortized each reporting period to determine whether events and circumstances continue to support an indefinite useful life. We are required to evaluate our indefinite-lived intangible assets for impairment annually and when an event occurs or circumstances change to suggest the carrying amount may not be recoverable. In performing the impairment test, we compare the fair value of the indefinite-lived intangible asset with its carrying amount with the measurement of the impairment based on the excess of the carrying value over its fair value.
See Note 9 - Goodwill and Other Intangible Assets.
Impairment of Long-Lived Assets
In compliance with current accounting standards regarding the accounting for the impairment or disposal of long-lived assets at the asset group level, the recoverability of the carrying values of long-lived assets, including finite-lived intangible assets, is assessed at a minimum annually, or whenever, in management's judgment, events or changes in circumstances indicate that the carrying value of such asset groups may not be recoverable based on estimated future cash flows. If this assessment indicates that the carrying values will not be recoverable, as determined based on undiscounted cash flows over the remaining useful lives, an impairment loss is recognized. The impairment loss equals the excess of the carrying value over the fair value of the asset group. The fair value of the asset group is based on prices of similar assets, if available, or discounted cash flows. Based on the Company's review, the carrying values of its asset groups are recoverable, and no impairment losses have been recorded for the periods presented.
Foreign Currency and Other Comprehensive Income
Gains and losses resulting from balance sheet translation of foreign operations where a foreign currency is the functional currency are included as a separate component of accumulated other comprehensive income within stockholders' equity representing substantially all of the balances within accumulated other comprehensive income. Remeasurements of intercompany loans denominated in a different currency than the functional currency of the entity that are of a long-term investment nature are recognized as other comprehensive income within stockholders’ equity. Gains and losses resulting from balance sheet remeasurements of assets and liabilities denominated in a different currency than the functional currency, other than intercompany loans that are of a long-term investment nature, are included in the consolidated statements of income as incurred.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Foreign Exchange Risk
A portion of revenues, earnings and net investments in foreign affiliates are exposed to changes in foreign currency exchange rates. We seek to manage our foreign exchange risk in part through operational means, including managing expected local currency revenues in relation to local currency costs and local currency assets in relation to local currency liabilities. In order to reduce our exposure to fluctuations in currency exchange rates, we may also enter into foreign exchange agreements with financial institutions. As of December 31, 2013 and 2012, we had outstanding foreign currency forward purchase contracts with notional amounts of $7.4 million and $12.4 million, respectively, hedging expected cash flows denominated in Euros. As a result of this contract, we recorded other comprehensive income of $0.4 million and a loss of $1.0 million for the years ended December 31, 2013 and 2012, respectively, and a $0.9 million foreign exchange loss related to amounts reclassified from accumulated other comprehensive loss into an expense on the income statement for the year ended December 31, 2013. Foreign exchange losses associated with our operations have totaled $0.8 million in 2013, $2.1 million in 2012 and $1.4 million in 2011 and were included in “Other operating expense.”
Interest Capitalization
Interest costs for the construction of certain long-term assets are capitalized and amortized over the related assets' estimated useful lives. For the years ended December 31, 2013, 2012, and 2011, $0.8 million, $3.5 million and $5.3 million were capitalized, respectively.
Revenue and Cost Recognition
Revenue from the sale of products, not accounted for utilizing the percentage-of-completion method, is recognized when delivery to and acceptance by the customer has occurred, when title and all significant risks of ownership have passed to the customer, collectability is probable and pricing is fixed and determinable. Our product sales terms do not include significant post-delivery obligations. For significant projects, revenues are recognized under the percentage-of-completion method, measured by the percentage of costs incurred to date compared to estimated total costs for each contract (cost-to-cost method). Billings on such contracts in excess of costs incurred and estimated profits are classified as deferred revenue. Costs incurred and estimated profits in excess of billings on percentage-of-completion contracts are recognized as unbilled receivables. Management believes this method is the most appropriate measure of progress on large contracts. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Factors that may affect future project costs and margins include shipyard access, weather, production efficiencies, availability and costs of labor, materials and subcomponents. These factors can significantly impact the accuracy of the Company’s estimates and materially impact the Company’s future reported earnings. Our accommodations segment derives the majority of its revenue from lodging and related ancillary services. Accommodations segment revenue is recognized in the period in which services are provided pursuant to the terms of the contractual relationships with customers. In some contracts, rates may vary over the contract term. In these cases, revenue may be deferred and recognized over a straight-line basis over the contract term. In our well site services segment, revenues are recognized based on a periodic (usually daily) rate or when the services are rendered. Proceeds from customers for the cost of oilfield rental equipment that is damaged or lost downhole are reflected as gains or losses on the disposition of assets after considering the write-off of the remaining net book value of the equipment. For drilling services contracts based on footage drilled, we recognize revenues as footage is drilled. Revenues exclude taxes assessed based on revenues such as sales or value added taxes.
Cost of goods sold includes all direct material and labor costs and those costs related to contract performance, such as indirect labor, supplies, tools and repairs. In our accommodations segment cost of services includes labor, food, utility costs, cleaning supplies, and other costs of operating the accommodations facilities. Selling, general, and administrative costs are charged to expense as incurred.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Income Taxes
The Company follows the liability method of accounting for income taxes in accordance with current accounting standards regarding the accounting for income taxes. Under this method, deferred income taxes are recorded based upon the differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets or liabilities are recovered or settled.
When the Company's earnings from foreign subsidiaries are considered to be indefinitely reinvested, no provision for U.S. income taxes is made for these earnings. If any of the subsidiaries have a distribution of earnings in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the various foreign countries.
In accordance with current accounting standards, the Company records a valuation allowance in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized. Management will continue to evaluate the appropriateness of the valuation allowance in the future based upon the operating results of the Company.
In accounting for income taxes, we are required by the provisions of current accounting standards regarding the accounting for uncertainty in income taxes to estimate a liability for future income taxes. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax regulations. We recognize liabilities for anticipated tax audit issues in the U.S. and other tax jurisdictions based on our estimate of whether, and the extent to which, additional taxes will be due. If we ultimately determine that payment of these amounts is unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine that the liability is no longer necessary. We record an additional charge in our provision for taxes in the period in which we determine that the recorded tax liability is less than we expect the ultimate assessment to be.
Discontinued Operations
The operating results of a component of our business that either has been disposed of or is classified as held for sale are presented as discontinued operation when both of the following conditions are met: (a) the operations and cash flows of the component have been or will be eliminated from our ongoing operations as a result of the disposal transaction and (b) we will not have any significant continuing involvement in the operations of the disposed component. We consider a component of our business to be one that comprises operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of our business.
Receivables and Concentration of Credit Risk
Based on the nature of its customer base, the Company does not believe that it has any significant concentrations of credit risk other than its concentration in the worldwide oil and gas and Australian mining industries. The Company evaluates the credit-worthiness of its significant, new and existing customers' financial condition and, generally, the Company does not require significant collateral from its customers.
Allowances for Doubtful Accounts
The Company maintains allowances for doubtful accounts for estimated losses resulting from the inability of the Company's customers to make required payments. If a trade receivable is deemed to be uncollectible, such receivable is charged-off against the allowance for doubtful accounts. The Company considers the following factors when determining if collection of revenue is reasonably assured: customer credit-worthiness, past transaction history with the customer, current economic industry trends, customer solvency and changes in customer payment terms. If the Company has no previous experience with the customer, the Company typically obtains reports from various credit organizations to ensure that the customer has a history of paying its creditors. The Company may also request financial information, including financial statements or other documents to ensure that the customer has the means of making payment. If these factors do not indicate collection is reasonably assured, the Company would require a prepayment or other arrangement to support revenue recognition and recording of a trade receivable. If the financial condition of the Company's customers were to deteriorate, adversely affecting their ability to make payments, additional allowances would be required.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Earnings per Share
Diluted EPS amounts include the effect of the Company's outstanding stock options and restricted stock shares under the treasury stock method. We have shares of restricted stock issued and outstanding, some of which remain subject to vesting requirements. Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute earnings per share (EPS) amounts under the two class method in periods in which we have earnings from continuing operations.
The presentation of basic EPS amounts on the face of the accompanying consolidated statements of operations is computed by dividing the net income applicable to the Company’s common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except that the denominator includes dilutive common stock equivalents and the income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any.
In addition, before their conversion in July 2012, shares of our 2 3/8% Contingent Convertible Senior Subordinated Notes (2 3/8% Notes) assumed to be issued upon conversion were included in the calculation of fully diluted shares outstanding and fully diluted earnings per share. The weighted average number of these shares totaled 1,793,244 and 3,023,420 during the years ended December 31, 2012 and December 31, 2011, respectively.
Stock-Based Compensation
Current accounting standards regarding share-based payments require companies to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period. In addition to service based awards, in 2013 and 2012 the Company also issued performance based awards which may vest in an amount that will depend on the Company’s achievement of specified performance objectives. The performance based awards have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital. During 2013 and 2012, the Company also granted phantom shares under the Canadian Long-Term Incentive Plan, which provides for the granting of units of phantom shares to key Canadian employees. These awards vest in equal annual installments and are accounted for as a liability based on the fair value of the Company’s stock price. Participants granted units of phantom shares are entitled to a lump sum cash payment equal to the fair market value of a share of the Company’s common stock on the vesting date. During the years ended December 31, 2013, 2012 and 2011, the continuing operations of the Company recognized non-cash general and administrative expenses for stock options, restricted stock awards and deferred stock awards totaling $25.0 million, $17.4 million and $13.4 million, respectively. The Company accounts for assets held in a Rabbi Trust for certain participants under the Company's deferred compensation plan in accordance with current accounting standards as described in Note 15.
In connection with the September 2013 sale of our tubular services business, Sooner, modifications were made to outstanding equity options and awards for Sooner employees which resulted in $4.4 million in expense being recognized. This expense is included in “Net income from discontinued operations, net of tax” on the Consolidated Statement of Income for the year ended December 31, 2013 and is included in the transaction costs considered in the calculation of the $128.4 million pre-tax gain on the disposal of Sooner.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Guarantees
The Company applies current accounting standards regarding guarantor's accounting and disclosure requirements for guarantees, including indirect indebtedness of others, for the Company's obligations under certain guarantees.
Some product sales in our offshore products and accommodations businesses are sold with a warranty, generally ranging from 12 to 18 months. Parts and labor are covered under the terms of the warranty agreement. Warranty provisions are estimated based upon historical experience by product, configuration and geographic region. Our total liability related to estimated warranties was $2.4 million and $1.8 million at December 31, 2013 and 2012, respectively.
During the ordinary course of business, the Company also provides standby letters of credit or other guarantee instruments to certain parties as required for certain transactions initiated by either the Company or its subsidiaries. As of December 31, 2013, the maximum potential amount of future payments that the Company could be required to make under these guarantee agreements (letters of credit) was approximately $39.2 million. The Company has not recorded any liability in connection with these guarantee arrangements. The Company does not believe, based on historical experience and information currently available, that it is likely that any amounts will be required to be paid under these guarantee arrangements.
Use of Estimates
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires the use of estimates and assumptions by management in determining the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Examples of a few such estimates include potential future adjustments as a result of contingent consideration arrangements pursuant to business combinations and other contractual agreements, revenue and income recognized on the percentage-of-completion method, estimates of the amount and timing of costs to be incurred for asset retirement obligations, any valuation allowance recorded on net deferred tax assets, warranty, reserves on inventory and allowance for doubtful accounts. Actual results could materially differ from those estimates.
Accounting for Contingencies
We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on their fair value or our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include future consideration due sellers as a result of the terms of a business combination, litigation, taxes, interest, insurance claims, warranty claims, contract claims and obligations and discontinued operations.
Subsequent Events
In accordance with authoritative guidance, the Company evaluates all events and transactions that occur after the balance sheet date, but before financial statements are issued for possible recognition or disclosure.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
3. Details of Selected Balance Sheet Accounts
Additional information regarding selected balance sheet accounts at December 31, 2013 and 2012 is presented below (in thousands):
Depreciation expense was $261.2 million, $214.2 million and $173.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.
4. Recent Accounting Pronouncements
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
5. Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income decreased from $107.1 million at December 31, 2012 to an accumulated other comprehensive loss of $85.7 million at December 31, 2013, a net change of $192.8 million, primarily as a result of decreases in the Canadian and Australian dollar exchange rates compared to the U.S. dollar. The Canadian dollar was valued at an exchange rate of U.S. $0.94 at December 31, 2013 compared to U.S. $1.01 at December 31, 2012, a decrease of 6%. The Australian dollar was valued at an exchange rate of U.S. $0.89 at December 31, 2013 compared to U.S. $1.04 at December 31, 2012, a decrease of 14%. Excluding intercompany balances, our Canadian dollar and Australian dollar functional currency net assets totaled approximately C$983 million and A$957 million and C$785 million and A$869 million, respectively, at December 30, 2013 and 2012.
6. Acquisitions and Supplemental Cash Flow Information
Components of cash used for acquisitions as reflected in the consolidated statements of cash flows for the years ended December 31, 2013, 2012 and 2011 are summarized as follows (in thousands):
On December 2, 2013, we acquired all of the equity of Quality Connector Systems, LLC (QCS). Headquartered in Houston, Texas, QCS designs, manufactures and markets a portfolio of proprietary deep and shallow water pipeline connectors for subsea pipeline construction, repair and expansion projects. Subject to customary post-closing adjustments, total cash consideration was $42.5 million. The operations of QCS have been included in our offshore products segment since the acquisition date.
On December 14, 2012, we acquired all of the equity of Tempress Technologies, Inc. (Tempress) for purchase price consideration of $49.8 million consisting of $32.8 million in cash plus contingent consideration with an estimated fair value of $17.0 million at closing. During 2013, the estimated fair market value of the contingent liability was increased to $20.0 million due to favorable developments related to a patent application by Tempress, resulting in a $3.0 million, or $0.05 per diluted share, charge to other operating expense. The patent was granted in the third quarter of 2013 and the $20.0 million of contingent consideration was paid to the former shareholders of Tempress. The Company’s current escrowed deposits of $5.3 million include other consideration for seller transaction indemnities, are considered restricted cash and are classified as “Other current assets” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent assets” in our December 31, 2012 Consolidated Balance Sheet. Liabilities for escrowed amounts expected to be paid to the seller also totaled $5.3 million and are classified as “Other current liabilities” in our December 31, 2013 Consolidated Balance Sheet and “Other noncurrent liabilities” in our December 31, 2012 Consolidated Balance Sheet. Headquartered in Kent, Washington, Tempress designs, develops and markets a suite of highly specialized, hydraulically-activated tools utilized during downhole completion activities. The operations of Tempress have been included in our well site services segment since the acquisition date.
On July 2, 2012, we acquired Piper Valve Systems, Ltd (Piper). Headquartered in Oklahoma City, Oklahoma, Piper designs and manufactures high pressure valves and manifold components for oil and gas industry projects offshore (surface and subsea) and onshore. Piper's valve technology complements our offshore products segment, allowing us to integrate their valve products and services into our existing subsea products such as pipeline end manifolds and terminals, increasing our suite of global deepwater product and service offerings. Cash consideration paid for the acquisition totaled $48.0 million. The operations of Piper have been included in our offshore products segment since the acquisition date.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
In December 2010, we acquired all of the operating assets of Mountain West Oilfield Service and Supplies, Inc. and Ufford Leasing LLC (Mountain West) for total consideration of $47.1 million including estimated contingent consideration of $4.0 million. During the first quarter of 2013, the liability for the estimated contingent consideration recorded in connection with this transaction was adjusted to its estimated fair value of zero resulting in income of $4.0 million, recorded in “other operating expense, net” in our consolidated income statement. Contingent consideration for the Mountain West acquisition was estimated based upon the amount of earnings before interest, depreciation, amortization and taxes expected to be earned by the acquired business during the three-year period ended December 31, 2013, subject to adjustment for capital spending levels.
The Company funded all of its acquisitions with cash on hand and/or draws under our credit facilities. See Note 10 - Long-term Debt for additional information on our credit facilities.
Supplemental Cash Flow Information
Cash paid during the years ended December 31, 2013, 2012 and 2011 for interest and income taxes was as follows (in thousands):
7. Discontinued Operations
On September 6, 2013, the Company entered into a Stock Purchase Agreement with Marubeni-Itochu for the sale of Sooner, which comprised the entirety of the Company’s tubular services segment. Total consideration received by the Company was $600 million, which remains subject to customary post-closing adjustments. We recognized a net gain on disposal of $128.4 million ($84.0 million after-tax), which is included within “Net income from discontinued operations, net of tax”.
In connection with this transaction, the parties have entered into a transition services agreement for the Company to provide certain information technology applications and infrastructure and various administrative services to Sooner during the transition period ranging from one to three months from the closing date depending on the nature of the service provided in exchange for monthly service fees. Either party has the option to terminate such transition services with notice at any time and Sooner may also request to extend such services. The transition services were extended through February 2014. The future continuing cash flows from the disposed business to the Company resulting from the transition services agreement are not significant and do not constitute a material continuing financial interest in Sooner.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Sooner, which had previously been presented as a separate reporting unit, meets the criteria for being reported as a discontinued operation and has been reclassified from continuing operations. The amounts in the table below reflect the operating results of Sooner reported as discontinued operations for the years ended December 31, 2013, 2012 and 2011 (in thousands) and includes the $128.4 million ($84.0 after-tax) net gain related to the disposal of Sooner.
The following table summarizes the major classes of assets and liabilities held for sale in the Company’s Consolidated Balance Sheet related to Sooner (in thousands):
8. Earnings Per Share (EPS)
Our calculations of diluted earnings per share for the years ended December 31, 2013, 2012 and 2011 exclude 263,838 shares, 399,134 shares and 179,804 shares, respectively, issuable pursuant to outstanding stock options and restricted stock awards, due to their antidilutive effect.
9. Goodwill and Other Intangible Assets
The Company does not amortize goodwill but tests for impairment using a fair value approach, at the "reporting unit" level. A reporting unit is the operating segment, or a business one level below that operating segment (the "component" level) if discrete financial information is prepared and regularly reviewed by management at the component level. The Company had three reporting units with goodwill as of December 31, 2013. Goodwill is allocated to each of the reporting units based on actual acquisitions made by the Company and its subsidiaries. The Company recognizes an impairment loss for any amount by which the carrying amount of a reporting unit's goodwill exceeds the reporting unit's IFV of goodwill. If our initial qualitative assessment of potential goodwill impairment indicates that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, the Company uses, as appropriate in the current circumstance, comparative market multiples, discounted cash flow calculations and acquisition comparables to establish the reporting unit's fair value (a Level 3 fair value measurement).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Company amortizes the cost of other intangibles over their estimated useful lives unless such lives are deemed indefinite. Amortizable intangible assets are reviewed for impairment if there are indicators of impairment based on undiscounted cash flows and, if impaired, written down to fair value based on either discounted cash flows or appraised values. Intangible assets with indefinite lives are tested for impairment annually by comparing the fair value of the indefinite-lived intangible asset to its carrying value with the measurement of the impairment based on the excess of the carrying value over its fair value. As of December 31, 2013, no provision for impairment of other intangible assets was required.
Changes in the carrying amount of goodwill for the years ended December 31, 2013 and 2012 are as follows (in thousands):
The following table presents the total amount of intangibles assigned and the total accumulated amortization for major intangible asset classes as of December 31, 2013 and 2012 (in thousands):
The weighted average remaining amortization period for all intangible assets, other than goodwill and indefinite- lived intangibles, was 8.9 years as of December 31, 2013 and 8.6 years as of December 31, 2012. Total amortization expense is expected to be $15.0 million in 2014, $13.4 million in each of 2015 and 2016, $13.2 million in 2017 and $13.1 million in 2018. Amortization expense was $15.3 million, $13.6 million and $13.2 million in the years ended December 31, 2013, 2012 and 2011, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
10. Long-term Debt
As of December 31, 2013 and 2012, long-term debt consisted of the following (in thousands):
Scheduled maturities of combined long-term debt as of December 31, 2013, are as follows (in thousands):
The Company's capital leases consist primarily of plant facilities and equipment. The value of capitalized leases and the related accumulated depreciation totaled $1.7 million and $0.6 million, respectively, at December 31, 2013. The value of capitalized leases and the related accumulated depreciation totaled $1.4 million and $1.0 million, respectively, at December 31, 2012.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
5 1/8% Senior Unsecured Notes
On December 21, 2012, the Company sold $400 million aggregate principal amount of 5 1/8% Senior Notes due 2023 (5 1/8% Notes) through a private placement to qualified institutional buyers. The 5 1/8% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 5 1/8% per annum and mature on January 1, 2023. At any time prior to January 15, 2016, the Company may redeem up to 35% of the 5 1/8% Notes at a redemption price of 105.125% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after January 15, 2018, the Company may redeem some or all of the 5 1/8% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
The Company utilized approximately $334 million of the net proceeds of the 5 1/8% Notes to repay borrowings under its U.S. revolving credit facility. The remaining net proceeds of approximately $61 million were utilized for general corporate purposes.
On December 21, 2012, in connection with the issuance of the 5 1/8% Notes, the Company entered into an Indenture (the 5 1/8% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The 5 1/8% Notes Indenture restricts the Company's ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 5 1/8% Notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no Default (as defined in the 5 1/8% Notes Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The Indenture contains customary events of default. As of December 31, 2013, the Company was in compliance with all covenants of the 5 1/8% Notes Indenture.
In the fourth quarter of 2013, the Company repurchased $34.0 million aggregate principal amount of the 5 1/8% Notes. As a result of this transaction, the Company recognized a loss on extinguishment of debt of $4.1 million.
6 1/2% Senior Unsecured Notes
On June 1, 2011, the Company sold $600 million aggregate principal amount of 6 1/2% Senior Notes due 2019 (6 1/2% Notes) through a private placement to qualified institutional buyers. The 6 1/2% Notes are senior unsecured obligations of the Company, are guaranteed by our material U.S. subsidiaries (the Guarantors), bear interest at a rate of 6 1/2% per annum and mature on June 1, 2019. At any time prior to June 1, 2014, the Company may redeem up to 35% of the 6 1/2% Notes at a redemption price of 106.500% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. Prior to June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. On and after June 1, 2014, the Company may redeem some or all of the 6 1/2% Notes at redemption prices (expressed as percentages of principal amount), plus accrued and unpaid interest to the redemption date. The optional redemption prices as a percentage of principal amount are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Company utilized approximately $515 million of the net proceeds of the 6 1/2% Note offering in June 2011 to repay borrowings outstanding under its credit facilities. The remaining net proceeds of approximately $75 million were utilized for general corporate purposes.
On June 1, 2011, in connection with the issuance of the 6 1/2% Notes, the Company entered into an Indenture (the 6 1/2% Notes Indenture) with the Guarantors and Wells Fargo Bank, N.A., as trustee. The Indenture restricts the Company's ability and the ability of the Guarantors to: (i) incur additional debt; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 6 1/2% Notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Ratings Services and no Default (as defined in the 6 1/2% Notes Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants. The 6 1/2% Notes Indenture contains customary events of default. As of December 31, 2013, the Company was in compliance with all covenants of the 6 1/2% Notes Indenture.
2 3/8% Contingent Convertible Senior Notes
On May 17, 2012, the Company gave notice of the redemption of all of its outstanding 2 3/8% Notes due 2025 (the 2 3/8% Notes), totaling $175 million at a redemption price equal to 100% of the principal amount thereof plus accrued interest. In July 2012, rather than having their 2 3/8% Notes redeemed, on or prior to July 5, 2012, holders of $174,990,000 aggregate principal amount of the 2 3/8% Notes converted their 2 3/8% Notes and received cash up to the principal amount and, in aggregate, 3,012,380 shares of the Company’s common stock valued at $220.6 million.
An effective interest rate of 7.17% was applied as of the issuance date for our 2 3/8% Notes in accordance with ASC 470-20 - Debt with Conversion and Other Options. Interest expense on the 2 3/8% Notes, excluding amortization of debt issue costs, was as follows (in thousands):
Credit Facilities
Our current bank credit facilities include a U.S. revolving credit facility and a Canadian revolving facility. These credit facilities are governed by an Amended and Restated Credit Agreement dated as of December 10, 2010 (Credit Agreement) by and among the Company, PTI Group Inc., PTI Premium Camp Services, Ltd., the Lenders party thereto, Wells Fargo Bank, N.A., as administrative agent and U.S. collateral agent and Royal Bank of Canada, as Canadian administrative agent and Canadian collateral agent. The U.S. and Canadian bank credit facilities currently contain total commitments available of $750 million, including Total U.S. Commitments (as defined in the Credit Agreement) of U.S. $500 million, and Total Canadian Commitments (as defined in the Credit Agreement) of U.S. $250 million. We repaid Canadian and U.S. term loan balances previously outstanding in full during 2013, which are permanent reductions of availability under our credit facilities. The maturity date of the Credit Agreement is December 10, 2015. Amounts borrowed under these facilities bear interest, at the Company's election, at either:
•
a variable rate equal to LIBOR (or, in the case of Canadian dollar denominated borrowings, the Bankers' Acceptance discount rate) plus a margin ranging from 2.0% to 3.0%; or
•
an alternate base rate equal to the higher of the bank's prime rate and the federal funds effective rate (or, in the case of Canadian dollar denominated borrowings, the Canadian Prime Rate).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Commitment fees ranging from 0.375% to 0.50% per year are paid on the undrawn portion of the facilities, depending upon our leverage ratio.
The credit facilities are guaranteed by all of the Company's active domestic subsidiaries and, in some cases, the Company's Canadian and other foreign subsidiaries. The credit facilities are secured by a first priority lien on all the Company's inventory, accounts receivable and other material tangible and intangible assets, as well as those of the Company's active subsidiaries. However, no more than 65% of the voting stock of any foreign subsidiary is required to be pledged if the pledge of any greater percentage would result in adverse tax consequences.
The Credit Agreement contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Specifically, we must maintain an interest coverage ratio, defined as the ratio of consolidated EBITDA, to consolidated interest expense of at least 3.0 to 1.0 and our maximum leverage ratio, defined as the ratio of total debt to consolidated EBITDA of no greater than 3.0 to 1.0. Each of the factors considered in the calculations of these ratios are defined in the Credit Agreement. EBITDA and consolidated interest as defined, exclude goodwill impairments, debt discount amortization and other non-cash charges. As of December 31, 2013, we were in compliance with our debt covenants. The credit facilities also contain negative covenants that limit the Company's ability to borrow additional funds, encumber assets, pay dividends, sell assets and enter into other significant transactions.
Under the Company's credit facilities, the occurrence of specified change of control events involving our company would constitute an event of default that would permit the banks to, among other things, accelerate the maturity of the facilities and cause them to become immediately due and payable in full.
As of December 31, 2013, we had $33.6 million of outstanding letters of credit, leaving $716.4 million available to be drawn under the facilities.
On September 18, 2012, the Company’s Australian accommodations subsidiary, The MAC Services Group Pty Limited (The MAC), entered into a A$300 million revolving loan facility governed by a Syndicated Facility Agreement (The MAC Group Facility Agreement), between The MAC, J.P. Morgan Australia Limited, as Australian agent and security trustee, JPMorgan Chase Bank, N.A., as U.S. agent, and the lenders party thereto, which is guaranteed by the Company and The MAC’s subsidiaries. The maturity date of The MAC Group Facility Agreement is December 10, 2015. Under the terms of the MAC Group Facility Agreement, loans bear interest for a particular interest period at a rate per annum equal to the sum of the average interest rate paid by banks for loans of the equivalent period and an applicable percentage ranging from 2.00% to 3.00% based upon the Australian Borrower’s leverage ratio. The MAC Group Facility Agreement contains representations, warranties and covenants that are customary for similar credit arrangements, including, among other things, covenants relating to financial reporting and notification, payment of obligations, and notification of certain events. Financial covenants in the MAC Group Facility Agreement also require The MAC not to permit: (i) the interest coverage ratio (the ratio of consolidated EBITDA to consolidated interest expense) to be less than 4.0 to 1.0 for any period of four consecutive fiscal quarters of The MAC; and (ii) the leverage ratio (the ratio of total debt to consolidated EBITDA) to be greater than 3.0 to 1.0 for any period of four consecutive fiscal quarters of The MAC. Each of the factors considered in the calculations of ratios are defined in The MAC Group Facility Agreement. The MAC Group Facility Agreement contains various customary restrictive covenants, subject to certain exceptions, that limit The MAC and its subsidiaries from, among other things, incurring additional indebtedness or guarantees, creating liens or other encumbrances on property, entering into a merger or similar transaction, selling or transferring certain property, making certain restricted payments and entering into transactions with affiliates. As of December 31, 2013, we were in compliance with our Australian debt covenants. The MAC Group Facility Agreement replaced The MAC’s previous A$150 million revolving loan facility. As of December 31, 2013, we had no borrowings outstanding under the The MAC Group Facility Agreement.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
11. Stock Repurchase Program
On September 6, 2013, the Company announced an increase in its Board-authorized Company stock repurchase program from $200 million to $500 million for the repurchase of the Company’s common stock, par value $.01 per share. As of December 31, 2013, the Company had approximately 54.2 million shares of common stock outstanding. The Board of Directors’ authorization is limited in duration and expires on September 1, 2014. Subject to applicable securities laws, such purchases will be at such times and in such amounts as the Company deems appropriate. As of December 31, 2013, a total of $131.2 million of our stock (1,385,388 shares) had been repurchased under this program, leaving a total authorization of up to approximately $368.8 million remaining available under the program at year end. Through January 27, 2014, we had purchased an additional 1,009,665 shares for $100.0 million leaving $268.8 million remaining under the program.
12. Retirement Plans
The Company sponsors defined contribution plans. Participation in these plans is available to substantially all employees. The Company recognized expense of $28.2 million, $26.6 million and $19.4 million, respectively, related to matching contributions under its various defined contribution plans during the years ended December 31, 2013, 2012 and 2011, respectively.
13. Income Taxes
Consolidated pre-tax income (loss) for the years ended December 31, 2013, 2012 and 2011 consisted of the following (in thousands):
The components of the income tax provision for the years ended December 31, 2013, 2012 and 2011 consisted of the following (in thousands):
The provision for taxes differs from an amount computed at U.S. statutory rates as follows for the years ended December 31, 2013, 2012 and 2011 consisted (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The significant items giving rise to the deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows (in thousands):
Reclassifications of the Company's deferred tax balance based on net current items and net non-current items as of December 31, 2012 and 2011 are as follows (in thousands):
The analysis of deferred tax assets and liabilities detailed above as of December 31, 2012 relate to continuing and discontinued operations.
Our primary deferred tax assets at December 31, 2013, were related to employee benefit costs for our Equity Participation Plan, deductible goodwill and other intangibles, allowance for inventory obsolescence and foreign tax credit carryforwards. The foreign tax credits will expire in varying amounts after 2019.
Our income tax provision for the year ended December 31, 2013 totaled $120.0 million, or 27.50% of pretax income, compared to $149.0 million, or 27.01% of pretax income, for the year ended December 31, 2012. Our income tax provision for the year ended December 31, 2011 totaled $107.6 million or 27.50% of pretax income.
Appropriate U.S. and foreign income taxes have been provided for earnings of foreign subsidiary companies that are expected to be remitted in the near future. The cumulative amount of undistributed earnings of foreign subsidiaries that the Company intends to indefinitely reinvest, and upon which foreign taxes have been accrued or paid but no deferred US income taxes have been provided is $1.3 billion at December 31, 2013, the majority of which has been generated in Canada and Australia. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to U.S. income taxes (subject to adjustment for foreign tax credits) and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings after consideration of available foreign tax credits.
The American Jobs Creation Act of 2004 that was signed into law in October 2004 introduced a requirement for companies to disclose any penalties imposed on them or any of their consolidated subsidiaries by the IRS for failing to satisfy tax disclosure requirements relating to "reportable transactions." During the year ended December 31, 2013, no penalties were imposed on the Company or its consolidated subsidiaries for failure to disclose reportable transactions to the IRS.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The Company files tax returns in the jurisdictions in which they are required. All of these returns are subject to examination or audit and possible adjustment as a result of assessments by taxing authorities. The Company believes that it has recorded sufficient tax liabilities and does not expect the resolution of any examination or audit of its tax returns would have a material adverse effect on its operating results, financial condition or liquidity.
Tax years subsequent to 2009 remain open to U.S. federal tax audit and, because of Net Operating Losses (NOL's) utilized by the Company, years from 1994 to 2002 remain subject to federal tax audit with respect to NOL's available for tax carryforward. Our Canadian subsidiaries' federal tax returns subsequent to 2008 are subject to audit by the Canada Revenue Agency. Our Australian subsidiary’s federal tax returns subsequent to 2007 are subject to audit by the Australian Taxation Office.
We account for uncertain tax positions using a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.
The total amount of unrecognized tax benefits as of December 31, 2013 was $0.8 million. The unrecognized tax benefits, if recognized, would affect the effective tax rate. The Company accrues interest and penalties related to unrecognized tax benefits as a component of the Company's provision for income taxes. As of December 31, 2013 and 2012, the Company had accrued $0.1 million and $0.2 million, respectively, of interest expense and penalties.
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):
It is reasonably possible that the amount of unrecognized tax benefits will change during the next twelve months due to the closing of the statute of limitations and that change, if it were to occur, could have a favorable or unfavorable impact on our results of operation.
14. Commitments and Contingencies
The Company leases a portion of its equipment, office space, computer equipment, automobiles and trucks under leases which expire at various dates.
Minimum future operating lease obligations in effect at December 31, 2013, were as follows (in thousands):
Rental expense under operating leases was $19.4 million, $16.5 million and $14.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.
The Company is a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials as a result of its products or operations. Some of these claims relate to matters occurring prior to its acquisition of businesses, and some relate to businesses it has sold. In certain cases, the Company is entitled to indemnification from the sellers of businesses, and in other cases, it has indemnified the buyers of businesses from it. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
15. Stock-Based Compensation
Current accounting standards require companies to measure the cost of employee services received in exchange for an award of equity instruments (typically stock options) based on the grant-date fair value of the award. The fair value is estimated using option-pricing models. The resulting cost is recognized over the period during which an employee is required to provide service in exchange for the awards, usually the vesting period.
Stock-based compensation pre-tax expense from continuing operations recognized in the years ended December 31, 2013, 2012 and 2011 totaled $28.9 million, $18.5 million and $13.4 million, or $0.39, $0.24 and $0.17 per diluted share after tax, respectively. Stock-based compensation pre-tax expense from discontinued operations recognized in the years ended December 31, 2013, 2012 and 2011 totaled $5.6 million, $1.5 million and $1.2 million, or $0.07, $0.02 and $0.02 per diluted share after tax, respectively. All tables below reflect activity for both continuing and discontinued operations.
In connection with the 2013 sale of Sooner, modifications were made to outstanding equity options and awards for Sooner employees which resulted in $4.4 million in expense. This expense is included in “Net income from discontinued operations, net of tax” on the Consolidated Statement of Income for the year ended December 31, 2013 and is included in the transaction costs considered in the calculation of the $128.4 million pre-tax gain on the disposal of Sooner.
Stock Options
The fair value of each option grant is estimated on the date of grant using a Black-Scholes option pricing model that uses the assumptions noted in the following table. The risk-free interest rate is based on the U.S. Treasury yield curve in effect for the expected term of the option at the time of grant. The dividend yield on our common stock is assumed to be zero since we do not pay dividends and have no current plans to do so in the future. The expected market price volatility of our common stock is based on an estimate made by us that considers the historical and implied volatility of our common stock as well as a peer group of companies over a time period equal to the expected term of the option. The expected life of the options awarded in 2013, 2012 and 2011 was based on a formula considering the vesting period, term of the options awarded and past experience.
The following table presents the changes in stock options outstanding and related information for each of the three years ended December 31, 2013, 2012 and 2011:
The weighted average fair values of options granted during 2013, 2012 and 2011 were $28.31, $37.38, and $33.23 per share, respectively. All options awarded in 2013 had a term of ten years and were granted with exercise prices at the grant date closing market price. The total intrinsic value of options exercised during 2013, 2012 and 2011 were $43.6 million, $38.3 million and $24.9 million, respectively. Cash received by the Company from option exercises during 2013, 2012 and 2011 totaled $16.4 million, $13.6 million and $14.2 million, respectively. The tax benefit realized for the tax deduction from stock options exercised during 2013, 2012 and 2011 totaled $7.4 million, $6.9 million and $7.8 million, respectively.
The following table summarizes information for outstanding stock options outstanding at December 31, 2013:
OIL STATES INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Restricted Stock Awards
The following table presents the changes of restricted stock awards and related information for 2013:
During 2013, we granted restricted stock and deferred stock awards totaling 325,733 shares valued at a total of $26.7 million. Of the restricted and deferred stock awards granted in 2013, 278,757 awards vest in four equal annual installments beginning in February 2014, 30,314 awards are performance based awards that may vest in February 2016 in an amount that will depend on the Company’s achievement of specified performance objectives, 9,800 awards vest 100% in May 2014, 3,500 awards vest 100% in February 2014 and 2,750 awards vest 100% in March 2014. The 2013 performance based awards (30,314 shares at target performance level) with three-year cliff vesting have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital for the three year period commencing January 1, 2013 and ending December 31, 2015. During 2013, the Company also granted 71,500 units of phantom shares under the Canadian Long-Term Incentive Plan, which provides for the granting of units of phantom shares to key Canadian employees. These awards vest in three equal annual installments beginning in February 2014 and are accounted for as a liability based on the market price of the Company’s stock. Participants granted units of phantom shares are entitled to a lump sum cash payment equal to the fair market value of a share of the Company’s common stock on the vesting date. A total of 357,544 and 217,415 shares of restricted stock and deferred stock were awarded in 2012 and 2011, respectively, with aggregate values of $29.2 million and $16.3 million, respectively. In 2012, performance shares were awarded (47,625 shares at target level performance) with three-year cliff vesting which have a performance criteria that will be measured based upon the Company’s achievement levels of average after-tax annual return on invested capital for the three year period commencing January 1, 2012 and ending December 31, 2014.
The weighted average grant date fair value per share for restricted stock awards granted in 2013, 2012 and 2011 was $82.05, $84.46 and $74.97, respectively. The total fair value of restricted stock awards vested in 2013, 2012 and 2011 was $18.7 million, $16.1 million and $13.2 million, respectively. As of December 31, 2013, there was $54.8 million of total compensation costs related to nonvested restricted stock and deferred stock awards not yet recognized, which is expected to be recognized over a weighted average period of 2 years.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
At December 31, 2013, a total of 1,783,009 shares were available for future grant under the Equity Participation Plan.
Deferred Compensation Plan
The Company maintains a nonqualified deferred compensation plan (the Deferred Compensation Plan) that permits eligible employees and directors to elect to defer the receipt of all or a portion of their directors’ fees and/or salary and annual bonuses. Employee contributions to the Deferred Compensation Plan are matched by the Company at the same percentage as if the employee was a participant in the Company's 401(k) Retirement Plan and was not subject to the IRS limitations on match-eligible compensation. The Deferred Compensation Plan also permits the Company to make discretionary contributions to any employee's account, although none have been made to date. Director's contributions are not matched by the Company. Since inception of the plan, this discretionary contribution provision has been limited to a matching of the participants' contributions on a basis equivalent to matching permitted under the Company's 401(k) Retirement Savings Plan. The vesting of contributions to the participants’ accounts is also equivalent to the vesting requirements of the Company's 401(k) Retirement Savings Plan. The Deferred Compensation Plan does not have dollar limits on tax-deferred contributions. The assets of the Deferred Compensation Plan are held in a Rabbi Trust (Trust) and, therefore, are available to satisfy the claims of the Company's creditors in the event of bankruptcy or insolvency of the Company. Participants have the ability to direct the Plan Administrator to invest the assets in their individual accounts, including any discretionary contributions by the Company, in ten pre-approved mutual funds held by the Trust which cover a variety of securities and mutual funds. In addition, participants currently have the right to request that the Plan Administrator to re-allocate the portfolio of investments (i.e. cash or mutual funds) in the participants' individual accounts within the Trust. Company contributions are in the form of cash. Distributions from the plan are generally made upon the participants' termination as a director and/or employee, as applicable, of the Company. Participants receive payments from the Deferred Compensation Plan in cash. At December 31, 2013, Trust assets totaled $15.2 million, the majority of which is classified as “Other noncurrent assets” in the Company’s Consolidated Balance Sheet. The fair value of the investments was based on quoted market prices in active markets (a Level 1 fair value measurement). Amounts payable to the plan participants at December 31, 2013, including the fair value of the shares of the Company's common stock that are reflected as treasury stock, was $16.8 million and is classified as "Other noncurrent liabilities" in the consolidated balance sheet. The Company accounts for the Deferred Compensation Plan in accordance with current accounting standards regarding the accounting for deferred compensation arrangements where amounts earned are held in a Rabbi Trust and invested.
In accordance with current accounting standards, all fair value fluctuations of the Trust assets have been reflected in the consolidated statements of income. Increases or decreases in the value of the plan assets, exclusive of the shares of common stock of the Company, have been included as compensation adjustments in the respective statements of income. Increases or decreases in the fair value of the deferred compensation liability, including the shares of common stock of the Company held by the Trust, while recorded as treasury stock, are also included as compensation adjustments in the consolidated statements of income. In response to the changes in total fair value of the Company's common stock held by the Trust, the Company recorded net compensation expense adjustments to the liability of $0.5 million in 2013, ($0.1) million in 2012 and $0.2 million in 2011.
16. Segment and Related Information
In accordance with current accounting standards regarding disclosures about segments of an enterprise and related information, the Company has identified the following reportable segments: well site services, accommodations and offshore products. The Company's reportable segments represent strategic business units that offer different products and services. They are managed separately because each business requires different technologies and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. Separate business lines within the well site services segment have been disclosed to provide additional detail for that segment.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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Financial information by business segment for continuing operations for each of the three years ended December 31, 2013, 2012 and 2011, is summarized in the following table in thousands. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.
Financial information by geographic segment for continuing operations for each of the three years ended December 31, 2013, 2012 and 2011, is summarized below in thousands. Revenues in the United States include export sales. Revenues are attributable to countries based on the location of the entity selling the products or performing the services. Total assets are attributable to countries based on the physical location of the entity and its operating assets and do not include intercompany balances.
Imperial Oil accounted for more than 10% of the Company's revenues in the years ended December 31, 2013, 2012 and 2011. Equity in net income of unconsolidated affiliates is not included in operating income.
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17. Valuation Allowances
Activity in the valuation accounts was as follows (in thousands):
18. Quarterly Financial Information (Unaudited)
The following table summarizes quarterly financial information for 2013 and 2012 (in thousands, except per share amounts):
(1)
Represents "revenues" less "product costs" and "service and other costs" included in the Company's consolidated statements of income.
(2)
In the first quarter of 2013, we recognized a gain of $4.0 million, or $0.05 per diluted share after-tax, from a decrease to a liability associated with contingent acquisition consideration in our U.S. accommodations business. In the first quarter of 2012, we recognized a gain of $17.9 million, or $0.23 per diluted share after-tax, from a favorable contract settlement reported in our U.S. accommodations business.
(3)
In the second quarter of 2013, we recognized a charge of $3.0 million, or $0.05 per diluted share, from an increase in contingent acquisition consideration in our completion services business and we incurred $1.9 million, or $0.02 per diluted share after tax, of transaction costs primarily related to the proposed spin-off of our accommodations segment. In the second quarter of 2012, we recognized a pre-tax gain of $2.5 million, or $0.03 per diluted share after-tax, related to insurance proceeds received in excess of net book value from the constructive total loss of a drilling rig lost in a fire.
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(Continued)
(4)
In the third quarter of 2013, we recognized a net gain on the disposal of our tubular services segment of $128.6 million, or $1.51 per diluted share after-tax, which is included within net income attributable to discontinued operations. In addition, in the third quarter of 2013, we recognized a pre-tax gain on the disposal of land and an associated building of $4.6 million, or $0.06 per diluted share after tax, a pre-tax loss on the extinguishment of debt of $3.3 million, or $0.04 per diluted share after tax and we incurred $2.6 million, or $0.03 per diluted share after tax, of transaction costs related to the proposed spin-off of our accommodations segment.
(5)
In the fourth quarter of 2013, we recognized a pre-tax loss on the extinguishment of debt of $4.1 million, or $0.05 per diluted share after tax, and we incurred $1.6 million, or $0.02 per diluted share after-tax, of transaction costs related to the proposed spin-off of our accommodations segment.
Amounts are calculated independently for each of the quarters presented. Therefore, the sum of the quarterly amounts may not equal the total calculated for the year.
19. Proposed Spin-Off of Accommodations Business
On July 30, 2013, we announced that our Board of Directors approved pursuing the spin-off of our accommodations business into a stand-alone, publicly traded corporation through a tax-free distribution of the accommodations business to the Company’s shareholders. The objective of the spin-off is to more effectively focus on two distinct businesses, achieve lower cost of capital for our accommodations business, to pursue more tailored and aggressive growth strategies and optimize operating efficiencies among other objectives. The spin-off is subject to market conditions, the receipt of an affirmative IRS ruling or independent tax opinion, the completion of a review by the Commission of a Form 10 filed by the accommodations business, the execution of separation and intercompany agreements and final approval of our Board of Directors and is expected to be completed in the second quarter of 2014. In connection with the proposed spin-off, we anticipate that we will refinance our existing debt. Specifically, we intend to commence a tender offer for any and all of our outstanding 5 1/8% Notes and 6 1/2% Notes. We intend to fund this tender offer in part with the proceeds of a cash dividend to be paid to us by the accommodations business immediately prior to the consummation of the proposed spin-off. We anticipate that this cash dividend will be within a range of $650.0 million to $850.0 million. In connection with the spin-off, we also intend to refinance our existing credit facilities with a single, U.S. revolving credit facility. The Accommodations business will initially be spun-off as a C-Corporation, which offers a faster path to separation. The Accommodations business will continue to assess the feasibility and advisability of a potential future conversion into a real estate investment trust (REIT). In connection with this announced spin-off, we anticipate the need to separately capitalize the accommodations business and to refinance the Company’s existing debt.
20. Condensed Consolidating Financial Information
Certain wholly-owned subsidiaries, as detailed below (the Guarantor Subsidiaries), have guaranteed all of our 6 1/2% Notes and 5 1/8% Notes. These guarantees are full and unconditional, subject to the following release provisions:
●
in connection with any sale, exchange or transfer (by merger, consolidation or otherwise) of the capital stock of that guarantor after which that guarantor is no longer a restricted subsidiary;
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upon proper designation of a guarantor by the Company as an unrestricted subsidiary;
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upon the release or discharge of all outstanding guarantees by a guarantor of indebtedness of the Company and its restricted subsidiaries under any credit facility;
●
upon legal or covenant defeasance or satisfaction and discharge of the indenture; or
●
upon the dissolution of a guarantor, provided no event of default has occurred under the indentures and is continuing.
The following condensed consolidating financial information is included so that separate financial statements of the Guarantor Subsidiaries are not required to be filed with the Commission. The condensed consolidating financial information presents investments in both consolidated and unconsolidated affiliates using the equity method of accounting.
The following consolidating financial information presents: condensed consolidating statements of income for each of the years ended December 31, 2013, 2012 and 2011, condensed consolidating balance sheets as December 31, 2013 and December 31, 2012 and the statements of cash flows for each of the years ended December 31, 2013, 2012 and 2011 of (a) the Company, parent/guarantor, (b) Acute Technological Services, Inc., Capstar Holding, L.L.C., Capstar Drilling, Inc., General Marine Leasing, L.L.C., Oil States Energy Services L.L.C., Oil States Energy Services Holding, Inc., OSES International Holding, L.L.C., Oil States Management, Inc., Oil States Industries, Inc., Oil States Skagit SMATCO, L.L.C., PTI Group USA L.L.C., PTI Mars Holdco 1, L.L.C. and Tempress Technologies, Inc. (the Guarantor Subsidiaries), (c) the non-guarantor subsidiaries, (d) consolidating adjustments necessary to consolidate the Company and its subsidiaries and (e) the Company on a consolidated basis.
With our sale of Sooner, Inc. on September 6, 2013, it is no longer a Guarantor Subsidiary. The Condensed Consolidated Statements of Income and Balance Sheets have been reclassified for all periods presented to reflect only the Company’s continuing operations.
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Condensed Consolidating Statements of Income and Comprehensive Income
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Condensed Consolidating Statements of Income and Comprehensive Income
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Condensed Consolidating Statements of Income and Comprehensive Income
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Condensed Consolidating Balance Sheets
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Condensed Consolidating Balance Sheets
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Condensed Consolidating Statements of Cash Flows
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Condensed Consolidating Statements of Cash Flows
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Condensed Consolidating Statements of Cash Flows