10-K 1 keg10-k12312013.htm 10-K KEG 10-K 12/31/2013
 
 
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;

10


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.

11


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

12


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

14


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.”

21


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
)
 

22


 
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.”

23


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.

24


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.

25


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.


26


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.

27


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.

28


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.

29


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


30


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.

31


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

32


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

34


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.

35


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.

36


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;

37


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

38


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.

39


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.

40


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.

41


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

42


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.


43


ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Key Energy Services, Inc. and Subsidiaries
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 

44


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

45


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

46


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

47


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
)