UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________________
Form 10-K
(Mark One)
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended December 31, 2013
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
Commission file number 001-08038
KEY ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
Maryland | 04-2648081 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
1301 McKinney Street
Suite 1800
Houston, Texas 77010
(Address of principal executive offices, including Zip Code)
(713) 651-4300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Exchange on Which Registered | |
Common Stock, $0.10 par value | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
None
Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act). Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer ¨ | Non-accelerated filer ¨ | Smaller reporting company ¨ | |||
(Do not check if a smaller reporting company) | ||||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2013, based on the $5.95 per share closing price for the registrant’s common stock as quoted on the New York Stock Exchange on such date, was $778.9 million (for purposes of calculating these amounts, only directors, officers and beneficial owners of 10% or more of the outstanding common stock of the registrant have been deemed affiliates).
As of February 17, 2014, the number of outstanding shares of common stock of the registrant was 152,928,294.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 with respect to the 2014 Annual Meeting of Stockholders are incorporated by reference into Part III of this Form 10-K.
KEY ENERGY SERVICES, INC.
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2013
INDEX
Page Number | ||
PART I | ||
ITEM 1. | ||
ITEM 1A. | ||
ITEM 1B. | ||
ITEM 2. | ||
ITEM 3. | ||
ITEM 4. | ||
PART II | ||
ITEM 5. | ||
ITEM 6. | ||
ITEM 7. | ||
ITEM 7A. | ||
ITEM 8. | ||
ITEM 9. | ||
ITEM 9A. | ||
ITEM 9B. | ||
PART III | ||
ITEM 10. | ||
ITEM 11. | ||
ITEM 12. | ||
ITEM 13. | ||
ITEM 14. | ||
PART IV | ||
ITEM 15. | ||
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about Key Energy Services, Inc. and its wholly owned and controlled subsidiaries, our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “should,” “predicts,” “expects,” “believes,” “anticipates,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties and are not guarantees of performance. Future actions, events and conditions and future results of operations may differ materially from those expressed in these statements. In evaluating those statements, you should carefully consider the risks outlined in “Item 1A. Risk Factors.”
We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date of this report except as required by law. All of our written and oral forward-looking statements are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements.
Important factors that may affect our expectations, estimates or projections include, but are not limited to, the following:
• | conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies; |
• | volatility in oil and natural gas prices; |
• | our ability to finance future growth of our operations or future acquisitions; |
• | our ability to implement price increases or maintain pricing on our core services; |
• | industry capacity; |
• | increased labor costs or unavailability of skilled workers; |
• | asset impairments or other charges; |
• | the periodic low demand for our services and resulting operating losses; |
• | our highly competitive industry as well as operating risks, which are primarily self-insured, and the possibility that our insurance may not be adequate to cover all of our losses or liabilities; |
• | the economic, political and social instability risks of doing business in certain foreign countries; |
• | our historically high employee turnover rate and our ability to replace or add workers; |
• | our ability to incur debt or long-term lease obligations or to implement technological developments and enhancements; |
• | significant costs and liabilities resulting from environmental, health and safety laws and regulations, including those relating to hydraulic fracturing; |
• | severe weather impacts on our business; |
• | our ability to successfully identify, make and integrate acquisitions; |
• | the loss of one or more of our larger customers; |
• | the impact of compliance with climate change legislation or initiatives; |
• | our ability to generate sufficient cash flow to meet debt service obligations; |
• | the amount of our debt and the limitations imposed by the covenants in the agreements governing our debt; |
• | an increase in our debt service obligations due to variable rate indebtedness; and |
• | other factors affecting our business described in “Item 1A. Risk Factors.” |
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PART I
ITEM 1. BUSINESS
General Description of Business
Key Energy Services, Inc. (NYSE: KEG), a Maryland corporation, is the largest onshore, rig-based well servicing contractor based on the number of rigs owned. References to “Key,” the “Company,” “we,” “us” or “our” in this report refer to Key Energy Services, Inc., its wholly owned subsidiaries and its controlled subsidiaries. We were organized in April 1977 and commenced operations in July 1978 under the name National Environmental Group, Inc. In December 1992, we became Key Energy Group, Inc. and we changed our name to Key Energy Services, Inc. in December 1998.
We provide a full range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and we have operations in Mexico, Colombia, Ecuador, the Middle East and Russia. In addition, we have a technology development and control systems business based in Canada.
The following is a description of the various products and services that we provide and our major competitors for those products and services.
Service Offerings
Our reportable segments are U.S. and International. We also have a “Functional Support” segment associated with overhead costs in support of our reportable segments. The U.S. reporting segment includes our domestic rig-based services, fluid management services, fishing and rental services, and coiled tubing services. The International reportable segment includes our operations in Mexico, Colombia, Ecuador, Russia, Bahrain and Oman. Our Canadian subsidiary is also reflected in our International reportable segment. We evaluate the performance of our operating segments based on gross margin measures. All inter-segment sales pricing is based on current market conditions. The following is a description of the segments: See “Note 23. Segment Information” in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our reportable business segments and the various geographical areas where we operate.
U.S. Segment
Rig-Based Services
Our rig-based services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass various sizes and capabilities, allowing us to service all types of wells with depths up to 20,000 feet. Many of our rigs are outfitted with our proprietary KeyView® technology, which captures and reports well site operating data and provides safety control systems. We believe that this technology allows our customers and our crews to better monitor well site operations, improves efficiency and safety, and adds value to the services that we offer.
The completion and recompletion services provided by our rigs prepare wells for production, whether newly drilled, or recently extended through a workover operation. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. Completion services vary by well and our work may take a few days to several weeks to perform, depending on the nature of the completion.
The workover services that we provide are designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover.
Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or natural gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to identify and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform.
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Our rig fleet is also used in the process of permanently shutting-in oil or natural gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.
We believe that the largest competitors for our U.S. rig-based services include Nabors Industries Ltd., Basic Energy Services, Inc., Superior Energy Services, Inc., Forbes Energy Services Ltd. and Pioneer Energy Services Corp. Numerous smaller companies also compete in our rig-based markets in the United States.
Fluid Management Services
We provide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal (“SWD”) wells owned by us or a third party. Demand and pricing for these services generally correspond to demand for our well service rigs.
We believe that the largest competitors for our domestic fluid management services include Basic Energy Services, Inc., Superior Energy Services, Inc., Nabors Industries Ltd., Heckmann Water Resources Corporation (owned by Nuverra Environmental Solutions) and Stallion Oilfield Services Ltd. Numerous smaller companies also compete in the fluid management services market in the United States.
Coiled Tubing Services
Coiled tubing services involve the use of a continuous metal pipe spooled onto a large reel which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing is also used for a number of horizontal well applications such as milling temporary isolation plugs that separate frac zones and various other pre- and post-hydraulic fracturing well preparation services.
Our primary competitors in the coiled tubing services market include Schlumberger Ltd., Baker Hughes Incorporated, Halliburton Company and Superior Energy Services, Inc. Numerous smaller companies also compete in our coiled tubing services markets in the United States.
Fishing and Rental Services
We offer a full line of fishing services and rental equipment designed for use in providing both onshore and offshore drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units and foam air units.
As a result of the 2011 acquisition of Edge Oilfield Services, LLC and Summit Oilfield Services, LLC (collectively, “Edge”), our rental inventory also includes frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. We also provide well testing services.
Demand for our fishing and rental services is also closely related to capital spending by oil and natural gas producers, which is generally a function of oil and natural gas prices.
Our primary competitors for our fishing and rental services include Baker Oil Tools (owned by Baker Hughes Incorporated), Weatherford International Ltd., Basic Energy Services, Inc., Smith Services (owned by Schlumberger), Superior Energy Services, Inc., Quail Tools (owned by Parker Drilling Company) and Knight Oil Tools. Numerous smaller companies also compete in our fishing and rental services markets in the United States.
International Segment
Our International segment includes operations in Mexico, Colombia, Ecuador, the Middle East and Russia. In addition, we have a technology development and control systems business based in Canada. Also, prior to the sale of our Argentina business in the third quarter of 2012, we operated in Argentina. We are reporting the results of our Argentina business as discontinued operations for the 2011 and 2012 periods. We provide rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives in each of our international markets.
In addition, in Mexico we provide drilling, coiled tubing, wireline and project management and consulting services. Our work in Mexico also requires us to provide third-party services, which vary in scope by project.
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In the Middle East, we operate in the Kingdom of Bahrain and Oman. On August 5, 2013, we agreed to the dissolution of AlMansoori Key Energy Services, LLC, a joint venture formed under the laws of Abu Dhabi, UAE, and the acquisition of the underlying business for $5.1 million. See “Note 2. Acquisitions” in “Item 8. Financial Statements and Supplementary Data” for further discussion.
Our Russian operations provide drilling, workover, and reservoir engineering services. On April 9, 2013, we completed the acquisition of the remaining 50% noncontrolling interest in OOO Geostream Services Group (“Geostream”), a limited liability company incorporated in the Russian Federation, for $14.6 million. We now own 100% of Geostream. See “Note 2. Acquisitions” in “Item 8. Financial Statements and Supplementary Data” for further discussion.
Our technology development and control systems business based in Canada is focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.
Functional Support Segment
Our Functional Support segment includes unallocated overhead costs associated with sales, safety and administrative support for our U.S. and International reporting segments.
Equipment Overview
We categorize our rigs and equipment as marketed or stacked. We consider a marketed rig or piece of equipment to be a unit that is working, on standby, or down for repairs but with work orders assigned to it or that is available for work. A stacked rig or piece of equipment is a unit that is in the remanufacturing process and could not be put to work without significant investment in repairs and additional equipment or we intend to salvage the unit for parts, sell the unit or scrap the unit. The definitions of marketed and stacked are used for the majority of our equipment.
Rigs
As mentioned above, our fleet is diverse and allows us to work on all types of wells, ranging from very shallow wells to wells as deep as 20,000 feet. The following table classifies our rigs based on horsepower (“HP”). Typically, higher HP rigs will be utilized on deep wells while lower HP rigs will be used on shallow wells. In most cases, these rigs can be reassigned to other regions should market conditions warrant the transfer of equipment.
Horse Power | ||||||||
< 450 HP | ≥ 450 HP | Total | ||||||
Marketed | 638 | 160 | 798 | |||||
Stacked | 169 | 20 | 189 | |||||
Total | 807 | 180 | 987 | |||||
Coiled Tubing
Coiled tubing uses a spooled continuous metal pipe that is injected downhole in oil and gas wells in order to convey tools, log, stimulate, clean-out and perform other intervention functions. Typically, larger diameter coiled tubing is able to service longer lateral horizontal wells. The table below summarizes our coiled tubing fleet by pipe diameter as of December 31, 2013:
Pipe Diameter | ||||||||
< 2" | ≥ 2" | Total | ||||||
Marketed | 17 | 27 | 44 | |||||
Stacked | 3 | 4 | 7 | |||||
Total | 20 | 31 | 51 | |||||
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Fluid Management Services
We have an extensive and diverse fleet of oilfield transportation service vehicles. We broadly define an oilfield transportation service vehicle as any heavy-duty, revenue-generating vehicle weighing over one ton. Our transportation fleet includes vacuum trucks, winch trucks, hot oilers and other vehicles, including kill trucks and various hauling and transport trucks. The table below summarizes our fluid management services fleet as of December 31, 2013:
Marketed | Stacked | Total | ||||||
Truck Type | ||||||||
Vacuum Trucks | 673 | 149 | 822 | |||||
Winch Trucks | 96 | 27 | 123 | |||||
Hot Oil Trucks | 60 | 9 | 69 | |||||
Other | 111 | 41 | 152 | |||||
Total | 940 | 226 | 1,166 | |||||
Disposal Wells
As part of our fluid management services, we provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in SWD wells. The table below summarizes our SWD facilities, and brine and freshwater stations by state as of December 31, 2013:
Owned | Leased | Total | ||||||
Location | ||||||||
Arkansas | 1 | 1 | 2 | |||||
Louisiana | 2 | — | 2 | |||||
Montana | — | 2 | 2 | |||||
New Mexico | 3 | 8 | 11 | |||||
North Dakota | 1 | 8 | 9 | |||||
Texas | 30 | 36 | 66 | |||||
Total | 37 | 55 | 92 | |||||
Other Business Data
Raw Materials
We purchase a wide variety of raw materials, parts and components that are made by other manufacturers and suppliers for our use. We are not dependent on any single source of supply for those parts, supplies or materials.
Customers
Our customers include major oil companies, foreign national oil companies, and independent oil and natural gas production companies. During the year ended December 31, 2013, Chevron Texaco Exploration & Production accounted for 15% of our consolidated revenue. During the year ended December 31, 2012, the Mexican national oil company, Petróleos Mexicanos (“Pemex”), and Occidental Petroleum Corporation accounted for 12% and 10% of our consolidated revenue, respectively. No other customer accounted for more than 10% of our consolidated revenue in 2013 or 2012. No single customer accounted for more than 10% of our consolidated revenues during the year ended December 31, 2011.
Receivables outstanding from Pemex were approximately 19% and 31% of our total accounts receivable as of December 31, 2013 and 2012, respectively. No other customers accounted for more than 10% of our total accounts receivable as of December 31, 2013 and 2012.
Competition and Other External Factors
The markets in which we operate are highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. We devote substantial resources toward employee safety and training programs. In addition, we believe that our proprietary KeyView® system provides important safety enhancements. We believe many of our larger customers place
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increased emphasis on the safety, performance and quality of the crews, equipment and services provided by their contractors. Although we believe customers consider all of these factors, price is often the primary factor in determining which service provider is awarded the work. However, in numerous instances, we secure and maintain work for large customers for which efficiency, safety, technology, size of fleet and availability of other services are of equal importance to price.
The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven for the most part by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Furthermore, in a low commodity price environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.
The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of U.S. and international oil and natural gas exploration, development and production activity, as well as the equipment capacity in any particular region.
Seasonality
Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted during the winter months due to inclement weather, fewer daylight hours and holidays. During the summer months, our operations may be impacted by tropical or other inclement weather systems. During periods of heavy snow, ice or rain, we may not be able to operate or move our equipment between locations, thereby reducing our ability to provide services and generate revenues. In addition, the majority of our equipment works only during daylight hours. In the winter months when days become shorter, this reduces the amount of time that our assets can work and therefore has a negative impact on total hours worked. Lastly, during the fourth quarter, we historically have experienced significant slowdown during the Thanksgiving and Christmas holiday seasons and demand sometimes slows during this period as our customers' exhaust their annual spending budgets.
Patents, Trade Secrets, Trademarks and Copyrights
We own numerous patents, trademarks and proprietary technology that we believe provide us with a competitive advantage in the various markets in which we operate or intend to operate. We have devoted significant resources to developing technological improvements in our well service business and have sought patent protection both inside and outside the United States for products and methods that appear to have commercial significance. All the issued patents have varying remaining durations and begin expiring between 2014 and 2032. The most notable of our technologies include numerous patents surrounding our KeyView® system.
We own several trademarks that are important to our business both in the United States and in foreign countries. In general, depending upon the jurisdiction, trademarks are valid as long as they are in use, or their registrations are properly maintained and they have not been found to become generic. Registrations of trademarks can generally be renewed indefinitely as long as the trademarks are in use. While our patents and trademarks, in the aggregate, are of considerable importance to maintaining our competitive position, no single patent or trademark is considered to be of a critical or essential nature to our business.
We also rely on a combination of trade secret laws, copyright and contractual provisions to establish and protect proprietary rights in our products and services. We typically enter into confidentiality agreements with our employees, strategic partners and suppliers and limit access to the distribution of our proprietary information.
Employees
As of December 31, 2013, we employed approximately 6,800 persons in our U.S. operations and approximately 1,600 additional persons in Mexico, Colombia, Ecuador, the Middle East, Russia and Canada. Our domestic employees are not represented by a labor union and are not covered by collective bargaining agreements. In Mexico, we have entered into a collective bargaining agreement that applies to our workers in Mexico performing work under our Pemex contracts. As noted below in “Item 1A. Risk Factors,” we have historically experienced a high employee turnover rate. We have not experienced any significant work stoppages associated with labor disputes or grievances and consider our relations with our employees to be generally satisfactory.
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Governmental Regulations
Our operations are subject to various federal, state and local laws and regulations pertaining to health, safety and the environment. We cannot predict the level of enforcement of existing laws or regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. We also cannot predict whether additional laws and regulations affecting our business will be adopted, or the effect such changes might have on us, our financial condition or our business. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our operations are subject and for which a lack of compliance may have a material adverse impact on our results of operations, financial position or cash flows. We believe that we are in material compliance with all such laws.
Environmental Regulations
Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and other regulated substances. Various environmental laws and regulations require prevention, and where necessary, cleanup of spills and leaks of such materials, and some of our operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as “CERCLA” or the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct of certain defined persons, including current and prior owners or operators of a site where a release of hazardous substances occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be jointly and severally liable for the costs of cleaning up the hazardous substances, for damages to natural resources and for the costs of certain health studies.
In the course of our operations, we occasionally generate materials that are considered “hazardous substances” and, as a result, may incur CERCLA liability for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants. We also generate solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state statutes.
Although we use operating and disposal practices that are standard in the industry, hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these hydrocarbons and wastes were taken for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including contaminated groundwater), or to perform remedial activities to prevent future contamination.
Air Emissions
The Clean Air Act, as amended, or “CAA,” and similar state laws and regulations restrict the emission of air pollutants and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain approvals or permits for construction, modification or operation of certain projects or facilities and may require use of emission controls.
Global Warming and Climate Change
Some scientific studies suggest that emissions of greenhouse gases (including carbon dioxide and methane) may contribute to warming of the Earth’s atmosphere. While we do not believe our operations raise climate change issues different from those generally raised by commercial use of fossil fuels, legislation or regulatory programs that restrict greenhouse gas emissions in areas where we conduct business could increase our costs in order to comply with any new laws.
Water Discharges
We operate facilities that are subject to requirements of the Clean Water Act, as amended, or “CWA,” and analogous state laws that impose restrictions and controls on the discharge of pollutants into navigable waters. Spill prevention, control and counter-measure requirements under the CWA require implementation of measures to help prevent the contamination of navigable waters in the event of a hydrocarbon spill. Other requirements for the prevention of spills are established under the Oil Pollution Act of 1990, as amended, or “OPA,” which applies to owners and operators of vessels, including barges, offshore platforms and certain onshore facilities. Under OPA, regulated parties are strictly and jointly and severally liable for oil spills and must establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.
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Occupational Safety and Health Act
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard communication standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees and state and local government authorities.
Saltwater Disposal Wells
We operate SWD wells that are subject to the CWA, Safe Drinking Water Act, and state and local laws and regulations, including those established by the Underground Injection Control Program of the Environmental Protection Agency (“EPA”), which establishes the minimum program requirements. Most of our SWD wells are located in Texas. We also operate SWD wells in Arkansas, Louisiana, Montana, New Mexico and North Dakota. Regulations in these states require us to obtain an Underground Injection Control permit to operate each of our SWD wells. The applicable regulatory agency may suspend or modify one or more of our permits if our well operations are likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or if the well leaks into the environment.
Access to Company Reports
Our Web site address is www.keyenergy.com, and we make available free of charge through our Web site our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports, as soon as reasonably practicable after such materials are electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). Our Web site also includes general information about us, including our Corporate Governance Guidelines and charters for the committees of our board of directors. Information on our Web site or any other Web site is not a part of this report.
ITEM 1A. RISK FACTORS
In addition to the other information in this report, the following factors should be considered in evaluating us and our business.
Our business is cyclical and depends on conditions in the oil and natural gas industry, especially oil and natural gas prices and capital expenditures by oil and natural gas companies. Volatility in oil and natural gas prices, tight credit markets and disruptions in the U.S. and global economies and financial systems may adversely impact our business.
Prices for oil and natural gas historically have been volatile and as a result of changes in the supply of, and demand for, oil and natural gas and other factors. These include changes resulting from. among other things, the ability of the Organization of Petroleum Export Countries (“OPEC”) to support oil prices, changes in the levels of oil and natural gas production in the United States, domestic and worldwide economic conditions and political instability in oil-producing countries. We depend on our customers' willingness to make capital expenditures to explore for, develop and produce oil and natural gas. Therefore, weakness in oil and natural gas prices (or the perception by our customers that oil and natural gas prices will decrease in the future) could result in a reduction in the utilization of our equipment and result in lower rates for our services.
Our customers' willingness to undertake exploration and production activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, including:
• | prices, and expectations about future prices, of oil and natural gas; |
• | domestic and worldwide economic conditions; |
• | domestic and foreign supply of and demand for oil and natural gas; |
• | the price and quantity of imports of foreign oil and natural gas including the ability of OPEC to set and maintain production levels for oil; |
• | the cost of exploring for, developing, producing and delivering oil and natural gas; |
• | the level of excess production capacity, available pipeline, storage and other transportation capacity; |
• | lead times associated with acquiring equipment and products and availability of qualified personnel; |
• | the expected rates of decline in production from existing and prospective wells; |
• | the discovery rates of new oil and gas reserves; |
• | federal, state and local regulation of exploration and drilling activities and equipment, material or supplies that we furnish; |
• | public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities; |
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• | weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area and severe winter weather that can interfere with our operations; |
• | political instability in oil and natural gas producing countries; |
• | advances in exploration, development and production technologies or in technologies affecting energy consumption; |
• | the price and availability of alternative fuel and energy sources; |
• | uncertainty in capital and commodities markets; and |
• | changes in the value of the U.S. dollar relative to other major global currencies. |
A substantial decline in oil and natural gas prices generally leads to decreased spending by our customers. While higher oil and natural gas prices generally lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material adverse effect on our business, financial condition, results of operations and cash flow.
Spending by exploration and production companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause exploration and production companies to make additional reductions to capital budgets in the future even if oil prices remain at current levels or natural gas prices increase from current levels. Any such cuts in spending will curtail drilling programs as well as discretionary spending on well services, which may result in a reduction in the demand for our services, and the rates we can charge and the utilization of our assets. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could also have a material adverse impact on our business, even in a stronger oil and natural gas price environment.
We may be unable to implement price increases or maintain existing prices on our core services.
We periodically seek to increase the prices of our services to offset rising costs and to generate higher returns for our stockholders. However, we operate in a very competitive industry and as a result, we are not always successful in raising, or maintaining our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including new well service rigs, fluid hauling trucks, coiled tubing units and new fishing and rental equipment, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase or maintain prices. Furthermore, during periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our profitability.
Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our prices or to increase our prices as costs increase could have a material adverse effect on our business, financial position and results of operations.
We participate in a capital-intensive industry. We may not be able to finance future growth of our operations or future acquisitions.
Our activities require substantial capital expenditures. If our cash flow from operating activities and borrowings under our 2011 Credit Facility (as defined below) are not sufficient to fund our capital expenditure budget, we would be required to fund these expenditures through debt or equity or alternative financing plans, such as refinancing or restructuring our debt or selling assets.
Our ability to raise debt or equity capital or to refinance or restructure our debt will depend on the condition of the capital markets and our financial condition at such time, among other things. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. If debt and equity capital or alternative financing plans are not available or are not available on economically attractive terms, we would be required to curtail our capital spending, and our ability to grow our business and sustain or improve our profits may be adversely affected. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.
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Increased labor costs or the unavailability of skilled workers could hurt our operations.
Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions, and which can increase our labor costs or subject us to liabilities to our employees. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. Labor costs may increase in the future, and such increases could have a material adverse effect on our business, financial condition and results of operations.
Our future financial results could be adversely impacted by asset impairments or other charges.
We have recorded goodwill impairment charges and asset impairment charges in the past. We periodically evaluate our long-lived assets, including our property and equipment, indefinite-lived intangible assets, and goodwill for impairment. In performing these assessments, we project future cash flows on a discounted basis for goodwill, and on an undiscounted basis for other long-lived assets, and compare these cash flows to the carrying amount of the related assets. These cash flow projections are based on our current operating plans, estimates and judgmental assumptions. We perform the assessment of potential impairment on our goodwill and indefinite-lived intangible assets at least annually in the fourth quarter, or more often if events and circumstances warrant. We perform the assessment of potential impairment for our property and equipment whenever facts and circumstances indicate that the carrying value of those assets may not be recoverable due to various external or internal factors. If we determine that our estimates of future cash flows were inaccurate or our actual results are materially different from what we have predicted, we could record additional impairment charges in future periods, which could have a material adverse effect on our financial position and results of operations.
We have operated at a loss in the past and there is no assurance of our profitability in the future.
Historically, we have experienced periods of low demand for our services and have incurred operating losses. In the future, we may incur further operating losses and experience negative operating cash flow. We may not be able to reduce our costs, increase our revenues, or reduce our debt service obligations sufficient to achieve or maintain profitability and generate positive operating income in the future.
Our business involves certain operating risks, which are primarily self-insured, and our insurance may not be adequate to cover all insured losses or liabilities we might incur in our operations.
Our operations are subject to many hazards and risks, including the following:
• | accidents resulting in serious bodily injury and the loss of life or property; |
• | liabilities from accidents or damage by our fleet of trucks, rigs and other equipment; |
• | pollution and other damage to the environment; |
• | reservoir damage; |
• | blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere or an underground formation; and |
• | fires and explosions. |
If any of these hazards occur, they could result in suspension of operations, damage to or destruction of our equipment and the property of others, or injury or death to our or a third party's personnel.
We self-insure against a significant portion of these liabilities. For losses in excess of our self-insurance limits, we maintain insurance from unaffiliated commercial carriers. However, our insurance may not be adequate to cover all losses or liabilities that we might incur in our operations. Furthermore, our insurance may not adequately protect us against liability from all of the hazards of our business. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. We also are subject to the risk that we may be unable to maintain or obtain insurance of the type and amount we desire at a reasonable cost. If we were to incur a significant liability for which we were uninsured or for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.
We operate in a highly competitive industry, with intense price competition, which may intensify as our competitors expand their operations.
The market for oilfield services in which we operate is highly competitive and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially
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greater financial resources than we do. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers.
The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. The competitive environment has intensified as recent mergers among exploration and production companies have reduced the number of available customers. The fact that drilling rigs and other vehicles and oilfield services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. We may be competing for work against competitors that may be better able to withstand industry downturns and may be better suited to compete on the basis of price, retain skilled personnel and acquire new equipment and technologies, all of which could affect our revenues and profitability.
We are subject to the economic, political and social instability risks of doing business in certain foreign countries.
We currently have operations based in Mexico, Colombia, Ecuador, the Middle East and Russia and we own a technology development and control systems business based in Canada. In the future, we may expand our operations into other foreign countries. As a result, we are exposed to risks of international operations, including:
• | increased governmental ownership and regulation of the economy in the markets in which we operate; |
• | inflation and adverse economic conditions stemming from governmental attempts to reduce inflation, such as imposition of higher interest rates and wage and price controls; |
• | economic and financial instability of national oil companies; |
• | increased trade barriers, such as higher tariffs and taxes on imports of commodity products; |
• | exposure to foreign currency exchange rates; |
• | exchange controls or other currency restrictions; |
• | war, civil unrest or significant political instability; |
• | restrictions on repatriation of income or capital; |
• | expropriation, confiscatory taxation, nationalization or other government actions with respect to our assets located in the markets where we operate; |
• | governmental policies limiting investments by and returns to foreign investors; |
• | labor unrest and strikes; |
• | deprivation of contract rights; and |
• | restrictive governmental regulation and bureaucratic delays. |
The occurrence of one or more of these risks may:
• | negatively impact our results of operations; |
• | restrict the movement of funds and equipment to and from affected countries; and |
• | inhibit our ability to collect receivables. |
Historically, we have experienced a high employee turnover rate. Any difficulty we experience replacing or adding workers could adversely affect our business.
We believe that the high turnover rate in our industry is attributable to the nature of oilfield services work, which is physically demanding and performed outdoors. As a result, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. The potential inability or lack of desire by workers to commute to our facilities and job sites, as well as the competition for workers from competitors or other industries, are factors that could negatively affect our ability to attract and retain workers. We may not be able to recruit, train and retain an adequate number of workers to replace departing workers. The inability to maintain an adequate workforce could have a material adverse effect on our business, financial condition and results of operations.
We may not be successful in implementing and maintaining technology development and enhancements. New technology may cause us to become less competitive.
The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to implement new technologies before we can. If we are unable to develop and implement new technologies or products on a timely basis and at competitive cost, our business, financial condition, results of operations and cash flows could be adversely affected.
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An important component of our business strategy is to incorporate the KeyView® system, our proprietary technology, into our well service rigs. The inability to successfully develop, integrate and protect this technology could:
• | limit our ability to improve our market position; |
• | increase our operating costs; and |
• | limit our ability to recoup the investments made in this technological initiative. |
The loss of or a substantial reduction in activity by one or more of our largest customers could materially and adversely affect our business, financial condition and results of operations.
One customer accounted for more than 10% of our total consolidated revenues for the year ended December 31, 2013, and our ten largest customers represented approximately 47% of our consolidated revenues for the period. The loss of or a substantial reduction in activity by one or more of these customers could have an adverse effect on our business, financial condition and results of operations.
Potential adoption of future state or federal laws or regulations surrounding the hydraulic fracturing process could make it more difficult to complete oil or natural gas wells and could materially and adversely affect our business, financial condition and results of operations.
Many of our customers utilize hydraulic fracturing services during the life of a well. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in underground formations where water, sand and other additives are pumped under high pressure into the formation. Although we are not a provider of hydraulic fracturing services, many of our services complement the hydraulic fracturing process.
Legislation has been introduced in Congress to provide for broader federal regulation of hydraulic fracturing operations and the reporting and public disclosure of chemicals used in the fracturing process. Additionally, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act and in May 2012 issued draft guidance for fracturing operations that involved diesel fuels. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our customers' business and operations could be subject to delays and increased operating and compliance costs, which could negatively impact the number of active wells in the marketplaces we serve. New regulations addressing hydraulic fracturing and chemical disclosure have been approved or are under consideration by a number of states and some municipalities have sought to restrict or ban hydraulic fracturing within their jurisdictions. The adoption of future federal, state or municipal laws regulating the hydraulic fracturing process could negatively impact our business, financial condition and results of operations.
We may incur significant costs and liabilities as a result of environmental, health and safety laws and regulations that govern our operations.
Our operations are subject to U.S. federal, state and local and foreign laws and regulations that impose limitations on the discharge of pollutants into the environment and establish standards for the handling, storage and disposal of waste materials, including toxic and hazardous wastes. To comply with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various governmental authorities. While the cost of such compliance has not been significant in the past, new laws, regulations or enforcement policies could become more stringent and significantly increase our compliance costs or limit our future business opportunities, which could have a material adverse effect on our financial condition and results of operations.
Our operations pose risks of environmental liability, including leakage from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. Therefore, in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, results of operations and cash flow. Additionally, an increase in regulatory requirements on oil and natural gas exploration and completion activities could significantly delay or interrupt our operations.
Increasing regulatory expansion could adversely impact costs associated with our offshore fishing and rental services.
The scope of regulation of our services may increase in light of the April 2010 Macondo accident and resulting oil spill in the Gulf of Mexico, including possible increases in liabilities or funding requirements imposed by governmental agencies. In
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2012, the Bureau of Safety and Environmental Enforcement, or “BSEE”, expanded its regulatory oversight beyond oil and gas operators to include service and equipment contractors. In addition, U.S. federal law imposes on certain entities deemed to be “responsible parties” a variety of regulations related to the prevention of oil spills, releases of hazardous substances, and liability for removal costs and natural resource, real property and certain economic damages arising from such incidents. Some of these laws may impose strict and/or joint and several liability for certain costs and damages without regard to the conduct of the parties. As a provider of services and rental equipment for offshore drilling and workover services, we may be deemed a “responsible party” under federal law. The implementation of such laws and the adoption and implementation of future regulatory initiatives, or the specific responsibilities that may arise from such initiatives may subject us to increased costs and liabilities, which could interrupt our operations or have an adverse effect on our revenue or results of operations.
Severe weather could have a material adverse effect on our business.
Our business could be materially and adversely affected by severe weather. Our customers' oil and natural gas operations located in Louisiana and parts of Texas may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. Furthermore, our customers' operations may be adversely affected by seasonal weather conditions. Adverse weather can also directly impede our own operations. Repercussions of severe weather conditions may include:
• | curtailment of services; |
• | weather-related damage to facilities and equipment, resulting in suspension of operations; |
• | inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and |
• | loss of productivity. |
These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters may also adversely affect the demand for our services by decreasing the demand for natural gas.
We may not be successful in identifying, making and integrating acquisitions.
An important component of our growth strategy is to make acquisitions that will strengthen our core services or presence in selected markets. The success of this strategy will depend, among other things, on our ability to identify suitable acquisition candidates, to negotiate acceptable financial and other terms, to timely and successfully integrate acquired business or assets into our existing businesses and to retain the key personnel and the customer base of acquired businesses. Any future acquisitions could present a number of risks, including but not limited to:
• | incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets; |
• | failure to successfully integrate the operations or management of any acquired operations or assets in a timely manner; |
• | failure to retain or attract key employees; |
• | diversion of management's attention from existing operations or other priorities; and |
• | inability to secure sufficient financing, sufficient financing on economically attractive terms, that may be required for any such acquisition or investment. |
Our business plan anticipates, and is based upon our ability to successfully complete and integrate, acquisitions of other businesses or assets in a timely and cost effective manner. Our failure to do so could adversely affect our business, financial condition or results of operations.
Compliance with climate change legislation or initiatives could negatively impact our business.
Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases, or “GHG”, from stationary sources, which may include our equipment and operations. At the federal level, the EPA has already issued regulations that require us to establish and report an inventory of GHG emissions. The EPA also has established a GHG permitting requirement for large stationary sources and may lower the threshold of the permitting program, which could include our equipment and operations. Legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for natural gas and oil. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program.
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Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation could reduce demand for oil and natural gas. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas. Management cannot predict the impact of the changing demand for oil and natural gas services and products, and any major changes may have a material effect on our business, financial condition, results of operations and cash flows.
The amount of our debt and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.
Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including:
• | making it more difficult for us to satisfy our obligations under the agreement governing our indebtedness and increasing the risk that we may default on our debt obligations; |
• | requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities; |
• | limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes and other activities; |
• | limiting management's flexibility in operating our business; |
• | limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; |
• | diminishing our ability to withstand successfully a downturn in our business or the economy generally; |
• | placing us at a competitive disadvantage against less leveraged competitors; and |
• | making us vulnerable to increases in interest rates, because certain of our debt will vary with prevailing interest rates. |
We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the consequent acceleration of our obligation to repay outstanding debt. Our ability to comply with debt covenants and other restrictions may be affected by events beyond our control, including general economic and financial conditions.
In particular, under the terms of our indebtedness, we must comply with certain financial ratios and satisfy certain financial condition tests, several of which become more restrictive over time and could require us to take action to reduce our debt or take some other action in order to comply with them. Our ability to satisfy required financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial and industry conditions, and we may not be able to continue to meet those ratios and tests in the future. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. If we default, lenders under our senior secured revolving credit facility will no longer be obligated to extend credit to us and they, as well as the trustee for our outstanding notes, could elect to declare all amounts outstanding under our 2011 Credit Facility or indentures, as applicable, together with accrued interest, to be immediately due and payable. The results of such actions would have a significant negative impact on our results of operations, financial position and cash flows.
We may incur more debt and long-term lease obligations in the future.
The agreements governing our long-term debt restrict, but do not prohibit, us from incurring additional indebtedness and other obligations in the future. As of December 31, 2013, we had $767.6 million of total debt.
An increase in our level of indebtedness could exacerbate the risks described in the immediately preceding risk factor and the occurrence of any of such events could result in a material adverse effect on our business, financial condition, results of operations, and business prospects.
We may not be able to generate sufficient cash flow to meet our debt service obligations.
Our ability to make payments on our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and natural gas industry, general economic and financial conditions, competition in the markets in which we operate, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control. This risk could be exacerbated by any economic downturn or instability in the U.S. and global credit markets.
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Our business may not generate sufficient cash flow from operations to service our outstanding indebtedness. In addition, future borrowings may not be available to us in amounts sufficient to enable us to repay our indebtedness or to fund our other capital needs. If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:
• | refinancing or restructuring our debt; |
• | selling assets; |
• | reducing or delaying acquisitions or capital investments, such as remanufacturing our rigs and related equipment; or |
• | seeking to raise additional capital. |
We may not be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, and implementing any such alternative financing plans may not allow us to meet our debt obligations. In addition, a downgrade in our credit rating would make it more difficult for us to raise additional debt in the future. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to obtain alternative financings, could materially and adversely affect our business, financial condition, results of operations and future prospects for growth.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our 2011 Credit Facility bear interest at variable rates, exposing us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
Our failure to comply with the Foreign Corrupt Practices Act (“FCPA”) and similar laws may have a negative impact on our ongoing operations.
Our ability to comply with the FCPA and similar laws is dependent on the success of our ongoing compliance program, including our ability to continue to manage our agents, affiliates and business partners, and supervise, train and retain competent employees. Our compliance program is also dependent on the efforts of our employees to comply with applicable law and our Business Code of Conduct. We could be subject to sanctions and civil and criminal prosecution as well as fines and penalties in the event of a finding of violation of the FCPA or similar laws by us or any of our employees.
Our bylaws contain provisions that may prevent or delay a change in control.
Our bylaws contain certain provisions designed to enhance the ability of our board of directors to respond to unsolicited attempts to acquire control of the Company. These provisions:
• | establish a classified board of directors, providing for three-year staggered terms of office for all members of our board of directors; |
• | set limitations on the removal of directors; |
• | enable our board of directors to set the number of directors and to fill vacancies on the board occurring between stockholder meetings; and |
• | set limitations on who may call a special meeting of stockholders. |
These provisions may have the effect of entrenching management and may deprive investors of the opportunity to sell their shares to potential acquirers seeking control of the Company at a premium over prevailing prices. This potential inability to obtain a control premium could reduce the price of our common stock.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
We lease office space for our principal executive offices in Houston, Texas. We also lease local office space in the various countries in which we operate. Additionally, we own or lease numerous rig facilities, storage facilities, truck facilities and sales and administrative offices throughout the geographic regions in which we operate. We lease temporary facilities to house employees in regions where infrastructure is limited. In connection with our fluid management services, we operate a number of owned and leased SWD facilities, and brine and freshwater stations. Our leased properties are subject to various lease terms and expirations.
We believe all properties that we currently occupy are suitable for their intended uses. We believe that our current facilities are sufficient to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.
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The following table shows our active owned and leased properties, as well as active SWD facilities, categorized by geographic region as of December 31, 2013:
Region | Office, Repair & Service and Other(1) | SWDs, Brine and Freshwater Stations(2) | Operational Field Services Facilities | |||||
United States | ||||||||
Owned | 9 | 37 | 75 | |||||
Leased | 76 | 55 | 53 | |||||
International | ||||||||
Owned | — | — | — | |||||
Leased | 40 | — | 6 | |||||
TOTAL | 125 | 92 | 134 | |||||
(1) | Includes 57 residential properties leased in the United States and 14 residential properties leased outside the United States used to house employees. |
(2) | Includes SWD facilities as “leased” if we own the wellbore for the SWD but lease the land. In other cases, we lease both the wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain the wellbore at the termination of the lease. |
ITEM 3. LEGAL PROCEEDINGS
We are subject to various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of our ordinary course litigation will result in a material adverse effect on our consolidated financial position, results of operations or cash flows.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market and Share Prices
Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “KEG.” As of February 17, 2014, there were 616 registered holders of 152,928,294 issued and outstanding shares of common stock. This number of registered holders does not include holders that have shares of common stock held for them in “street name”, meaning that the shares are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that have shares held in “street name” are not. The following table sets forth the reported high and low closing price of our common stock for the periods indicated:
High | Low | ||||||
Year Ended December 31, 2013 | |||||||
1st Quarter | $ | 9.38 | $ | 7.15 | |||
2nd Quarter | 7.80 | 5.61 | |||||
3rd Quarter | 8.01 | 6.08 | |||||
4th Quarter | 8.88 | 6.90 | |||||
High | Low | ||||||
Year Ended December 31, 2012 | |||||||
1st Quarter | $ | 17.82 | $ | 14.33 | |||
2nd Quarter | 15.73 | 6.86 | |||||
3rd Quarter | 9.51 | 6.67 | |||||
4th Quarter | 7.39 | 5.82 | |||||
The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate it by reference into such filing.
The following performance graph compares the performance of our common stock to the PHLX Oil Service Sector Index, the Russell 1000 Index, the Russell 2000 Index and a peer group as established by management.
The peer group consists of the following companies: Baker Hughes Incorporated, Basic Energy Services, Inc., Exterran Holdings, Inc., Helix Energy Solutions Group, Inc., Noble Corporation, Oceaneering International Inc., Oil States International Inc., Patterson UTI Energy Inc., RPC, Inc., Superior Energy Services, Inc. and Weatherford International Ltd.
During 2008, we moved from the Russell 2000 Index to the Russell 1000 Index and, during 2009, we moved back from the Russell 1000 Index to the Russell 2000 Index. For comparative purposes, both the Russell 2000 and the Russell 1000 Indices are reflected in the following performance graph.
The graph below compares the cumulative five-year total return to holders of our common stock with the cumulative total returns of the PHLX Oil Service Sector, the listed Russell Indices and our peer group. The graph assumes that the value of the investment in our common stock and each index (including reinvestment of dividends) was $100 at December 31, 2008 and tracks the return on the investment through December 31, 2013.
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COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Key Energy Services, Inc., the Russell 2000 Index, the Russell 1000 Index,
the PHLX Oil Service Sector Index and Peer Group
* $100 invested on December 31, 2008 in stock or index, including reinvestment of dividends. Fiscal years ended December 31.
Dividend Policy
There were no dividends declared or paid on our common stock for the years ended December 31, 2013, 2012 and 2011. Under the terms of our 2011 Credit Facility, we must meet certain financial covenants before we may pay dividends. We do not currently intend to pay dividends.
Issuer Purchases of Equity Securities
During the fourth quarter of 2013, we repurchased an aggregate of 1,813 shares of our common stock. The repurchases were to satisfy tax withholding obligations that arose upon vesting of restricted stock. Set forth below is a summary of the share repurchases:
Period | Total Number of Shares Purchased | Average Price Paid Per Share(1) | ||||
October 1, 2013 to October 31, 2013 | — | $ | — | |||
November 1, 2013 to November 30, 2013 | 584 | $ | 8.02 | |||
December 1, 2013 to December 31, 2013 | 1,229 | $ | 7.90 | |||
(1) | The price paid per share with respect to the tax withholding repurchases was determined using the closing prices on the applicable vesting date, as quoted on the NYSE. |
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Equity Compensation Plan Information
The following table sets forth information as of December 31, 2013 with respect to equity compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance. The material features of each of these plans are described in “Note 20. Share-Based Compensation” in “Item 8. Financial Statement and Supplementary Date.”
Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants And Rights (a) | Weighted Average Exercise Price of Outstanding Options, Warrants And Rights (b) | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (c) | ||||||
(in thousands) | (in thousands) | ||||||||
Equity compensation plans approved by stockholders(1) | 1,649 | $ | 14.37 | 2,485 | |||||
Equity compensation plans not approved by stockholders | — | $ | — | — | |||||
Total | 1,649 | 2,485 | |||||||
(1) | Represents options and other stock-based awards granted under the Key Energy Services, Inc. 2012 Equity and Cash Incentive Plan (the “2012 Incentive Plan”), the Key Energy Services, Inc. 2009 Equity and Cash Incentive Plan (the “2009 Incentive Plan”), the Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan (the “2007 Incentive Plan”), and the Key Energy Group, Inc. 1997 Incentive Plan (the “1997 Incentive Plan”). |
ITEM 6. SELECTED FINANCIAL DATA
The following historical selected financial data as of and for the years ended December 31, 2009 through December 31, 2013 has been derived from our audited financial statements included in “Item 8. Financial Statements and Supplementary Data.” For the years ended December 31, 2009 through December 31, 2011, we have reclassified the historical results of operations of our Argentina business as discontinued operations. Additionally, for the years ended December 31, 2009 and December 31, 2010, we have reclassified the historical results of operations of our pressure pumping and wireline businesses as discontinued operations. The historical selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included in “Item 8. Financial Statements and Supplementary Data.”
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RESULTS OF OPERATIONS DATA
Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
(in thousands, except per share amounts) | |||||||||||||||||||
REVENUES | $ | 1,591,676 | $ | 1,960,070 | $ | 1,729,211 | $ | 1,062,595 | $ | 887,074 | |||||||||
COSTS AND EXPENSES: | |||||||||||||||||||
Direct operating expenses | 1,114,462 | 1,308,845 | 1,085,190 | 746,441 | 609,807 | ||||||||||||||
Depreciation and amortization expense | 225,297 | 213,783 | 166,946 | 133,898 | 145,491 | ||||||||||||||
General and administrative expenses | 221,753 | 230,496 | 223,299 | 186,188 | 160,220 | ||||||||||||||
Asset retirements and impairments | — | — | — | — | 96,768 | ||||||||||||||
Operating income (loss) | 30,164 | 206,946 | 253,776 | (3,932 | ) | (125,212 | ) | ||||||||||||
Loss on early extinguishment of debt | — | — | 46,451 | — | 472 | ||||||||||||||
Interest expense, net of amounts capitalized | 55,204 | 53,566 | 40,849 | 41,240 | 39,241 | ||||||||||||||
Other income, net | (803 | ) | (6,649 | ) | (8,977 | ) | (2,807 | ) | (624 | ) | |||||||||
Income (loss) from continuing operations before tax | (24,237 | ) | 160,029 | 175,453 | (42,365 | ) | (164,301 | ) | |||||||||||
Income tax (expense) benefit | 3,064 | (57,352 | ) | (64,117 | ) | 17,961 | 61,532 | ||||||||||||
Income (loss) from continuing operations | (21,173 | ) | 102,677 | 111,336 | (24,404 | ) | (102,769 | ) | |||||||||||
Income (loss) from discontinued operations, net of tax | — | (93,568 | ) | (10,681 | ) | 94,753 | (53,907 | ) | |||||||||||
Net income (loss) | (21,173 | ) | 9,109 | 100,655 | 70,349 | (156,676 | ) | ||||||||||||
Income (loss) attributable to noncontrolling interest | 595 | 1,487 | (806 | ) | (3,146 | ) | (555 | ) | |||||||||||
INCOME (LOSS) ATTRIBUTABLE TO KEY | $ | (21,768 | ) | $ | 7,622 | $ | 101,461 | $ | 73,495 | $ | (156,121 | ) | |||||||
Earnings (loss) per share from continuing operations attributable to Key: | |||||||||||||||||||
Basic | $ | (0.14 | ) | $ | 0.67 | $ | 0.77 | $ | (0.16 | ) | $ | (0.84 | ) | ||||||
Diluted | $ | (0.14 | ) | $ | 0.67 | $ | 0.76 | $ | (0.16 | ) | $ | (0.84 | ) | ||||||
Earnings (loss) per share from discontinued operations: | |||||||||||||||||||
Basic | $ | — | $ | (0.62 | ) | $ | (0.07 | ) | $ | 0.73 | $ | (0.45 | ) | ||||||
Diluted | $ | — | $ | (0.62 | ) | $ | (0.07 | ) | $ | 0.73 | $ | (0.45 | ) | ||||||
Earnings (loss) per share attributable to Key: | |||||||||||||||||||
Basic | $ | (0.14 | ) | $ | 0.05 | $ | 0.70 | $ | 0.57 | $ | (1.29 | ) | |||||||
Diluted | $ | (0.14 | ) | $ | 0.05 | $ | 0.69 | $ | 0.57 | $ | (1.29 | ) | |||||||
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Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
(in thousands) | |||||||||||||||||||
Income (loss) from continuing operations attributable to Key: | |||||||||||||||||||
Income (loss) from continuing operations | $ | (21,173 | ) | $ | 102,677 | $ | 111,336 | $ | (24,404 | ) | $ | (102,769 | ) | ||||||
Income (loss) attributable to noncontrolling interest | 595 | 1,487 | (806 | ) | (3,146 | ) | (555 | ) | |||||||||||
Income (loss) from continuing operations attributable to Key | $ | (21,768 | ) | $ | 101,190 | $ | 112,142 | $ | (21,258 | ) | $ | (102,214 | ) | ||||||
Weighted Average Shares Outstanding: | |||||||||||||||||||
Basic | 152,271 | 151,106 | 145,909 | 129,368 | 121,072 | ||||||||||||||
Diluted | 152,271 | 151,125 | 146,217 | 129,368 | 121,072 | ||||||||||||||
CASH FLOW DATA
Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
(in thousands) | |||||||||||||||||||
Net cash provided by operating activities | $ | 228,643 | $ | 369,660 | $ | 188,305 | $ | 129,805 | $ | 184,837 | |||||||||
Net cash used in investing activities | (160,881 | ) | (428,709 | ) | (520,090 | ) | (8,631 | ) | (110,636 | ) | |||||||||
Net cash provided by (used in) financing activities | (85,492 | ) | 73,946 | 306,084 | (100,205 | ) | (127,475 | ) | |||||||||||
Effect of changes in exchange rates on cash | 87 | (4,391 | ) | 4,516 | (1,735 | ) | (2,023 | ) | |||||||||||
BALANCE SHEET DATA
Year Ended December 31, | |||||||||||||||||||
2013 | 2012 | 2011 | 2010 | 2009 | |||||||||||||||
(in thousands) | |||||||||||||||||||
Working capital | $ | 273,809 | $ | 284,698 | $ | 311,060 | $ | 132,385 | $ | 194,363 | |||||||||
Property and equipment, gross | 2,606,738 | 2,528,578 | 2,184,810 | 1,789,571 | 1,604,523 | ||||||||||||||
Property and equipment, net | 1,365,646 | 1,436,674 | 1,197,300 | 920,797 | 776,349 | ||||||||||||||
Total assets | 2,587,470 | 2,761,588 | 2,599,120 | 1,892,936 | 1,664,410 | ||||||||||||||
Long-term debt and capital leases, net of current maturities | 763,981 | 848,110 | 773,975 | 427,121 | 523,949 | ||||||||||||||
Total liabilities | 1,336,377 | 1,474,256 | 1,384,489 | 911,133 | 921,270 | ||||||||||||||
Equity | 1,251,093 | 1,287,332 | 1,214,631 | 981,803 | 743,140 | ||||||||||||||
Cash dividends per common share | — | — | — | — | — | ||||||||||||||
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes thereto in “Item 8. Financial Statements and Supplementary Data.” The discussion below contains forward-looking statements that are based upon our current expectations and are subject to uncertainty and changes in circumstances including those identified in “Cautionary Note Regarding Forward-Looking Statements” above. Actual results may differ materially from these expectations due to potentially inaccurate assumptions and known or unknown risks and uncertainties. Such forward-looking statements should be read in conjunction with our disclosures under “Item 1A. Risk Factors.”
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Overview
We provide a full range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies to produce, maintain and enhance the flow of oil and natural gas throughout the life of a well. These services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and we have operations in Mexico, Colombia, Ecuador, the Middle East and Russia. In addition, we have a technology development and control systems business based in Canada.
The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven primarily by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Further, in a lower-priced environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.
Business and Growth Strategies
Focus on Horizontal Well Services
In recent years the number of horizontal wells drilled in the U.S. has increased significantly. Horizontal wells tend to involve a higher degree of service intensity associated with their drilling and completion, and we believe ultimately the maintenance required over their lifetime. To capitalize on this growing market segment we have built and acquired new equipment, including more capable rigs and coiled tubing units, upgraded existing equipment capable of providing services integral to the completion and maintenance of horizontal wellbores and acquired frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. We also expanded all our service offerings into unconventional shale regions where horizontal activity is most prevalent including the Bakken shale, the Eagle Ford shale and others. As horizontal wells have become more prevalent in the Permian Basin, we have expanded our operations, with all of our service offerings in that market. We intend to continue our focus on the expansion of horizontal well service offerings in existing markets and into new markets in the United States.
Continue Expansion in International Markets
We presently operate internationally in Mexico, Colombia, Ecuador, the Middle East and Russia, particularly in regions of those countries with large mature oilfields facing production declines. We believe that our experience with domestic mature oilfields and our proprietary technologies, including our KeyView® system, provides us with the opportunity to compete for new business in foreign markets. We continue to evaluate international expansion opportunities in the regions where we already have a presence as well as other regions.
Pursue Prudent Acquisitions in Complementary Businesses
We are focused on maximizing cash flows from acquisitions and other investments we have made, and we have added an internal financial metric, Key Value Added, or “KVA,” to evaluate our investments. We intend to continue our disciplined approach to acquisitions, seeking opportunities, domestic and internationally, that strengthen our presence in selected regional markets and provide opportunities to expand our core services. We also seek to acquire technologies, assets and businesses that represent a good operational, strategic, and/or synergistic fit with our existing service offerings.
PERFORMANCE MEASURES
The Baker Hughes U.S. rig count data, which is publicly available on a weekly basis, is often used as a coincident indicator of overall Exploration and Production (“E&P”) company spending and broader oilfield activity. In assessing overall activity in the U.S. onshore oilfield service industry in which we operate, we believe that the Baker Hughes U.S. land drilling rig count is the best barometer of E&P companies' capital spending and resulting activity levels. Historically, our activity levels have been highly correlated to U.S. onshore capital spending by our E&P company customers as a group.
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Year | WTI Cushing Crude Oil(1) | NYMEX Henry Hub Natural Gas(1) | Average Baker Hughes U.S. Land Drilling Rigs(2) | |||||||
2009 | $ | 61.95 | $ | 4.28 | 1,046 | |||||
2010 | $ | 79.48 | $ | 4.38 | 1,514 | |||||
2011 | $ | 94.87 | $ | 4.03 | 1,846 | |||||
2012 | $ | 94.05 | $ | 2.75 | 1,871 | |||||
2013 | $ | 97.98 | $ | 3.73 | 1,705 | |||||
(1) | Represents the average of the monthly average prices for each of the years presented. Source: U.S. Energy Information Administration, Bloomberg. |
(2) | Source: www.bakerhughes.com |
Internally, we measure activity levels for our well servicing operations primarily through our rig and trucking hours. Generally, as capital spending by E&P companies increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by E&P companies, we generally provide fewer rig and trucking services, which results in lower hours worked. The following table presents our quarterly rig and trucking hours from 2011 through 2013.
Rig Hours | Trucking Hours | Key’s U.S. Working Days(3) | |||||||
U.S. | International(1) | Total(2) | |||||||
2013: | |||||||||
First Quarter | 337,714 | 114,103 | 451,817 | 580,862 | 62 | ||||
Second Quarter | 365,956 | 65,280 | 431,236 | 559,584 | 64 | ||||
Third Quarter | 360,112 | 55,105 | 415,217 | 524,513 | 64 | ||||
Fourth Quarter | 343,626 | 46,553 | 390,179 | 507,636 | 62 | ||||
Total 2013 | 1,407,408 | 281,041 | 1,688,449 | 2,172,595 | 252 | ||||
2012: | |||||||||
First Quarter | 435,280 | 84,469 | 519,749 | 722,718 | 64 | ||||
Second Quarter | 428,864 | 104,656 | 533,520 | 685,587 | 63 | ||||
Third Quarter | 412,998 | 103,448 | 516,446 | 607,480 | 63 | ||||
Fourth Quarter | 357,628 | 113,246 | 470,874 | 594,770 | 62 | ||||
Total 2012 | 1,634,770 | 405,819 | 2,040,589 | 2,610,555 | 252 | ||||
2011: | |||||||||
First Quarter | 415,691 | 52,965 | 468,656 | 711,701 | 64 | ||||
Second Quarter | 426,278 | 59,384 | 485,662 | 776,382 | 63 | ||||
Third Quarter | 428,236 | 66,375 | 494,611 | 757,550 | 64 | ||||
Fourth Quarter | 413,052 | 69,528 | 482,580 | 721,411 | 61 | ||||
Total 2011 | 1,683,257 | 248,252 | 1,931,509 | 2,967,044 | 252 | ||||
(1) | International rig hours exclude rig hours generated in Argentina, as our Argentina operations were sold in the third quarter of 2012 and are reported as discontinued operations. Argentina hours were 54,625 and 55,972 for the first and second quarters of 2012, respectively. Argentina rig hours were 56,804, 59,255, 59,532 and 50,876 for the first, second, third and fourth quarters of 2011, respectively. |
(2) | Total rig hours included U.S. rig hours and international rig hours, as described in footnote (1) above. |
(3) | Key's U.S. working days are the number of weekdays during the quarter minus national holidays. |
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MARKET CONDITIONS AND OUTLOOK
Market Conditions — Year Ended December 31, 2013
Our core businesses depend on our customers' willingness to make expenditures to produce, develop and explore for oil and natural gas. Industry conditions are influenced by numerous factors, such as the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, and political instability in oil producing countries.
Fourth quarter 2013 U.S. revenues were down 6.1% as compared to the third quarter of 2013. Fourth quarter 2013 results were impacted by seasonal effects and multiple severe weather events. Despite these factors, we were able to maintain revenue consistent with expectations heading in to the fourth quarter as a growing customer base and certain customers returning to work in the last few weeks of the quarter to offset severe weather helped mitigate further revenue declines.
Fourth quarter 2013 international revenues were down 14.5% compared to third quarter 2013. Our International results were impacted by the continued activity slowdown in the North Region of Mexico, our principal operating region. Our prior expectation, based on indications from senior Pemex officials was that some activity would return in our operating regions in the fourth quarter as Pemex prepared for a return to normal activity levels in 2014. During the fourth quarter of 2013, the Mexican government ratified energy reform that, amongst many other facets, required Pemex to submit proposals for assets it wishes to operate in the future in a process known as "Round Zero". Operations in the North Region effectively ceased as energy reform emerged and Round Zero commenced.
Market Outlook
We continue to position Key to thrive in a flat market through balanced service offerings across the wells' life, giving Key exposure to unconventional horizontal well and legacy vertical well activities. We believe that the high value service we provide across the well life cycle yields many incremental opportunities for Key.
As we look to 2014 U.S. customer capital spending and market activity, we are seeing positive demand signals from many of our customers and have seen the pace of inquiries for our services increase during 2014. We expect the horizontal oil well count to continue to increase, especially in the Permian Basin, and we believe we are well positioned to benefit from this trend in both our production and completion-driven businesses. We also expect to continue to benefit from our efforts to broaden our customer base and deliver Key's value proposition to a new band of customers which should allow us to further expand our base of business. We believe the improvements in our cost structure over the course of 2013 and our effort to increase utilization with our existing assets should allow Key to improve returns in our U.S. segment.
Internationally, we are taking the necessary actions to insulate ourselves from further losses and allow us to operate profitably as we await the benefits of Mexican energy reform. We plan to redeploy approximately two dozen of our 41 rigs in Mexico back to the U.S. during 2014 which will reduce our fixed cost structure internationally. We believe that activity will improve in the North Region of Mexico once the National Hydrocarbons Commission approves the assets which Pemex will continue to manage. Until such time, we expect to achieve cash-flow breakeven in our International segment during 2014 which will help mitigate losses in our consolidated business while maintaining option value for when activity in Mexico returns.
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RESULTS OF OPERATIONS
Consolidated Results of Operations
The following table shows our consolidated results of operations for the years ended December 31, 2013, 2012 and 2011:
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands, except per share amounts) | |||||||||||
REVENUES | $ | 1,591,676 | $ | 1,960,070 | $ | 1,729,211 | |||||
COSTS AND EXPENSES: | |||||||||||
Direct operating expenses | 1,114,462 | 1,308,845 | 1,085,190 | ||||||||
Depreciation and amortization expense | 225,297 | 213,783 | 166,946 | ||||||||
General and administrative expenses | 221,753 | 230,496 | 223,299 | ||||||||
Operating income | 30,164 | 206,946 | 253,776 | ||||||||
Loss on early extinguishment of debt | — | — | 46,451 | ||||||||
Interest expense, net of amounts capitalized | 55,204 | 53,566 | 40,849 | ||||||||
Other income, net | (803 | ) | (6,649 | ) | (8,977 | ) | |||||
Income (loss) from continuing operations before tax | (24,237 | ) | 160,029 | 175,453 | |||||||
Income tax (expense) benefit | 3,064 | (57,352 | ) | (64,117 | ) | ||||||
Income (loss) from continuing operations | (21,173 | ) | 102,677 | 111,336 | |||||||
Loss from discontinued operations, net of tax | — | (93,568 | ) | (10,681 | ) | ||||||
Net income (loss) | (21,173 | ) | 9,109 | 100,655 | |||||||
Income (loss) attributable to noncontrolling interest | 595 | 1,487 | (806 | ) | |||||||
INCOME (LOSS) ATTRIBUTABLE TO KEY | $ | (21,768 | ) | $ | 7,622 | $ | 101,461 | ||||
Years Ended December 31, 2013 and 2012
For the year ended December 31, 2013, our operating income was $30.2 million, compared to $206.9 million for the year ended December 31, 2012. Loss per diluted share was $0.14 for the year ended December 31, 2013 compared to $0.05 income per diluted share for the year ended December 31, 2012.
Revenues
Our revenues for the year ended December 31, 2013 decreased $368.4 million, or 18.8%, to $1.59 billion from $1.96 billion for the year ended December 31, 2012, primarily due to lower demand for our rig-based services in oil markets and overall weaker economic conditions affecting both our domestic and international operations. See “Segment Operating Results — Years Ended December 31, 2013 and 2012” below for a more detailed discussion of the change in our revenues.
Direct operating expenses
Our direct operating expenses decreased $194.4 million, or 14.9%, to $1.1 billion (70.0% of revenues) for the year ended December 31, 2013, compared to $1.3 billion (66.8% of revenues) for the year ended December 31, 2012. The decrease was a direct result of activity decreases in our business and improved operating efficiencies in our rig-based services and coiled tubing services. The operating efficiencies were partially offset by charges of $6.3 million primarily associated with severance costs, $2.3 million of costs primarily associated with rig mobilizations from the North Region of Mexico to the South Region of Mexico and to other countries, including the U.S., and $1.9 million of lease cancellation fees which caused direct operating expenses as a percentage of revenue to be higher in 2013 than 2012. See “Segment Operating Results — Years Ended December 31, 2013 and 2012” below for a more detailed discussion of the change in our direct operating expenses.
Depreciation and amortization expense
Depreciation and amortization expense increased $11.5 million, or 5.4%, to $225.3 million (14.2% of revenues) for the year ended December 31, 2013, compared to $213.8 million (10.9% of revenues) for the year ended December 31, 2012. The increase is primarily attributable to the 2013 impact of increased capital expenditures in 2012.
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General and administrative expenses
General and administrative expenses decreased $8.7 million, or 3.8%, to $221.8 million (13.9% of revenues) for the year ended December 31, 2013, compared to $230.5 million (11.8% of revenues) for the year ended December 31, 2012. The decrease is primarily related to lower third party consulting fees partially offset by a $2.2 million charge associated with the retirement of an executive recorded during first quarter of 2013 and $2.2 million of expenses primarily associated with severance costs recorded during the second quarter of 2013.
Interest expense, net of amounts capitalized
Interest expense increased $1.6 million to $55.2 million (3.5% of revenues), for the year ended December 31, 2013, compared to $53.6 million (2.7% of revenues) for the year ended December 31, 2012. Interest expense for the year ended December 31, 2013 increased due to the issuance of the additional $200 million aggregate principal amount of 2021 Notes (as defined below) during March 2012.
Other income, net
During the year ended December 31, 2013, we recognized other income, net, of $0.8 million, compared to $6.6 million for the year ended December 31, 2012. Our foreign exchange (gain) loss relates to U.S. dollar-denominated transactions in our foreign locations and fluctuations in exchange rates between local currencies and the U.S. dollar. The table below presents comparative detailed information about other income, net at December 31, 2013 and 2012:
Year Ended December 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Interest income | $ | (220 | ) | $ | (46 | ) | |
Foreign exchange (gain) loss | 834 | (4,726 | ) | ||||
Other, net | (1,417 | ) | (1,877 | ) | |||
Total | $ | (803 | ) | $ | (6,649 | ) | |
Income tax (expense) benefit
Our income tax benefit on continuing operations was $3.1 million (12.6% effective rate) on pre-tax loss of $24.2 million for the year ended December 31, 2013, compared to an income tax expense of $57.4 million (35.8% effective rate) on a pre-tax income of $160.0 million for the year ended December 31, 2012. Our effective tax rates differ from the statutory rate of 35% primarily because of state, local and foreign income taxes, and the tax effects of permanent items attributable to book-tax differences.
Discontinued operations
Our net loss from discontinued operations for the year ended December 31, 2013 was zero compared to $93.6 million for the year ended December 31, 2012. The 2012 loss is related to our Argentina business, which was sold in September 2012. Included in the loss from discontinued operations is a pre-tax loss of $85.8 million, which includes a noncash impairment charge of $41.5 million recorded in the first quarter of 2012, and a write-off of $51.9 million cumulative translation adjustment previously recorded in accumulated other comprehensive loss. For further discussion see “Note 3. Discontinued Operations” in “Item 8. Financial Statements and Supplementary Data.”
Noncontrolling interest
For the year ended December 31, 2013, we allocated $0.6 million associated with the income incurred by our joint ventures to the noncontrolling interest holders of these ventures compared to income of $1.5 million for the year ended December 31, 2012. The decrease in income allocated to noncontrolling interest holders is due to our acquisition of our remaining noncontrolling interests in 2013 resulting in less income being allocated to noncontrolling interests holders.
Years Ended December 31, 2012 and 2011
For the year ended December 31, 2012, our operating income was $207.0 million, compared to $253.8 million for the year ended December 31, 2011. Income per diluted share was $0.05 for the year ended December 31, 2012 compared to $0.69 per diluted share for the year ended December 31, 2011. Income and income per share during 2011 was impacted by our loss on the early extinguishment of debt.
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Revenues
Our revenues for the year ended December 31, 2012 increased $230.9 million, or 13.4%, to $1.96 billion from $1.73 billion for the year ended December 31, 2011, primarily due to strong demand for our rig-based services in oil markets, improved pricing and overall economic conditions during the first half of 2012 as well as both domestic and international expansion of our business. See “Segment Operating Results — Years Ended December 31, 2012 and 2011” below for a more detailed discussion of the change in our revenues.
Direct operating expenses
Our direct operating expenses increased $223.7 million, or 20.6%, to $1.3 billion (66.8% of revenues) for the year ended December 31, 2012, compared to $1.1 billion (62.8% of revenues) for the year ended December 31, 2011. We incurred additional costs during the period to relocate assets and personnel from declining natural gas markets to oil markets. In addition, we experienced increased competition in the oil markets we serve giving rise to higher labor costs. See “Segment Operating Results — Years Ended December 31, 2012 and 2011” below for a more detailed discussion of the change in our direct operating expenses.
Depreciation and amortization expense
Depreciation and amortization expense increased $46.8 million, or 28.1%, to $213.8 million (10.9% of revenues) for the year ended December 31, 2012, compared to $166.9 million (9.7% of revenues) for the year ended December 31, 2011. The increase was primarily attributable to the increase in our fixed asset base through our acquisitions during 2011, as well as increased capital expenditures during a portion of 2011 and full year 2012.
General and administrative expenses
General and administrative expenses increased $7.2 million, or 3.2%, to $230.5 million (11.8% of revenues) for the year ended December 31, 2012, compared to $223.3 million (12.9% of revenues) for the year ended December 31, 2011. The increase was primarily due to higher employee compensation, benefit costs and professional fees. In addition, prior year expenses were offset by a favorable legal settlement of $5.5 million in which Key Energy Services, Inc. was the plantiff.
Loss on early extinguishment of debt
Loss on early extinguishment of debt was zero for the year ended December 31, 2012, compared to $46.5 million for the year ended December 31, 2011, due to our tender offer for and purchase of our 8.375% Senior Notes due 2014 (the “2014 Notes”) and the termination of our prior credit facility during the first quarter of 2011. The loss consisted of the tender premium on the 2014 Notes, as well as transaction fees and the write-off of the unamortized portion of deferred financing costs.
Interest expense, net of amounts capitalized
Interest expense increased $12.7 million to $53.6 million (2.7% of revenues), for the year ended December 31, 2012, compared to $40.8 million (2.4% of revenues) for the year ended December 31, 2011. Overall, interest rates on our debt in 2012 declined compared to 2011 due to our repurchase of the 2014 Notes and the issuance of the 6.75% Senior Notes due 2021 during the first quarter of 2011. However, interest expense for the year ended December 31, 2012 increased due to the issuance of an additional $200.0 million aggregate principal amount of 2021 Notes and a higher outstanding balance under our 2011 Credit Facility.
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Other income, net
During the year ended December 31, 2012, we recognized other income, net, of $6.6 million, compared to $9.0 million for the year ended December 31, 2011. In the second quarter of 2011, we sold our equity interest in IROC Energy Services Corp. (“IROC”) and recorded a gain on the sale of $4.8 million. Our foreign exchange gain relates to an increase in U.S. dollar-denominated transactions in our foreign locations and fluctuations in the strength of the U.S. dollar. The table below presents comparative detailed information about other income, net at December 31, 2012 and 2011:
Year Ended December 31, | |||||||
2012 | 2011 | ||||||
(in thousands) | |||||||
Interest income | $ | (46 | ) | $ | (26 | ) | |
Foreign exchange gain | (4,726 | ) | (3,058 | ) | |||
Gain on sale of equity method investment | — | (4,783 | ) | ||||
Other, net | (1,877 | ) | (1,110 | ) | |||
Total | $ | (6,649 | ) | $ | (8,977 | ) | |
Income tax expense
Our income tax expense on continuing operations was $57.4 million (35.8% effective rate) on pre-tax income of $160.0 million for the year ended December 31, 2012, compared $64.1 million (36.5% effective rate) on a pre-tax income of $175.5 million in 2011. Our effective tax rates differ from the statutory rate of 35% primarily because of state, local and foreign income taxes, and the tax effects of permanent items attributable to book-tax differences.
Discontinued operations
Our net loss from discontinued operations was $93.6 million for the year ended December 31, 2012, compared to $10.7 million for the year ended December 31, 2011. These losses related to our Argentina business, which was sold in September 2012. Included in the loss from discontinued operations for the year ended December 31, 2012 is a pre-tax loss of $85.8 million, which includes the noncash impairment charge of $41.5 million recorded in the first quarter of 2012, and a write-off of $51.9 million cumulative translation adjustment previously recorded in Accumulated other comprehensive loss. For further discussion see “Note 3. Discontinued Operations” in “Item 8. Financial Statements and Supplementary Data.”
Noncontrolling interest
For the year ended December 31, 2012, we allocated $1.5 million associated with the income incurred by our joint ventures to the noncontrolling interest holders of these ventures compared to a net loss of $0.8 million for the year ended December 31, 2011.
Segment Operating Results
Years Ended December 31, 2013 and 2012
The following table shows operating results for each of our reportable segments for the years ended December 31, 2013 and 2012 (in thousands):
For the year ended December 31, 2013
U.S. | International | Functional Support | Total | ||||||||||||
Revenues from external customers | $ | 1,376,969 | $ | 214,707 | $ | — | $ | 1,591,676 | |||||||
Operating expenses | 1,184,637 | 241,364 | 135,511 | 1,561,512 | |||||||||||
Operating income (loss) | 192,332 | (26,657 | ) | (135,511 | ) | 30,164 | |||||||||
For the year ended December 31, 2012
U.S. | International | Functional Support | Total | ||||||||||||
Revenues from external customers | $ | 1,626,768 | $ | 333,302 | $ | — | $ | 1,960,070 | |||||||
Operating expenses | 1,341,427 | 270,310 | 141,387 | 1,753,124 | |||||||||||
Operating income (loss) | 285,341 | 62,992 | (141,387 | ) | 206,946 | ||||||||||
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U.S.
Revenues for our U.S. segment decreased $249.8 million, or 15.4%, to $1.38 billion for the year ended December 31, 2013, compared to $1.63 billion for the year ended December 31, 2012. The decrease for this segment was due to reduced customer spending, lower activity in natural gas markets and increased competition.
Operating expenses for our U.S. segment were $1.18 billion during the year ended December 31, 2013, which represented a decrease of $156.8 million, or 11.7%, compared to $1.34 billion for the year ended December 31, 2012. The decrease was directly attributable to lower activity in oil markets during the period and improved operating efficiencies in Key's rig-based services and coiled tubing services, partially offset by labor cost inefficiencies due to weather related work delays and charge of $1.6 million related to lease cancellation fees.
International
Revenues for our international segment decreased $118.6 million, or 35.6%, to $214.7 million for the year ended December 31, 2013, compared to $333.3 million for the year ended December 31, 2012. The decrease was primarily attributable to lower customer activity in Mexico.
Operating expenses for our international segment decreased $28.9 million, or 10.7%, to $241.4 million for the year ended December 31, 2013, compared to $270.3 million for the year ended December 31, 2012. These expenses decreased as a direct result of lower customer activity in Mexico partially offset by charges of $4.8 million primarily associated with severance costs and $2.1 million of costs associated with rig mobilizations from the North Region of Mexico to the South Region of Mexico and to other countries, including the U.S.
Functional support
Operating expenses for our functional support segment decreased $5.9 million, or 4.2%, to $135.5 million (8.5% of consolidated revenues) for the year ended December 31, 2013 compared to $141.4 million (7.2% of consolidated revenues) for the year ended December 31, 2012. The decrease reflects lower consulting fees partially offset by higher severance costs and incentive bonus and equity based compensation accruals.
Years Ended December 31, 2012 and 2011
The following table shows operating results for each of our reportable segments for the years ended December 31, 2012 and 2011 (in thousands):
For the year ended December 31, 2012
U.S. | International | Functional Support | Total | ||||||||||||
Revenues from external customers | $ | 1,626,768 | $ | 333,302 | $ | — | $ | 1,960,070 | |||||||
Operating expenses | 1,341,427 | 270,310 | 141,387 | 1,753,124 | |||||||||||
Operating income (loss) | 285,341 | 62,992 | (141,387 | ) | 206,946 | ||||||||||
For the year ended December 31, 2011
U.S. | International | Functional Support | Total | ||||||||||||
Revenues from external customers | $ | 1,530,087 | $ | 199,124 | $ | — | $ | 1,729,211 | |||||||
Operating expenses | 1,172,481 | 160,203 | 142,751 | 1,475,435 | |||||||||||
Operating income (loss) | 357,606 | 38,921 | (142,751 | ) | 253,776 | ||||||||||
U.S.
Revenues for our U.S. segment increased $96.7 million, or 6.3%, to $1.63 billion for the year ended December 31, 2012, compared to $1.53 billion for the year ended December 31, 2011. The increase was due to an increase in activity for our rig-based services and fishing and rental services along with improved pricing.
Operating expenses for our U.S. segment were $1.34 billion during the year ended December 31, 2012, which represented an increase of $168.9 million, or 14.4%, compared to $1.17 billion for the same period in 2011. We incurred additional costs during 2012 to relocate assets and personnel from declining natural gas markets to oil markets. As a result, we experienced increased activity in oil markets during 2012 combined with the impact of inflationary pressure on fuel, wages and benefit-related expenses.
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International
Revenues for our international segment increased $134.2 million, or 67.4%, to $333.3 million for the year ended December 31, 2012, compared to $199.1 million for the year ended December 31, 2011. The increase was primarily attributable to increased activity in Mexico.
Operating expenses for our international segment increased $110.1 million, or 68.7%, to $270.3 million for the year ended December 31, 2012, compared to $160.2 million for the year ended December 31, 2011. These expenses increased as a direct result of additional activity during the period. We also incurred additional costs to mobilize assets to Oman and Mexico.
Functional support
Operating expenses for our functional support segment decreased $1.4 million, or 1.0%, to $141.4 million (7.2% of consolidated revenues) for the year ended December 31, 2012 compared to $142.8 million (8.3% of consolidated revenues) for the year ended December 31, 2011. The decrease in costs primarily related to lower bonus and equity based compensation expenses. In addition, prior year expenses were offset by a favorable legal settlement of $5.5 million in which Key Energy Services, Inc. was the plaintiff.
Liquidity and Capital Resources
We require capital to fund ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions. Our primary sources of liquidity are cash flows generated from our operations, available cash and borrowings under our senior secured revolving credit facility. We maintain a senior secured credit facility pursuant to a revolving credit agreement with several lenders and JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, and Capital One, N.A., Wells Fargo Bank, N.A., Credit Agricole Corporate and Investment Bank and DnB NOR Bank ASA, as Co-Documentation Agents (as amended on July 27, 2011, our “2011 Credit Facility”). Our 2011 Credit Facility consists of a revolving credit facility, letter of credit sub-facility and swing line facility, up to an aggregate principal amount of $550.0 million, all of which will mature no later than March 31, 2016. We intend to use these sources of liquidity to fund our working capital requirements, capital expenditures, strategic investments and acquisitions.
In 2014, we expect to access available funds under our 2011 Credit Facility to meet our cash requirements for day-to-day operations and in times of peak needs throughout the year. Our planned capital expenditures, as well as any acquisitions we choose to pursue, could be financed through a combination of cash on hand, cash flow from operations, borrowings under our 2011 Credit Facility and, in the case of acquisitions, equity. We believe that our internally generated cash flows from operations, current reserves of cash and availability under our 2011 Credit Facility are sufficient to finance our cash requirements for current and future operations, budgeted capital expenditures and debt service for the next twelve months. Under the terms of our 2011 Credit Facility, committed letters of credit count against our borrowing capacity. As of December 31, 2013, we had $85.0 million in borrowings and $54.1 million of letters of credit outstanding under our 2011 Credit Facility, leaving $410.9 million of unused borrowing capacity subject to covenant compliance on the facility.
All obligations under our 2011 Credit Facility are guaranteed by most of our subsidiaries and are secured by most of our assets, including our accounts receivable, inventory and equipment. See further discussion under “Debt Service” below.
As of December 31, 2013, our adjusted working capital (working capital excluding the current portion of long-term debt of $3.6 million) was $277.4 million. Adjusted working capital (working capital excluding the current portion of capital lease obligations of $0.4 million) at December 31, 2012 was $285.1 million. Our adjusted working capital decreased during 2013 as a result of decrease in cash and cash equivalents, net receivables and inventory partially offset by decrease in accrued taxes.
As of December 31, 2013, we had $28.3 million of cash, of which approximately $2.5 million was held in the bank accounts of our foreign subsidiaries. As of December 31, 2013, $0.1 million of the cash held by our foreign subsidiaries was held in U.S. bank accounts and denominated in U.S. dollars. We believe that the cash held by our wholly owned foreign subsidiaries could be repatriated for general corporate use without material withholdings.
Cash Flows
During the year ended December 31, 2013, we generated cash flows from operating activities of $228.6 million, compared to $369.7 million for the year ended December 31, 2012. These operating cash inflows primarily relate to net income from continuing operations adjusted for non cash items.
Cash used in investing activities was $160.9 million and $428.7 million for years ended December 31, 2013 and 2012, respectively. Investing cash outflows during these periods consisted primarily of capital expenditures. Capital expenditures during 2013 primarily relate to replacement assets for our existing fleet and equipment. Additionally, during 2013, we
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completed the acquisition of the remaining 50% noncontrolling interest in Geostream for $14.6 million. Capital expenditures during 2012 primarily relate to the increased demand for our services compared to 2011 and associated growth initiatives.
Cash used in financing activities was $85.5 million during the year ended December 31, 2013, compared to cash provided by financing activities of $73.9 million during the year ended December 31, 2012. Overall financing cash outflows for 2013 primarily relate to net payments on our 2011 Credit Facility. Overall financing cash inflows for 2012 primarily relate to the proceeds from the issuance of an additional $200.0 million of 2021 Notes, partially offset by net payments on our 2011Credit Facility.
The following table summarizes our cash flows for the years ended December 31, 2013 and 2012:
Year Ended December 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Net cash provided by operating activities | $ | 228,643 | $ | 369,660 | |||
Cash paid for capital expenditures | (164,137 | ) | (447,160 | ) | |||
Proceeds from sale of fixed assets | 17,256 | 17,127 | |||||
Proceeds received from sale of assets held for sale | 600 | 2,000 | |||||
Acquisition of the 50% noncontrolling interest in Geostream | (14,600 | ) | — | ||||
Investment in Wilayat Key Energy, LLC | — | (676 | ) | ||||
Repayments of capital lease obligations | (393 | ) | (1,959 | ) | |||
Proceeds from long-term debt | — | 205,000 | |||||
Proceeds from borrowings on revolving credit facility | 220,000 | 275,000 | |||||
Repayments on revolving credit facility | (300,000 | ) | (405,000 | ) | |||
Payment of deferred financing costs | (69 | ) | (4,597 | ) | |||
Other financing activities, net | (5,030 | ) | 5,502 | ||||
Effect of changes in exchange rates on cash | 87 | (4,391 | ) | ||||
Net increase (decrease) in cash and cash equivalents | $ | (17,643 | ) | $ | 10,506 | ||
Debt Service
At December 31, 2013, our annual maturities on our indebtedness, consisting only of our 2014 Notes, 2021 Notes and borrowings under our 2011 Credit Facility at year-end, were as follows:
Principal Payments | |||
(in thousands) | |||
2014 | $ | 3,573 | |
2015 | — | ||
2016 | 85,000 | ||
2017 | — | ||
2018 and thereafter | 675,000 | ||
Total | $ | 763,573 | |
Interest on $675.0 million of our 2021 Notes is due on March 1 and September 1 of each year. Our 2021 Notes mature on September 1, 2021. Interest on the remaining $3.6 million aggregate principal amount of our 2014 Notes is due on June 1 and December 1 of each year. Our 2014 Notes mature on December 1, 2014. Interest paid on our 2014 Notes and 2021 Notes during 2013 and 2012 was $45.9 million and $38.9 million, respectively. We expect to fund interest payments from cash on hand and cash generated by operations.
2014 Notes
On November 29, 2007, we issued $425.0 million aggregate principal amount of 2014 Notes. On March 4, 2011, we repurchased $421.3 million aggregate principal amount of the 2014 Notes at a purchase price of $1,090 per $1,000 principal amount. On March 15, 2011, we repurchased an additional $0.1 million aggregate principal amount at a purchase price of $1,060 per $1,000 principal amount. In connection with the repurchases of the 2014 Notes, we incurred a loss of $44.3 million on the early extinguishment of debt related to the premium paid on the tender, the payment of related fees and the write-off of unamortized loan fees.
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2021 Notes
We issued $475.0 million aggregate principal amount of 6.75% Senior Notes due 2021 (the “Initial 2021 Notes”) on March 4, 2011 and issued an additional $200.0 million aggregate principal amount of the 2021 Notes (the “Additional 2021 Notes” and, together with the Initial 2021 Notes, the “2021 Notes”) in a private placement on March 8, 2012 under an indenture dated March 4, 2011 (the “Base Indenture”), as supplemented by a first supplemental indenture dated March 4, 2011 and amended by a further supplemental indenture dated March 8, 2012 (the “Supplemental Indenture” and, together with the Base Indenture, the “Indenture”). We used the net proceeds to repay senior secured indebtedness under our revolving bank credit facility. We capitalized $4.6 million of financing costs associated with the issuance of the 2021 Notes that will be amortized over the term of the notes.
On March 5, 2013, we completed an offer to exchange the $200.0 million in aggregate principal amount of unregistered Additional 2021 Notes for an equal principal amount of such notes registered under the Securities Act of 1933. All of the 2021 Notes are treated as a single class under the Indenture and as of the closing of the exchange offer, bear the same CUSIP and ISIN numbers.
The 2021 Notes are general unsecured senior obligations and are effectively subordinated to all of our existing and future secured indebtedness. The 2021 Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries.
On or after March 1, 2016, the 2021 Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, at the redemption prices below (expressed as percentages of the principal amount redeemed), plus accrued and unpaid interest to the applicable redemption date, if redeemed during the twelve-month period beginning on March 1 of the years indicated below:
Year | Percentage | |
2016 | 103.375 | % |
2017 | 102.250 | % |
2018 | 101.125 | % |
2019 and thereafter | 100.000 | % |
At any time and from time to time before March 1, 2014, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the outstanding 2021 Notes at a redemption price of 106.750% of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds from any one or more equity offerings provided that (i) at least 65% of the aggregate principal amount of the 2021 Notes remains outstanding immediately after each such redemption and (ii) each such redemption shall occur within 180 days of the date of the closing of such equity offering.
In addition, at any time and from time to time prior to March 1, 2016, we may, at our option, redeem all or a portion of the 2021 Notes at a redemption price equal to 100% of the principal amount plus a premium with respect to the 2021 Notes plus accrued and unpaid interest to the redemption date. The premium is the excess of (i) the present value of the redemption price of 103.375 of the principal amount, plus all remaining scheduled interest payments due through March 1, 2016 discounted at the treasury rate plus 0.50% over (ii) the principal amount of the note. If we experience a change of control, subject to certain exceptions, we must give holders of the 2021 Notes the opportunity to sell to us their 2021 Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest to the date of purchase.
We are subject to certain negative covenants under the Indenture. The Indenture limits our ability to, among other things:
• | incur additional indebtedness and issue preferred equity interests; |
• | pay dividends or make other distributions or repurchase or redeem equity interests; |
• | make loans and investments; |
• | enter into sale and leaseback transactions; |
• | sell, transfer or otherwise convey assets; |
• | create liens; |
• | enter into transactions with affiliates; |
• | enter into agreements restricting subsidiaries’ ability to pay dividends; |
• | designate future subsidiaries as unrestricted subsidiaries; and |
• | consolidate, merge or sell all or substantially all of the applicable entities’ assets. |
These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions relating to the covenants of our 2011 Credit Facility discussed below. Substantially all of the covenants will terminate before the 2021 Notes mature if one of two specified ratings agencies assigns the 2021 Notes an investment grade rating in the future and no
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events of default exist under the Indenture. As of December 31, 2013, the 2021 Notes were below investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the 2021 Notes later falls below investment grade. We were in compliance with all covenants at December 31, 2013.
2011 Credit Facility
Our 2011 Credit Facility is an important source of liquidity for us. Our 2011 Credit Facility consists of a revolving credit facility, letter of credit sub-facility and swing line facility totaling $550 million, all of which will mature no later than March 31, 2016. The maximum amount that we may borrow under the facility may be subject to limitation due to the operation of the covenants contained in the facility. Our 2011 Credit Facility allows us to request increases in the total commitments under the facility by up to $100.0 million in the aggregate in part or in full anytime during the term of our 2011 Credit Facility, with any such increases being subject to compliance with the restrictive covenants in our 2011 Credit Facility and in the Indenture, as well as lender approval.
We capitalized $4.9 million of financing costs in connection with the execution of our 2011 Credit Facility and an additional $1.4 million related to a subsequent amendment that will be amortized over the term of the debt.
Our interest rate per annum applicable to our 2011 Credit Facility is, at our option, (i) adjusted LIBOR plus the applicable margin or (ii) the higher of (x) JPMorgan’s prime rate, (y) the Federal Funds rate plus 0.5% and (z) one-month adjusted LIBOR plus 1.0%, plus in each case the applicable margin for all other loans. The applicable margin for LIBOR loans ranges from 225 to 300 basis points, and the applicable margin for all other loans ranges from 125 to 200 basis points, depending upon our consolidated total leverage ratio as defined in our 2011 Credit Facility. Unused commitment fees on the facility equal 0.50%.
The 2011 Credit Facility contains certain financial covenants, which, among other things, limit our annual capital expenditures, restrict our ability to repurchase shares and require us to maintain certain financial ratios. The financial ratios require that:
• | our ratio of consolidated funded indebtedness to total capitalization be no greater than 45%; |
• | our senior secured leverage ratio of senior secured funded debt to trailing four quarters of earnings before interest, taxes, depreciation and amortization (as calculated pursuant to the terms of our 2011 Credit Facility, “EBITDA”) be no greater than 2.00 to 1.00; |
• | we maintain a collateral coverage ratio, the ratio of the aggregate book value of the collateral to the amount of the total commitments, as of the last day of any fiscal quarter of at least 2.00 to 1.00; |
• | we maintain a consolidated interest coverage ratio of trailing four quarters EBITDA to interest expense of at least 3.00 to 1.00; and |
• | we limit our capital expenditures and investments in foreign subsidiaries to $250.0 million per fiscal year, if the consolidated total leverage ratio exceeds 3.00 to 1.00. |
In addition, our 2011 Credit Facility contains certain affirmative and negative covenants, including, without limitation, restrictions on (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments (with acquisitions permitted so long as, after giving pro forma effect thereto, no default or event of default exists under our 2011 Credit Facility, the pro forma consolidated total leverage ratio does not exceed 4.00 to 1.00, we are in compliance with other financial covenants and we have at least $25.0 million of availability under our 2011 Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from, equityholders; (vii) making investments, loans or advances; (viii) selling properties; (ix) prepaying, redeeming or repurchasing subordinated (contractually or structurally) debt; (x) engaging in transactions with affiliates; (xi) entering into hedging arrangements; (xii) entering into sale and leaseback transactions; (xiii) granting negative pledges other than to the lenders; (xiv) changes in the nature of business; (xv) amending organizational documents; and (xvi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions.
We were in compliance with these covenants at December 31, 2013. We may prepay our 2011 Credit Facility in whole or in part at any time without premium or penalty, subject to certain reimbursements to the lenders for breakage and redeployment costs. As of December 31, 2013, we had borrowings of $85.0 million under the revolving credit facility and $54.1 million of letters of credit outstanding, leaving $410.9 million of undrawn borrowing capacity, subject to covenant compliance on the facility, under our 2011 Credit Facility. For the years ended December 31, 2013 and 2012, the weighted average interest rates on the outstanding borrowings under our 2011 Credit Facility was 2.76% and 2.71%, respectively.
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Letter of Credit Facility
On November 7, 2013, we entered into an uncommitted, unsecured $15.0 million letter of credit facility to be used solely for the issuances of performance letters of credit. As of December 31, 2013, $4.8 million of letters of credit were outstanding leaving $10.2 million of unused borrowing capacity under the facility.
Capital Lease Agreements
From time to time, we lease equipment, such as vehicles, tractors, trailers, frac tanks and forklifts, from financial institutions under master lease agreements. As of December 31, 2013, no capital leases were outstanding.
Off-Balance Sheet Arrangements
At December 31, 2013, we did not, and we currently do not, have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Contractual Obligations
Set forth below is a summary of our contractual obligations as of December 31, 2013. The obligations we pay in future periods reflect certain assumptions, including variability in interest rates on our variable-rate obligations and the duration of our obligations, and actual payments in future periods may vary.
Payments Due by Period | |||||||||||||||||||
Total | Less than 1 Year (2014) | 1-3 Years (2015-2017) | 4-5 Years (2018-2019) | After 5 Years (2020+) | |||||||||||||||
(in thousands) | |||||||||||||||||||
2014 Notes | 3,573 | 3,573 | — | — | — | ||||||||||||||
2021 Notes | 675,000 | — | — | — | 675,000 | ||||||||||||||
Interest associated with 2014 and 2021 Notes | 345,950 | 45,862 | 136,812 | 91,125 | 72,151 | ||||||||||||||
Borrowings under 2011 Credit Facility | 85,000 | — | 85,000 | — | — | ||||||||||||||
Interest associated with 2011 Credit Facility(1) | 5,506 | 2,448 | 3,058 | — | — | ||||||||||||||
Commitment and availability fees associated with 2011 Credit Facility | 6,677 | 2,054 | 4,623 | — | — | ||||||||||||||
Non-cancelable operating leases | 50,135 | 18,723 | 25,086 | 3,987 | 2,339 | ||||||||||||||
Liabilities for uncertain tax positions | 935 | 442 | 493 | — | — | ||||||||||||||
Equity based compensation liability awards(2) | 1,232 | 1,232 | — | — | — | ||||||||||||||
Total | $ | 1,174,008 | $ | 74,334 | $ | 255,072 | $ | 95,112 | $ | 749,490 | |||||||||
(1) | Based on interest rates in effect at December 31, 2013. |
(2) | Based on our closing stock price at December 31, 2013. |
Debt Compliance
At December 31, 2013, we were in compliance with all the financial covenants under our 2011 Credit Facility, our 2014 Notes and 2021 Notes. Based on management’s current projections, we expect to be in compliance with all the covenants under our 2011 Credit Facility, 2014 Notes and 2021 Notes for the next twelve months. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. See “Item 1A. Risk Factors.”
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Capital Expenditures
During the year ended December 31, 2013, our capital expenditures totaled $164.1 million, primarily related to the ongoing replacement to our rig service fleet, including the addition of forty-seven rigs, coiled tubing units, fluid transportation equipment and rental equipment including drill pipe. Our capital expenditure plan for 2014 of $198 million is primarily related to equipment replacement needs, including ongoing replacement to our rig services fleet. Our capital expenditure program for 2014 is subject to market conditions, including activity levels, commodity prices, industry capacity and specific customer needs. Our focus for 2014 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2014 to increase market share or expand our presence into a new market. We currently anticipate funding our 2014 capital expenditures through a combination of cash on hand, operating cash flow, and borrowings under our 2011 Credit Facility. Should our operating cash flows or activity levels prove to be insufficient to warrant our currently planned capital spending levels, management expects it will adjust our capital spending plans accordingly. We may also incur capital expenditures for strategic investments and acquisitions.
Acquisitions
Geostream
On April 9, 2013, we completed the acquisition of the remaining 50% noncontrolling interest in Geostream for $14.6 million. We now own 100% of Geostream.
AlMansoori Key Energy Services, LCC
On August 5, 2013, we agreed to the dissolution of AlMansoori Key Energy Services, LLC, a joint venture formed under the laws of Abu Dhabi, UAE, and the acquisition of the underlying business for $5.1 million.
Edge
We completed our acquisition of Edge in August 2011. Edge primarily rents frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. It also provides well testing services, rental equipment such as pumps and power swivels and oilfield fishing services.
The total consideration for the acquisition was approximately $305.9 million consisting of approximately 7.5 million shares of our common stock and approximately $187.9 million in cash, which included $26.3 million to reimburse Edge for growth capital expenditures incurred between March 1, 2011 and the date of closing, net of working capital adjustments of $1.8 million.
Other
In January 2011, we acquired, through purchase or lease, 10 SWD wells from Equity Energy Company for approximately $14.3 million. Most of these SWD wells are located in North Dakota.
We anticipate that acquisitions of complementary companies, assets and lines of businesses will continue to play an important role in our business strategy. While there are currently no unannounced agreements or ongoing negotiations for the acquisition of any material businesses or assets, such transactions can be effected quickly and may occur at any time.
Critical Accounting Policies
Our Accounting Department is responsible for the development and application of our accounting policies and internal control procedures and reports to the Chief Financial Officer.
The process and preparation of our financial statements in conformity with generally accepted accounting principles in the United States (“GAAP”) requires us to make certain estimates, judgments and assumptions, which may affect the reported amounts of our assets and liabilities, disclosures of contingencies at the balance sheet date, the amounts of revenues and expenses recognized during the reporting period and the presentation of our statement of cash flows. We may record materially different amounts if these estimates, judgments and assumptions change or if actual results differ. However, we analyze our estimates, assumptions and judgments based on our historical experience and various other factors that we believe to be reasonable under the circumstances.
We have identified the following critical accounting policies that require a significant amount of estimation and judgment to accurately present our financial position, results of operations and cash flows:
• | Revenue recognition; |
• | Estimate of reserves for workers’ compensation, vehicular liability and other self-insurance; |
• | Contingencies; |
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• | Income taxes; |
• | Estimates of depreciable lives; |
• | Valuation of indefinite-lived intangible assets; |
• | Valuation of tangible and finite-lived intangible assets; and |
• | Valuation of equity-based compensation. |
Revenue Recognition
We recognize revenue when all of the following criteria have been met: (i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price to the customer is fixed and determinable and (iv) collectability is reasonably assured.
• | Evidence of an arrangement exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement. |
• | Delivery has occurred or services have been rendered when we have completed requirements pursuant to the terms of the arrangement as evidenced by a field ticket or service log. |
• | The price to the customer is fixed and determinable when the amount that is required to be paid is agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a field ticket. |
• | Collectability is reasonably assured when we screen our customers and provide goods and services to customers according to determined credit terms that have been granted in accordance with our credit policy. |
We present our revenues net of any sales taxes collected by us from our customers that are required to be remitted to local or state governmental taxing authorities.
We review our contracts for multiple element revenue arrangements. Deliverables will be separated into units of accounting and assigned fair value if they have standalone value to our customer, have objective and reliable evidence of fair value, and delivery of undelivered items is substantially controlled by us. We believe that the negotiated prices for deliverables in our services contracts are representative of fair value since the acceptance or non-acceptance of each element in the contract does not affect the other elements.
Workers’ Compensation, Vehicular Liability and Other Self-Insurance
The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not be available to cover any or all of these risks, and, if available, we might not be able to obtain such insurance without a substantial increase in premiums. It is possible that, in addition to higher premiums, future insurance coverage may be subject to higher deductibles and coverage restrictions.
We estimate our liability arising out of uninsured and potentially insured events, including workers’ compensation, employer’s liability, vehicular liability, and general liability, and record accruals in our consolidated financial statements. Reserves related to claims are based on the specific facts and circumstances of the insured event and our past experience with similar claims and trend analysis. We adjust loss estimates in the calculation of these accruals based upon actual claim settlements and reported claims. Loss estimates for individual claims are adjusted based upon actual claim judgments, settlements and reported claims. The actual outcome of these claims could differ significantly from estimated amounts. Changes in our assumptions and estimates could potentially have a negative impact on our earnings.
We are largely self-insured against physical damage to our property, rigs, equipment and automobiles due to large deductibles or self-insurance.
Contingencies
We are periodically required to record other loss contingencies, which relate to lawsuits, claims, proceedings and tax-related audits in the normal course of our operations, on our consolidated balance sheet. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We periodically review our loss contingencies to ensure that we have recorded appropriate liabilities on the balance sheet. We adjust these liabilities based on estimates and judgments made by management with respect to the likely outcome of these matters, including the effect of any applicable insurance coverage for litigation matters. Our estimates and judgments could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. Actual results could vary materially from these reserves.
We record liabilities when environmental assessment indicates that site remediation efforts are probable and the costs can be reasonably estimated. We measure environmental liabilities based, in part, on relevant past experience, currently enacted
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laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability or the low amount in a range of estimates. These assumptions involve the judgments and estimates of management, and any changes in assumptions or new information could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.
We record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flows change, the change may have a material impact on our results of operations.
Income Taxes
We account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, yet deferred until future periods. Current taxes payable represent our liability related to our income tax return for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatment of certain items for tax and accounting purposes or whether such differences are permanent. The final determination of our tax liability involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred.
We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record uncertain tax positions at their net recognizable amount, based on the amount that management deems is more likely than not to be sustained upon ultimate settlement with the tax authorities in the domestic and international tax jurisdictions in which we operate.
If our estimates or assumptions regarding our current and deferred tax items are inaccurate or are modified, these changes could have potentially material negative impacts on our earnings.
Estimates of Depreciable Lives
We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy-duty trucks and trailers, to compute depreciation expense, to estimate future asset retirement obligations and to conduct impairment tests. We base the estimates of our depreciable lives on a number of factors, such as the environment in which the assets operate, industry factors including forecasted prices and competition, and the assumption that we provide the appropriate amount of capital expenditures while the asset is in operation to maintain economical operation of the asset and prevent untimely demise to scrap. The useful lives of our intangible assets are determined by the years over which we expect the assets to generate a benefit based on legal, contractual or other expectations.
We depreciate our operational assets over their depreciable lives to their salvage value, which is generally 10% of the acquisition cost. We recognize a gain or loss upon ultimate disposal of the asset based on the difference between the carrying value of the asset on the disposal date and any proceeds we receive in connection with the disposal.
We periodically analyze our estimates of the depreciable lives of our fixed assets to determine if the depreciable periods and salvage value continue to be appropriate. We also analyze useful lives and salvage value when events or conditions occur that could shorten the remaining depreciable life of the asset. We review the depreciable periods and salvage values for reasonableness, given current conditions. As a result, our depreciation expense is based upon estimates of depreciable lives of the fixed assets, the salvage value and economic factors, all of which require management to make significant judgments and estimates. If we determine that the depreciable lives should be different than originally estimated, depreciation expense may increase or decrease and impairments in the carrying values of our fixed assets may result, which could negatively impact our earnings.
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Valuation of Indefinite-Lived Intangible Assets
We periodically review our intangible assets not subject to amortization, including our goodwill, to determine whether an impairment of those assets may exist. These tests must be made on at least an annual basis, or more often if circumstances indicate that the assets may be impaired. These circumstances include, but are not limited to, significant adverse changes in the business climate.
The test for impairment of indefinite-lived intangible assets allows us to first assess the qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If our qualitative analysis shows that it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount we will perform the two-step goodwill impairment test. In the first step, a fair value is calculated for each of our reporting units, and that fair value is compared to the current carrying value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit exceeds its carrying value, there is no potential impairment, and the second step is not performed. If the carrying value exceeds the fair value of the reporting unit, then the second step is required.
The second step of the test for impairment compares the implied fair value of the reporting unit’s goodwill to its current carrying value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount of goodwill that would be recognized in a business combination, with the purchase price being equal to the fair value of the reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no impairment charge is recorded. If the carrying value of the reporting unit’s goodwill is in excess of its implied fair value, an impairment charge equal to the excess is recorded.
We have historically evaluated our goodwill for impairment one level below the reporting segment level, at the reporting unit level, annually as of December 31 or more frequently if impairment indicators arose in accordance with Accounting Standards Codification (ASC) Topic 350. In the third quarter of 2013, we changed the date of our annual assessment of goodwill impairment to October 1 of each year. The change in the assessment date does not delay, accelerate, avoid or cause an impairment charge, nor does this change result in adjustments to previously issued financial statements. We believe that the change in date aligns with our planning cycle, which should create a synergy and allow the goodwill impairment analysis to be embedded with the projection of future results for business planning purposes. We believe this will enhance the quality of the goodwill impairment analysis. Also, the change in date allows us more time to identify and respond to any issues noted in the analysis before finalization of SEC filings, which will improve the quality of financial reporting. As such, the Company has prospectively applied the change in annual goodwill impairment testing date beginning in the fourth quarter of 2013.
We conducted our annual impairment test for goodwill and other intangible assets not subject to amortization as of October 1, 2013. In determining the fair value of our reporting units, we use a weighted-average approach of three commonly used valuation techniques — a discounted cash flow method, a guideline companies method, and a similar transactions method. We assigned a weight to the results of each of these methods based on the facts and circumstances that are in existence for that testing period. We assigned more weight to the discounted cash flow method as we believe it is more representative of the future of the business.
In addition to the estimates made by management regarding the weighting of the various valuation techniques, the creation of the techniques themselves requires that we make significant estimates and assumptions. The discounted cash flow method, which was assigned the highest weight by management during the current year, requires us to make assumptions about future cash flows, future growth rates, tax rates in future periods, book-tax differences in the carrying value of our assets in future periods, and discount rates. The assumptions about future cash flows and growth rates are based on our current budgets for future periods, as well as our strategic plans, the beliefs of management about future activity levels, and analysts’ expectations about our revenues, profitability and cash flows in future periods. The assumptions about our future tax rates and book-tax differences in the carrying value of our assets in future periods are based on the assumptions about our future cash flows and growth rates, and management’s knowledge of and beliefs about tax law and practice in current and future periods. The assumptions about discount rates include an assessment of the specific risk associated with each reporting unit being tested, and were developed with the assistance of a third-party valuation consultant. The ultimate conclusions of the valuation techniques remain our responsibility.
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While this test is required on an annual basis, it can also be required more frequently based on changes in external factors or other triggering events. We conducted our most recent annual test for impairment of our goodwill and other indefinite-lived intangible assets as of October 1, 2013. On that date, our reporting units for the purposes of impairment testing were rig-based services, fluid management services, coiled tubing services, fishing and rental services and our Russian and Canadian reporting units. Our goodwill by reporting unit as of December 31, 2013 is as follows (in thousands, except for percentages):
U.S. | |||||||
Rig-Based Services | $ | 283,401 | 45 | % | |||
Coiled Tubing Services | 102,799 | 16 | % | ||||
Fishing and Rental Services | 173,463 | 28 | % | ||||
Fluid Management Services | 19,301 | 3 | % | ||||
Functional Support | 18,493 | 3 | % | ||||
Subtotal | 597,457 | 95 | % | ||||
International | |||||||
Canada | 4,381 | 1 | % | ||||
Russia | 23,037 | 4 | % | ||||
Subtotal | 27,418 | 5 | % | ||||
Total | $ | 624,875 | 100 | % | |||
We also have intangible assets that are not amortized of $5.1 million and $8.5 million related to our fishing and rental services reporting unit and our Russian reporting unit, respectively. These tradenames are tested for impairment annually using a relief from royalty method.
We performed our qualitative analysis of goodwill impairment as of October 1, 2013. Based on this analysis, our Canadian reporting unit did not have a triggering event that would indicate it was “more likely than not” that the carrying value of this reporting unit was higher than its fair value. However, we determined it was necessary to perform the first step of the goodwill impairment test for our rig services, fluid management services, coiled tubing services, fishing and rental services and Russian reporting units. Under the first step of the goodwill impairment test, we compared the fair value of each reporting unit to its carrying amount, including goodwill. Based on the results of step 1, the fair value of our rig-based services, fluid management services, coiled tubing services, fishing and rental services and our Russian reporting units exceeded their carrying value by 11%, 4%, 19%, 21% and 86%, respectively. A key assumption in our model was our forecast of increased revenue for 2014 for rig-based services, fluid management services and fishing and rental services, followed by nominal revenue increases through 2018. We anticipate our coiled tubing services and Russian reporting units to have increased revenue in future years. Potential events that could affect this assumption include the level of development, exploration and production activity of, and corresponding capital spending by, oil and natural gas companies in Russia, oil and natural gas production costs, government regulations and conditions in the worldwide oil and natural gas industry. Other possible factors that could affect this assumption are the ability to acquire and deploy additional assets and deployment of these assets into the region. Because the fair value of the reporting units exceeded their carrying values, we determined that no impairment of our goodwill associated with our reporting units existed as of October 1, 2013, and that step two of the impairment test was not required.
As noted above, the determination of the fair value of our reporting units is heavily dependent upon certain estimates and assumptions that we make about our reporting units. While the estimates and assumptions that we made regarding our reporting units for our 2013 annual test indicated that the fair values of the reporting units exceeded their carrying values, and although we believe that our estimates and assumptions are reasonable, it is possible that changes in those estimates and assumptions could impact the determination of the fair value of our reporting units. Discount rates we use in future periods could change substantially if the cost of debt or equity were to significantly increase or decrease, or if we were to choose different comparable companies in determining the appropriate discount rate for our reporting units. Additionally, our future projected cash flows for our reporting units could significantly impact the fair value of our reporting units, and if our current projections about our future activity levels, pricing, and cost structure are inaccurate, the fair value of our reporting units could change materially. If the current overall economy further declines or if there is a significant and rapid adverse change in our business in the near- or mid-term for any of our reporting units, our current estimates of the fair value of our reporting units could decrease significantly, leading to possible impairment charges in future periods. Based on our current knowledge and beliefs, we do not think that material adverse changes to our current estimates and assumptions such that our rig-based services, coiled tubing services, fishing and rental services and our Russian reporting units would fail step one of the impairment test are reasonably possible. Based on the forecast for fluid management services, which has a cushion of four percent, we expect the business will show a rebound of growth in 2014 and future years thus we do not anticipate an impairment.
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Valuation of Tangible and Finite-Lived Intangible Assets
Our fixed assets and finite-lived intangibles are tested for potential impairment when circumstances or events indicate a possible impairment may exist. These circumstances or events are referred to as “trigger events” and examples of such trigger events include, but are not limited to, an adverse change in market conditions, a significant decrease in benefits being derived from an acquired business, a change in the use of an asset, or a significant disposal of a particular asset or asset class.
If a trigger event occurs, an impairment test is performed based on an undiscounted cash flow analysis. To perform an impairment test, we make judgments, estimates and assumptions regarding long-term forecasts of revenues and expenses relating to the assets subject to review. Market conditions, energy prices, estimated depreciable lives of the assets, discount rate assumptions and legal factors impact our operations and have a significant effect on the estimates we use to determine whether our assets are impaired. If the results of the analysis indicate that the carrying value of the assets being tested for impairment are not recoverable, then we record an impairment charge to write the carrying value of the assets down to their fair value. Using different judgments, assumptions or estimates, we could potentially arrive at a materially different fair value for the assets being tested for impairment, which may result in an impairment charge.
We did not identify any trigger events causing us to test our tangible and finite-lived intangible assets for impairment during the years ended December 31, 2013, 2012 and 2011.
Valuation of Equity-Based Compensation
We have granted stock options, stock-settled stock appreciation rights (“SARs”), restricted stock (“RSAs” and “RSUs”), phantom shares and performance units to our employees and non-employee directors. The option and SAR awards we grant are fair valued using a Black-Scholes option model on the grant date and are amortized to compensation expense over the vesting period of the option or SAR award, net of estimated and actual forfeitures. Compensation related to RSAs and RSUs is based on the fair value of the award on the grant date and is recognized based on the vesting requirements that have been satisfied during the period. Phantom shares are accounted for at fair value, and changes in the fair value of these awards are recorded as compensation expense during the period. Performance units provide a cash incentive award, the unit value of which is determined with reference to our common stock. See “Note 20. Share Based Compensation” in “Item 8. Financial Statements and Supplementary Data” for a more detailed discussion of performance units measurement.
In utilizing the Black-Scholes option pricing model to determine fair values of awards, certain assumptions are made which are based on subjective expectations, and are subject to change. A change in one or more of these assumptions would impact the expense associated with future grants. These key assumptions include the volatility in the price of our common stock, the risk-free interest rate and the expected life of awards. We did not grant any stock options during the years ended December 31, 2013, 2012 and 2011.
New Accounting Standards Adopted in this Report
There are no new accounting standards that have been adopted or not yet adopted in this report.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to certain market risks as part of our ongoing business operations, including risks from changes in interest rates, foreign currency exchange rates and equity prices that could impact our financial position, results of operations and cash flows. We manage our exposure to these risks through regular operating and financing activities, and may, on a limited basis, use derivative financial instruments to manage this risk. Derivative financial instruments were not used in the years ended December 31, 2013, 2012 and 2011. To the extent that we use such derivative financial instruments, we will use them only as risk management tools and not for speculative investment purposes.
Interest Rate Risk
As of December 31, 2013, we had outstanding $675.0 million of 2021 Notes and $3.6 million of 2014 Notes. These notes are fixed-rate obligations, and as such do not subject us to risks associated with changes in interest rates. Borrowings under our 2011 Credit Facility bear interest at variable interest rates, and therefore expose us to interest rate risk. As of December 31, 2013, the weighted average interest rates on our outstanding variable-rate debt obligations was 2.88%. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by $0.2 million.
Foreign Currency Risk
As of December 31, 2013, we conduct operations in Mexico, Colombia, Ecuador, the Middle East and Russia. We also have a Canadian subsidiary. As of December 31, 2011, the functional currency for Mexico, Russia and Canada was the local currency and the functional currency for Colombia and the Middle East was the U. S. dollar. Due to significant changes in economic facts and circumstances, the functional currency for Mexico and Canada was changed to the U.S. dollar effective
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January 1, 2012. For balances denominated in our Russian subsidiaries’ local currency, changes in the value of their assets and liabilities due to changes in exchange rates are deferred and accumulated in other comprehensive income until we liquidate our investment. Our Russian foreign subsidiaries must remeasure their account balances at the end of each period to an equivalent amount of local currency, with changes reflected in earnings during the period. A hypothetical 10% decrease in the average value of the U.S. dollar relative to the value of the local currency for our Russian subsidiaries would increase our net income by $0.1 million.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Key Energy Services, Inc. and Subsidiaries
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Key Energy Services, Inc.
We have audited the accompanying consolidated balance sheets of Key Energy Services, Inc. (a Maryland corporation) and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, changes in shareholders' 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Energy Services, Inc. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2014 expressed an unqualified opinion on the effectiveness of internal control over financial reporting.
/s/ GRANT THORNTON LLP
Houston, Texas
February 25, 2014
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Key Energy Services, Inc.
We have audited the internal control over financial reporting of Key Energy Services, Inc. (a Maryland corporation) and subsidiaries (the “Company”) as of December 31, 2013, based on criteria established in the 1992 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's 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.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the 1992 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2013, and our report dated February 25, 2014 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
February 25, 2014
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Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31, | |||||||
2013 | 2012 | ||||||
(in thousands, except share amounts) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 28,306 | $ | 45,949 | |||
Accounts receivable, net of allowance for doubtful accounts of $766 and $2,860 | 348,966 | 404,390 | |||||
Inventories | 32,335 | 38,622 | |||||
Other current assets | 96,546 | 100,833 | |||||
Total current assets | 506,153 | 589,794 | |||||
Property and equipment, gross | 2,606,738 | 2,528,578 | |||||
Accumulated depreciation | (1,241,092 | ) | (1,091,904 | ) | |||
Property and equipment, net | 1,365,646 | 1,436,674 | |||||
Goodwill | 624,875 | 626,481 | |||||
Other intangible assets, net | 41,146 | 60,905 | |||||
Deferred financing costs, net | 13,897 | 16,628 | |||||
Deposits | 1,533 | 7,339 | |||||
Equity method investments | 962 | 966 | |||||
Other assets | 33,258 | 22,801 | |||||
TOTAL ASSETS | $ | 2,587,470 | $ | 2,761,588 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 58,826 | $ | 104,073 | |||
Other current liabilities | 169,945 | 200,630 | |||||
Current portion of capital lease obligations | — | 393 | |||||
Current portion of long-term debt | 3,573 | — | |||||
Total current liabilities | 232,344 | 305,096 | |||||
Long-term debt | 763,981 | 848,110 | |||||
Workers’ compensation, vehicular and health insurance liabilities | 29,944 | 33,676 | |||||
Deferred tax liabilities | 284,453 | 259,453 | |||||
Other non-current accrued liabilities | 25,655 | 27,921 | |||||
Commitments and contingencies | |||||||
Equity: | |||||||
Common stock, $0.10 par value; 200,000,000 shares authorized, 152,331,006 and 151,069,609 shares issued and outstanding | 15,233 | 15,108 | |||||
Additional paid-in capital | 953,306 | 925,132 | |||||
Accumulated other comprehensive loss | (15,414 | ) | (6,148 | ) | |||
Retained earnings | 297,968 | 319,736 | |||||
Total equity attributable to Key | 1,251,093 | 1,253,828 | |||||
Noncontrolling interest | — | 33,504 | |||||
Total equity | 1,251,093 | 1,287,332 | |||||
TOTAL LIABILITIES AND EQUITY | $ | 2,587,470 | $ | 2,761,588 | |||
See the accompanying notes which are an integral part of these consolidated financial statements
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Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands, except per share amounts) | |||||||||||
REVENUES | $ | 1,591,676 | $ | 1,960,070 | $ | 1,729,211 | |||||
COSTS AND EXPENSES: | |||||||||||
Direct operating expenses | 1,114,462 | 1,308,845 | 1,085,190 | ||||||||
Depreciation and amortization expense | 225,297 | 213,783 | 166,946 | ||||||||
General and administrative expenses | 221,753 | 230,496 | 223,299 | ||||||||
Operating income | 30,164 | 206,946 | 253,776 | ||||||||
Loss on early extinguishment of debt | — | — | 46,451 | ||||||||
Interest expense, net of amounts capitalized | 55,204 | 53,566 | 40,849 | ||||||||
Other income, net | (803 | ) | (6,649 | ) | (8,977 | ) | |||||
Income (loss) from continuing operations before tax | (24,237 | ) | 160,029 | 175,453 | |||||||
Income tax (expense) benefit | 3,064 | (57,352 | ) | (64,117 | ) | ||||||
Income (loss) from continuing operations | (21,173 | ) | 102,677 | 111,336 | |||||||
Loss from discontinued operations, net of tax | — | (93,568 | ) | (10,681 | ) | ||||||
Net income (loss) | (21,173 | ) | 9,109 | 100,655 | |||||||
Income (loss) attributable to noncontrolling interest | 595 | 1,487 | (806 | ) | |||||||
INCOME (LOSS) ATTRIBUTABLE TO KEY | $ | (21,768 | ) | $ | 7,622 | $ | 101,461 | ||||
Earnings (loss) per share from continuing operations attributable to Key: | |||||||||||
Basic | $ | (0.14 | ) | $ | 0.67 | $ | 0.77 | ||||
Diluted | $ | (0.14 | ) | $ | 0.67 | $ | 0.76 | ||||
Loss per share from discontinued operations: | |||||||||||
Basic | $ | — | $ | (0.62 | ) | $ | (0.07 | ) | |||
Diluted | $ | — | $ | (0.62 | ) | $ | (0.07 | ) | |||
Earnings (loss) per share attributable to Key: | |||||||||||
Basic | $ | (0.14 | ) | $ | 0.05 | $ | 0.70 | ||||
Diluted | $ | (0.14 | ) | $ | 0.05 | $ | 0.69 | ||||
Income (loss) from continuing operations attributable to Key: | |||||||||||
Income (loss) from continuing operations | $ | (21,173 | ) | $ | 102,677 | $ | 111,336 | ||||
Income (loss) attributable to noncontrolling interest | 595 | 1,487 | (806 | ) | |||||||
Income (loss) from continuing operations attributable to Key | $ | (21,768 | ) | $ | 101,190 | $ | 112,142 | ||||
Weighted Average Shares Outstanding: | |||||||||||
Basic | 152,271 | 151,106 | 145,909 | ||||||||
Diluted | 152,271 | 151,125 | 146,217 | ||||||||
See the accompanying notes which are an integral part of these consolidated financial statements
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Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
INCOME (LOSS) FROM CONTINUING OPERATIONS | $ | (21,173 | ) | $ | 102,677 | $ | 111,336 | ||||
Other comprehensive income (loss), net of tax: | |||||||||||
Foreign currency translation income (loss), net of tax of $0, $0, and $734 | (5,607 | ) | 1,933 | (7,194 | ) | ||||||
Reclassification adjustment for sales of foreign subsidiaries | — | 51,892 | — | ||||||||
Gain on sale of equity method investment, net of tax of $0, $0, and $(410) | — | — | 1,061 | ||||||||
Total other comprehensive income (loss), net of tax | (5,607 | ) | 53,825 | (6,133 | ) | ||||||
COMPREHENSIVE INCOME (LOSS) FROM CONTINUING OPERATIONS, NET OF TAX | (26,780 | ) | 156,502 | 105,203 | |||||||
Comprehensive loss from discontinued operations, net of tax | — | (93,568 | ) | (13,081 | ) | ||||||
COMPREHENSIVE INCOME (LOSS) | (26,780 | ) | 62,934 | 92,122 | |||||||
Comprehensive (income) loss attributable to noncontrolling interest | 96 | (3,229 | ) | 2,442 | |||||||
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO KEY | $ | (26,684 | ) | $ | 59,705 | $ | 94,564 | ||||
See the accompanying notes which are an integral part of these consolidated financial statements
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Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||
Net income (loss) | $ | (21,173 | ) | $ | 9,109 | $ | 100,655 | ||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
Depreciation and amortization expense | 225,297 | 213,783 | 169,604 | ||||||||
Asset retirements and impairments | — | 84,732 | — | ||||||||
Bad debt expense | 634 | 1,299 | 2,559 | ||||||||
Accretion of asset retirement obligations | 604 | 594 | 594 | ||||||||
(Income) loss from equity method investments | 447 | 926 | (266 | ) | |||||||
Gain on sale of equity method investment | — | — | (4,783 | ) | |||||||
Amortization of deferred financing costs and premium on debt | 2,244 | 2,664 | 2,150 | ||||||||
Deferred income tax expense (benefit) | (11,929 | ) | 35,998 | 85,792 | |||||||
Capitalized interest | (607 | ) | (1,314 | ) | (1,735 | ) | |||||
(Gain) loss on disposal of assets, net | (2,972 | ) | 1,661 | (3,726 | ) | ||||||
Loss on early extinguishment of debt | — | — | 46,451 | ||||||||
Share-based compensation | 13,785 | 13,306 | 15,609 | ||||||||
Excess tax expense (benefit) from share-based compensation | 1,848 | (4,085 | ) | (4,859 | ) | ||||||
Changes in working capital: | |||||||||||
Accounts receivable | 54,003 | (15,409 | ) | (152,771 | ) | ||||||
Other current assets | 5,915 | (42,558 | ) | (22,110 | ) | ||||||
Accounts payable and accrued liabilities | (82,318 | ) | 60,665 | 3,720 | |||||||
Share-based compensation liability awards | 954 | 1,555 | 385 | ||||||||
Other assets and liabilities | 41,911 | 6,734 | (48,964 | ) | |||||||
Net cash provided by operating activities | 228,643 | 369,660 | 188,305 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||
Capital expenditures | (164,137 | ) | (447,160 | ) | (359,097 | ) | |||||
Proceeds from sale of fixed assets | 17,256 | 17,127 | 14,100 | ||||||||
Proceeds from sale of assets held for sale | 600 | 2,000 | — | ||||||||
Acquisitions, net of cash acquired of $0, $0 and $886, respectively | — | — | (187,058 | ) | |||||||
Acquisition of the 50% noncontrolling interest in Geostream | (14,600 | ) | — | — | |||||||
Investment in Wilayat Key Energy, LLC | — | (676 | ) | — | |||||||
Proceeds from sale of equity method investment | — | — | 11,965 | ||||||||
Net cash used in investing activities | (160,881 | ) | (428,709 | ) | (520,090 | ) | |||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||
Repayments of long-term debt | — | — | (421,427 | ) | |||||||
Payment of bond tender premium | — | — | (39,082 | ) | |||||||
Proceeds from long-term debt | — | 205,000 | 475,000 | ||||||||
Repayments of capital lease obligations | (393 | ) | (1,959 | ) | (4,016 | ) | |||||
Proceeds from borrowings on revolving credit facility | 220,000 | 275,000 | 418,000 | ||||||||
Repayments on revolving credit facility | (300,000 | ) | (405,000 | ) | (123,000 | ) | |||||
Payment of deferred financing costs | (69 | ) | (4,597 | ) | (16,485 | ) | |||||
Repurchases of common stock | (3,196 | ) | (7,519 | ) | (5,681 | ) | |||||
Proceeds from exercise of stock options and warrants | 14 | 901 | 8,000 | ||||||||
Excess tax (expense) benefit from share-based compensation | (1,848 | ) | 4,085 | 4,859 | |||||||
Other financing activities | — | 8,035 | 9,916 | ||||||||
Net cash provided by (used in) financing activities | (85,492 | ) | 73,946 | 306,084 | |||||||
Effect of changes in exchange rates on cash | 87 | (4,391 | ) | 4,516 | |||||||
Net increase (decrease) in cash and cash equivalents | (17,643 | ) | 10,506 | (21,185 | ) | ||||||
Cash and cash equivalents, beginning of period | 45,949 | 35,443 | 56,628 | ||||||||
Cash and cash equivalents, end of period | $ | 28,306 | $ | 45,949 | $ | 35,443 | |||||
See the accompanying notes which are an integral part of these consolidated financial statements
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Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
COMMON STOCKHOLDERS | Noncontrolling Interest | Total | ||||||||||||||||||||||||
Common Stock | Additional Paid-in Capital | Accumulated Other Comprehensive Loss | Retained Earnings | |||||||||||||||||||||||
Number of Shares | Amount at par | |||||||||||||||||||||||||
(in thousands, except per share data) | ||||||||||||||||||||||||||
BALANCE AT DECEMBER 31, 2010 | 141,656 | $ | 14,166 | $ | 775,601 | $ | (51,334 | ) | $ | 210,653 | $ | 32,717 | $ | 981,803 | ||||||||||||
Foreign currency translation | (5,558 | ) | — | (1,636 | ) | (7,194 | ) | |||||||||||||||||||
Foreign currency impact on sale of Argentina (Note 3) | — | — | — | (2,400 | ) | — | — | (2,400 | ) | |||||||||||||||||
Common stock purchases | (384 | ) | (39 | ) | (5,642 | ) | — | — | — | (5,681 | ) | |||||||||||||||
Exercise of stock options and warrants | 728 | 73 | 7,927 | — | — | — | 8,000 | |||||||||||||||||||
Issuance of shares in acquisition | 7,549 | 755 | 117,164 | — | — | — | 117,919 | |||||||||||||||||||
Share-based compensation | 1,184 | 118 | 15,491 | — | — | — | 15,609 | |||||||||||||||||||
Tax benefit from share-based compensation | — | — | 4,859 | — | — | 4,859 | ||||||||||||||||||||
Foreign currency impact of sale of equity investment, net of tax (Note 12) | — | — | — | 1,061 | — | — | 1,061 | |||||||||||||||||||
Net income (loss) | — | — | — | — | 101,461 | (806 | ) | 100,655 | ||||||||||||||||||
BALANCE AT DECEMBER 31, 2011 | 150,733 | 15,073 | 915,400 | (58,231 | ) | 312,114 | 30,275 | 1,214,631 | ||||||||||||||||||
Foreign currency translation | — | — | — | 191 | — | 1,742 | 1,933 | |||||||||||||||||||
Foreign currency impact on sale of Argentina (Note 3) | — | — | — | 51,892 | — | — | 51,892 | |||||||||||||||||||
Common stock purchases | (483 | ) | (48 | ) | (7,471 | ) | — | — | — | (7,519 | ) | |||||||||||||||
Exercise of stock options and warrants | 100 | 10 | 891 | — | — | — | 901 | |||||||||||||||||||
Share-based compensation | 788 | 80 | 13,226 | — | — | — | 13,306 | |||||||||||||||||||
Tax benefit from share-based compensation | — | — | 4,085 | — | — | — | 4,085 | |||||||||||||||||||
Shares surrendered | (68 | ) | (7 | ) | (999 | ) | — | — | — | (1,006 | ) | |||||||||||||||
Net income | — | — | — | — | 7,622 | 1,487 | 9,109 | |||||||||||||||||||
BALANCE AT DECEMBER 31, 2012 | 151,070 | 15,108 | 925,132 | (6,148 | ) | 319,736 | 33,504 | 1,287,332 | ||||||||||||||||||
Foreign currency translation | — | — | — | (4,916 | ) | — | (691 | ) | (5,607 | ) | ||||||||||||||||
Common stock purchases | (416 | ) | (42 | ) | (3,154 | ) | — | — | — | (3,196 | ) | |||||||||||||||
Exercise of stock options | 4 | — | 14 | — | — | — | 14 | |||||||||||||||||||
Share-based compensation | 1,673 | 167 | 13,618 | — | — | — | 13,785 | |||||||||||||||||||
Tax expense from share-based compensation | — | — | (1,848 | ) | — | — | — | (1,848 | ) | |||||||||||||||||
Acquisition of the 50% noncontrolling interest in Geostream (Note 2) | — | — | 22,432 | (4,350 | ) | — | (31,196 | ) | (13,114 | ) | ||||||||||||||||
Acquisition of the 51% noncontrolling interest in AlMansoori Key Energy Services, LLC (Note 2) | — | — | (2,888 | ) | — | — | (2,212 | ) | (5,100 | ) | ||||||||||||||||
Net income (loss) | — | — | — | — | (21,768 | ) | 595 | (21,173 | ) | |||||||||||||||||
BALANCE AT DECEMBER 31, 2013 | 152,331 | $ | 15,233 | $ | 953,306 | $ | (15,414 | ) | $ | 297,968 | $ | — | $ | 1,251,093 | ||||||||||||
See the accompanying notes which are an integral part of these consolidated financial statements
51
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Key Energy Services, Inc., its wholly owned subsidiaries and its controlled subsidiaries (collectively, “Key,” the “Company,” “we,” “us” and “our”) provide a full range of well services to major oil companies, foreign national oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States, and we have operations in Mexico, Colombia, Ecuador, the Middle East and Russia. In addition, we have a technology development and control systems business based in Canada.
Basis of Presentation
The consolidated financial statements included in this Annual Report on Form 10-K present our financial position, results of operations and cash flows for the periods presented in accordance with generally accepted accounting principles in the United States (“GAAP”).
The preparation of these consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets, (iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves, (vii) provide allowances for our uncollectible accounts receivable, (viii) value our asset retirement obligations, and (ix) value our equity-based compensation. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates relate to improved information not previously available. Because of the limitations inherent in this process, our actual results may differ materially from these estimates. We believe that our estimates are reasonable.
We have evaluated events occurring after the balance sheet date included in this Annual Report on Form 10-K for possible disclosure as a subsequent event. Management monitored for subsequent events through the date that these financial statements were issued.
On February 17, 2012, the Company announced its decision to sell its business and operations in Argentina (the “Argentina business”) and on September 14, 2012 completed the sale of the Argentina business. In accordance with applicable accounting requirements and guidance, the Company has reclassified and presented the Argentina business as a discontinued operation for the 2011 and 2012 periods.
Principles of Consolidation
Within our consolidated financial statements, we include our accounts and the accounts of our majority-owned or controlled subsidiaries. We eliminate intercompany accounts and transactions. When we have an interest in an entity for which we do not have significant control or influence, we account for that interest using the cost method. When we have an interest in an entity and can exert significant influence but not control, we account for that interest using the equity method.
Acquisitions
From time to time, we acquire businesses or assets that are consistent with our long-term growth strategy. Results of operations for acquisitions are included in our financial statements beginning on the date of acquisition and are accounted for using the acquisition method. For all business combinations (whether partial, full or in stages), the acquirer records 100% of all assets and liabilities of the acquired business, including goodwill, at their fair values; including contingent consideration. Final valuations of assets and liabilities are obtained and recorded as soon as practicable no later than one year from the date of the acquisition.
Revenue Recognition
We recognize revenue when all of the following criteria have been met: (i) evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price to the customer is fixed and determinable and (iv) collectability is reasonably assured.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
• | Evidence of an arrangement exists when a final understanding between us and our customer has occurred, and can be evidenced by a completed customer purchase order, field ticket, supplier contract, or master service agreement. |
• | Delivery has occurred or services have been rendered when we have completed requirements pursuant to the terms of the arrangement as evidenced by a field ticket or service log. |
• | The price to the customer is fixed and determinable when the amount that is required to be paid is agreed upon. Evidence of the price being fixed and determinable is evidenced by contractual terms, our price book, a completed customer purchase order, or a field ticket. |
• | Collectability is reasonably assured when we screen our customers and provide goods and services to customers according to determined credit terms that have been granted in accordance with our credit policy. |
We present our revenues net of any sales taxes collected by us from our customers that are required to be remitted to local or state governmental taxing authorities.
We review our contracts for multiple element revenue arrangements. Deliverables will be separated into units of accounting and assigned fair value if they have standalone value to our customer, have objective and reliable evidence of fair value, and delivery of undelivered items is substantially controlled by us. We believe that the negotiated prices for deliverables in our services contracts are representative of fair value since the acceptance or non-acceptance of each element in the contract does not affect the other elements.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash equivalents. At December 31, 2013, we have not entered into any compensating balance arrangements, but all of our obligations under our 2011 Credit Facility (as defined below) with a syndicate of banks of which JPMorgan Chase Bank, N.A. is the administrative agent were secured by most of our assets, including assets held by our subsidiaries, which includes our cash and cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.
We maintain our cash in bank deposit and brokerage accounts which exceed federally insured limits. As of December 31, 2013, accounts were guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 and substantially all of our accounts held deposits in excess of the FDIC limits.
We believe that the cash held by our other foreign subsidiaries could be repatriated for general corporate use without material withholdings. From time to time and in the normal course of business in connection with our operations or ongoing legal matters, we are required to place certain amounts of our cash in deposit accounts with restrictions that limit our ability to withdraw those funds.
Certain of our cash accounts are zero-balance controlled disbursement accounts that do not have right of offset against our other cash balances. We present the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets.
Accounts Receivable and Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable if we determine that there is a possibility that we will not collect all or part of the outstanding balances. We regularly review accounts over 150 days past due from the invoice date for collectability and establish or adjust our allowance as necessary using the specific identification method. If we exhaust all collection efforts and determine that the balance will never be collected, we write off the accounts receivable and the associated provision for uncollectible accounts.
From time to time we are entitled to proceeds under our insurance policies for amounts that we have reserved in our self-insurance liability. We present these insurance receivables gross on our balance sheet as a component of other assets, separate from the corresponding liability.
Concentration of Credit Risk and Significant Customers
Our customers include major oil and natural gas production companies, independent oil and natural gas production companies, and foreign national oil and natural gas production companies. We perform ongoing credit evaluations of our customers and usually do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial position should be considered in light of the fluctuations in demand experienced by oilfield service companies as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial position as supply and demand factors directly affect utilization and hours which are the primary determinants of our net cash provided by operating activities.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During the year ended December 31, 2013, Chevron Texaco Exploration and Production accounted for 15% of our consolidated revenue. During the year ended December 31, 2012, Pemex and Occidental Petroleum Corporation accounted for 12% and 10% of our consolidated revenue, respectively. No other customer accounted for more than 10% of our consolidated revenue in 2013 or 2012. No single customer accounted for more than 10% of our consolidated revenue during the year ended December 31, 2011.
Receivables outstanding from Pemex were approximately 19% and 31% of our total accounts receivable as of December 31, 2013 and 2012, respectively. No other customer accounted for more than 10% of our total accounts receivable as of December 31, 2013 and 2012.
Inventories
Inventories, which consist primarily of equipment parts and spares for use in our operations and supplies held for consumption, are valued at the lower of average cost or market.
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated depreciable lives of the assets using the straight-line method. Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $206.2 million, $190.5 million and $145.7 million, respectively. We depreciate our operational assets over their depreciable lives to their salvage value, which is a value higher than the assets’ value as scrap. Salvage value approximates 10% of an operational asset’s acquisition cost. When an operational asset is stacked or taken out of service, we review its physical condition, depreciable life and ultimate salvage value to determine if the asset is operable and whether the remaining depreciable life and salvage value should be adjusted. When we scrap an asset, we accelerate the depreciation of the asset down to its salvage value. When we dispose of an asset, a gain or loss is recognized.
As of December 31, 2013, the estimated useful lives of our asset classes are as follows:
Description | Years |
Well service rigs and components | 3-15 |
Oilfield trucks, vehicles and related equipment | 5-10 |
Coiled tubing units and equipment | 10-12 |
Fishing and rental tools, tubulars and pressure control equipment | 3-10 |
Disposal wells | 15-30 |
Furniture and equipment | 3-7 |
Buildings and improvements | 15-30 |
From time to time, we lease certain of our operating assets under capital lease obligations whose terms run from 55 to 60 months. These assets are depreciated over their estimated useful lives or the term of the capital lease obligation, whichever is shorter.
A long-lived asset or asset group should be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. For purposes of testing for impairment, we group our long-lived assets along our lines of business based on the services provided, which is the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. We would record an impairment charge, reducing the net carrying value to an estimated fair value, if the asset group’s estimated future cash flows were less than its net carrying value. Events or changes in circumstance that cause us to evaluate our fixed assets for recoverability and possible impairment may include changes in market conditions, such as adverse movements in the prices of oil and natural gas, or changes of an asset group, such as its expected future life, intended use or physical condition, which could reduce the fair value of certain of our property and equipment. The development of future cash flows and the determination of fair value for an asset group involves significant judgment and estimates. We did not identify any triggering events or record any asset impairments during 2013, 2012 or 2011.
Asset Retirement Obligations
We recognize a liability for the fair value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset. We depreciate the additional cost over the estimated useful life of the assets. Our obligations to perform our asset retirement activities are unconditional, despite the uncertainties that may exist surrounding an individual retirement activity. Accordingly, we recognize a liability for the fair value of a conditional asset
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
retirement obligation if the fair value can be reasonably estimated. In determining the fair value, we examine the inputs that we believe a market participant would use if we were to transfer the liability. We probability-weight the potential costs a third-party would charge, adjust the cost for inflation for the estimated life of the asset, and discount this cost using our credit adjusted risk free rate. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the cash flows change, such changes may have a material impact on our results of operations. See “Note 11. Asset Retirement Obligations.”
Deposits
Due to capacity constraints on equipment manufacturers, we have been required to make advanced payments for certain oilfield service equipment and other items used in the normal course of business. As of December 31, 2013 and December 31, 2012, deposits totaled $1.5 million and $7.3 million, respectively. Deposits as of December 31, 2012 consisted primarily of payments made related to high demand long-lead time items.
Capitalized Interest
Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using an effective interest rate based on related debt until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets, and is included in the depreciation and amortization line in the accompanying consolidated statements of operations.
Deferred Financing Costs
Deferred financing costs associated with long-term debt are carried at cost and are amortized to interest expense using the effective interest method over the life of the related debt instrument. When the related debt instrument is retired, any remaining unamortized costs are included in the determination of the gain or loss on the extinguishment of the debt. We record gains and losses from the extinguishment of debt as a part of continuing operations. See “Note 15. Long-term Debt,” for further discussion.
Goodwill and Other Intangible Assets
Goodwill results from business combinations and represents the excess of the acquisition consideration over the fair value of the net assets acquired. Goodwill and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired.
The test for impairment of indefinite-lived intangible assets allows us to first assess the qualitative factors to determine whether it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If our qualitative analysis shows that it is “more likely than not” that the fair value of a reporting unit is less than its carrying amount we will perform the two-step goodwill impairment test. In the first step of the test, a fair value is calculated for each of our reporting units, and that fair value is compared to the carrying value of the reporting unit, including the reporting unit’s goodwill. If the fair value of the reporting unit exceeds its carrying value, there is no impairment, and the second step of the test is not performed. If the carrying value exceeds the fair value for the reporting unit, then the second step of the test is required.
The second step of the test compares the implied fair value of the reporting unit’s goodwill to its carrying value. The implied fair value of the reporting unit’s goodwill is determined in the same manner as the amount of goodwill recognized in a business combination, with the purchase price being equal to the fair value of the reporting unit. If the implied fair value of the reporting unit’s goodwill is in excess of its carrying value, no impairment is recorded. If the carrying value is in excess of the implied fair value, an impairment equal to the excess is recorded.
To assist management in the preparation and analysis of the valuation of our reporting units, we utilize the services of a third-party valuation consultant. The ultimate conclusions of the valuation techniques remain our sole responsibility. The determination of the fair value used in the test is heavily impacted by the market prices of our equity and debt securities, as well as the assumptions and estimates about our future activity levels, profitability and cash flows. We conduct our annual impairment test as of October 1 of each year. For the annual test completed as of October 1, 2013, no impairment of our goodwill was indicated. See “Note 9. Goodwill and Other Intangible Assets,” for further discussion.
Internal-Use Software
We capitalize costs incurred during the application development stage of internal-use software and amortize these costs over the software’s estimated useful life, generally five to seven years. Costs incurred related to selection or maintenance of internal-use software are expensed as incurred.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Litigation
When estimating our liabilities related to litigation, we take into account all available facts and circumstances in order to determine whether a loss is probable and reasonably estimable.
Various suits and claims arising in the ordinary course of business are pending against us. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We are also exposed to various claims abroad. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable. See “Note 16. Commitments and Contingencies.”
Environmental
Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants, and regulated substances. These operations are subject to various federal, state and local laws and regulations intended to protect the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. We record liabilities on an undiscounted basis when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. While our litigation reserves reflect the application of our insurance coverage, our environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to the matters at issue. See “Note 16. Commitments and Contingencies.”
Self-Insurance
We are largely self-insured against physical damage to our equipment and automobiles as well as workers’ compensation claims. The accruals that we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. To assist management with the liability amount for our self-insurance reserves, we utilize the services of a third party actuary. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims. See “Note 16. Commitments and Contingencies.”
Income Taxes
We account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, but which are deferred until future periods. Current taxes payable represent our liability related to our income tax returns for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Management estimates the changes in both deferred tax assets and liabilities using the basis of assets and liabilities for financial reporting purposes and for enacted rates that management estimates will be in effect when the differences reverse. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatments of certain items for tax and accounting purposes or whether such differences are permanent. The final determination of our tax liability involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred.
We establish valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record uncertain tax positions at their net recognizable amount, based on the amount that management deems is more likely than not to be sustained upon ultimate settlement with the tax authorities in the domestic and international tax jurisdictions in which we operate. See “Note 14. Income Taxes” for further discussion of accounting for income taxes, changes in our valuation allowance, components of our tax rate reconciliation and realization of loss carryforwards.
Earnings Per Share
Basic earnings per common share is determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the period. Diluted earnings per common share is based on the
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
increased number of shares that would be outstanding assuming conversion of dilutive outstanding convertible securities using the treasury stock and “as if converted” methods. See “Note 10. Earnings Per Share.”
Share-Based Compensation
In the past, we have issued stock options, shares of restricted common stock, restricted stock units, stock appreciation rights (“SARs”), phantom shares and performance units to our employees as part of those employees’ compensation and as a retention tool. For our options, restricted shares and SARs, we calculate the fair value of the awards on the grant date and amortize that fair value to compensation expense ratably over the vesting period of the award, net of estimated and actual forfeitures. The fair value of our stock option and SAR awards are estimated using a Black-Scholes fair value model. The valuation of our stock options and SARs requires us to estimate the expected term of award, which we estimated using the simplified method, as we did not have sufficient historical exercise information because of past legal restrictions on the exercise of our stock options. Additionally, the valuation of our stock option and SARs awards is also dependent on our historical stock price volatility, which we calculate using a lookback period equivalent to the expected term of the award, a risk-free interest rate, and an estimate of future forfeitures. The grant-date fair value of our restricted stock awards is determined using our stock price on the grant date. Our phantom shares and performance units are treated as “liability” awards and carried at fair value at each balance sheet date, with changes in fair value recorded as a component of compensation expense and an offsetting liability on our consolidated balance sheet. We record share-based compensation as a component of general and administrative and direct operating expense for the applicable individual. See “Note 20. Share-Based Compensation.”
Foreign Currency Gains and Losses
With respect to our operations in Russia, where the local currency is the functional currency, assets and liabilities are translated at the rates of exchange on the balance sheet date, while income and expense items are translated at average rates of exchange during the period. The resulting gains or losses arising from the translation of accounts from the functional currency to the U.S. dollar are included as a separate component of stockholders’ equity in other comprehensive income until a partial or complete sale or liquidation of our net investment in the foreign entity. As of December 31, 2011, the functional currency for Mexico, Russia and Canada was the local currency and the functional currency for Colombia and the Middle East was the U. S. dollar. Due to significant changes in economic facts and circumstances, the functional currency for Mexico and Canada was changed to the U.S. dollar effective January 1, 2012. See “Note 17. Accumulated Other Comprehensive Loss.”
From time to time our foreign subsidiaries may enter into transactions that are denominated in currencies other than their functional currency. These transactions are initially recorded in the functional currency of that subsidiary based on the applicable exchange rate in effect on the date of the transaction. At the end of each month, these transactions are remeasured to an equivalent amount of the functional currency based on the applicable exchange rates in effect at that time. Any adjustment required to remeasure a transaction to the equivalent amount of the functional currency at the end of the month is recorded in the income or loss of the foreign subsidiary as a component of other income, net.
Comprehensive Income
We display comprehensive income (loss) and its components in our financial statements, and we classify items of comprehensive income by their nature in our financial statements and display the accumulated balance of other comprehensive income separately in our stockholders’ equity.
Leases
We lease real property and equipment through various leasing arrangements. When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine whether the lease should be accounted for as an operating lease or a capital lease.
We periodically incur costs to improve the assets that we lease under these arrangements. If the value of the leasehold improvements exceeds our threshold for capitalization, we record the improvement as a component of our property and equipment and amortize the improvement over the useful life of the improvement or the lease term, whichever is shorter.
Certain of our operating lease agreements are structured to include scheduled and specified rent increases over the term of the lease agreement. These increases may be the result of an inducement or “rent holiday” conveyed to us early in the lease, or are included to reflect the anticipated effects of inflation. We recognize scheduled and specified rent increases on a straight-line basis over the term of the lease agreement. In addition, certain of our operating lease agreements contain incentives to induce us to enter into the lease agreement, such as up-front cash payments to us, payment by the lessor of our costs, such as moving expenses, or the assumption by the lessor of our pre-existing lease agreements with third parties. Any payments made
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
to us or on our behalf represent incentives that we consider to be a reduction of our rent expense, and are recognized on a straight-line basis over the term of the lease agreement.
New Accounting Standards Adopted in this Report
There are no new accounting standards that have been adopted or not yet adopted in this report.
NOTE 2. ACQUISITIONS
2013 Acquisition of Noncontrolling Interests
Geostream. On October 31, 2008, we acquired a 26% interest Geostream, a limited liability company incorporated in the Russian Federation that provides a wide range of drilling, workover and reservoir engineering services for $17.4 million. On September 1, 2009, we acquired an additional 24% interest for $16.4 million, which brought our total investment in Geostream to 50% and provided us a controlling interest with representation on Geostream's board of directors. We accounted for the second investment as a business combination achieved in stages. The results of Geostream have been included in our consolidated financial statements since the initial acquisition date, with the portion outside of our control forming a noncontrolling interest. On April 9, 2013, we completed the acquisition of the remaining 50% noncontrolling interest in Geostream for $14.6 million. Geostream is now our wholly owned subsidiary. The acquisition was accounted for as an equity transaction. Therefore, our acquisition of the noncontrolling interest in Geostream in the second quarter of 2013 did not result in a gain or loss.
AlMansoori Key Energy Services, LLC. On March 7, 2010, we entered into an agreement with AlMansoori Petroleum Services, LLC (“AlMansoori”) to form the joint venture AlMansoori Key Energy Services, LLC, a joint venture under the laws of Abu Dhabi, UAE. The purpose of the joint venture was to engage in conventional workover and drilling services, coiled tubing services, fishing and rental services, rig monitoring services, pipe handling services and fluids, waste treatment and handling services. Although AlMansoori held a 51% interest in the joint venture and we held a 49% interest, we held three of the five board of directors seats and a controlling financial interest. In addition, profits and losses of the joint venture were shared on equal terms and in equal amounts with AlMansoori. Because the joint venture did not have sufficient resources to carry on its activities without our financial support, we determined it to be a variable interest entity of which we were the primary beneficiary. We consolidated the entity in our financial statements. On August 5, 2013, we agreed to the dissolution of AlMansoori Key Energy Services, LLC and the acquisition of the underlying business for $5.1 million. The $5.1 million is expected to be paid in 2014 and is recorded in "other current liabilities" in our 2013 consolidated balance sheet. The acquisition of the 51% noncontrolling interest in AlMansoori Key Energy Services, LLC was accounted for as an equity transaction therefore did not result in a gain or loss.
The effects of changes in our ownership interests in Geostream and AlMansoori Key Energy Services, LLC for the year ended December 31, 2013 were as follows (in thousands):
Net loss attributable to Key | $ | (21,768 | ) |
Transfers from the noncontrolling interests | |||
Increase in Key's paid-in capital for purchase of the 50% noncontrolling interest in Geostream | 22,432 | ||
Decrease in Key's paid-in capital for purchase of the 51% noncontrolling interest in AlMansoori Key Energy Services, LLC | (2,888 | ) | |
Net transfers from noncontrolling interests | 19,544 | ||
Change from net loss attributable to Key and transfers from noncontrolling interests | $ | (2,224 | ) |
2011 Acquisitions
Edge Oilfield Services, LLC (“Edge”). On August 5, 2011, we completed the acquisition of Edge. We accounted for this acquisition as a business combination. The results of operations for Edge have been included in our consolidated financial statements from the acquisition date.
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The total consideration for the acquisition was approximately $305.9 million consisting of approximately 7.5 million shares of our common stock and approximately $187.9 million in cash, which included $26.3 million to reimburse Edge for growth capital expenditures incurred between March 1, 2011 and the date of closing, net of working capital adjustments of $1.8 million. We finalized the purchase accounting related to this acquisition as of June 30, 2012.
The following table summarizes the fair values of the assets acquired and liabilities assumed (in thousands):
Cash | $ | 189,696 | |
Key common stock | 117,919 | ||
Consideration transferred | 307,615 | ||
Working capital adjustment | (1,752 | ) | |
Total | $ | 305,863 | |
The fair value of the 7.5 million common shares issued was $15.62 per share based on the closing price on the acquisition date (August 5, 2011).
The following table summarizes the fair values of the assets acquired and the liabilities assumed (in thousands):
At August 5, 2011: | |||
Cash and cash equivalents | $ | 886 | |
Accounts receivable | 21,124 | ||
Other current assets | 234 | ||
Property and equipment | 87,185 | ||
Intangible assets | 49,310 | ||
Other long term assets | 3,826 | ||
Total identifiable assets acquired | 162,565 | ||
Current liabilities | 19,406 | ||
Total liabilities assumed | 19,406 | ||
Net identifiable assets acquired | 143,159 | ||
Goodwill | 162,704 | ||
Net assets acquired | $ | 305,863 | |
Of the $49.3 million of acquired intangible assets, $40.0 million was assigned to customer relationships that will be amortized as the value of the relationships are realized using expected rates of 12.5%, 30.0%, 30.0%, 11.0%, 6.4%, 3.8%, 2.5%, 1.7%, 1.2% and 0.8% from 2011 through 2020. In addition, $5.1 million of acquired intangible assets was assigned to tradenames and are not subject to amortization. The remaining $4.2 million of acquired intangible assets was assigned to non-compete agreements that will be amortized on a straight-line basis over 38 months.
The fair value and gross contractual amount of accounts receivable acquired on August 5, 2011 was $21.1 million.
All of the goodwill acquired was assigned to our fishing and rental business, which is part of our U.S. reportable segment. We believe the goodwill recognized is attributable primarily to the acquired workforce and expansion of a growing service line. All of the goodwill is expected to be deductible for income tax purposes.
Transaction costs related to this acquisition were $3.6 million for the year ended December 31, 2011, and are included in general and administrative expenses in the 2011 consolidated statement of operations.
Included in our consolidated statements of operations for the year ended December 31, 2011, related to this acquisition are revenues of $52.5 million and operating income of $14.7 million from the acquisition date through December 31, 2011.
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The following represents the pro forma consolidated income statement as if the Edge acquisition had been included in our consolidated results prior to 2011 for the year ended December 31, 2011:
2011 | |||
(unaudited) (in thousands, except per share amounts) | |||
REVENUES | $ | 1,803,768 | |
COSTS AND EXPENSES: | |||
Direct operating expenses | 1,115,770 | ||
Depreciation and amortization expense(1) | 176,298 | ||
General and administrative expenses(2) | 227,652 | ||
Operating income | 284,048 | ||
Loss on early extinguishment of debt | 46,451 | ||
Interest expense, net of amounts capitalized | 42,389 | ||
Other income, net | (7,585 | ) | |
Income from continuing operations before tax | 202,793 | ||
Income tax expense(3) | (76,169 | ) | |
Income from continuing operations | 126,624 | ||
Loss from discontinued operations, net of tax | (10,303 | ) | |
Net income | 116,321 | ||
Loss attributable to noncontrolling interest | (806 | ) | |
INCOME ATTRIBUTABLE TO KEY | $ | 117,127 | |
Earnings per share attributable to Key: | |||
Basic | $ | 0.79 | |
Diluted | $ | 0.79 | |
Weighted average shares outstanding(4): | |||
Basic | 150,397 | ||
Diluted | 150,705 | ||
(1) | Depreciation and amortization expense has been adjusted to reflect the additional expense that would have been charged assuming the fair value adjustments to property and equipment and intangible assets had been applied prior to 2011. |
(2) | Transaction costs of $3.6 million have been removed as these costs would have occurred prior to 2011. |
(3) | Income tax expense has been adjusted to reflect applicable corporate tax as if Edge had been acquired and converted from its LLC status prior to 2011. |
(4) | Weighted average shares outstanding has been adjusted to reflect the issuance of shares in the Edge transaction as if the transaction occurred prior to 2011. |
These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of our results if the acquisition had occurred for the year ended December 2011. These amounts have been calculated after applying our accounting policies and adjusting the results of Edge as if these changes had been applied prior to 2011, together with the consequential tax effects.
Equity Energy Company (“EEC”). In January 2011, we acquired, through purchase or lease, 10 saltwater disposal (“SWD”) wells from EEC for approximately $14.3 million. Most of these SWD wells are located in North Dakota. We accounted for this purchase as an asset acquisition.
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NOTE 3. DISCONTINUED OPERATIONS
In September 2012, we completed the sale of our Argentina operations for approximately $12.5 million, net of transaction costs. The $12.5 million net proceeds from the sale of Argentina operations included $2.0 million received in cash and the balance in notes receivable which was comprised of three sets of non-interest bearing notes for a total of six notes. Of the first set of notes, originally due in September 2013, one note was paid in full and retired, and the second note was restructured with a maturity date of September 16, 2014, payable in thirteen monthly payments. The first four payments totaling $0.6 million, which includes the repayment of the first note, were received in the fourth quarter of 2013 and the remaining nine payments are expected to follow each month thereafter. The maturity dates, payment terms and balances of the remaining two sets of notes did not change. These notes are included in "Other current assets" in our condensed consolidated balance sheets.
In connection with the sale, we recognized a total loss of $85.8 million, which includes the noncash impairment charge of $41.5 million recorded in the first quarter of 2012, and a write-off of $51.9 million cumulative translation adjustment previously recorded in accumulated other comprehensive loss during the third quarter of 2012. We are reporting the results of our Argentina operations in discontinued operations for all periods presented.
The following table presents the results of operations for the Argentina business sold in this transaction for the years ended December 31, 2012 and 2011.
Year Ended December 31, | |||||||
2012 | 2011 | ||||||
(in thousands) | |||||||
REVENUES | $ | 75,815 | $ | 117,672 | |||
COSTS AND EXPENSES: | |||||||
Direct operating expenses | 72,664 | 111,893 | |||||
Depreciation and amortization expense | 143 | 2,658 | |||||
General and administrative expenses | 11,232 | 14,769 | |||||
Asset retirements and impairments | 85,755 | — | |||||
Operating loss | (93,979 | ) | (11,648 | ) | |||
Interest expense, net of amounts capitalized | 168 | 1,694 | |||||
Other expense, net | 3,725 | 3,159 | |||||
Loss before taxes | (97,872 | ) | (16,501 | ) | |||
Income tax benefit | 4,304 | 5,820 | |||||
Net loss | $ | (93,568 | ) | $ | (10,681 | ) | |
NOTE 4. SEVERANCE, CONTRACT TERMINATION AND MOBILIZATION COSTS
In the second quarter of 2013, we implemented a significant restructuring of our fluid management services and our corporate cost structure to better align them with current market conditions. As a result of this restructuring, we recognized approximately $6.3 million of severance expenses in the second quarter of 2013. The severance costs were based on obligations under our existing severance agreements. Furthermore, we recognized lease cancellation fees of $1.9 million primarily related to our fluid management services. Additionally, in our international business, due to customer spending reductions in Mexico, we began redeploying idle rigs from the North Region of Mexico to higher demand markets, incurring mobilization cost of $2.3 million. These costs are reflected in our consolidated statements of operations and include $8.3 million of direct operating expenses and $2.2 million of general and administrative expenses. On a segment basis, $2.6 million is associated with our U.S. operations, $7.2 million is associated with our international operations and the remaining $0.7 million is associated with our Functional Support segment. The restructuring activities were implemented in the second quarter of 2013 and were completed in the fourth quarter of 2013.
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Presented below are the categories of the liabilities recorded in connection with our restructuring by segment and in consolidation:
Severance | Lease Cancellation Fees | Mobilization Costs | Total | ||||||||||||
(in thousands) | |||||||||||||||
U.S. | |||||||||||||||
Balance as of December 31, 2012 | $ | — | $ | — | $ | — | $ | — | |||||||
Expense | 746 | 1,630 | 218 | 2,594 | |||||||||||
Payment | (724 | ) | — | — | (724 | ) | |||||||||
Balance as of June 30, 2013 | 22 | 1,630 | 218 | 1,870 | |||||||||||
Payment | (22 | ) | (571 | ) | (218 | ) | (811 | ) | |||||||
Balance as of September 30, 2013 | — | 1,059 | — | 1,059 | |||||||||||
Payment | — | (1,059 | ) | — | (1,059 | ) | |||||||||
Balance as of December 31, 2013 | $ | — | $ | — | $ | — | $ | — | |||||||
International | |||||||||||||||
Balance as of December 31, 2012 | $ | — | $ | — | $ | — | $ | — | |||||||
Expense | 4,843 | 307 | 2,077 | 7,227 | |||||||||||
Payment | (4,533 | ) | (307 | ) | (1,054 | ) | (5,894 | ) | |||||||
Balance as of June 30, 2013 | 310 | — | 1,023 | 1,333 | |||||||||||
Payment | (310 | ) | — | (1,023 | ) | (1,333 | ) | ||||||||
Balance as of September 30, 2013 | — | — | — | — | |||||||||||
Payment | — | — | — | — | |||||||||||
Balance as of December 31, 2013 | $ | — | $ | — | $ | — | $ | — | |||||||
Functional Support | |||||||||||||||
Balance as of December 31, 2012 | $ | — | $ | — | $ | — | $ | — | |||||||
Expense | 732 | — | — | 732 | |||||||||||
Payment | (732 | ) | — | — | (732 | ) | |||||||||
Balance as of June 30, 2013 | — | — | — | — | |||||||||||
Payment | — | — | — | — | |||||||||||
Balance as of September 30, 2013 | — | — | — | — | |||||||||||
Payment | — | — | — | — | |||||||||||
Balance as of December 31, 2013 | $ | — | $ | — | $ | — | $ | — | |||||||
Consolidated | |||||||||||||||
Balance as of December 31, 2012 | $ | — | $ | — | $ | — | $ | — | |||||||
Expense | 6,321 | 1,937 | 2,295 | 10,553 | |||||||||||
Payment | (5,989 | ) | (307 | ) | (1,054 | ) | (7,350 | ) | |||||||
Balance as of June 30, 2013 | 332 | 1,630 | 1,241 | 3,203 | |||||||||||
Payment | (332 | ) | (571 | ) | (1,241 | ) | (2,144 | ) | |||||||
Balance as of September 30, 2013 | — | 1,059 | — | 1,059 | |||||||||||
Payment | — | (1,059 | ) | — | (1,059 | ) | |||||||||
Balance as of December 31, 2013 | $ | — | $ | — | $ | — | $ | — | |||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 5. OTHER BALANCE SHEET INFORMATION
The table below presents comparative detailed information about other current assets at December 31, 2013 and 2012:
December 31, 2013 | December 31, 2012 | ||||||
(in thousands) | |||||||
Other current assets: | |||||||
Current deferred tax assets | $ | 11,707 | $ | 20,026 | |||
Prepaid current assets | 28,435 | 27,736 | |||||
Reinsurance receivable | 9,113 | 10,217 | |||||
VAT asset | 21,683 | 32,762 | |||||
Other | 25,608 | 10,092 | |||||
Total | $ | 96,546 | $ | 100,833 | |||
The table below presents comparative detailed information about other current liabilities at December 31, 2013 and 2012:
December 31, 2013 | December 31, 2012 | ||||||
(in thousands) | |||||||
Other current liabilities: | |||||||
Accrued payroll, taxes and employee benefits | $ | 34,956 | $ | 31,708 | |||
Accrued operating expenditures | 36,573 | 42,137 | |||||
Income, sales, use and other taxes | 37,064 | 62,709 | |||||
Self-insurance reserves | 32,129 | 35,742 | |||||
Accrued interest | 15,285 | 15,301 | |||||
Accrued insurance premiums | 8,049 | 8,021 | |||||
Other | 5,889 | 5,012 | |||||
Total | $ | 169,945 | $ | 200,630 | |||
The table below presents comparative detailed information about other non-current accrued liabilities at December 31, 2013 and 2012:
December 31, 2013 | December 31, 2012 | ||||||
(in thousands) | |||||||
Other non-current accrued liabilities: | |||||||
Asset retirement obligations | $ | 11,999 | $ | 11,659 | |||
Environmental liabilities | 6,176 | 4,539 | |||||
Accrued rent | 853 | 1,424 | |||||
Accrued sales, use and other taxes | 5,552 | 6,952 | |||||
Other | 1,075 | 3,347 | |||||
Total | $ | 25,655 | $ | 27,921 | |||
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NOTE 6. OTHER INCOME, NET
The table below presents comparative detailed information about our other income and expense from continuing operations for the years ended December 31, 2013, 2012 and 2011:
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Interest income | $ | (220 | ) | $ | (46 | ) | $ | (26 | ) | ||
Foreign exchange (gain) loss | 834 | (4,726 | ) | (3,058 | ) | ||||||
Gain on sale of equity method investment | — | — | (4,783 | ) | |||||||
Other, net | (1,417 | ) | (1,877 | ) | (1,110 | ) | |||||
Total | $ | (803 | ) | $ | (6,649 | ) | $ | (8,977 | ) | ||
NOTE 7. ALLOWANCE FOR DOUBTFUL ACCOUNTS
The table below presents a rollforward of our allowance for doubtful accounts for the years ended December 31, 2013, 2012 and 2011:
Additions | |||||||||||||||||||
Balance at Beginning of Period | Charged to Expense | Charged to Other Accounts | Deductions | Balance at End of Period | |||||||||||||||
(in thousands) | |||||||||||||||||||
As of December 31, 2013 | $ | 2,860 | $ | 634 | $ | — | $ | (2,728 | ) | $ | 766 | ||||||||
As of December 31, 2012 | 8,013 | 1,299 | 6 | (6,458 | ) | 2,860 | |||||||||||||
As of December 31, 2011 | 7,717 | 2,559 | 519 | (2,782 | ) | 8,013 | |||||||||||||
NOTE 8. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
December 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Major classes of property and equipment: | |||||||
Oilfield service equipment | $ | 1,960,208 | $ | 1,825,707 | |||
Disposal wells | 87,681 | 86,970 | |||||
Motor vehicles | 304,244 | 306,161 | |||||
Furniture and equipment | 122,218 | 112,828 | |||||
Buildings and land | 86,085 | 69,158 | |||||
Work in progress | 46,302 | 127,754 | |||||
Gross property and equipment | 2,606,738 | 2,528,578 | |||||
Accumulated depreciation | (1,241,092 | ) | (1,091,904 | ) | |||
Net property and equipment | $ | 1,365,646 | $ | 1,436,674 | |||
Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using an effective interest rate based on related debt until the underlying assets are placed into service. Capitalized interest for the years ended December 31, 2013, 2012 and 2011 was $0.6 million, $1.3 million, and $1.7 million, respectively.
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As of December 31, 2013, we have no capital lease obligations. The carrying value of assets acquired under capital leases as of December 31, 2012 is as follows (in thousands):
Values of assets leased under capital lease obligations: | |||
Well servicing equipment | $ | 249 | |
Motor vehicles | 37,827 | ||
Gross values | 38,076 | ||
Accumulated depreciation | (33,692 | ) | |
Carrying value of leased assets | $ | 4,384 | |
Depreciation of assets held under capital leases was $1.9 million, $2.8 million, and $2.8 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in depreciation and amortization expense in the accompanying consolidated statements of operations.
There were no asset impairment charges for the years ended December 31, 2013, 2012 and 2011.
NOTE 9. GOODWILL AND OTHER INTANGIBLE ASSETS
The changes in the carrying amount of our goodwill for the years ended December 31, 2013 and 2012 are as follows:
U.S. | International | Total | |||||||||
(in thousands) | |||||||||||
December 31, 2011 | $ | 595,049 | $ | 27,724 | $ | 622,773 | |||||
Purchase price allocation adjustments, net | 2,407 | — | 2,407 | ||||||||
Impact of foreign currency translation | — | 1,301 | 1,301 | ||||||||
December 31, 2012 | 597,456 | 29,025 | 626,481 | ||||||||
Impact of foreign currency translation | — | (1,606 | ) | (1,606 | ) | ||||||
December 31, 2013 | $ | 597,456 | $ | 27,419 | $ | 624,875 | |||||
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The components of our other intangible assets as of December 31, 2013 and 2012 are as follows:
December 31, 2013 | December 31, 2012 | ||||||
(in thousands) | |||||||
Noncompete agreements: | |||||||
Gross carrying value | $ | 9,332 | $ | 9,332 | |||
Accumulated amortization | (7,104 | ) | (5,022 | ) | |||
Net carrying value | $ | 2,228 | $ | 4,310 | |||
Patents, trademarks and tradename: | |||||||
Gross carrying value | $ | 14,039 | $ | 14,689 | |||
Accumulated amortization | (223 | ) | (410 | ) | |||
Net carrying value | $ | 13,816 | $ | 14,279 | |||
Customer relationships and contracts: | |||||||
Gross carrying value | $ | 100,271 | $ | 100,481 | |||
Accumulated amortization | (78,926 | ) | (62,143 | ) | |||
Net carrying value | $ | 21,345 | $ | 38,338 | |||
Developed technology: | |||||||
Gross carrying value | $ | 7,583 | $ | 7,583 | |||
Accumulated amortization | (3,826 | ) | (3,605 | ) | |||
Net carrying value | $ | 3,757 | $ | 3,978 | |||
Customer backlog: | |||||||
Gross carrying value | $ | 779 | $ | 779 | |||
Accumulated amortization | (779 | ) | (779 | ) | |||
Net carrying value | $ | — | $ | — | |||
Total: | |||||||
Gross carrying value | $ | 132,004 | $ | 132,864 | |||
Accumulated amortization | (90,858 | ) | (71,959 | ) | |||
Net carrying value | $ | 41,146 | $ | 60,905 | |||
Amortization expense for our intangible assets with determinable lives was as follows:
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Noncompete agreements | $ | 2,082 | $ | 3,827 | $ | 4,154 | |||||
Patents and trademarks | 40 | 309 | 202 | ||||||||
Customer relationships and contracts | 16,726 | 18,941 | 15,830 | ||||||||
Developed technology | 221 | 221 | 883 | ||||||||
Customer backlog | — | — | 162 | ||||||||
Total intangible asset amortization expense | $ | 19,069 | $ | 23,298 | $ | 21,231 | |||||
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Of our intangible assets at December 31, 2013, $13.6 million are indefinite-lived tradenames and not subject to amortization. These tradenames are tested for impairment annually using a relief from royalty method. The weighted average remaining amortization periods and expected amortization expense for the next five years for our definite lived intangible assets are as follows:
Weighted average remaining amortization period (years) | Expected Amortization Expense | ||||||||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
Noncompete agreements | 0.8 | $ | 1,670 | $ | 284 | $ | 207 | $ | 67 | $ | — | ||||||||||
Patents and trademarks | 4.4 | 40 | 40 | 40 | 40 | 17 | |||||||||||||||
Customer relationships and contracts | 6.0 | 7,896 | 5,060 | 3,437 | 2,441 | 1,120 | |||||||||||||||
Developed technology | 17.0 | 346 | 371 | 371 | 371 | 371 | |||||||||||||||
Total intangible asset amortization expense | $ | 9,952 | $ | 5,755 | $ | 4,055 | $ | 2,919 | $ | 1,508 | |||||||||||
Certain of our goodwill and intangible assets are denominated in Russian Rubles and, as such, the values of these assets are subject to fluctuations associated with changes in exchange rates. Additionally, certain of these assets are also subject to purchase accounting adjustments. Purchase accounting adjustments in 2012 relate to the reduction of fixed assets acquired from Edge in 2011. We do not believe the impact of these purchase accounting adjustments is material to our consolidated financial statements for the year ended December 31, 2012.
We have historically evaluated our goodwill for impairment one level below the reporting segment level, at the reporting unit level, annually as of December 31 or more frequently if impairment indicators arose in accordance with Accounting Standards Codification (ASC) Topic 350. In the third quarter of 2013, we changed the date of our annual assessment of goodwill impairment to October 1 of each year. The change in the assessment date does not delay, accelerate, avoid or cause an impairment charge, nor does this change result in adjustments to previously issued financial statements. We believe that the change in date aligns with the our planning cycle, which should create a synergy and allow the goodwill impairment analysis to be embedded with the projection of future results for business planning purposes. We believe this will enhance the quality of the goodwill impairment analysis. Also, the change in date allows us more time to identify and respond to any issues noted in the analysis before finalization of SEC filings, which will improve the quality of financial reporting. As such, the Company has prospectively applied the change in annual goodwill impairment testing date beginning in the fourth quarter of 2013.
We performed our qualitative analysis of goodwill impairment as of October 1, 2013. Based on this analysis, our Canadian reporting unit did not have a triggering event that would indicate it was “more likely than not” that the carrying value of this reporting unit was higher than its fair value. However, we determined it was necessary to perform the first step of the goodwill impairment test for our rig-based services, coiled tubing services, fishing and rental services, fluid management services and Russian reporting units. Under the first step of the goodwill impairment test, we compared the fair value of each reporting unit to its carrying amount, including goodwill. Based on the results of step 1, the fair value of our rig-based services, fluid management services, coiled tubing services, fishing and rental services and our Russian reporting units exceeded their carrying value by 11% , 4% , 19%, 21% and 86%, respectively. A key assumption in our model was our forecast of increased revenue for 2014 for rig-based services, fluid management services and fishing and rental services, followed by nominal revenue increases through 2018. We anticipate our coiled tubing services and Russian reporting units to have increased revenue in future years. Potential events that could affect this assumption include the level of development, exploration and production activity of, and corresponding capital spending by, oil and natural gas companies in Russia, oil and natural gas production costs, government regulations and conditions in the worldwide oil and natural gas industry. Other possible factors that could affect this assumption are the ability to acquire and deploy additional assets and deployment of these assets into the region. Because the fair value of the reporting units exceeded their carrying values, we determined that no impairment of our goodwill associated with our reporting units existed as of October 1, 2013 and that step two of the impairment test was not required.
67
NOTE 10. EARNINGS PER SHARE
The following table presents our basic and diluted earnings per share (“EPS”) for the years ended December 31, 2013, 2012 and 2011:
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands, except per share amounts) | |||||||||||
Basic EPS Calculation: | |||||||||||
Numerator | |||||||||||
Income (loss) from continuing operations attributable to Key | $ | (21,768 | ) | $ | 101,190 | $ | 112,142 | ||||
Loss from discontinued operations, net of tax | — | (93,568 | ) | (10,681 | ) | ||||||
Income (loss) attributable to Key | $ | (21,768 | ) | $ | 7,622 | $ | 101,461 | ||||
Denominator | |||||||||||
Weighted average shares outstanding | 152,271 | 151,106 | 145,909 | ||||||||
Basic earnings (loss) per share from continuing operations attributable to Key | $ | (0.14 | ) | $ | 0.67 | $ | 0.77 | ||||
Basic loss per share from discontinued operations | — | (0.62 | ) | (0.07 | ) | ||||||
Basic earnings (loss) per share attributable to Key | $ | (0.14 | ) | $ | 0.05 | $ | 0.70 | ||||
Diluted EPS Calculation: | |||||||||||
Numerator | |||||||||||
Income (loss) from continuing operations attributable to Key | $ | (21,768 | ) | $ | 101,190 | $ | 112,142 | ||||
Loss from discontinued operations, net of tax | — | (93,568 | ) | (10,681 | ) | ||||||
Income (loss) attributable to Key | $ | (21,768 | ) | $ | 7,622 | $ | 101,461 | ||||
Denominator | |||||||||||
Weighted average shares outstanding | 152,271 | 151,106 | 145,909 | ||||||||
Stock options | — | 19 | 201 | ||||||||
Warrants | — | — | 48 | ||||||||
Stock appreciation rights | — | — | 59 | ||||||||
Total | 152,271 | 151,125 | 146,217 | ||||||||
Diluted earnings (loss) per share from continuing operations attributable to Key | $ | (0.14 | ) | $ | 0.67 | $ | 0.76 | ||||
Diluted loss per share from discontinued operations | — | (0.62 | ) | (0.07 | ) | ||||||
Diluted earnings (loss) per share attributable to Key | $ | (0.14 | ) | $ | 0.05 | $ | 0.69 | ||||
Stock options, warrants and SARs are included in the computation of diluted earnings per share using the treasury stock method. Restricted stock awards are legally considered issued and outstanding when granted and are included in basic weighted average shares outstanding. The diluted earnings per share calculation for the year ended December 31, 2013 exclude the potential exercise of 1.7 million stock options and 0.3 million SARs due to net losses from continuing operations. December 31, 2012 and 2011 excludes the potential exercise of 2.0 million and 1.3 million stock options, respectively, because the effect would be anti-dilutive due to the exercise prices exceeding the average price of our stock. The diluted earnings per share calculation for the year ended December 31, 2012 also excluded the potential exercise of 0.4 million SARs, because the effects of such exercises on earnings per share would be anti-dilutive. None of our SARs were anti-dilutive for the year ended December 31, 2011.
There have been no material changes in share amounts subsequent to the balance sheet date that would have a material impact on the earnings per share calculation for the year ended December 31, 2013. However, we issued 0.9 million shares of restricted stock on January 30, 2014.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 11. ASSET RETIREMENT OBLIGATIONS
In connection with our well servicing activities, we operate a number of SWD facilities. Our operations involve the transportation, handling and disposal of fluids in our SWD facilities that are by-products of the drilling process. SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with the retirement of these properties. As a result, we have incurred costs associated with the proper storage and disposal of these materials.
Annual accretion of the assets associated with the asset retirement obligations was $0.6 million for the years ended December 31, 2013, 2012 and 2011. A summary of changes in our asset retirement obligations is as follows (in thousands):
Balance at December 31, 2011 | $ | 11,928 | |
Additions | — | ||
Costs incurred | (251 | ) | |
Accretion expense | 594 | ||
Disposals | (612 | ) | |
Balance at December 31, 2012 | 11,659 | ||
Additions | 174 | ||
Costs incurred | (135 | ) | |
Accretion expense | 604 | ||
Disposals | (303 | ) | |
Balance at December 31, 2013 | $ | 11,999 | |
NOTE 12. EQUITY METHOD INVESTMENTS
IROC Energy Services Corp.
In April 2011, we sold all of our equity interest (approximately 8.7 million shares) in IROC Energy Services Corp., an Alberta-based oilfield services company, for $12.0 million, net of fees. We recorded a net gain on this sale of $4.8 million (including the write-off of the cumulative translation adjustment of $1.1 million, net of tax) during the second quarter of 2011, as the proceeds received exceeded the carrying value of our investment.
Other
As of December 31, 2013, we have other equity method investments that are not material on a combined basis.
NOTE 13. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The following is a summary of the carrying amounts and estimated fair values of our financial instruments as of December 31, 2013 and 2012.
Cash, cash equivalents, accounts receivable, accounts payable and accrued liabilities. These carrying amounts approximate fair value because of the short maturity of the instruments or because the carrying value is equal to the fair value of those instruments on the balance sheet date.
December 31, 2013 | December 31, 2012 | ||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||
(in thousands) | |||||||||||||||
Financial assets: | |||||||||||||||
Notes receivable — Argentina operations sale | $ | 12,355 | $ | 12,355 | $ | 12,955 | $ | 12,955 | |||||||
Financial liabilities: | |||||||||||||||
6.75% Senior Notes | $ | 675,000 | $ | 690,390 | $ | 675,000 | $ | 680,510 | |||||||
8.375% Senior Notes | 3,573 | 3,627 | 3,573 | 3,656 | |||||||||||
Credit Facility revolving loans | 85,000 | 85,000 | 165,000 | 165,000 | |||||||||||
Notes receivable — Argentina operations sale. The fair value of these notes are based upon the quoted market Treasury rates as of the dates indicated. The carrying values of these items approximate their fair values due to the maturity dates rapidly approaching, thus giving way to discount rates that are similar.
69
6.75% Senior Notes due 2021. The fair value of these notes is based upon the quoted market prices for those securities as of the dates indicated. The carrying value of these notes as of December 31, 2013 was $675.0 million, and the fair value was $690.4 million (102.3% of carrying value).
8.375% Senior Notes due 2014. The fair value of these notes is based upon the quoted market prices for those securities as of the dates indicated. The carrying value of these notes as of December 31, 2013 was $3.6 million and the fair value was $3.6 million (101.5% of carrying value).
Credit Facility Revolving Loans. Because of their variable interest rates, the fair values of the revolving loans borrowed under our 2011 Credit Facility approximate their carrying values. The carrying and fair values of these loans as of December 31, 2013 were $85.0 million.
NOTE 14. INCOME TAXES
The components of our income tax expense are as follows:
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Current income tax (expense) benefit: | |||||||||||
Federal and state | $ | (8,515 | ) | $ | (16,165 | ) | $ | 28,291 | |||
Foreign | (350 | ) | (5,189 | ) | (796 | ) | |||||
(8,865 | ) | (21,354 | ) | 27,495 | |||||||
Deferred income tax (expense) benefit: | |||||||||||
Federal and state | (4,870 | ) | (32,729 | ) | (89,421 | ) | |||||
Foreign | 16,799 | (3,269 | ) | (2,191 | ) | ||||||
11,929 | (35,998 | ) | (91,612 | ) | |||||||
Total income tax (expense) benefit | $ | 3,064 | $ | (57,352 | ) | $ | (64,117 | ) | |||
The sources of our income or loss from continuing operations before income taxes and noncontrolling interest were as follows:
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Domestic income | $ | 29,086 | $ | 129,865 | $ | 160,755 | |||||
Foreign (loss) income | (53,323 | ) | 30,164 | 14,698 | |||||||
Total income (loss) | $ | (24,237 | ) | $ | 160,029 | $ | 175,453 | ||||
We made federal income tax payments of $30.0 million, $5.1 million and $53.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. We made state income tax payments of $2.9 million, $2.9 million and $7.6 million for the years ended December 31, 2013, 2012 and 2011, respectively. We made foreign tax payments of $2.3 million, $5.2 million and $2.9 million for the years ended December 31, 2013, 2012 and 2011, respectively. For the years ended December 31, 2013, 2012 and 2011, tax benefit (expense) allocated to stockholders’ equity for compensation expense for income tax purposes in excess of amounts recognized for financial reporting purposes was $1.8 million, $4.1 million and $4.9 million, respectively. In addition, we received federal income tax refunds of $25.1 million, $16.7 million and $26.2 million during the years ended December 31, 2013, 2012 and 2011, respectively.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Income tax expense differs from amounts computed by applying the statutory federal rate as follows:
Year Ended December 31, | ||||||||
2013 | 2012 | 2011 | ||||||
Income tax computed at Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | ||
State taxes | (6.0 | )% | 2.5 | % | 2.7 | % | ||
Meals and entertainment | (7.7 | )% | — | % | — | % | ||
Foreign rate difference | (8.0 | )% | — | % | — | % | ||
Other | (0.7 | )% | (1.7 | )% | (1.3 | )% | ||
Effective income tax rate | 12.6 | % | 35.8 | % | 36.4 | % | ||
As of December 31, 2013 and 2012, our deferred tax assets and liabilities consisted of the following:
December 31, | |||||||
2013 | 2012 | ||||||
(in thousands) | |||||||
Deferred tax assets: | |||||||
Net operating loss and tax credit carryforwards | $ | 36,860 | $ | 16,026 | |||
Capital loss carryforwards | 21,417 | 21,417 | |||||
Self-insurance reserves | 16,217 | 18,167 | |||||
Allowance for doubtful accounts | 199 | 965 | |||||
Accrued liabilities | 8,981 | 10,794 | |||||
Share-based compensation | 7,759 | 11,377 | |||||
Other | (392 | ) | 261 | ||||
Total deferred tax assets | 91,041 | 79,007 | |||||
Valuation allowance for deferred tax assets | (22,248 | ) | (22,248 | ) | |||
Net deferred tax assets | 68,793 | 56,759 | |||||
Deferred tax liabilities: | |||||||
Property and equipment | (269,167 | ) | (248,902 | ) | |||
Intangible assets | (48,807 | ) | (42,553 | ) | |||
Other | (1,252 | ) | (1,856 | ) | |||
Total deferred tax liabilities | (319,226 | ) | (293,311 | ) | |||
Net deferred tax liability, net of valuation allowance | $ | (250,433 | ) | $ | (236,552 | ) | |
The December 31, 2013 net deferred tax liability balance is comprised of $284.5 million long-term deferred tax liability, less $11.7 million current deferred tax asset and $22.3 million long-term deferred tax asset. The December 31, 2012 net deferred liability balance is comprised of $259.5 million long-term deferred tax liability, less $20.0 million current deferred tax asset and $2.9 million long-term deferred tax asset.
In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. To fully realize the deferred income tax assets related to our federal net operating loss carryforwards that do not have a valuation allowance due to Section 382 limitations, we would need to generate future federal taxable income of approximately $0.1 million over the next five years. With certain exceptions noted below, we believe that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to the historical evidence, it is more likely than not that these assets will be realized.
We estimate that as of December 31, 2013, 2012 and 2011, we have available $2.4 million, $2.8 million and $79.3 million, respectively, of federal net operating loss carryforwards. Approximately $2.4 million of our net operating losses as of December 31, 2013 are subject to a $5,000 annual Section 382 limitation and expire in 2016 through 2018. The gross deferred tax asset associated with our federal net operating loss carryforward at December 31, 2013 is $0.8 million. Due to annual limitations under Sections 382 and 383, management believes that we will not be able to utilize all available carryforwards
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
prior to their ultimate expiration. At December 31, 2013 and 2012, we had a valuation allowance of $0.8 million related to the deferred tax asset associated with our remaining federal net operating loss carryforwards that will expire before utilization due to Section 382 limitations.
We estimate that as of December 31, 2013, 2012 and 2011, we have available approximately $64.9 million, $44.4 million and $73.3 million, respectively, of state net operating loss carryforwards that will expire between 2014 to 2032. The deferred tax asset associated with our remaining state net operating loss carryforwards at December 31, 2013 is $3.3 million, net of federal tax benefit. Management believes that it is more likely than not that we will be able to utilize all available state carryforwards prior to their ultimate expiration.
We estimate that as of December 31, 2013, 2012 and 2011, we have available approximately $117.6 million, $34.4 million, and $39.6 million, respectively, of foreign net operating loss carryforwards that will expire between 2020 and 2030. The gross deferred tax asset associated with our foreign net operating loss carryforwards at December 31, 2013 is $32.7 million. Management believes that it is more likely than not that we will be able to utilize the net operating loss carryforwards prior to their ultimate expiration in all foreign jurisdictions in which we currently operate.
The Company recognized a valuation allowance of $21.4 million as of December 31, 2013 against the deferred tax asset associated with the capital loss carryforward. The capital loss carryforward will expire in 2017.
We did not provide for U.S. income taxes or withholding taxes on unremitted earnings of our Mexico, Canada, Colombia, Ecuador and the Middle East subsidiaries, as these earnings are considered permanently reinvested because the cash flow generated by these businesses is needed to fund additional equipment and working capital requirements. Furthermore, we did not provide for U.S. income taxes on unremitted earnings of our other foreign subsidiaries as our tax basis in these foreign subsidiaries exceeded the book basis.
We file income tax returns in the United States federal jurisdiction and various states and foreign jurisdictions. We are currently under audit by the Internal Revenue Service for the tax year ended December 31, 2010 and 2011. Our other significant filings are in Mexico, which have been examined through 2008.
As of December 31, 2013, 2012 and 2011, we had $0.9 million, $1.2 million and $1.8 million, respectively, of unrecognized tax benefits which, if recognized, would impact our effective tax rate. We have accrued $0.4 million, $0.3 million and $0.6 million for the payment of interest and penalties as of December 31, 2013, 2012 and 2011, respectively. We believe that it is reasonably possible that $0.4 million of our currently remaining unrecognized tax positions, each of which are individually insignificant, may be recognized by the end of 2014 as a result of a lapse of the statute of limitations and settlement of an open audit.
We recognized a net tax benefit of $0.5 million in 2013 for expirations of statutes of limitations.
The following table presents the gross activity during 2013 and 2012 related to our liabilities for uncertain tax positions (in thousands):
Balance at January 1, 2012 | $ | 2,080 | |
Additions based on tax positions related to the current year | 205 | ||
Reductions for tax positions from prior years | (692 | ) | |
Settlements | — | ||
Balance at December 31, 2012 | 1,593 | ||
Additions based on tax positions related to the current year | 251 | ||
Reductions for tax positions from prior years | (473 | ) | |
Settlements | — | ||
Balance at December 31, 2013 | $ | 1,371 | |
Tax Legislative Changes
The Small Business Jobs Act of 2010. The Small Business Jobs Act of 2010 extended the first-year bonus depreciation deduction of 50% of the adjusted basis of qualified property acquired and placed in service during 2010 and increased the deduction to 100% of the adjusted basis of qualified property acquired and placed in service after September 8, 2010 and before January 1, 2012. We had $199.9 million of qualifying additions in 2011 resulting in bonus tax depreciation of $199.9 million. In 2012 we had $201.8 million of qualifying additions resulting in bonus depreciation of $100.9 million.
72
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 15. LONG-TERM DEBT
The components of our long-term debt are as follows:
December 31, 2013 | December 31, 2012 | ||||||
(in thousands) | |||||||
6.75% Senior Notes due 2021 | $ | 675,000 | $ | 675,000 | |||
8.375% Senior Notes due 2014 | 3,573 | 3,573 | |||||
Senior Secured Credit Facility revolving loans due 2016 | 85,000 | 165,000 | |||||
Net unamortized premium on debt | 3,981 | 4,537 | |||||
Capital lease obligations | — | 393 | |||||
Total debt | 767,554 | 848,503 | |||||
Less current portion | (3,573 | ) | (393 | ) | |||
Total long-term debt and capital leases | $ | 763,981 | $ | 848,110 | |||
8.375% Senior Notes due 2014
On November 29, 2007, we issued $425.0 million aggregate principal amount of 8.375% Senior Notes due 2014 (the “2014 Notes”). On March 4, 2011, we repurchased $421.3 million aggregate principal amount of our 2014 Notes at a purchase price of $1,090 per $1,000 principal amount. On March 15, 2011, we repurchased an additional $0.1 million aggregate principal amount at a purchase price of $1,060 per $1,000 principal amount. In connection with the repurchase of the 2014 Notes, we incurred a loss of $44.3 million on the early extinguishment of debt related to the premium paid on the tender, the payment of related fees and the write-off of unamortized loan fees. Interest on the remaining $3.6 million aggregate principal amount of 2014 Notes outstanding is payable on June 1 and December 1 of each year.
6.75% Senior Notes due 2021
We issued $475.0 million aggregate principal amount of 6.75% Senior Notes due 2021 (the “Initial 2021 Notes”) on March 4, 2011 and issued an additional $200.0 million aggregate principal amount of the 2021 Notes (the “Additional 2021 Notes” and, together with the Initial 2021 Notes, the “2021 Notes”) in a private placement on March 8, 2012 under an indenture dated March 4, 2011 (the “Base Indenture”), as supplemented by a first supplemental indenture dated March 4, 2011 and amended by a further supplemental indenture dated March 8, 2012 (the “Supplemental Indenture” and, together with the Base Indenture, the “Indenture”). We used the net proceeds to repay senior secured indebtedness under our revolving bank credit facility. We capitalized $4.6 million of financing costs associated with the issuance of the 2021 Notes that will be amortized over the term of the notes.
On March 5, 2013, we completed an offer to exchange the $200.0 million in aggregate principal amount of unregistered Additional 2021 Notes for an equal principal amount of such notes registered under the Securities Act of 1933. All of the 2021 Notes are treated as a single class under the Indenture and as of the closing of the exchange offer, bear the same CUSIP and ISIN numbers.
The 2021 Notes are general unsecured senior obligations and are effectively subordinated to all of our existing and future secured indebtedness. The 2021 Notes are or will be jointly and severally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. Interest on the 2021 Notes is payable on March 1 and September 1 of each year. The 2021 Notes mature on March 1, 2021.
On or after March 1, 2016, the 2021 Notes will be subject to redemption at any time and from time to time at our option, in whole or in part, at the redemption prices below (expressed as percentages of the principal amount redeemed), plus accrued and unpaid interest to the applicable redemption date, if redeemed during the twelve-month period beginning on March 1 of the years indicated below:
Year | Percentage | |
2016 | 103.375 | % |
2017 | 102.250 | % |
2018 | 101.125 | % |
2019 and thereafter | 100.000 | % |
73
Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
At any time and from time to time before March 1, 2014, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the outstanding 2021 Notes at a redemption price of 106.750% of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cash proceeds from any one or more equity offerings provided that (i) at least 65% of the aggregate principal amount of the 2021 Notes remains outstanding immediately after each such redemption and (ii) each such redemption shall occur within 180 days of the date of the closing of such equity offering.
In addition, at any time and from time to time prior to March 1, 2016, we may, at our option, redeem all or a portion of the 2021 Notes at a redemption price equal to 100% of the principal amount plus a premium with respect to the 2021 Notes plus accrued and unpaid interest to the redemption date. The premium is the excess of (i) the present value of the redemption price of 103.375% of the principal amount, plus all remaining scheduled interest payments due through March 1, 2016 discounted at the treasury rate plus 0.5% over (ii) the principal amount of the note. If we experience a change of control, subject to certain exceptions, we must give holders of the 2021 Notes the opportunity to sell to us their 2021 Notes, in whole or in part, at a purchase price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest to the date of purchase.
We are subject to certain negative covenants under the Indenture. The Indenture limits our ability to, among other things:
• | incur additional indebtedness and issue preferred equity interests; |
• | pay dividends or make other distributions or repurchase or redeem equity interests; |
• | make loans and investments; |
• | enter into sale and leaseback transactions; |
• | sell, transfer or otherwise convey assets; |
• | create liens; |
• | enter into transactions with affiliates; |
• | enter into agreements restricting subsidiaries’ ability to pay dividends; |
• | designate future subsidiaries as unrestricted subsidiaries; and |
• | consolidate, merge or sell all or substantially all of the applicable entities’ assets. |
These covenants are subject to certain exceptions and qualifications, and contain cross-default provisions relating to the covenants of our 2011 Credit Facility discussed below. Substantially all of the covenants will terminate before the 2021 Notes mature if one of two specified ratings agencies assigns the 2021 Notes an investment grade rating in the future and no events of default exist under the Indenture. As of December 31, 2013, the 2021 Notes were below investment grade. Any covenants that cease to apply to us as a result of achieving an investment grade rating will not be restored, even if the credit rating assigned to the 2021 Notes later falls below investment grade. We were in compliance with these covenants at December 31, 2013.
Senior Secured Credit Facility
We are party to a $550.0 million senior secured revolving bank credit facility with JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, and Capital One, N.A., Wells Fargo Bank, N.A., Credit Agricole Corporate and Investment Bank and DnB NOR Bank ASA, as Co-Documentation Agent (as amended, our “2011 Credit Facility”), which is an important source of liquidity for us. Our 2011 Credit Facility consists of a revolving credit facility, letter of credit sub-facility and swing line facility, all of which will mature no later than March 31, 2016. The maximum amount that we may borrow under the facility may be subject to limitation due to the operation of the covenants contained in the facility. Our 2011 Credit Facility allows us to request increases in the total commitments under the facility by up to $100.0 million in the aggregate in part or in full anytime during the term of our 2011 Credit Facility, with any such increases being subject to compliance with the restrictive covenants in our 2011 Credit Facility and in the Indenture, as well as lender approval.
We capitalized $4.9 million of financing costs in connection with the execution of our 2011 Credit Facility and an additional $1.4 million related to a subsequent amendment that will be amortized over the term of the debt.
The interest rate per annum applicable to the 2011 Credit Facility is, at our option, (i) adjusted LIBOR plus the applicable margin or (ii) the higher of (x) JPMorgan’s prime rate, (y) the Federal Funds rate plus 0.5% and (z) one-month adjusted LIBOR plus 1.0%, plus in each case the applicable margin for all other loans. The applicable margin for LIBOR loans ranges from 225 to 300 basis points, and the applicable margin for all other loans ranges from 125 to 200 basis points, depending upon our consolidated total leverage ratio as defined in the 2011 Credit Facility. Unused commitment fees on the facility equal 0.50%.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Our 2011 Credit Facility contains certain financial covenants, which, among other things, limit our annual capital expenditures, restrict our ability to repurchase shares and require us to maintain certain financial ratios. The financial ratios require that:
• | our ratio of consolidated funded indebtedness to total capitalization be no greater than 45%; |
• | our senior secured leverage ratio of senior secured funded debt to trailing four quarters of earnings before interest, taxes, depreciation and amortization (as calculated pursuant to the terms of our 2011 Credit Facility, “EBITDA”) be no greater than 2.00 to 1.00; |
• | we maintain a collateral coverage ratio, the ratio of the aggregate book value of the collateral to the amount of the total commitments, as of the last day of any fiscal quarter of at least 2.00 to 1.00; |
• | we maintain a consolidated interest coverage ratio of trailing four quarters EBITDA to interest expense of at least 3.00 to 1.00; and |
• | we limit our capital expenditures and investments in foreign subsidiaries to $250.0 million per fiscal year, if the consolidated total leverage ratio exceeds 3.00 to 1.00. |
In addition, our 2011 Credit Facility contains certain affirmative and negative covenants, including, without limitation, restrictions on (i) liens; (ii) debt, guarantees and other contingent obligations; (iii) mergers and consolidations; (iv) sales, transfers and other dispositions of property or assets; (v) loans, acquisitions, joint ventures and other investments (with acquisitions permitted so long as, after giving pro forma effect thereto, no default or event of default exists under our 2011 Credit Facility, the pro forma consolidated total leverage ratio does not exceed 4.00 to 1.00, we are in compliance with other financial covenants and we have at least $25.0 million of availability under our 2011 Credit Facility); (vi) dividends and other distributions to, and redemptions and repurchases from, equityholders; (vii) making investments, loans or advances; (viii) selling properties; (ix) prepaying, redeeming or repurchasing subordinated (contractually or structurally) debt; (x) engaging in transactions with affiliates; (xi) entering into hedging arrangements; (xii) entering into sale and leaseback transactions; (xiii) granting negative pledges other than to the lenders; (xiv) changes in the nature of business; (xv) amending organizational documents; and (xvi) changes in accounting policies or reporting practices; in each of the foregoing cases, with certain exceptions.
We were in compliance with these covenants at December 31, 2013. We may prepay our 2011 Credit Facility in whole or in part at any time without premium or penalty, subject to certain reimbursements to the lenders for breakage and redeployment costs. As of December 31, 2013, we had borrowings of $85.0 million under the revolving credit facility and $54.1 million of letters of credit outstanding, leaving $410.9 million of undrawn borrowing capacity, subject to covenant compliance, under our 2011 Credit Facility. For the years ended December 31, 2013 and 2012, the weighted average interest rates on the outstanding borrowings under our 2011 Credit Facility was 2.76% and 2.71%, respectively.
Letter of Credit Facility
On November 7, 2013, we entered into an uncommitted, unsecured $15.0 million letter of credit facility to be used solely for the issuances of performance letters of credit. As of December 31, 2013, $4.8 million of letters of credit were outstanding leaving $10.2 million of unused borrowing capacity under the facility.
Long-Term Debt Principal Repayment and Interest Expense
Presented below is a schedule of the repayment requirements of long-term debt for each of the next five years and thereafter as of December 31, 2013:
Principal Amount of Long-Term Debt | |||
(in thousands) | |||
2014 | $ | 3,573 | |
2015 | — | ||
2016 | 85,000 | ||
2017 | — | ||
2018 | — | ||
Thereafter | 675,000 | ||
Total long-term debt | $ | 763,573 | |
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Interest expense for the years ended December 31, 2013, 2012 and 2011 consisted of the following:
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Cash payments | $ | 51,705 | $ | 46,767 | $ | 32,204 | |||||
Commitment and agency fees paid | 1,799 | 1,450 | 1,456 | ||||||||
Amortization of premium on debt | (556 | ) | (463 | ) | — | ||||||
Amortization of deferred financing costs | 2,800 | 2,695 | 2,150 | ||||||||
Net change in accrued interest | 63 | 4,431 | 6,774 | ||||||||
Capitalized interest | (607 | ) | (1,314 | ) | (1,735 | ) | |||||
Net interest expense | $ | 55,204 | $ | 53,566 | $ | 40,849 | |||||
As of December 31, 2013, 2012 and 2011, the weighted average interest rates of our variable rate debt was 2.88%, 2.70% and 2.72%, respectively.
Deferred Financing Costs
A summary of deferred financing costs including cost capitalized, amortized, and written off in the determination of the loss on extinguishment of debt for the years ended December 31, 2013 and 2012 are presented in the table below (in thousands):
Balance at December 31, 2011 | $ | 14,771 | |
Capitalized costs | 4,552 | ||
Amortization | (2,695 | ) | |
Balance at December 31, 2012 | 16,628 | ||
Capitalized costs | 69 | ||
Amortization | (2,800 | ) | |
Balance at December 31, 2013 | $ | 13,897 | |
NOTE 16. COMMITMENTS AND CONTINGENCIES
Operating Lease Arrangements
We lease certain property and equipment under non-cancelable operating leases that expire at various dates through 2021, with varying payment dates throughout each month. In addition, we have a number of leases scheduled to expire during 2014.
As of December 31, 2013, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):
Lease Payments | |||
2014 | $ | 18,723 | |
2015 | 12,095 | ||
2016 | 9,383 | ||
2017 | 3,608 | ||
2018 | 2,261 | ||
Thereafter | 4,065 | ||
Total | $ | 50,135 | |
We are also party to a significant number of month-to-month leases that are cancelable at any time. Operating lease expense was $23.9 million, $24.4 million, and $26.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.
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Litigation
Various suits and claims arising in the ordinary course of business are pending against us. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We are also exposed to various claims abroad. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and the need for disclosure of these items, if any. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable. As of December 31, 2013, the aggregate amount of our liabilities related to litigation that are deemed probable and reasonably estimable is $0.3 million. We do not believe that the disposition of any of these matters will result in an additional loss materially in excess of amounts that have been recorded. Our liabilities related to litigation matters that were deemed probable and reasonably estimable as of December 31, 2012 were $0.8 million.
During the second and third quarter of 2013, three lawsuits with similar allegations of violations of California's wage and hour laws were filed in California. The lawsuits allege failure to pay overtime, failure to pay minimum wages, improper payroll deductions, failure to pay final wages in a timely manner, and violations of the California meal and break period laws, among other claims. We intend to vigorously investigate and defend these actions; however, because these cases are in the very early stages, we cannot predict the outcome of these lawsuits at this time and, accordingly, cannot estimate any possible loss or range of loss.
Patent Settlement
In June 2011, we agreed to accept $5.5 million in damages, which was paid in full in July 2011, related to the settlement of a KeyView® system patent infringement lawsuit. We recognized related legal fees and other expenses of $1.4 million during the year ended December 31, 2011. The settlement amount was recorded in general and administrative expenses on the consolidated statement of operations. The resolution of this matter did not have a material effect on our results of operations for the year ended December 31, 2011.
Tax Audits
We are routinely the subject of audits by tax authorities, and in the past have received material assessments from tax auditors. As of December 31, 2013 and 2012, we have recorded reserves that management feels are appropriate for future potential liabilities as a result of prior audits. While we believe we have fully reserved for these assessments, the ultimate amount of settlements can vary from our estimates.
Self-Insurance Reserves
We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicular liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. As of December 31, 2013 and 2012, we have recorded $62.1 million and $69.4 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had approximately $18.5 million and $20.6 million of insurance receivables as of December 31, 2013 and 2012, respectively. We feel that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued for existing claims.
Environmental Remediation Liabilities
For environmental reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. As of December 31, 2013 and 2012, we have recorded $6.2 million and $4.5 million, respectively, for our environmental remediation liabilities. We believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued.
We provide performance bonds to provide financial surety assurances for the remediation and maintenance of our SWD properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 17. ACCUMULATED OTHER COMPREHENSIVE LOSS
The components of our accumulated other comprehensive loss are as follows (in thousands):
December 31, | |||||||
2013 | 2012 | ||||||
Foreign currency translation loss | $ | (15,414 | ) | $ | (6,148 | ) | |
Accumulated other comprehensive loss | $ | (15,414 | ) | $ | (6,148 | ) | |
Upon the completion of the sale of our Argentina operations on September 14, 2012, the accumulated foreign currency translation balance related to Argentina was reversed out of our accumulated other comprehensive loss and recorded as part of our 2012 loss from discontinued operations.
The local currency is the functional currency for our operations in Russia. As of December 31, 2011, the functional currency for Mexico, Russia and Canada was the local currency and the functional currency for Colombia and the Middle East was the U.S. dollar. Due to significant changes in economic facts and circumstances, the functional currency for Mexico and Canada was changed to the U.S. dollar effective January 1, 2012. The cumulative translation gains and losses resulting from translating financial statements from the functional currency to U.S. dollars are included in other comprehensive income and accumulated in stockholders’ equity until a partial or complete sale or liquidation of our net investment in the entity.
The table below summarizes the conversion ratios used to translate the financial statements and the cumulative currency translation gains and losses, net of tax, for each currency:
Mexican Peso | Canadian Dollar | Russian Rouble | Total | |||||||||||||
As of December 31, 2013: | ||||||||||||||||
Conversion ratio | 13.06 : 1 | 1.07 : 1 | 32.77 : 1 | n/a | ||||||||||||
Cumulative translation adjustment | $ | (1,815 | ) | $ | (752 | ) | $ | (12,847 | ) | $ | (15,414 | ) | ||||
As of December 31, 2012: | ||||||||||||||||
Conversion ratio | 13.01 : 1 | 1:00 : 1 | 30.44 : 1 | n/a | ||||||||||||
Cumulative translation adjustment | $ | (1,815 | ) | $ | (752 | ) | $ | (3,581 | ) | $ | (6,148 | ) | ||||
NOTE 18. EMPLOYEE BENEFIT PLANS
We maintain a 401(k) plan as part of our employee benefits package. We match 100% of employee contributions up to 4% of the employee’s salary, which vest immediately, into our 401(k) plan, subject to maximums of $10,200 and $10,000 for the years ended December 31, 2013 and 2012, respectively. Our matching contributions were $10.4 million and $10.7 million for the years ended December 31, 2013 and 2012, respectively. We do not offer participants the option to purchase shares of our common stock through a 401(k) plan fund.
NOTE 19. STOCKHOLDERS’ EQUITY
Common Stock
As of December 31, 2013 and 2012, we had 200,000,000 shares of common stock authorized with a par value of $0.10 per share, of which 152,331,006 shares were issued and outstanding at December 31, 2013 and 151,069,609 shares were issued and outstanding at December 31, 2012. During 2013, 2012 and 2011, no dividends were declared or paid. Under the terms of the 2014 Notes, the 2021 Notes and our 2011 Credit Facility, we must meet certain financial covenants before we may pay dividends. We currently do not intend to pay dividends.
Tax Withholding
We repurchase shares of restricted common stock that have been previously granted to certain of our employees, pursuant to an agreement under which those individuals are permitted to sell shares back to us in order to satisfy the minimum income tax withholding requirements related to vesting of these grants. We repurchased a total of 416,101 shares, 482,951 shares and 383,884 shares for an aggregate cost of $3.2 million, $7.5 million and $5.7 million during 2013, 2012 and 2011, respectively, which represented the fair market value of the shares based on the price of our stock on the dates of purchase.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 20. SHARE-BASED COMPENSATION
2012 Incentive Plan
On May 17, 2012, our stockholders approved the 2012 Equity and Cash Incentive Plan (the “2012 Incentive Plan”). The 2012 Incentive Plan is administered by our board of directors or a committee designated by our board of directors (the “Committee”). Our board of directors or the Committee (the “Administrator”) will have the power and authority to select Participants (as defined below) in the 2012 Incentive Plan and grant Awards (as defined below) to such Participants pursuant to the terms of the 2012 Incentive Plan. The 2012 Incentive Plan expires May 17, 2022.
Subject to adjustment, the total number of shares of our common stock that will be available for the grant of Awards under the 2012 Incentive Plan may not exceed 4,000,000 shares; however, for purposes of this limitation, any stock subject to an Award that is canceled, forfeited, expires or otherwise terminates without the issuance of stock, is settled in cash, or is exchanged with the Administrator's permission, prior to the issuance of stock, for an Award not involving stock, will again become available for issuance under the 2012 Incentive Plan. However, the full number of SARs granted that are to be settled by the issuance of stock will count against the plan limit described above, regardless of the number of shares of stock actually issued upon settlement of the stock appreciation rights. Shares of stock surrendered or withheld in payment of the exercise price of an option and shares of stock withheld by the Company to satisfy tax withholding obligations will count against the plan limit described above. Subject to adjustment, no Participant will be granted, during any one year period, options to purchase common stock and/or SARs with respect to more than 500,000 shares of common stock. Stock available for distribution under the 2012 Incentive Plan will be authorized and unissued shares, treasury shares or shares we reacquire in any manner.
Awards may be in the form of stock options (incentive stock options and nonqualified stock options), restricted stock, restricted stock units, performance compensation awards and SARs (collectively, "Awards"). Awards may be granted to employees, directors and, in some cases, consultants and those individuals whom the Administrator determines are reasonably expected to become employees, directors or consultants following the grant date of the Award (“Participants”). However, incentive stock options may be granted only to employees.
Our board of directors at any time, and from time to time, may amend or terminate the 2012 Incentive Plan. However, except as provided otherwise in the 2012 Incentive Plan, no amendment will be effective unless approved by the stockholders of the Company to the extent stockholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. Further, if the exercise price of an option, including an incentive stock option, exceeds the fair market value of our common stock on a given date, the Committee has the authority to reduce the exercise price of such option to a new exercise price that is no less than the then-current fair market value of our common stock; provided that such action shall first have been approved by a vote of our stockholders. The Administrator at any time, and from time to time, may amend the terms of any one or more Awards; however, if the amendment would constitute an impairment of the rights under any Award, we must request the consent of the Participant and the Participant must consent in writing. It is expressly contemplated that the board may amend the 2012 Incentive Plan in any respect our board of directors deem necessary or advisable to provide eligible employees with the maximum benefits provided or to be provided under the provisions of the Internal Revenue Code of 1986, as amended, and the regulations promulgated thereunder relating to incentive stock options and/or to bring the 2012 Incentive Plan and/or Awards granted under it into compliance therewith. As of December 31, 2013, there were 1.6 million shares available for grant under the 2012 Incentive Plan.
2009 Incentive Plan
On June 4, 2009, our stockholders approved the 2009 Equity and Cash Incentive Plan (the “2009 Incentive Plan”). The 2009 Incentive Plan is administered by our board of directors or the applicable Committee designated by the board. The Administrator will have the power and authority to select Participants in the 2009 Incentive Plan and to grant Awards to such Participants pursuant to the terms of the 2009 Incentive Plan. The 2009 Incentive Plan expires June 4, 2019.
Subject to adjustment, the total number of shares of our common stock available for the grant of Awards under the 2009 Incentive Plan may not exceed 4,000,000 shares; however, for purposes of this limitation, any stock subject to an Award that is canceled, forfeited or expires prior to exercise or realization will again become available for issuance under the 2009 Incentive Plan. Subject to adjustment, no Participant will be granted, during any one year period, options to purchase common stock and/or SARs with respect to more than 500,000 shares of common stock. Stock available for distribution under the 2009 Incentive Plan will come from authorized and unissued shares or shares we reacquire in any manner. All awards under the 2009 Incentive Plan are granted at fair market value on the date of issuance.
Awards may be granted to employees, directors and, in some cases, consultants and those individuals whom the Administrator determines are reasonably expected to become employees, directors or consultants following the grant date of the
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Award (“Participants”). However, incentive stock options may be granted only to employees. Vesting periods may be set at the board’s discretion but are generally set at two to four years. Awards to our directors are generally not subject to vesting.
Our board of directors at any time, and from time to time, may amend or terminate the 2009 Incentive Plan. However, no repricing of stock options is permitted unless approved by our stockholders, and, except as provided otherwise in the 2009 Incentive Plan, no other amendment will be effective unless approved by our stockholders to the extent stockholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. As of December 31, 2013, there were 0.6 million shares available for grant under the 2009 Incentive Plan.
2007 Incentive Plan
On December 6, 2007, our stockholders approved the 2007 Equity and Cash Incentive Plan (the “2007 Incentive Plan”). The 2007 Incentive Plan is substantially similar to the 2009 Incentive Plan except for certain differences related to treatment of Awards at retirement and transferability of Awards at death. The 2007 Incentive Plan expires December 6, 2017.
Subject to adjustment, the total number of shares of our common stock that are available for the grant of Awards under the 2007 Incentive Plan may not exceed 4,000,000 shares; however, for purposes of this limitation, any stock subject to an award that is canceled, forfeited or expires prior to exercise or realization will again become available for issuance under the 2007 Incentive Plan.
Our board of directors at any time, and from time to time, may amend or terminate the 2007 Incentive Plan. However, except as provided otherwise in the 2007 Incentive Plan, no amendment will be effective unless approved by our stockholders to the extent stockholder approval is necessary to satisfy any applicable law or securities exchange listing requirements. As of December 31, 2013, there were 0.3 million shares available for grant under the 2007 Incentive Plan.
Stock Option Awards
Stock option awards granted under our incentive plans have a maximum contractual term of ten years from the date of grant. Shares issuable upon exercise of a stock option are issued from authorized but unissued shares of our common stock. The following tables summarize the stock option activity (shares in thousands):
Year Ended December 31, 2013 | ||||||||||
Options | Weighted Average Exercise Price | Weighted Average Fair Value | ||||||||
Outstanding at beginning of period | 1,820 | $ | 14.04 | $ | 5.91 | |||||
Granted | — | $ | — | $ | — | |||||
Exercised | (4 | ) | $ | 3.87 | $ | 1.67 | ||||
Cancelled or expired | (444 | ) | $ | 13.93 | $ | 5.65 | ||||
Outstanding at end of period | 1,372 | $ | 14.10 | $ | 6.00 | |||||
Exercisable at end of period | 1,372 | $ | 14.10 | $ | 6.00 | |||||
Year Ended December 31, 2012 | ||||||||||
Options | Weighted Average Exercise Price | Weighted Average Fair Value | ||||||||
Outstanding at beginning of period | 2,137 | $ | 13.87 | $ | 5.84 | |||||
Granted | — | $ | — | $ | — | |||||
Exercised | (114 | ) | $ | 9.76 | $ | 4.83 | ||||
Cancelled or expired | (203 | ) | $ | 14.68 | $ | 5.91 | ||||
Outstanding at end of period | 1,820 | $ | 14.04 | $ | 5.91 | |||||
Exercisable at end of period | 1,820 | $ | 14.04 | $ | 5.91 | |||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Year Ended December 31, 2011 | ||||||||||
Options | Weighted Average Exercise Price | Weighted Average Fair Value | ||||||||
Outstanding at beginning of period | 2,816 | $ | 13.52 | $ | 5.72 | |||||
Granted | — | $ | — | $ | — | |||||
Exercised | (647 | ) | $ | 12.29 | $ | 5.31 | ||||
Cancelled or expired | (32 | ) | $ | 13.89 | $ | 5.86 | ||||
Outstanding at end of period | 2,137 | $ | 13.87 | $ | 5.84 | |||||
Exercisable at end of period | 2,126 | $ | 13.92 | $ | 5.87 | |||||
The following tables summarize information about the stock options outstanding at December 31, 2013 (shares in thousands):
Options Outstanding | |||||||||||||
Weighted Average Remaining Contractual Life (Years) | Number of Options Outstanding | Weighted Average Exercise Price | Weighted Average Fair Value | ||||||||||
Range of exercise prices: | |||||||||||||
$3.87 - $9.37 | 4.92 | 6 | $ | 4.01 | $ | 1.72 | |||||||
$9.38 - $13.10 | 1.48 | 335 | $ | 11.92 | $ | 5.95 | |||||||
$13.11 - $15.05 | 3.59 | 995 | $ | 14.82 | $ | 6.04 | |||||||
$15.06 - $19.42 | 4.47 | 36 | $ | 16.18 | $ | 6.07 | |||||||
1,372 | $ | 14.10 | $ | 6.00 | |||||||||
Aggregate intrinsic value (in thousands) | $ | 24 | |||||||||||
Options Exercisable | ||||||||||||||
Number of Options Exercisable | Weighted Average Exercise Price | Weighted Average Fair Value | ||||||||||||
Range of exercise prices: | ||||||||||||||
$3.87 - $9.37 | 6 | $ | 4.01 | $ | 1.72 | |||||||||
$9.38 - $13.10 | 335 | $ | 11.92 | $ | 5.95 | |||||||||
$13.11 - $15.05 | 995 | $ | 14.82 | $ | 6.04 | |||||||||
$15.06 - $19.42 | 36 | $ | 16.18 | $ | 6.07 | |||||||||
1,372 | $ | 14.10 | $ | 6.00 | ||||||||||
Aggregate intrinsic value (in thousands) | $ | 24 | ||||||||||||
We did not grant any stock options during the years ended December 31, 2013, 2012 and 2011. No stock options vested during the year ended December 31, 2013. We recognized zero, less than $0.1 million and less than $0.1 million in pre-tax expense related to stock options for the years ended December 31, 2013, 2012 and 2011, respectively. We recognized tax benefits of zero, less than $0.1 million and less than $0.1 million, related to our stock options for the years ended December 31, 2013, 2012 and 2011, respectively. All of the stock option awards were vested as of December 31, 2012. The weighted average remaining contractual term for stock option awards exercisable as of December 31, 2013 is 3.1 years. The intrinsic value of the options exercised for the years ended December 31, 2013, 2012 and 2011 was less than $0.1 million, $0.6 million and $3.0 million, respectively. Cash received from the exercise of options for the year ended December 31, 2013, was less than $0.1 million with zero associated tax benefits.
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Common Stock Awards
The total fair market value of all common stock awards granted during the years ended December 31, 2013, 2012 and 2011 was $15.7 million, $14.9 million and $18.4 million, respectively.
The following tables summarize information for the years ended December 31, 2013, 2012 and 2011 about the common share awards that we have issued (shares in thousands):
Year Ended December 31, 2013 | |||||||||||||
Outstanding | Weighted Average Issuance Price | Vested | Weighted Average Issuance Price | ||||||||||
Shares at beginning of period | 6,160 | $ | 8.87 | 4,383 | $ | 6.12 | |||||||
Shares issued during period(1) | 2,062 | $ | 7.59 | 475 | $ | 6.92 | |||||||
Previously issued shares vesting during period | — | $ | — | 1,094 | $ | 12.13 | |||||||
Shares cancelled during period | (386 | ) | $ | 9.64 | — | $ | — | ||||||
Shares repurchased during period | (416 | ) | $ | 7.51 | (416 | ) | $ | 7.51 | |||||
Shares at end of period | 7,420 | $ | 8.55 | 5,536 | $ | 7.27 | |||||||
Year Ended December 31, 2012 | |||||||||||||
Outstanding | Weighted Average Issuance Price | Vested | Weighted Average Issuance Price | ||||||||||
Shares at beginning of period | 5,874 | $ | 8.78 | 2,876 | $ | 6.27 | |||||||
Shares issued during period(1) | 1,106 | $ | 13.50 | 153 | $ | 10.29 | |||||||
Previously issued shares vesting during period | — | $ | — | 1,837 | $ | 7.98 | |||||||
Shares cancelled during period | (337 | ) | $ | 13.13 | — | $ | — | ||||||
Shares repurchased during period | (483 | ) | $ | 15.42 | (483 | ) | $ | 15.42 | |||||
Shares at end of period | 6,160 | $ | 8.87 | 4,383 | $ | 6.12 | |||||||
Year Ended December 31, 2011 | |||||||||||||
Outstanding | Weighted Average Issuance Price | Vested | Weighted Average Issuance Price | ||||||||||
Shares at beginning of period | 5,027 | $ | 7.98 | 1,913 | $ | 8.41 | |||||||
Shares issued during period(1) | 1,370 | $ | 13.43 | 101 | $ | 1.18 | |||||||
Previously issued shares vesting during period | — | $ | — | 1,246 | $ | 5.99 | |||||||
Shares cancelled during period | (139 | ) | $ | 9.43 | — | $ | — | ||||||
Shares repurchased during period | (384 | ) | $ | 14.68 | (384 | ) | $ | 14.68 | |||||
Shares at end of period | 5,874 | $ | 8.78 | 2,876 | $ | 6.27 | |||||||
(1) | Includes 288,780 shares, 153,063 shares and 99,999 shares of common stock issued to our non-employee directors that vested immediately upon issuance during 2013, 2012 and 2011, respectively. |
For common stock grants that vest immediately upon issuance, we record expense equal to the fair market value of the shares on the date of grant. For common stock awards that do not immediately vest, we recognize compensation expense ratably over the graded vesting period of the grant, net of estimated and actual forfeitures. For the years ended December 31, 2013, 2012 and 2011, we recognized $13.8 million, $13.3 million and $15.6 million, respectively, of pre-tax expense from continuing operations associated with common stock awards, including common stock grants to our outside directors. In connection with the expense related to common stock awards recognized during the year ended December 31, 2013, we recognized tax benefits of $5.2 million. Tax benefits for the years ended December 31, 2012 and 2011 were $4.2 million and $6.0 million, respectively. For the unvested common stock awards outstanding as of December 31, 2013, we anticipate that we will recognize $8.8 million of pre-tax expense over the next 0.9 years.
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Performance Units
On January 21, 2013, the Compensation Committee of the board of directors adopted the Performance Unit Award Agreement (the “2012 PU Award Agreement”) under the 2012 Incentive Plan and the 2013 Performance Unit Plan (the “2013 PU Plan”). We believe that the 2013 PU Plan and 2012 PU Award Agreement will enable us to obtain and retain employees who will contribute to our long term success by aligning the interests of our executives with the interests of our stockholders by providing compensation that is linked directly to increases in share value.
In January 2013, we issued 0.4 million performance units to our executive officers under the 2012 Incentive Plan with such material terms as set forth in the 2012 PU Award Agreement. In February 2013, we issued 0.2 million performance units to certain other employees under the 2013 PU Plan. The performance units are measured based on two performance periods from January 1, 2013 to December 31, 2013 and from January 1, 2014 to December 31, 2014. One half of the performance units are measured based on the first performance period, and the other half are measured based on the second performance period. The number of performance units that may be earned by a participant is determined at the end of each performance period based on the relative placement of Key's total stockholder return for that period within the peer group, as follows:
Company Placement for the Performance Period | Percentile Ranking in Peer Group | Performance Units Earned as a Percentage of Target | ||||
First | 100 | % | 200 | % | ||
Second | 91 | % | 180 | % | ||
Third | 82 | % | 160 | % | ||
Fourth | 73 | % | 140 | % | ||
Fifth | 64 | % | 120 | % | ||
Sixth | 55 | % | 100 | % | ||
Seventh | 45 | % | 75 | % | ||
Eighth | 36 | % | 50 | % | ||
Ninth | 27 | % | 25 | % | ||
Tenth | 18 | % | — | % | ||
Eleventh | 9 | % | — | % | ||
Twelfth | — | % | — | % | ||
If any performance units vest for a given performance period, the award holder will be paid a cash amount equal to the vested percentage of the performance units multiplied by the closing stock price of our common stock on the last trading day of the performance period. We account for the performance units as a liability-type award as they are settled in cash. As of December 31, 2013, the fair value of outstanding performance units was $2.2 million, and is being accreted to compensation expense over the vesting terms of the awards. As of December 31, 2013, the unrecognized compensation cost related to our unvested performance units is estimated to be $1.1 million and is expected to be recognized over a weighted-average period of 1.0 years.
Phantom Share Plan
In December 2006, we announced the implementation of a “Phantom Share Plan,” in which certain of our employees were granted “Phantom Shares.” Phantom Shares vest ratably over a four-year period and convey the right to the grantee to receive a cash payment on the anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer this payment to a later date. The Phantom Shares are a “liability” type award and we account for these awards at fair value. We recognize compensation expense related to the Phantom Shares based on the change in the fair value of the awards during the period and the percentage of the service requirement that has been performed, net of estimated and actual forfeitures, with an offsetting liability recorded on our consolidated balance sheets. We recognized pre-tax compensation benefit from continuing operation, associated with the Phantom Shares of zero, less than $0.1 million and $0.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2013, no Phantom Shares were outstanding.
We recognized income tax benefit associated with the Phantom Shares of zero, less than $0.1 million and $0.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. During 2013, there were no cash payments related to the Phantom Shares.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Stock Appreciation Rights
In August 2007, we issued approximately 587,000 SARs to our executive officers. Each SAR has a ten-year term from the date of grant. The vesting of all outstanding SAR awards was accelerated during the fourth quarter of 2008. Upon the exercise of a SAR, the recipient will receive an amount equal to the difference between the exercise price and the fair market value of a share of our common stock on the date of exercise, multiplied by the number of shares of common stock for which the SAR was exercised. All payments will be made in shares of our common stock. Prior to exercise, the SAR does not entitle the recipient to receive any shares of our common stock and does not provide the recipient with any voting or other stockholders’ rights. We account for these SARs as equity awards and recognize compensation expense ratably over the vesting period of the SAR based on their fair value on the date of issuance, net of estimated and actual forfeitures. We did not recognize any expense associated with these awards during 2013, 2012 and 2011. We did not forfeit any SARs during 2013. As of December 31, 2013, 0.3 million SARs remained unexercised.
NOTE 21. TRANSACTIONS WITH RELATED PARTIES
Employee Loans and Advances
From time to time, we have made certain retention loans and relocation loans to employees other than executive officers. The retention loans are forgiven over various time periods so long as the employee continues their employment with us. The relocation loans are repaid upon the employee selling their prior residence. As of December 31, 2013 and 2012, we did not have any employee loans and advances outstanding.
Transactions with Affiliates
In October 2010, we acquired certain subsidiaries, together with associated assets, from OFS Energy Services, LLC (“OFS”), an oilfield services company owned by ArcLight Capital Partners, LLC. At the time of the acquisition, OFS conducted business with companies owned by a former owner and employee of an OFS subsidiary that we purchased. Subsequent to the acquisition, we continued to provide services to these companies. The prices charged to these companies for our services are at rates that are equivalent to the prices charged to our other customers in the U.S. market. As of December 31, 2013 and 2012, our receivables from these related parties totaled less than $0.1 million and $0.2 million, respectively. Revenues from these customers for the years ended December 31, 2013, 2012 and 2011 were $0.1 million, $2.7 million and $2.7 million, respectively.
We provide services to an exploration and production company owned by one of our former employees. The prices charged to this company for these services are at rates that are an average of the prices charged to other customers in the California market where the services are provided. As of December 31, 2013 and 2012, our receivables from this company totaled less than $0.1 million and $0.2 million, respectively. Revenues from this company totaled $1.1 million, $5.1 million and $5.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Board of Director Relationships
A member of our board of directors is the Executive Vice President, General Counsel and Chief Administrative Officer of Anadarko Petroleum Corporation (“Anadarko”), which is one of our customers. Sales to Anadarko were $41.2 million, $37.0 million and $37.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. Receivables outstanding from Anadarko were $4.9 million and $3.5 million as of December 31, 2013 and 2012, respectively. Transactions with Anadarko for our services are made on terms consistent with other customers.
A former member of our board of directors who resigned in May 2011 is a member and managing director of the general partner of the indirect majority owner of one of our customers. Sales to this customer were $0.4 million, $0.4 million and $1.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. Receivables outstanding from this customer were less than $0.1 million as of December 31, 2013 and 2012. Transactions with this customer are made on terms consistent with other customers.
A member of our board of directors serves on the United States Advisory Board of the Alexander Proudfoot practice of Management Consulting Group PLC (“Proudfoot”), which provided consulting services related to our general and administrative cost restructuring initiative. Payments to Proudfoot were zero, $1.9 million and $4.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
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NOTE 22. SUPPLEMENTAL CASH FLOW INFORMATION
Year Ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(in thousands) | |||||||||||
Noncash investing and financing activities: | |||||||||||
Sale of Argentina operations/Notes receivable | $ | — | $ | 12,955 | $ | — | |||||
Common stock issued in acquisition | — | — | 117,919 | ||||||||
Asset retirement obligations | 174 | — | 741 | ||||||||
Supplemental cash flow information: | |||||||||||
Cash paid for interest | $ | 53,504 | $ | 48,217 | $ | 35,354 | |||||
Cash paid for taxes | 35,239 | 13,148 | 63,680 | ||||||||
Tax refunds | 26,361 | 18,681 | 27,206 | ||||||||
Cash paid for interest includes cash payments for interest on our long-term debt and capital lease obligations, and commitment and agency fees paid.
NOTE 23. SEGMENT INFORMATION
Our operating segments are U.S. and International. We also have a “Functional Support” segment associated with managing each of our reportable operating segments. Our domestic rig-based services, fluid management services, fishing and rental services, and coiled tubing services (formerly intervention services) are aggregated within our U.S. reportable segment. Our international rig-based services business and our Canadian technology development group are aggregated within our International reportable segment. We evaluate the performance of our operating segments based on revenue and income measures. All inter-segment sales pricing is based on current market conditions. The following is a description of the segments:
U.S. Segment
Rig-Based Services
Our rig-based services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass various sizes and capabilities, allowing us to service all types of wells with depths up to 20,000 feet. Many of our rigs are outfitted with our proprietary KeyView® technology, which captures and reports well site operating data and provides safety control systems. We believe that this technology allows our customers and our crews to better monitor well site operations, improves efficiency and safety, and adds value to the services that we offer.
The completion and recompletion services provided by our rigs prepare wells for production, whether newly drilled, or recently extended through a workover operation. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. Completion services vary by well and our work may take a few days to several weeks to perform, depending on the nature of the completion.
The workover services that we provide are designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover.
Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or natural gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to identify and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform.
85
Our rig fleet is also used in the process of permanently shutting-in oil or natural gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.
Fluid Management Services
We provide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in SWDs wells owned by us or a third party. In addition, we operate a fleet of hot oilers capable of pumping heated fluids used to clear soluble restrictions in a wellbore. Demand and pricing for these services generally correspond to demand for our well service rigs.
Coiled Tubing Services
Coiled tubing services involve the use of a continuous metal pipe spooled onto a large reel which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing is also used for a number of horizontal well applications such as milling temporary isolation plugs that separate frac zones, and various other pre- and post- hydraulic fracturing well preparation services.
Fishing and Rental Services
We offer a full line of services and rental equipment designed for use in providing both onshore and offshore drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units and foam air units.
As a result of the 2011 acquisition of Edge, our rental inventory also includes frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. We also provide well testing services.
Demand for our fishing and rental services is also closely related to capital spending by oil and natural gas producers, which is generally a function of oil and natural gas prices.
International Segment
Our International segment includes operations in Mexico, Colombia, Ecuador, the Middle East and Russia. In addition, we have a technology development and control systems business based in Canada. Also, prior to the sale of our Argentina business in the third quarter of 2012, we operated in Argentina. We are reporting the results of our Argentina business as discontinued operations for the 2011 and 2012 periods. We provide rig-based services such as the maintenance, workover, recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives in each of our international markets.
In addition, in Mexico we provide drilling, coiled tubing, wireline and project management and consulting services. Our work in Mexico also requires us to provide third party services which varies in scope by project.
In the Middle East, we operate in the Kingdom of Bahrain and Oman. On August 5, 2013, we agreed to the dissolution of AlMansoori Key Energy Services, LLC, a joint venture formed under the laws of Abu Dhabi, UAE, and the acquisition of the underlying business for $5.1 million. See “Note 2. Acquisitions” for further discussion.
Our Russian operations provide drilling, workover, and reservoir engineering services. On April 9, 2013, we completed the acquisition of the remaining 50% noncontrolling interest in Geostream for $14.6 million. We now own 100% of Geostream. See “Note 2. Acquisitions” for further discussion.
Our technology development and control systems business based in Canada is focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.
Functional Support Segment
Our Functional Support segment includes unallocated overhead costs associated with administrative support for our U.S. and International reporting segments.
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The following table presents our segment information as of and for the years ended December 31, 2013, 2012 and 2011 (in thousands):
As of and for the year ended December 31, 2013
U.S. | International | Functional Support(2) | Reconciling Eliminations | Total | |||||||||||||||
Revenues from external customers | $ | 1,376,969 | $ | 214,707 | $ | — | $ | — | $ | 1,591,676 | |||||||||
Intersegment revenues | 10,630 | 8,715 | 509 | (19,854 | ) | — | |||||||||||||
Depreciation and amortization | 181,976 | 30,227 | 13,094 | — | 225,297 | ||||||||||||||
Other operating expenses | 1,002,661 | 211,137 | 122,417 | — | 1,336,215 | ||||||||||||||
Operating income (loss) | 192,332 | (26,657 | ) | (135,511 | ) | — | 30,164 | ||||||||||||
Interest expense, net of amounts capitalized | 1 | 62 | 55,141 | — | 55,204 | ||||||||||||||
Income (loss) from continuing operations before tax | 192,539 | (26,795 | ) | (189,981 | ) | — | (24,237 | ) | |||||||||||
Long-lived assets(1) | 1,637,969 | 333,273 | 301,032 | (190,957 | ) | 2,081,317 | |||||||||||||
Total assets | 2,785,299 | 497,938 | (181,940 | ) | (513,827 | ) | 2,587,470 | ||||||||||||
Capital expenditures, excluding acquisitions | 125,518 | 19,541 | 19,078 | — | 164,137 | ||||||||||||||
As of and for the year ended December 31, 2012
U.S. | International | Functional Support(2) | Reconciling Eliminations | Total | |||||||||||||||
Revenues from external customers | $ | 1,626,768 | $ | 333,302 | $ | — | $ | — | $ | 1,960,070 | |||||||||
Intersegment revenues | 43,867 | 6,273 | 15 | (50,155 | ) | — | |||||||||||||
Depreciation and amortization | 182,502 | 19,643 | 11,638 | — | 213,783 | ||||||||||||||
Other operating expenses | 1,158,925 | 250,667 | 129,749 | — | 1,539,341 | ||||||||||||||
Operating income (loss) | 285,341 | 62,992 | (141,387 | ) | — | 206,946 | |||||||||||||
Interest expense, net of amounts capitalized | 17 | 172 | 53,377 | — | 53,566 | ||||||||||||||
Income (loss) from continuing operations before tax | 285,846 | 68,036 | (193,853 | ) | — | 160,029 | |||||||||||||
Long-lived assets(1) | 1,724,239 | 334,329 | 286,369 | (173,143 | ) | 2,171,794 | |||||||||||||
Total assets | 2,513,688 | 541,882 | 153,665 | (447,647 | ) | 2,761,588 | |||||||||||||
Capital expenditures, excluding acquisitions | 248,023 | 171,095 | 28,042 | — | 447,160 | ||||||||||||||
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As of and for the year ended December 31, 2011
U.S. | International | Functional Support(2) | Reconciling Eliminations | Total | |||||||||||||||
Revenues from external customers | $ | 1,530,087 | $ | 199,124 | $ | — | $ | — | $ | 1,729,211 | |||||||||
Intersegment revenues | 7,870 | 9,481 | 707 | (18,058 | ) | — | |||||||||||||
Depreciation and amortization | 142,257 | 13,515 | 11,174 | — | 166,946 | ||||||||||||||
Other operating expenses | 1,030,224 | 146,688 | 131,577 | — | 1,308,489 | ||||||||||||||
Operating (loss) income | 357,606 | 38,921 | (142,751 | ) | — | 253,776 | |||||||||||||
Interest expense, net of amounts capitalized | 37 | 18 | 40,794 | — | 40,849 | ||||||||||||||
Loss on early extinguishment of debt | — | — | 46,451 | — | 46,451 | ||||||||||||||
Income (loss) from continuing operations before tax | 358,072 | 41,936 | (224,555 | ) | — | 175,453 | |||||||||||||
Long-lived assets(1) | 1,851,148 | 223,034 | 233,739 | (309,364 | ) | 1,998,557 | |||||||||||||
Total assets | 2,330,061 | 414,780 | 394,864 | (540,585 | ) | 2,599,120 | |||||||||||||
Capital expenditures, excluding acquisitions | 298,342 | 45,045 | 15,710 | — | 359,097 | ||||||||||||||
(1) | Long lived assets include: fixed assets, goodwill, intangibles and other assets. |
(2) | Functional Support is geographically located in the United States. |
NOTE 24. UNAUDITED QUARTERLY RESULTS OF OPERATIONS
Set forth below is unaudited summarized quarterly information for the two most recent years covered by these consolidated financial statements (in thousands, except for per share data):
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
Year Ended December 31, 2013: | |||||||||||||||
Revenues | $ | 428,449 | $ | 411,390 | $ | 389,673 | $ | 362,164 | |||||||
Direct operating expenses | 299,182 | 287,102 | 268,297 | 259,881 | |||||||||||
Loss from continuing operations | (186 | ) | (3,772 | ) | (4,697 | ) | (12,518 | ) | |||||||
Net loss | (186 | ) | (3,772 | ) | (4,697 | ) | (12,518 | ) | |||||||
Loss attributable to Key | (274 | ) | (4,128 | ) | (4,848 | ) | (12,518 | ) | |||||||
Loss per share(1): | |||||||||||||||
Basic and Diluted | — | (0.03 | ) | (0.03 | ) | (0.08 | ) | ||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
Year Ended December 31, 2012: | |||||||||||||||
Revenues | $ | 486,751 | $ | 515,997 | $ | 490,851 | $ | 466,471 | |||||||
Direct operating expenses | 311,497 | 343,996 | 335,799 | 317,553 | |||||||||||
Income from continuing operations | 33,481 | 31,699 | 23,190 | 14,307 | |||||||||||
Net (loss) income | 2,576 | 29,245 | (37,019 | ) | 14,307 | ||||||||||
Income (loss) attributable to Key | 3,190 | 29,041 | (38,094 | ) | 13,485 | ||||||||||
Earnings (loss) per share(1): | |||||||||||||||
Basic and Diluted | 0.02 | 0.19 | (0.25 | ) | 0.09 | ||||||||||
(1) | Quarterly earnings per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings per common share. |
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 25. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
Our 2021 Notes are guaranteed by virtually all of our domestic subsidiaries, all of which are wholly owned. The guarantees are joint and several, full, complete and unconditional. There are no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.
As a result of these guarantee arrangements, we are required to present the following condensed consolidating financial information.
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2013 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Assets: | |||||||||||||||||||
Current assets | $ | 50,321 | $ | 398,188 | $ | 57,644 | $ | — | $ | 506,153 | |||||||||
Property and equipment, net | — | 1,244,216 | 121,430 | — | 1,365,646 | ||||||||||||||
Goodwill | — | 597,457 | 27,418 | — | 624,875 | ||||||||||||||
Deferred financing costs, net | 13,897 | — | — | — | 13,897 | ||||||||||||||
Intercompany notes and accounts receivable and investment in subsidiaries | 3,421,607 | 1,364,174 | 12,939 | (4,798,720 | ) | — | |||||||||||||
Other assets | — | 34,278 | 42,621 | — | 76,899 | ||||||||||||||
TOTAL ASSETS | $ | 3,485,825 | $ | 3,638,313 | $ | 262,052 | $ | (4,798,720 | ) | $ | 2,587,470 | ||||||||
Liabilities and equity: | |||||||||||||||||||
Current liabilities | $ | 26,097 | $ | 182,497 | $ | 23,750 | $ | — | $ | 232,344 | |||||||||
Long-term debt and capital leases, less current portion | 763,981 | — | — | — | 763,981 | ||||||||||||||
Intercompany notes and accounts payable | 1,162,648 | 2,667,943 | 97,050 | (3,927,641 | ) | — | |||||||||||||
Deferred tax liabilities | 280,828 | 4,643 | (1,819 | ) | 801 | 284,453 | |||||||||||||
Other long-term liabilities | 1,195 | 54,486 | (82 | ) | — | 55,599 | |||||||||||||
Equity | 1,251,076 | 728,744 | 143,153 | (871,880 | ) | 1,251,093 | |||||||||||||
TOTAL LIABILITIES AND EQUITY | $ | 3,485,825 | $ | 3,638,313 | $ | 262,052 | $ | (4,798,720 | ) | $ | 2,587,470 | ||||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2012 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Assets: | |||||||||||||||||||
Current assets | $ | 66,435 | $ | 469,049 | $ | 54,310 | $ | — | $ | 589,794 | |||||||||
Property and equipment, net | — | 1,329,379 | 107,295 | — | 1,436,674 | ||||||||||||||
Goodwill | — | 597,458 | 29,023 | — | 626,481 | ||||||||||||||
Deferred financing costs, net | 16,628 | — | — | — | 16,628 | ||||||||||||||
Intercompany notes and accounts receivable and investment in subsidiaries | 3,298,679 | 1,108,231 | (20,371 | ) | (4,386,539 | ) | — | ||||||||||||
Other assets | 8,068 | 39,696 | 44,247 | — | 92,011 | ||||||||||||||
TOTAL ASSETS | $ | 3,389,810 | $ | 3,543,813 | $ | 214,504 | $ | (4,386,539 | ) | $ | 2,761,588 | ||||||||
Liabilities and equity: | |||||||||||||||||||
Current liabilities | $ | 46,632 | $ | 226,773 | $ | 31,691 | $ | — | $ | 305,096 | |||||||||
Long-term debt and capital leases, less current portion | 848,110 | — | — | — | 848,110 | ||||||||||||||
Intercompany notes and accounts payable | 947,700 | 2,590,398 | 14,138 | (3,552,236 | ) | — | |||||||||||||
Deferred tax liabilities | 258,528 | 6,781 | (746 | ) | (5,110 | ) | 259,453 | ||||||||||||
Other long-term liabilities | 1,528 | 60,068 | 1 | — | 61,597 | ||||||||||||||
Equity | 1,287,312 | 659,793 | 169,420 | (829,193 | ) | 1,287,332 | |||||||||||||
TOTAL LIABILITIES AND EQUITY | $ | 3,389,810 | $ | 3,543,813 | $ | 214,504 | $ | (4,386,539 | ) | $ | 2,761,588 | ||||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 2013 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Revenues | $ | 148 | $ | 1,494,683 | $ | 161,536 | $ | (64,691 | ) | $ | 1,591,676 | ||||||||
Direct operating expense | — | 1,046,376 | 118,028 | (49,942 | ) | 1,114,462 | |||||||||||||
Depreciation and amortization expense | — | 214,334 | 10,963 | — | 225,297 | ||||||||||||||
General and administrative expense | 1,077 | 202,599 | 33,336 | (15,259 | ) | 221,753 | |||||||||||||
Operating (loss) income | (929 | ) | 31,374 | (791 | ) | 510 | 30,164 | ||||||||||||
Interest expense, net of amounts capitalized | 55,747 | (606 | ) | 63 | — | 55,204 | |||||||||||||
Other (income) expense, net | (3,616 | ) | (1,126 | ) | 316 | 3,623 | (803 | ) | |||||||||||
Income (loss) from continuing operations before taxes | (53,060 | ) | 33,106 | (1,170 | ) | (3,113 | ) | (24,237 | ) | ||||||||||
Income tax (expense) benefit | (13,385 | ) | 15,456 | 993 | — | 3,064 | |||||||||||||
Income (loss) from continuing operations | (66,445 | ) | 48,562 | (177 | ) | (3,113 | ) | (21,173 | ) | ||||||||||
Discontinued operations | — | — | — | — | — | ||||||||||||||
Net income (loss) | (66,445 | ) | 48,562 | (177 | ) | (3,113 | ) | (21,173 | ) | ||||||||||
Income attributable to noncontrolling interest | — | — | 595 | — | 595 | ||||||||||||||
INCOME (LOSS) ATTRIBUTABLE TO KEY | $ | (66,445 | ) | $ | 48,562 | $ | (772 | ) | $ | (3,113 | ) | $ | (21,768 | ) | |||||
Year Ended December 31, 2012 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Revenues | $ | 15 | $ | 1,867,198 | $ | 165,248 | $ | (72,391 | ) | $ | 1,960,070 | ||||||||
Direct operating expense | — | 1,254,087 | 117,293 | (62,535 | ) | 1,308,845 | |||||||||||||
Depreciation and amortization expense | — | 205,755 | 8,028 | — | 213,783 | ||||||||||||||
General and administrative expense | 1,046 | 216,069 | 24,853 | (11,472 | ) | 230,496 | |||||||||||||
Operating income (loss) | (1,031 | ) | 191,287 | 15,074 | 1,616 | 206,946 | |||||||||||||
Interest expense, net of amounts capitalized | 54,690 | (1,292 | ) | 170 | (2 | ) | 53,566 | ||||||||||||
Other income, net | (5,500 | ) | (1,474 | ) | (3,142 | ) | 3,467 | (6,649 | ) | ||||||||||
Income (loss) from continuing operations before taxes | (50,221 | ) | 194,053 | 18,046 | (1,849 | ) | 160,029 | ||||||||||||
Income tax expense | (48,893 | ) | (3,385 | ) | (5,073 | ) | (1 | ) | (57,352 | ) | |||||||||
Income (loss) from continuing operations | (99,114 | ) | 190,668 | 12,973 | (1,850 | ) | 102,677 | ||||||||||||
Loss from discontinued operations | — | — | (93,568 | ) | — | (93,568 | ) | ||||||||||||
Net income (loss) | (99,114 | ) | 190,668 | (80,595 | ) | (1,850 | ) | 9,109 | |||||||||||
Income attributable to noncontrolling interest | — | — | 1,487 | — | 1,487 | ||||||||||||||
INCOME (LOSS) ATTRIBUTABLE TO KEY | $ | (99,114 | ) | $ | 190,668 | $ | (82,082 | ) | $ | (1,850 | ) | $ | 7,622 | ||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 2011 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Revenues | $ | 707 | $ | 1,660,801 | $ | 106,289 | $ | (38,586 | ) | $ | 1,729,211 | ||||||||
Direct operating expense | — | 1,036,071 | 76,140 | (27,021 | ) | 1,085,190 | |||||||||||||
Depreciation and amortization expense | — | 160,884 | 6,062 | — | 166,946 | ||||||||||||||
General and administrative expense | 1,178 | 211,207 | 18,550 | (7,636 | ) | 223,299 | |||||||||||||
Operating income (loss) | (471 | ) | 252,639 | 5,537 | (3,929 | ) | 253,776 | ||||||||||||
Loss on early extinguishment of debt | 46,451 | — | — | — | 46,451 | ||||||||||||||
Interest expense, net of amounts capitalized | 42,551 | (1,713 | ) | 13 | (2 | ) | 40,849 | ||||||||||||
Other (income) expense, net | (6,351 | ) | 1,772 | (638 | ) | (3,760 | ) | (8,977 | ) | ||||||||||
Income (loss) from continuing operations before taxes | (83,122 | ) | 252,580 | 6,162 | (167 | ) | 175,453 | ||||||||||||
Income tax (expense) benefit | (61,130 | ) | (3,287 | ) | 300 | — | (64,117 | ) | |||||||||||
Income (loss) from continuing operations | (144,252 | ) | 249,293 | 6,462 | (167 | ) | 111,336 | ||||||||||||
Loss from discontinued operations | — | — | (10,681 | ) | — | (10,681 | ) | ||||||||||||
Net income (loss) | (144,252 | ) | 249,293 | (4,219 | ) | (167 | ) | 100,655 | |||||||||||
Loss attributable to noncontrolling interest | — | — | (806 | ) | — | (806 | ) | ||||||||||||
INCOME (LOSS) ATTRIBUTABLE TO KEY | $ | (144,252 | ) | $ | 249,293 | $ | (3,413 | ) | $ | (167 | ) | $ | 101,461 | ||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2013 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Net cash provided by operating activities | $ | — | $ | 222,364 | $ | 6,279 | $ | — | $ | 228,643 | |||||||||
Cash flows from investing activities: | |||||||||||||||||||
Capital expenditures | — | (157,443 | ) | (6,694 | ) | — | (164,137 | ) | |||||||||||
Acquisition of the 50% noncontrolling interest in Geostream | — | (14,600 | ) | — | — | (14,600 | ) | ||||||||||||
Intercompany notes and accounts | — | (68,597 | ) | — | 68,597 | — | |||||||||||||
Other investing activities, net | — | 17,856 | — | — | 17,856 | ||||||||||||||
Net cash used in investing activities | — | (222,784 | ) | (6,694 | ) | 68,597 | (160,881 | ) | |||||||||||
Cash flows from financing activities: | |||||||||||||||||||
Repayment of capital lease obligations | — | (393 | ) | — | — | (393 | ) | ||||||||||||
Proceeds from borrowings on revolving credit facility | 220,000 | — | — | — | 220,000 | ||||||||||||||
Repayments on revolving credit facility | (300,000 | ) | — | — | — | (300,000 | ) | ||||||||||||
Payment of deferred financing costs | (69 | ) | — | — | — | (69 | ) | ||||||||||||
Repurchases of common stock | (3,196 | ) | — | — | — | (3,196 | ) | ||||||||||||
Intercompany notes and accounts | 68,597 | — | — | (68,597 | ) | — | |||||||||||||
Other financing activities, net | (1,834 | ) | — | — | — | (1,834 | ) | ||||||||||||
Net cash used in financing activities | (16,502 | ) | (393 | ) | — | (68,597 | ) | (85,492 | ) | ||||||||||
Effect of changes in exchange rates on cash | — | — | 87 | — | 87 | ||||||||||||||
Net decrease in cash and cash equivalents | (16,502 | ) | (813 | ) | (328 | ) | — | (17,643 | ) | ||||||||||
Cash and cash equivalents at beginning of period | 39,617 | 1,601 | 4,731 | — | 45,949 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 23,115 | $ | 788 | $ | 4,403 | $ | — | $ | 28,306 | |||||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2012 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Net cash provided by operating activities | $ | — | $ | 349,208 | $ | 20,452 | $ | — | $ | 369,660 | |||||||||
Cash flows from investing activities: | |||||||||||||||||||
Capital expenditures | — | (430,045 | ) | (17,115 | ) | — | (447,160 | ) | |||||||||||
Intercompany notes and accounts | 676 | 49,926 | — | (50,602 | ) | — | |||||||||||||
Other investing activities, net | (676 | ) | 19,127 | — | — | 18,451 | |||||||||||||
Net cash used in investing activities | — | (360,992 | ) | (17,115 | ) | (50,602 | ) | (428,709 | ) | ||||||||||
Cash flows from financing activities: | |||||||||||||||||||
Proceeds from long term debt | 205,000 | — | — | — | 205,000 | ||||||||||||||
Repayments of capital lease obligations | — | (1,959 | ) | — | — | (1,959 | ) | ||||||||||||
Proceeds from borrowings on revolving credit facility | 275,000 | — | — | — | 275,000 | ||||||||||||||
Repayments on revolving credit facility | (405,000 | ) | — | — | — | (405,000 | ) | ||||||||||||
Payment of deferred financing cost | (4,597 | ) | — | — | — | (4,597 | ) | ||||||||||||
Repurchases of common stock | (7,519 | ) | — | — | — | (7,519 | ) | ||||||||||||
Intercompany notes and accounts | (49,926 | ) | (676 | ) | — | 50,602 | — | ||||||||||||
Other financing activities, net | 4,986 | 8,035 | — | — | 13,021 | ||||||||||||||
Net cash provided by financing activities | 17,944 | 5,400 | — | 50,602 | 73,946 | ||||||||||||||
Effect of changes in exchange rates on cash | — | — | (4,391 | ) | — | (4,391 | ) | ||||||||||||
Net increase (decrease) in cash | 17,944 | (6,384 | ) | (1,054 | ) | — | 10,506 | ||||||||||||
Cash and cash equivalents at beginning of period | 21,673 | 7,985 | 5,785 | — | 35,443 | ||||||||||||||
Cash and cash equivalents at end of period | $ | 39,617 | $ | 1,601 | $ | 4,731 | $ | — | $ | 45,949 | |||||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2011 | |||||||||||||||||||
Parent Company | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
(in thousands) | |||||||||||||||||||
Net cash provided by operating activities | $ | — | $ | 187,597 | $ | 708 | $ | — | $ | 188,305 | |||||||||
Cash flows from investing activities: | |||||||||||||||||||
Capital expenditures | — | (345,215 | ) | (13,882 | ) | — | (359,097 | ) | |||||||||||
Acquisitions, net of cash acquired | — | (187,058 | ) | — | — | (187,058 | ) | ||||||||||||
Intercompany notes and accounts | — | 278,511 | — | (278,511 | ) | — | |||||||||||||
Other investing activities, net | — | 26,065 | — | — | 26,065 | ||||||||||||||
Net cash used in investing activities | — | (227,697 | ) | (13,882 | ) | (278,511 | ) | (520,090 | ) | ||||||||||
Cash flows from financing activities: | |||||||||||||||||||
Repayments of long-term debt | (421,427 | ) | — | — | — | (421,427 | ) | ||||||||||||
Payment of bond tender premium | (39,082 | ) | — | — | — | (39,082 | ) | ||||||||||||
Proceeds from long term debt | 475,000 | — | — | — | 475,000 | ||||||||||||||
Repayments of capital lease obligations | — | (4,016 | ) | — | — | (4,016 | ) | ||||||||||||
Proceeds from borrowings on revolving credit facility | 418,000 | — | — | — | 418,000 | ||||||||||||||
Repayments on revolving credit facility | (123,000 | ) | — | — | — | (123,000 | ) | ||||||||||||
Payment of deferred financing cost | (16,485 | ) | — | — | — | (16,485 | ) | ||||||||||||
Repurchases of common stock | (5,681 | ) | — | — | — | (5,681 | ) | ||||||||||||
Intercompany notes and accounts | (278,511 | ) | — | — | 278,511 | — | |||||||||||||
Other financing activities, net | 12,859 | 9,128 | 788 | — | 22,775 | ||||||||||||||
Net cash provided by financing activities | 21,673 | 5,112 | 788 | 278,511 | 306,084 | ||||||||||||||
Effect of changes in exchange rates on cash | — | — | 4,516 | — | 4,516 | ||||||||||||||
Net increase (decrease) in cash | 21,673 | (34,988 | ) | (7,870 | ) | — | (21,185 | ) | |||||||||||
Cash and cash equivalents, beginning of period | — | 42,973 | 13,655 | — | 56,628 | ||||||||||||||
Cash and cash equivalents, end of period | $ | 21,673 | $ | 7,985 | $ | 5,785 | $ | — | $ | 35,443 | |||||||||
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain a set of disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
95
Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our principal executive and financial officers have concluded that our disclosure controls and procedures were effective as of the end of such period.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. 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. 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 our 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 generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and 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 financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting can also be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. 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. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.
Management conducted an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, management used the criteria described in 1992 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2013.
Our internal control over financial reporting has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report included herein.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during our last fiscal quarter of 2013, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10 is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.
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ITEM 11. EXECUTIVE COMPENSATION
Item 11 is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Item 12 is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Item 13 is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Item 14 is incorporated by reference to our definitive proxy statement to be filed pursuant to Regulation 14A under the Exchange Act. We expect to file the definitive proxy statement with the SEC within 120 days after the close of the year ended December 31, 2013.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The following financial statements and exhibits are filed as part of this report:
1. Financial Statements — See “Index to Consolidated Financial Statements” at Page 44.
2. We have omitted all financial statement schedules because they are not required or are not applicable, or the required information is shown in the financial statements or the notes to the financial statements.
3. Exhibits
The Exhibit Index, which follows the signature pages to this report and is incorporated by reference herein, sets forth a list of exhibits to this report.
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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.
KEY ENERGY SERVICES, INC.
By: | /s/ J. MARSHALL DODSON | |
J. Marshall Dodson, | ||
Senior Vice President and Chief Financial Officer (As duly authorized officer and Principal Financial Officer) | ||
Date: February 25, 2014
POWER OF ATTORNEY
Each person whose signature appears below hereby constitutes and appoints Richard J. Alario and J. Marshall Dodson, and each of them, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in their capacities and on February 25, 2014.
Signature | Title | |
/s/ RICHARD J. ALARIO | Chairman of the Board of Directors, President and Chief | |
Richard J. Alario | Executive Officer (Principal Executive Officer) | |
/s/ J. MARSHALL DODSON | Senior Vice President and Chief Financial Officer (Principal | |
J. Marshall Dodson | Financial Officer) | |
/s/ MARK A. COX | Vice President and Controller (Principal Accounting Officer) | |
Mark A. Cox | ||
/s/ LYNN R. COLEMAN | Director | |
Lynn R. Coleman | ||
/s/ KEVIN P. COLLINS | Director | |
Kevin P. Collins | ||
/s/ WILLIAM D. FERTIG | Director | |
William D. Fertig | ||
/s/ W. PHILLIP MARCUM | Director | |
W. Phillip Marcum | ||
/s/ RALPH S. MICHAEL, III | Director | |
Ralph S. Michael, III | ||
/s/ WILLIAM F. OWENS | Director | |
William F. Owens | ||
/s/ ROBERT K. REEVES | Director | |
Robert K. Reeves | ||
/s/ MARK H. ROSENBERG | Director | |
Mark H. Rosenberg | ||
/s/ J. ROBINSON WEST | Director | |
J. Robinson West | ||
/s/ ARLENE M. YOCUM | Director | |
Arlene M. Yocum | ||
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EXHIBIT INDEX
Exhibit No. | Description | |
2.1 | Asset Purchase Agreement, dated as of July 2, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on July 6, 2010, File No. 001-08038.) | |
2.2 | Amending Letter Agreement, dated September 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 001-08038) | |
2.3 | Amending Letter Agreement, dated October 1, 2010, by and among Key Energy Pressure Pumping Services, LLC, Key Electric Wireline Services, LLC, Key Energy Services, Inc., Portofino Acquisition Company (now known as Universal Pressure Pumping, Inc.) and Patterson UTI Energy, Inc. (Incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010, File No. 001-08038) | |
2.4 | Purchase and Sale Agreement, dated as of July 23, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.) | |
2.5 | Amendment No. 1 to Purchase and Sale Agreements, dated as of August 27, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.2 of the Company’s Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.) | |
2.6 | Amendment No. 2 to Purchase and Sale Agreements, dated as of September 30, 2010, by and among OFS Holdings, LLC, a Delaware limited liability company, OFS Energy Services, LLC, a Delaware limited liability company, Key Energy Services, Inc., a Maryland corporation, and Key Energy Services, LLC, a Texas limited liability company. (Incorporated by reference to Exhibit 2.3 of the Company’s Current Report on Form 8-K/A filed on October 8, 2010, File No. 001-08038.) | |
2.7 | Agreement and Plan of Merger, dated as of July 13, 2011, by and among Key Energy Services, Inc., Key Merger Sub I, Key Merger Sub II, Edge Oilfield Services, L.L.C., Summit Oilfield Services, L.L.C., the Edge Holders and the Summit Holders (Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed on July 15, 2011, File No. 001-08038.) | |
3.1 | Articles of Restatement of Key Energy Services, Inc. (Incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006, File No. 001-08038.) | |
3.2 | Unanimous consent of the Board of Directors of Key Energy Services, Inc., dated January 11, 2000, limiting the designation of the additional authorized shares to common stock. (Incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 001-08038.) | |
3.3 | Sixth Amended and Restated By-laws of Key Energy Services, Inc. as amended through November 14, 2013 (Incorporated by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K filed on November 19, 2013, File No. 001-08038.) | |
100
Exhibit No. | Description | |
4.1.1 | Indenture, dated as of November 29, 2007, among Key Energy Services, Inc., the guarantors party thereto and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.) | |
4.1.2 | First Supplemental Indenture, dated as of January 22, 2008, among Key Marine Services, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 001-08038.) | |
4.1.3 | Second Supplemental Indenture, dated as of January 13, 2009, among Key Energy Mexico, LLC, the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.6 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-08038.) | |
4.1.4 | Third Supplemental Indenture, dated as of July 31, 2009, among Key Energy Services California, Inc., the existing Guarantors and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.5 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.) | |
4.1.5 | Fourth Supplemental Indenture dated as of March 1, 2011 by and among Key Energy Services, Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on March 1, 2011, File No. 001-08038.) | |
4.1.6 | Fifth Supplemental Indenture dated as of January 17, 2013 by and among Key Energy Services, Inc., the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
4.2.1 | Indenture, dated as of March 4, 2011, among Key Energy Services, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on March 4, 2011, File No. 001-08038.) | |
4.2.2 | First Supplemental Indenture, dated as of March 4, 2011, among Key Energy Services, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on March 4, 2011, File No. 001-08038.) | |
4.2.3 | Amended First Supplemental Indenture, dated as of March 8, 2012, by and among Key Energy Services, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K filed March 9, 2012, File No. 001-08038.) | |
4.2.4 | Second Supplemental Indenture, dated as of January 17, 2013, among Key Energy Services, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.2.4 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
4.2.5 | Form of global note for 6.750% Senior Notes due 2021 (Incorporated by reference from Exhibit A to Exhibit 4.8). | |
4.2.6 | Form of global note for 6.750% Senior Notes due 2021. (Incorporated by reference from Exhibit A to Rule 144A/Regulation S Appendix to Exhibit 4.1 of the Company's Current Report on Form 8-K filed March 9, 2012, File No. 001-08038.) | |
4.2.7* | Registration Rights Agreement with MHR Group dated July 26, 2012. | |
101
Exhibit No. | Description | |
10.1.1† | Key Energy Services, Inc. 2007 Equity and Cash Incentive Plan. (Incorporated by Reference to Appendix A of the Company’s Schedule 14A Proxy Statement filed on November 1, 2007, File No. 001-08038.) | |
10.1.2† | Form of Nonstatutory Stock Option Agreement under 2007 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-08038.) | |
10.1.3† | Form of Restricted Stock Award Agreement under 2007 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 16, 2008, File No. 001-08038.) | |
10.2.1† | Key Energy Services, Inc. 2009 Equity and Cash Incentive Plan. (Incorporated by Reference to Appendix A of the Company’s Schedule 14A Proxy Statement filed on April 16, 2009, File No. 001-08038.) | |
10.2.2† | Form of Restricted Stock Award Agreement under 2009 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.) | |
10.2.3† | Form of Nonqualified Stock Option Agreement under 2009 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 001-08038.) | |
10.2.4† | Form of Restricted Stock Unit Award Agreement (Canadian) under 2009 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.2.4 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
10.2.5† | Form of Restricted Stock Unit Award Agreement (Non-Canadian) under 2009 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.2.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
10.2.6† | Form of Performance Unit Award Agreement under the Key Energy Services, Inc. 2009 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K filed January 20, 2012, File No. 001-08038.) | |
10.3† | Key Energy Services, Inc. 2012 Performance Unit Plan. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed January 20, 2012, File No. 001-08038.) | |
10.4.1† | Key Energy Services, Inc. 2012 Equity and Cash Incentive Plan. (Incorporated by reference to Appendix A of the Company's Proxy Statement on Schedule 14A filed on April 11, 2012, File No. 001-08038.) | |
10.4.2† | Form of Restricted Stock Award Agreement under 2012 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed January 25, 2013, File No. 001-08038.) | |
10.4.3† | Form of Performance Unit Award Agreement under 2012 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.2 of the Company's Current Report on Form 8-K filed January 25, 2013, File No. 001-08038.) | |
10.4.4† | Form of Nonstatutory Stock Option Agreement under 2012 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.4.4 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
10.4.5† | Form of Restricted Stock Unit Award Agreement (Canadian) under 2012 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.4.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
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Exhibit No. | Description | |
10.4.6† | Form of Restricted Stock Unit Award Agreement (Non-Canadian) under 2012 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
10.5† | Key Energy Services, Inc. 2013 Performance Unit Plan. (Incorporated by reference to Exhibit 10.5 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2012, File No. 001-0838.) | |
10.6† | Restated Employment Agreement, dated effective as of December 31, 2007, among Richard J. Alario, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.) | |
10.7† | Employment Agreement, dated as of March 26, 2009, by and between Trey Whichard and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 1, 2009, File No. 001-08038.) | |
10.8† | Restated Employment Agreement, dated effective as of December 31, 2007, among Newton W. Wilson III, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.) | |
10.9† | Amended and Restated Employment Agreement, dated October 22, 2008, between Kimberly R. Frye, Key Energy Services, Inc. and Key Energy Shared Services, LLC. (Incorporated by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-08038.) | |
10.10† | Restated Employment Agreement dated effective as of December 31, 2007, among Kim B. Clarke, Key Energy Services, Inc. and Key Energy Shared Services, LLC (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K filed on January 7, 2008, File No. 001-08038.) | |
10.11† | Employment Agreement, dated effective as of March 25, 2013, among J. Marshall Dodson and Key Energy Services, LLC (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated March 28, 2013, File No. 001-08038.) | |
10.12† | Form of Amendment to Employment Agreement, in the form executed on March 29, 2010, by and between Key Energy Services, Inc., Key Energy Shared Services, LLC, and each of Richard J. Alario, T.M. Whichard III, Newton W. Wilson III, Kim B. Clarke and Kim R. Frye. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 1, 2010, File No. 001-08038.) | |
10.13.1 | Credit Agreement, dated as of November 29, 2007, among Key Energy Services, Inc., each lender from time to time party thereto, Bank of America, N.A., as Paying Agent, Co-Administrative Agent, Swing Line Lender and L/C Issuer, and Wells Fargo Bank, National Association, as Co-Administrative Agent, Swing Line Lender and L/C Issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on November 30, 2007, File No. 001-08038.) | |
10.13.2 | Amendment No. 1 to Credit Agreement, dated as of October 27, 2009, among Key Energy Services, Inc., each lender from time to time party thereto, Bank of America, N.A., as Paying Agent, Co-Administrative Agent, Swing Line Lender and L/C Issuer, and Wells Fargo Bank, National Association, as Co-Administrative Agent, Swing Line Lender and L/C Issuer. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on October 29, 2009, File No. 001-08038.) | |
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Exhibit No. | Description | |
10.14.1 | Credit Agreement, dated as of March 31, 2011, among Key Energy Services, Inc., each of the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, N.A., as syndication agent, and Capital One, N.A. and Wells Fargo Bank, N.A., as co-documentation agents. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 5, 2011, File No. 001-08038.) | |
10.14.2 | First Amendment to Credit Agreement, dated as of July 27, 2011, among Key Energy Services, Inc., each of the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America, N.A., as syndication agent, and Capital One, N.A., Wells Fargo Bank, N.A., Credit Agricole Corporate and Investment Bank and DnB NOR Bank ASA, as co-documentation agents (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on July 29, 2011, File No. 001-08038.) | |
21* | Significant Subsidiaries of the Company. | |
23* | Consent of Independent Registered Public Accounting Firm. | |
31.1* | Certification of CEO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act. of 2002. | |
31.2* | Certification of CFO pursuant to Securities Exchange Act Rules 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32* | Certification of CEO and CFO pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
101* | Interactive Data File. | |
† | Indicates a management contract or compensatory plan, contract or arrangement in which any Director or any Executive Officer participates. | |
* | Filed herewith. | |
104