10-K 1 a201310k.htm 10-K 2013 10K

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark one)
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 1-8182
PIONEER ENERGY SERVICES CORP.
(Exact name of registrant as specified in its charter)
_____________________________________________ 
TEXAS
 
74-2088619
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification Number)
 
 
 
1250 N.E. Loop 410, Suite 1000
San Antonio, Texas
 
78209
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code: (855) 884-0575
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, $0.10 par value
 
NYSE
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨ No  þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the 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 Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
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  o
 
 
 
Accelerated filer  þ
Non-accelerated filer o
 
(Do not check if a smaller reporting company)
 
Smaller reporting company o
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 registrant’s common stock held by nonaffiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the New York Stock Exchange (NYSE) on June 30, 2013) was approximately $406.8 million.
As of January 30, 2014, there were 62,537,694 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant’s 2014 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.
 



TABLE OF CONTENTS
 
 
 
Page
 
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
 
Item 15.




PART I
INTRODUCTORY NOTE
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.
In addition, various statements contained in this Annual Report on Form 10-K, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Such forward-looking statements appear in Item 1—“Business” and Item 3—“Legal Proceedings” in Part I of this report; in Item 5—“Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities,” Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A—“Quantitative and Qualitative Disclosures About Market Risk” and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report; and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and we caution you not to place undue reliance on them. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
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general economic and business conditions and industry trends;
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levels and volatility of oil and gas prices;
•
decisions about exploration and development projects to be made by oil and gas exploration and production companies;
•
economic cycles and their impact on capital markets and liquidity;
•
the continued demand for drilling services or production services in the geographic areas where we operate;
•
the highly competitive nature of our business;
•
our future financial performance, including availability, terms and deployment of capital;
•
future compliance with covenants under our senior secured revolving credit facility and our senior notes;
•
the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry;
•
changes in technology and improvements in our competitors' equipment;
•
the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components;
•
the continued availability of qualified personnel;
•
the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions; and
•
changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment.
We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this report or elsewhere. We have discussed many of these factors in more detail elsewhere in this report. Other unpredictable or unknown factors could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements.

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We undertake no duty to update or revise any forward-looking statements, except as required by applicable securities laws and regulations. We advise our security holders that they should (1) be aware that unpredictable or unknown factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the risk factors set forth in Item 1A—“Risk Factors.”

Item 1.
Business
General
Pioneer Energy Services (formerly called "Pioneer Drilling Company") was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. In March 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired the coiled tubing services business of Go-Coil, L.L.C. ("Go-Coil") to expand our existing production services offerings.
In 2012, we changed our company name from "Pioneer Drilling Company" to "Pioneer Energy Services Corp." Our common stock trades on the New York Stock Exchange under the ticker symbol "PES." Our new name reflects our strategy to expand our service offerings beyond drilling services, which has been our core, legacy business. Pioneer Energy Services provides drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. We also provide coiled tubing and wireline services offshore in the Gulf of Mexico. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our clients.
We currently conduct our operations through two operating segments: our Drilling Services Segment and our Production Services Segment. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.
•
Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
14

West Texas
 
18

North Dakota
 
11

Utah
 
7

Appalachia
 
4

Colombia
 
8

 
 
62

In early 2011, we began construction of ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, based on term contracts. We deployed seven of these new-build drilling rigs during 2012, and deployed the final three in early 2013. All of our new-build drilling rigs are currently operating in shale or unconventional plays under long-term drilling contracts.

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During the second quarter of 2013, we sold two mechanical drilling rigs that were previously idle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. In September 2013, we decided to sell eight of our mechanical drilling rigs, for which we recognized an impairment charge of $9.2 million dollars during the third quarter. All eight drilling rigs were classified as held for sale at September 30, 2013 and were sold in late October 2013. We did not incur any additional gain or loss upon the sale of these rigs.
As of December 31, 2013, 50 of our 62 drilling rigs are earning revenues under drilling contracts, 39 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working. The remaining rig will begin working under its term contract after it is upgraded from 1,000 horsepower to 1,500 horsepower, which we expect will be completed by the end of the first quarter of 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.
•
Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:
•
Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of December 31, 2013, we operate ninety-nine 550 horsepower rigs and ten 600 horsepower rigs through 11 locations, mostly in the Gulf Coast and ArkLaTex regions, though we also have 14 rigs in North Dakota.
•
Wireline Services. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. To complete a well, the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. As of December 31, 2013, we operate through 24 locations with a fleet of 119 wireline units.
•
Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of December 31, 2013, our coiled tubing business consists of nine onshore and four offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.

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•
Fishing and Rental Services. During drilling operations, oil and gas exploration and production companies frequently rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing and fishing tools. We provide rental services out of three locations in Texas and Oklahoma. As of December 31, 2013 our fishing and rental tools have a gross book value of $17.3 million.

Pioneer Energy Services' corporate office is located at 1250 NE Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (855) 884-0575 and our website address is www.pioneeres.com. We make available free of charge though our website 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 material is electronically filed with the Securities and Exchange Commission (SEC). Information on our website is not incorporated into this report or otherwise made part of this report.
Industry Overview
Demand for oilfield services offered by our industry is a function of our clients’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected oil and natural gas prices.
From late 2008 and into late 2009, there was substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In response, our clients curtailed their drilling programs and reduced their production activities, particularly in natural gas producing regions, which resulted in a decrease in demand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in the capital markets and access to financing was limited. These conditions adversely affected our business environment.
With generally increasing oil prices in 2010 and 2011, exploration and production companies increased their exploration and production spending and industry equipment utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. During 2012, modest increases in exploration and production spending resulted in modest increases in industry equipment utilization and revenue rates during 2012, as compared to 2011. Despite generally increasing oil prices during 2013, industry equipment utilization levels have been slightly lower than industry levels during 2012, which is partially due to the advancements in technology and efficiency of drilling rigs. In addition, excess natural gas production in the U.S. shale regions continues to depress natural gas prices. If oil and natural gas prices decline, then industry equipment utilization and revenue rates could decrease domestically and in Colombia.
Colombia has experienced significant growth in oil production since 2008 largely due to the infusion of capital by international exploration and production companies as a result of the country's improved regulation and security. Historically, Colombian oil prices have generally trended in line with West Texas Intermediate (WTI) oil prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the impact on demand in North America. Demand for drilling and production services in Colombia is largely dependent upon the national oil company's long-term exploration and production programs.

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The trends in spot prices of WTI crude oil and Henry Hub natural gas, and the resulting trends in domestic land rig counts (per Baker Hughes) and domestic well servicing rig counts (per Guiberson/Association of Energy Service Companies) over the last five years are illustrated in the graphs below.
As shown in the charts above, the trends in industry rig counts are influenced by fluctuations in oil and natural gas prices, which affect the levels of capital and operating expenditures made by our clients.
Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or operating expenditure.
Capital expenditures by oil and gas exploration and production companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely deferred until prices return to an acceptable level.
In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field and are generally evaluated according to a simple short-term payout criterion that is far less dependent on commodity price forecasts.
Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.
Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.
For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.

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Competitive Strengths
Our competitive strengths include:
•
One of the Leading Providers in the Most Attractive Regions. Our 62 drilling rigs operate in many of the most attractive producing regions in the Americas, including the Bakken, Marcellus and Eagle Ford shales, and Permian and Uintah Basins, as well as Colombia. Our drilling rigs are located in six divisions throughout the United States and Colombia, diversifying our geographic exposure and limiting the impact of any regional slowdown. We believe the varied capabilities of our drilling rigs make them well suited to these areas where the optimal rig configuration is dictated by local geology and market conditions.
•
High Quality Assets. We have purchased 40 new-build drilling rigs since 2001, ten of which are new-build AC drilling rigs which we constructed during 2011 to 2013. Approximately 74% of our drilling rigs are capable of drilling horizontal wells and the majority of these rigs are also equipped with either a walking or skidding system for pad drilling. Approximately 74% of our production services assets have been built since 2007, and all of our well servicing rigs have at least 550 horsepower. We believe that our modern and well maintained fleet allows us to realize higher contract and utilization rates because we are able to offer our clients equipment that is more reliable and requires less downtime than older equipment.
•
Provide Services Throughout the Well Life Cycle. By offering our clients both drilling and production services, we capture revenue throughout the life cycle of a well and diversify our business. Our Drilling Services Segment performs work prior to initial production, and our Production Services Segment provides services such as logging, completion, perforation, workover and maintenance throughout the productive life of a well. We also provide certain end-of-well-life activities such as plugging and abandonment. Drilling and production services activity have historically exhibited different degrees of demand fluctuation, and we believe the diversity of our services reduces our exposure to decreases in demand for any single service activity. Further, the diversity of our service offerings enables us to cross-sell our services, benefiting our clients, allowing us to generate more business from existing clients and increasing our profits as we expand our services within existing markets.
•
Excellent Safety Record. Our safety program called “LiveSafe” focuses on creating an environment where everyone is committed to and recognizes the possibility of always working without incident or injury. We believe that by building strong relationships among our people we can achieve an excellent safety record. Our excellent safety record and reputation are critical to winning new business and expanding our relationships with existing clients. Our commitment to safety helps us to keep our employees safe and reduces our business risk.
•
Experienced Management Team. We believe that important competitive factors in establishing and maintaining long-term client relationships include having an experienced and skilled management team and maintaining employee continuity. Our CEO, Wm. Stacy Locke, joined Pioneer in 1995 as President and has 35 years of industry experience. Our two segment presidents, F.C. “Red” West and Joe Eustace, have 85 years of combined oilfield services experience. Our management team has operated through numerous oilfield services cycles and provides us with valuable long-term experience and a detailed understanding of client requirements. We also seek to maximize employee continuity and minimize employee turnover by maintaining modern equipment, a strong safety record, ongoing growth and competitive compensation. We have devoted, and will continue to devote, substantial resources to our employee safety and training programs and maintaining low employee turnover.
•
Longstanding and Diversified Clients. We maintain long-standing, high quality client relationships with a diverse group of large independent oil and gas exploration and production companies including Whiting Petroleum Corporation, which accounted for approximately 13% of our 2013 consolidated revenues, Apache Corporation, Hess Corporation, Pioneer Natural Resources and Continental Resources. We also maintain a good relationship with Ecopetrol, which accounted for approximately

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11% of our 2013 consolidated revenues. We believe our relationships with our clients are excellent and offer numerous opportunities for future growth.
Strategy
In past years, our strategy was to become a premier land drilling and production services company through steady and disciplined growth. We executed this strategy by acquiring and building a high quality drilling rig fleet and production services business which we operate in the most attractive drilling markets throughout the United States and in Colombia. Our long-term strategy is to maintain and leverage our position as a leading land drilling and production services company, continue to expand our relationships with existing clients, expand our client base in the areas where we currently operate and further enhance our geographic diversification through selective expansion. The key elements of this long-term strategy are focused on our:
•
Competitive Position in the Most Attractive Domestic Markets. Shale plays and non-shale oil or liquid rich environments are increasingly important to domestic hydrocarbon production and not all drilling rigs are capable of successfully drilling in these unconventional opportunities. We are currently operating in unconventional areas in the Bakken, Marcellus and Eagle Ford shales and Permian and Uintah Basins. All of the ten drilling rigs we recently constructed are currently operating in domestic shale and unconventional plays. Additionally, in recent years, we have added significant capacity to our production services fleets, which we believe are well positioned to capitalize on increased shale development.
•
Exposure to Oil and Liquids Rich Natural Gas Drilling Activity. We believe that our flexible drilling and production services fleets allow us to pursue varied opportunities, enabling us to focus on a favorable mix of natural gas, oil and liquids rich natural gas activity. In recent years, we have intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions and we continue to actively seek contracts with oil-focused producers. As of December 31, 2013, approximately 92% of our working drilling rigs and 78% of our production services assets are operating on wells that are targeting or producing oil or liquids rich natural gas.
•
International Presence. In 2007, we began operating in Colombia after a comprehensive review of international opportunities wherein we determined that Colombia offered an attractive mix of favorable business conditions, political stability, and a long-term commitment to expanding national oil and gas production. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working, while the remaining rig will begin working under its term contract after certain upgrades are completed during the first quarter of 2014.
•
Growth Through Select Capital Deployment. We have historically invested in the growth of our business by strategically upgrading our existing assets, selectively engaging in new-build opportunities, and through selective acquisitions. We have continued to make significant investments in the growth of our business over the past several years. For example, on December 31, 2011, we acquired a coiled tubing services business to expand our existing production services offerings. We have also added significant capacity to our other production services fleets through the addition of 56 wireline units and 35 well servicing rigs since the beginning of 2010. In 2011, we began construction, based on term contracts, of ten new-build AC drilling rigs, all of which are currently operating in domestic shale or unconventional plays.
With these capital projects recently completed, we have shifted our near-term focus toward reducing capital expenditures and using excess cash flows from operations to reduce outstanding debt balances and reposition ourselves for future long-term growth. Management efforts are currently focused on stringent cost control measures, the evaluation of nonstrategic or under-performing assets for potential liquidation and continued emphasis on the execution and performance of our core businesses. We believe this near-term strategy will position us to take advantage of future business opportunities and continue our long-term growth strategy.

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Overview of Our Segments and Services
Drilling Services Segment
There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment. Generally, drilling rigs operate with crews of five to six persons.
Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.
Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a traveling block and hook assembly that attaches to the rotating system, a mechanism known as the drawworks, a drilling line and ancillary equipment. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydraulic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.
The rotating equipment from top to bottom consists of a top drive or a swivel, the kelly, and kelly bushing, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the top drive or swivel and the drill bit as the drill stem. In a top drive system, the top drive hangs from a hook at the bottom of the traveling block. The top drive has a passageway for drilling mud to get into the drill pipe, and it has a heavy-duty electric motor connected to a threaded drive shaft which connects to and rotates the drill pipe. In a kelly drive system, the swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and both are threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.
Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the cost incurred and equipment used in drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points, the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud

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pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.
Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well.
Technological advancements and trends in our industry affect the demand for certain types of equipment. In a continuing effort to improve our drilling rig fleet, we have installed top drives on 46 rigs (with five additional spare top drives available for installation), iron roughnecks on 53 rigs (with sixteen additional spare iron roughnecks available for installation), walking/skidding systems on 28 rigs and automatic catwalks on 31 rigs. These upgrades provide our clients with drilling rigs that have more varied capabilities for drilling in unconventional plays, and they improve our efficiency and safety.
In horizontal drilling, operators can utilize top drives to reach formations that may not be accessible with conventional rotary drilling. Top drives provide maximum torque and rotational control, improved well control and better hole conditioning. In recent years, oil and gas exploration and production companies have increased the use of "pad drilling" whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Walking systems increase efficiency by allowing multiple wells to be drilled on the same pad site and permitting the drilling rig to move between wells while drill pipe remains in the derrick, thus reducing move times and costs. Our walking system enables the drilling rig to move forward, backward, and side to side which affords the operator additional flexibility.
An iron roughneck is a remotely operated pipe handling feature on the rig floor, which is used to help reduce the occurrence of repetitive motion injuries and decrease drill pipe tripping time. An automated catwalk is a drill pipe handling feature used to raise drill pipe, drill collars, casing, and other necessary items to the drilling rig floor. Its function significantly reduces pick up and lay down time, thereby decreasing operator costs for handling casing.
The following table sets forth historical information regarding utilization for our drilling rig fleet:
 
Year ended December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
Average number of operating rigs for the period
68.2

 
65.0

 
69.3

 
71.0

 
70.7

Average utilization rate
84
%
 
87
%
 
73
%
 
59
%
 
41
%
We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs. We rely on various oilfield service companies for major repair work and overhaul of our drilling equipment when needed. We also engage in periodic improvement of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.
As of December 31, 2013, we own a fleet of 40 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the overall cost of rig moves and reduce downtime between rig moves. This is most beneficial to us in periods of high rig utilization and in regions where there is less pad drilling.
We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. Spot market contracts generally provide for the drilling of a single well and typically permit the client to terminate on short notice. During periods of high rig demand, or for our newly constructed rigs, we enter into longer-term drilling contracts.

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Currently, we have contracts with terms of six months to four years in duration. As of December 31, 2013, we have 39 drilling rigs operating under term contracts, which if not renewed at the end of their terms, will expire as follows:
 
 
 
 
Term Contract Expiration by Period
 
 
Total
Term Contracts
 
Within
6 Months
 
6 Months
to 1 Year
 
1 Year to
18 Months
 
18 Months
to 2 Years
 
2 to 4 Years
United States
 
33

 
18

 
4

 
5

 
1

 
5

Colombia
 
6

 
—

 
6

 
—

 
—

 
—

 
 
39

 
18

 
10

 
5

 
1

 
5

As a provider of contract land drilling services, our business and the profitability of our operations depend on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. During periods of reduced drilling activity or excess rig capacity, price competition tends to increase and the profitability of daywork contracts tends to decrease, and in such a competitive price environment, we may be more inclined to enter into turnkey contracts that expose us to greater risk of loss but which offer higher potential contract profitability.
During the last three fiscal years, our drilling contracts have primarily been for daywork drilling and we have not performed any footage contract work. The following table presents, by type of contract, information about the total number of wells we completed for our clients during each of the last three fiscal years.
 
Year ended December 31,
Types of Contracts
2013
 
2012
 
2011
    Daywork
970

 
881

 
655

    Turnkey
27

 
11

 
17

Total number of wells
997

 
892

 
672

Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig and required personnel to our client who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the client bears a large portion of the out-of-pocket drilling costs and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.
Turnkey Contracts. Under a turnkey contract, we agree to drill a well for our client to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our client only after we have performed the terms of the drilling contract in full.
The risks to us under a turnkey contract are substantially greater than on a well drilled on a daywork basis. This is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks we assume. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.

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Footage Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to a turnkey contract, the risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. As with turnkey contracts, we manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a material adverse effect on our financial position and results of operations.
Production Services Segment
Well Servicing. Our well servicing rig fleet provides a range of services, including the completion of newly-drilled wells, maintenance and workover of existing wells, and plugging and abandonment of wells at the end of their useful lives.
Newly drilled wells require completion services to prepare the well for production. Well servicing rigs are frequently used to complete newly drilled wells to minimize the use of higher cost drilling rigs in the completion process. The completion process may involve selectively perforating the well casing in the productive zones to allow oil or gas to flow into the well bore, stimulating and testing these zones and installing the production string and other downhole equipment. The completion process typically requires a few days to several weeks, depending on the nature and type of the completion, and generally requires additional auxiliary equipment. Accordingly, completion services require less well-to-well mobilization of equipment and can provide higher operating margins than regular maintenance work. The demand for completion services is directly related to drilling activity levels, which are sensitive to changes in oil and gas prices.
Regular maintenance is required throughout the life of a well to sustain optimal levels of oil and gas production. Common maintenance services include repairing inoperable pumping equipment in an oil well and replacing defective tubing in a gas well. Our maintenance services involve relatively low-cost, short-duration jobs which are part of normal well operating costs. The need for maintenance does not directly depend on the level of drilling activity, although it is somewhat impacted by short-term fluctuations in oil and gas prices. Accordingly, maintenance services generally experience relatively stable demand; however, when oil or gas prices are too low to justify additional expenditures, operating companies may choose to temporarily shut in producing wells rather than incur additional maintenance costs.
In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. Our well servicing rigs are also used to convert former producing wells to injection wells through which water or carbon dioxide is then pumped into the formation for enhanced oil recovery operations. Workovers also include major subsurface repairs such as repair or replacement of well casing, recovery or replacement of tubing and removal of foreign objects from the well bore. These extensive workover operations are normally performed by a well servicing rig with additional specialized auxiliary equipment, which may include rotary drilling equipment, mud pumps, mud tanks and fishing tools, depending upon the particular type of workover operation. All of our well servicing rigs are designed to perform complex workover operations. A workover may require a few days to several weeks and generally requires additional auxiliary equipment. The demand for workover services is sensitive to oil and gas producers’ intermediate and long-term expectations for oil and gas prices.
Well servicing rigs are also used in the process of permanently closing oil and gas wells no longer capable of producing in economic quantities. Many well operators bid this work on a “turnkey” basis, requiring the service company to perform the entire job, including the sale or disposal of equipment salvaged from the well as part of the compensation received, and complying with state regulatory requirements. Plugging and abandonment work can

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provide favorable operating margins and is less sensitive to oil and gas pricing than drilling and workover activity since well operators must plug a well in accordance with state regulations when it is no longer productive. We perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies.
We typically bill clients for our well servicing on an hourly basis during the period that the rig is actively working. As of December 31, 2013, our fleet of well servicing rigs totaled 109 rigs, which we operate through 11 locations, mostly in the Gulf Coast and ArkLaTex regions, though we also have 14 rigs in North Dakota. Our fleet is among the newest in the industry, consisting of ninety-nine 550 horsepower and ten 600 horsepower rigs capable of working at depths of 20,000 feet.
Wireline Services. Wireline trucks, like well servicing rigs, are utilized throughout the life of a well. Wireline trucks are often used in place of a well servicing rig when there is no requirement to remove tubulars from the well in order to make repairs.
Wireline services typically utilize a single truck equipped with a spool of wireline that is used to lower and raise a variety of specialized tools in and out of the wellbore. Electric wireline contains a conduit that allows signals to be transmitted to or from tools located in the well. These tools can be used to measure pressures and temperatures as well as the condition of the casing and the cement that holds the casing in place. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology.
Other applications for wireline tools include placing equipment in or retrieving equipment from the wellbore, installing bridge plugs, perforating the casing in order to prepare the well for production, or cutting off pipe that is stuck in the well so that the free section can be recovered.
As of December 31, 2013, our wireline services fleet totaled 119 wireline units, including six offshore units, which we operate through 24 locations in Texas, Kansas, Colorado, Utah, Montana, North Dakota, Louisiana, Oklahoma and Wyoming.
Coiled Tubing Services. Coiled tubing is an important element of the production services industry today that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of December 31, 2013, our coiled tubing business consists of nine onshore and four offshore units, which are currently deployed in Texas and Louisiana.
Fishing and Rental Services. Our fishing and rental tool business provides a range of specialized services and equipment that are utilized on a non-routine basis for both drilling and well servicing operations. Drilling and well servicing rigs are equipped with a complement of tools to complete routine operations under normal conditions for most projects in the geographic area where they are employed. When downhole problems develop with drilling or servicing operations, or conditions require non-routine equipment, our clients will usually rely on a provider of rental and fishing tools to augment equipment that is provided with a typical drilling or well servicing rig package. The important rental tools that we offer include air drilling equipment, foam units, power swivels, and blowout preventers.
The term “fishing” applies to a wide variety of downhole operations designed to correct a problem that has developed when drilling or servicing a well. Often, the problem involves equipment that has become lodged in the well and cannot be removed without special equipment. Our clients employ our technicians and our tools that are specifically suited to retrieve the trapped equipment, or “fish,” in order for operations to resume.
Seasonality
All our production services operations are impacted by seasonal factors. Our business can be negatively impacted during the winter months due to inclement weather, fewer daylight hours, and holidays. Because our well

12

servicing rigs, wireline units and coiled tubing units are mobile, during periods of heavy snow, ice or rain, we may not be able to move our equipment between locations.
Clients
We provide drilling and production services to numerous major and independent oil and gas exploration and production companies that are active in the geographic areas in which we operate. The following table shows our three largest clients as a percentage of our total revenue for each of our last three fiscal years. 
 
Total Revenue
Percentage
Fiscal year ended December 31, 2013
 
Whiting Petroleum Company
12.6
%
Ecopetrol
10.7
%
Apache Corporation
5.9
%
 
 
Fiscal year ended December 31, 2012
 
Whiting Petroleum Company
10.1
%
Ecopetrol
9.7
%
Apache Corporation
5.5
%
 
 
Fiscal year ended December 31, 2011
 
Ecopetrol
13.5
%
Whiting Petroleum Corporation
10.6
%
Talisman Energy USA, Inc.
3.6
%
Competition
Drilling Services Segment
We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.
The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal competitors are Helmerich & Payne, Inc., Precision Drilling Trust, Patterson-UTI Energy, Inc. and Nabors Industries, Ltd. In addition to pricing and rig availability, we believe the following factors are also important to our clients in determining which drilling contractors to select:
•
the type and condition of each of the competing drilling rigs;
•
the mobility and efficiency of the rigs;
•
the quality of service and experience of the rig crews;
•
the safety records of our company;
•
the offering of ancillary services; and
•
the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, our safety record, our ability to offer ancillary services, the experience of our rig crews and the quality of service we provide to differentiate us from our competitors.

13

Drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and make any improvement in demand for drilling rigs in a particular region short-lived.
Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
•
better withstand industry downturns;
•
compete more effectively on the basis of price and technology;
•
better retain skilled rig personnel; and
•
build new rigs or acquire and refurbish existing rigs and place them into service more quickly than us in periods of high drilling demand.
Production Services Segment
The market for production services is highly competitive. Competition is influenced by such factors as price, capacity, availability of work crews, type and condition of equipment and reputation and experience of the service provider. We believe that an important competitive factor in establishing and maintaining long-term client relationships is having an experienced, skilled and well-trained work force. In recent years, many of our larger clients have placed increased emphasis on the safety performance and quality of the crews, equipment and services provided by their contractors. We have devoted, and will continue to devote, substantial resources toward employee safety and training programs. Although we believe clients consider all of these factors, price is generally the primary factor in determining which service provider is awarded the work. However, we believe that most clients are willing to pay a slight premium for the quality and efficient service we provide.
The largest well servicing providers that we compete with are Key Energy Services, Basic Energy Services, Nabors Industries, Superior Energy Services, Inc. and CC Forbes. In addition, there are numerous smaller companies that compete in our well servicing markets.
The wireline market is dominated by Schlumberger Ltd. and Halliburton Company. These companies have a substantially larger asset base than we do and operate in all major U.S. oil and natural gas producing basins. Other competitors include Weatherford International, Baker Hughes, Superior Energy Services, Basic Energy Services, and C&J Energy Services. The market for wireline services is very competitive, but historically we have competed effectively with our competitors based on performance and strong client service.
The market for coiled tubing has increased due to the growth in deep well and horizontal drilling. Our primary competitors in the coiled tubing services market include Schlumberger Ltd., Baker Hughes, Halliburton Company, Key Energy Services, RPC Inc. and Superior Energy Services, Inc. In addition, numerous small companies compete in our coiled tubing services markets in the United States.
The fishing and rental tools market is fragmented compared to our other product lines. Companies that provide fishing services generally compete based on the reputation of their fishing tool operators and their relationships with clients. Competition for rental tools is sometimes based on price; however, in most cases, when a client chooses a specific fishing tool operator for a particular job, then the necessary rental equipment will be part of that job as well. Our primary competitors in this service market include Baker Hughes, Weatherford International, Basic Energy Services, Key Energy Services, Quail Tools (owned by Parker Drilling) and Knight Oil Tools.
The need for well servicing, wireline, coiled tubing, and fishing and rental services fluctuates primarily in relation to the price (or anticipated price) of oil and natural gas, which in turn is driven by the supply of and demand for oil and natural gas. Generally, as supply of these 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.

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The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of domestic and international oil and gas exploration and development activity, as well as the equipment capacity in any particular region. For a more detailed discussion, see Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Raw Materials
The materials and supplies we use in our drilling and production services operations include fuels to operate our equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to clients. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in obtaining drilling equipment or supplies could limit our drilling operations and jeopardize our relations with clients. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our drilling rigs, which could have a material adverse effect on our financial condition and results of operations.
Operating Risks and Insurance
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:
•
blowouts;
•
fires and explosions;
•
loss of well control;
•
collapse of the borehole;
•
lost or stuck drill strings; and
•
damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
•
suspension of drilling operations;
•
damage to, or destruction of, our property and equipment and that of others;
•
personal injury and loss of life;
•
damage to producing or potentially productive oil and gas formations through which we drill; and
•
environmental damage.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our clients. However, clients who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a client to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
Our current insurance coverage includes property insurance on our rigs, drilling equipment, production services equipment and real property. Our insurance coverage for property damage to our rigs, drilling equipment and production services equipment is based on our estimates of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on drilling rigs of $500,000 per occurrence ($750,000 deductible

15

for rigs with an insured value greater than $10 million), and a deductible on production services equipment of $250,000 per occurrence. Our third-party liability insurance coverage is $76 million per occurrence and in the aggregate, with a deductible of $260,000 per occurrence. We also carry insurance coverage for pollution liability up to $20 million with a deductible of $250,000. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.
In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey contract drilling operations. This insurance covers “control-of-well,” including blowouts above and below the surface, redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million, $10 million, $15 million or $20 million, subject to a deductible of $150,000 or $250,000, depending on the area in which the well is drilled and its target depth. This policy also provides care, custody and control insurance, with a limit of $1 million, subject to a $100,000 deductible.
Employees
We currently have approximately 3,650 employees. The majority of our employees work in operations for our Drilling Services Segment and Production Services Segment and are primarily compensated on an hourly basis. The number of employees in operations fluctuates depending on the utilization of our drilling rigs, well servicing rigs, wireline units and coiled tubing units at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.
Our operations require the services of employees having the technical training and experience necessary to achieve proper operational standards. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining employees in our operations, shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material adverse effect on our financial condition and results of operations.
Facilities
We lease our corporate office facilities located at 1250 N.E. Loop 410, Suite 1000 San Antonio, Texas 78209. We conduct our business operations through 67 other real estate locations, of which we own 15, in the United States (Texas, Oklahoma, Colorado, Utah, Montana, North Dakota, Pennsylvania, Wyoming, Mississippi, Arkansas, Louisiana and Kansas) and internationally in Colombia. These real estate locations are primarily used for regional offices and storage and maintenance yards.
Governmental Regulation
Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands and coastal areas of the Gulf of Mexico, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids or contaminated water, or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency (EPA) “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

16

Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets that we purchased from others. Compliance with applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.
There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced in the United States and international regions in which we operate that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Colombia, which is a location where we provide drilling services), the Regional Greenhouse Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United States.
The U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On December 7, 2009, the EPA responded to the Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from motor vehicles contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change.
Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources. The stationary source final rule addresses the permitting of greenhouse gas emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration construction and Title V operating permit programs, pursuant to which these permit programs have been "tailored" to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA adopted rules requiring the monitoring and reporting of greenhouse gases from certain sources, including, among others, onshore oil and natural gas production facilities.
In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into the air. The EPA also issued regulations that establish standards for VOC emissions from several types of equipment at natural gas well sites, including storage tanks, compressors, dehydrators and pneumatic controllers.
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our clients operate and thus adversely affect demand for our services, which may in turn adversely affect our future results of operations. Finally, we cannot predict with any certainty whether changes to temperature, storm intensity or precipitation patterns as a result of climate change will have a material impact on our operations.

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Hydraulic fracturing is a commonly used process that involves injection of water, sand, and a minor amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground injection." The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and has developed draft guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. Congress has from time to time considered legislation to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the Internet.
Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the final results of which are expected in 2014. In addition, in April 2012, the EPA issued the first federal air standards for natural gas wells that are hydraulically fractured, which will require operators to significantly reduce VOC emissions through the use of “green completions” to capture natural gas that would otherwise escape into the air. These new rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through flaring until 2015, after which reduced emission (or “green”) completions must be used. The rules also establish specific new requirements, which were effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On September 23, 2013, the EPA published amendments to the rule which would, among other things, provide additional time for recently constructed, modified or reconstructed storage tanks to install emission controls. The EPA is continuing to consider other aspects of the new rules and may propose additional amendments by the end of 2013 or in early 2014. These rules may require a number of modifications to our clients’ and our own operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our clients, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations.
The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. The U.S. Department of the Interior has also proposed regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents.
In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our clients. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash flows.
In addition, our business depends on the demand for land drilling and production services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our clients, or otherwise directly or indirectly affect our operations.

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Our wireline operations involve the use of radioactive isotopes along with other nuclear, electrical, acoustic, and mechanical devices. Our activities involving the use of isotopes are regulated by the U.S. Nuclear Regulatory Commission and specified agencies of certain states. Additionally, we use high explosive charges for perforating casing and formations, and we use various explosive cutters to assist in wellbore cleanout. Such operations are regulated by the U.S. Department of Justice, Bureau of Alcohol, Tobacco, Firearms, and Explosives and require us to obtain licenses or other approvals for the use of densitometers as well as explosive charges. We have obtained these licenses and approvals when necessary and believe that we are in substantial compliance with these federal requirements.
Among the services we provide, we operate as a motor carrier for the transportation of our own equipment and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Available Information
Our Website address is www.pioneeres.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, are available free of charge through our Website as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission. The public may read and copy these materials at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. For additional information on the operations of the Securities and Exchange Commission’s Public Reference Room, please call 1-800-SEC-0330. In addition, the Securities and Exchange Commission maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. We have also posted on our Website our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Business Conduct and Ethics; Corporate Governance Guidelines; and Company Contact Information. Information on our website is not incorporated into this report or otherwise made part of this report.


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Item 1A.
Risk Factors
The information set forth in this Item 1A should be read in conjunction with the rest of the information included in this report, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and the financial statements and related notes this report contains. While we attempt to identify, manage and mitigate risks and uncertainties associated with our business to the extent practical under the circumstances, some level of risk and uncertainty will always be present. Additional risks and uncertainties that are not presently known to us or that we currently believe are immaterial also may negatively impact our business, financial condition or operating results.
Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operations and cash flows.
Risks Relating to the Oil and Gas Industry
We derive all our revenues from companies in the oil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.
As a provider of contract land drilling services and oil and gas production services, our business depends on the level of exploration and production activity in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and gas prices, and market expectations of potential changes in those prices, significantly affect the levels of those activities. Worldwide political, economic, and military events as well as natural disasters have contributed to oil and gas price volatility and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and gas prices or otherwise, could materially and adversely affect us by negatively impacting:
•
our revenues, cash flows and profitability;
•
the fair market value of our drilling rig fleet and production services equipment;
•
our ability to maintain or increase our borrowing capacity;
•
our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital; and
•
our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.
Depending on the market prices of oil and gas, oil and gas exploration and production companies may cancel or curtail their drilling programs and may lower production spending on existing wells, thereby reducing demand for our services. Many factors beyond our control affect oil and gas prices, including:
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the cost of exploring for, producing and delivering oil and gas;
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the discovery rate of new oil and gas reserves;
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the rate of decline of existing and new oil and gas reserves;
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available pipeline and other oil and gas transportation capacity;
•
the levels of oil and gas storage;
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the ability of oil and gas exploration and production companies to raise capital;
•
economic conditions in the United States and elsewhere;
•
actions by OPEC, the Organization of Petroleum Exporting Countries;
•
political instability in the Middle East and other major oil and gas producing regions;
•
governmental regulations, both domestic and foreign;
•
domestic and foreign tax policy;

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•
weather conditions in the United States and elsewhere;
•
the pace adopted by foreign governments for the exploration, development and production of their national reserves;
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the price of foreign imports of oil and gas; and
•
the overall supply and demand for oil and gas.
Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. During late 2008 and continuing into late 2009, oil and natural gas prices fell significantly below the levels seen in mid-2008. While oil prices have generally recovered from the low levels in late 2008, natural gas prices have remained depressed. Future declines in and volatility in oil and gas prices could materially and adversely affect our business and financial results.
Risks Relating to Our Business
Reduced demand for or excess capacity of drilling services or production services could adversely affect our profitability.
Our profitability in the future will depend on many factors, but largely on pricing and utilization rates for our drilling and production services. A reduction in the demand for drilling rigs or an increase in the supply of drilling rigs, whether through new construction or refurbishment, could decrease the dayrates and utilization rates for our drilling services, which would adversely affect our revenues and profitability. An increase in supply of well servicing rigs, wireline units, coiled tubing units, and fishing and rental tools and equipment, without a corresponding increase in demand, could similarly decrease the pricing and utilization rates of our production services, which would adversely affect our revenues and profitability.
We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.
We encounter substantial competition from other drilling contractors and other oilfield service companies. Our primary market areas are highly fragmented and competitive. The fact that drilling and production services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry and may result in an oversupply of equipment in an area. Contract drilling companies and other oilfield service companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling or production services improves in a region where we operate, our competitors might respond by moving in suitable rigs and production services equipment from other regions. An influx of equipment from other regions could rapidly intensify competition, reduce profitability and make any improvement in demand for drilling or production services short-lived.
Most drilling services contracts and production services contracts are awarded on the basis of competitive bids, which also results in price competition. In addition to pricing and equipment availability, we believe the following factors are also important to our clients in determining which drilling services or production services provider to select:
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the type and condition of each of the competing drilling rigs, well servicing rigs, wireline units and coiled tubing units;
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the mobility and efficiency of the equipment;
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the quality of service and experience of the crews;
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the safety record of the company providing the services;
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the offering of ancillary services; and
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the ability to provide drilling and production services equipment adaptable to, and personnel familiar with, new technologies and drilling and production techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, our safety record, our ability to offer ancillary services, the experience of our crews and the quality of service we provide to differentiate us from our competitors. This strategy is less effective when lower demand for

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drilling and production services intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an oversupply of drilling rigs or production services equipment can cause greater price competition, which can reduce our profitability.
We face competition from many competitors with greater resources.
Some of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
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better withstand industry downturns;
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compete more effectively on the basis of price and technology;
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retain skilled personnel; and
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build new rigs or acquire and refurbish existing rigs and place them into service more quickly than us in periods of high drilling demand.
Technological advancements and trends in our industry affect the demand for certain types of equipment.
Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.
Although we take measures to ensure that we use advanced technologies for drilling and production services equipment, changes in technology or improvements in our competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive, which could have an adverse effect on our financial condition and operating results.
Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect our financial position and our results of operations.
We have historically derived a portion of our revenues from turnkey drilling contracts, and we expect turnkey contracts will continue to represent a component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our client to a specified depth and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our client only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis because we must assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. In addition, since we are only paid by our clients after we have performed the terms of the drilling contract in full, our liquidity can be affected by the number of turnkey and footage contracts that we enter into.
Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operations.

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Our operations involve operating hazards, which, if not insured or indemnified against, could adversely affect our results of operations and financial condition.
Our operations are subject to the many hazards inherent in the drilling and well servicing industries, including the risks of:
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blowouts;
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cratering;
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fires and explosions;
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loss of well control;
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collapse of the borehole;
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damaged or lost drilling equipment; and
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damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
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suspension of operations;
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damage to, or destruction of, our property and equipment and that of others;
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personal injury and loss of life;
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damage to producing or potentially productive oil and gas formations through which we drill; and
•
environmental damage.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include, among other things, pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our clients. However, clients who provide contractual indemnification protection may not in all cases maintain adequate insurance or otherwise have the financial resources necessary to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a client to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.
We could be adversely affected if shortages of equipment, supplies or personnel occur.
From time to time there have been shortages of drilling and production services equipment and supplies during periods of high demand which we believe could recur. Shortages could result in increased prices for drilling and production services equipment or supplies that we may be unable to pass on to clients. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling and production services equipment or supplies could limit drilling and production services operations and jeopardize our relations with clients. In addition, shortages of drilling and production services equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.
Our strategy of constructing drilling rigs during periods of peak demand requires that we maintain an adequate supply of drilling rig components to complete our rig building program. Our suppliers may be unable to continue providing us the needed drilling rig components if their manufacturing sources are unable to fulfill their commitments.
Our operations require the services of employees having the technical training and experience necessary to achieve the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel have occurred in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the

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requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material adverse effect on our financial condition and results of operations.
Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.
As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. For example, since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components, and in March 2008, we acquired two production services businesses which significantly expanded our service offerings to include well servicing, wireline services and fishing and rental services. On December 31, 2011, we acquired the coiled tubing services business of Go-Coil to complement our existing production services offerings.
Our acquisition strategy in general, and our recent acquisitions in particular, involve numerous inherent risks, including:
•
unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including environmental liabilities;
•
difficulties in integrating the operations and assets of the acquired business and the acquired personnel;
•
limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business in order to comply with applicable periodic reporting requirements;
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potential losses of key employees and clients of the acquired businesses;
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risks of entering markets in which we have limited prior experience; and
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increases in our expenses and working capital requirements.
The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties that may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded business acquisitions and the growth of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing shareholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms.
Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.

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Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
Our indebtedness is primarily a result of the two production services businesses that we acquired in 2008 and the acquisition of Go-Coil in 2011. At December 31, 2013, our total debt balance of $502.5 million primarily consists of $419.6 million outstanding under our Senior Notes. As of December 31, 2013, our Revolving Credit Facility had a $80.0 million balance outstanding, with a current availability of $156.0 million.
Our current and future indebtedness could have important consequences, including:
•
impairing our ability to make investments and obtain additional financing for working capital, capital expenditures, acquisitions or other general corporate purposes;
•
limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to make principal and interest payments on our indebtedness;
•
making us more vulnerable to a downturn in our business, our industry or the economy in general as a substantial portion of our operating cash flow could be required to make principal and interest payments on our indebtedness, making it more difficult to react to changes in our business, industry and market conditions;
•
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•
limiting our ability to obtain additional financing that may be necessary to operate or expand our business;
•
putting us at a competitive disadvantage to competitors that have less debt; and
•
increasing our vulnerability to rising interest rates.
We anticipate that our cash generated by operations and our ability to borrow under the currently unused portion of our Revolving Credit Facility should allow us to meet our routine financial obligations for at least the next twelve months. However, our ability to make payments on our indebtedness, and to fund planned capital expenditures, will depend on our ability to generate cash in the future. This, to a certain extent, is subject to conditions in the oil and gas industry, general economic and financial conditions, competition in the markets where 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. 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 refurbishments of our rigs and related equipment; or
•
seeking to raise additional capital.
However, we may be unable to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, and any such alternative financing plans might be insufficient to allow us to meet our debt obligations. If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our Revolving Credit Facility or other instruments governing any future indebtedness, we could be in default under the terms of our Revolving Credit Facility or such instruments. In the event of a default, the lenders under our Revolving Credit Facility could elect to declare all the loans made under such facility to be due and payable together with accrued and unpaid interest and terminate their commitments thereunder and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

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Our Revolving Credit Facility and our Senior Notes impose restrictions on us that may affect our ability to successfully operate our business.
Our Revolving Credit Facility limits our ability to take various actions, such as:
•
limitations on the incurrence of additional indebtedness;
•
restrictions on investments, capital expenditures, mergers or consolidations, asset dispositions, acquisitions, transactions with affiliates and other transactions without the lenders’ consent; and
•
limitation on dividends and distributions.
In addition, our Revolving Credit Facility requires us to maintain certain financial ratios and to satisfy certain financial conditions, which may require us to reduce our debt or take some other action in order to comply with them.
The Indenture governing our Senior Notes contains certain restrictions on our and certain of our subsidiaries’ ability to:
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pay dividends on stock;
•
repurchase stock or redeem subordinated debt or make other restricted payments;
•
incur, assume or guarantee additional indebtedness or issue disqualified stock;
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create liens on the our assets;
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enter into sale and leaseback transactions;
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pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
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consolidate with or merge with or into, or sell all or substantially all of our properties to another person;
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enter into transactions with affiliates; and
•
enter into new lines of business.
The failure to comply with any of these restrictions or conditions would cause an event of default under our Revolving Credit Facility or our Senior Notes. An event of default, if not waived, could result in acceleration of the outstanding indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to pay our debt or borrow sufficient funds to refinance it. Even if new financing is available, it may not be available on terms that are acceptable to us. These restrictions could also limit our ability to obtain future financing, make needed capital expenditures, withstand a downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We also may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants under our Revolving Credit Facility and our Senior Notes.
Our international operations are subject to political, economic and other uncertainties not encountered in our domestic operations.
Our international operations are subject to political, economic and other uncertainties not generally encountered in our U.S. operations which include, among potential others:
•
risks of war, terrorism, civil unrest and kidnapping of employees;
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expropriation, confiscation or nationalization of our assets;
•
renegotiation or nullification of contracts;
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foreign taxation;
•
the inability to repatriate earnings or capital due to laws limiting the right and ability of foreign subsidiaries to pay dividends and remit earnings to affiliated companies;
•
changing political conditions and changing laws and policies affecting trade and investment;
•
concentration of clients;
•
regional economic downturns;

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•
the overlap of different tax structures;
•
the burden of complying with multiple and potentially conflicting laws;
•
the risks associated with the assertion of foreign sovereignty over areas in which our operations are conducted;
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the risks associated with any lack of compliance with the Foreign Corrupt Practices Act of 1977 ("FCPA") or other anti-corruption laws;
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the risks associated with fluctuating currency values, hard currency shortages and controls of foreign currency exchange;
•
difficulty in collecting international accounts receivable; and
•
potentially longer payment cycles.
Our international operations are concentrated in Colombia and most of our drilling contracts are with one client, Ecopetrol. We believe our relationship with Ecopetrol is good; however, the loss of this large client could have an adverse effect on our business, financial condition and result of operations.
Additionally, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.
We are committed to doing business in accordance with applicable anti-corruption laws and our code of conduct and ethics. We are subject, however, to the risk that our employees and agents may take action determined to be in violation of anti-corruption laws, including the FCPA or other similar laws. Any violation of the FCPA or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might materially adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.
Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:
•
environmental quality;
•
pollution control;
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remediation of contamination;
•
preservation of natural resources;
•
transportation, and
•
worker safety.
Our operations are subject to stringent federal, state and local laws, rules and regulations governing the protection of the environment and human health and safety. Some of those laws, rules and regulations relate to the disposal of hazardous substances, oilfield waste and other waste materials and restrict the types, quantities and concentrations of those substances that can be released into the environment. Several of those laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Our operations routinely involve the handling of significant amounts of waste materials, some of which are classified as hazardous substances. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to

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additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids, contaminated water or other substances, or for noncompliance with other aspects of applicable laws and regulations.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe Drinking Water Act, or SDWA, the federal Outer Continental Shelf Lands Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes that impose the requirements described above and provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also common for third parties to file claims for personal injury and property damage caused by substances released into the environment.
Environmental laws and regulations are complex and subject to frequent change. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets which we acquired from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination or regulatory noncompliance may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.
There are a variety of regulatory developments, proposals or requirements and legislative initiatives that have been introduced in the United States and international regions in which we operate that are focused on restricting the emission of carbon dioxide, methane and other greenhouse gases. Among these developments are the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Colombia, which is a location where we provide drilling services), the Regional Greenhouse Gas Initiative or “RGGI” in the Northeastern United States, and the Western Regional Climate Action Initiative in the Western United States.
The U.S. Congress has from time to time considered legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases.
In 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On December 7, 2009, the EPA responded to the Massachusetts, et al. v. EPA decision and issued a finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from motor vehicles contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change.
Based on these findings, in 2010 the EPA adopted two sets of regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of greenhouse gases from motor vehicles and another that requires certain construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources. The stationary source final rule addresses the permitting of greenhouse gas emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration construction and Title V operating permit programs, pursuant to which these permit programs have been "tailored" to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the

28

largest sources first subject to permitting. In addition, the EPA adopted rules requiring the monitoring and reporting of greenhouse gases from certain sources, including, among others, onshore oil and natural gas production facilities.
In April 2012, the EPA issued regulations specifically applicable to the oil and gas industry that will require operators to significantly reduce volatile organic compounds, or VOC, emissions from natural gas wells that are hydraulically fractured through the use of “green completions” to capture natural gas that would otherwise escape into the air. The EPA also issued regulations that establish standards for VOC emissions from several types of equipment at natural gas well sites, including storage tanks, compressors, dehydrators and pneumatic controllers.
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our clients operate and thus adversely affect demand for our services, which may in turn adversely affect our future results of operations. Finally, we cannot predict with any certainty whether changes to temperature, storm intensity or precipitation patterns as a result of climate change will have a material impact on our operations.
In addition, our business depends on the demand for land drilling and production services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our clients, or otherwise directly or indirectly affect our operations.
Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our drilling and well servicing activities and could adversely affect our financial position, results of operations and cash flows.
Hydraulic fracturing is a commonly used process that involves injection of water, sand, and a minor amount of certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act (SDWA) to exclude certain hydraulic fracturing practices from the definition of "underground injection." The EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and has developed draft guidance relating to such practices. In addition, repeal of the SDWA exclusion of hydraulic fracturing has been advocated by certain advocacy organizations and others in the public. Congress has from time

29

to time considered legislation to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, and to require the disclosure of the chemical constituents of hydraulic fracturing fluids to a regulatory agency, which would make the information public via the Internet.
Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing, the final results of which are expected in 2014. In addition, in April 2012, the EPA issued the first federal air standards for natural gas wells that are hydraulically fractured, which will require operators to significantly reduce VOC emissions through the use of “green completions” to capture natural gas that would otherwise escape into the air. These new rules address emissions of various pollutants frequently associated with oil and natural gas production and processing activities by, among other things, requiring new or reworked hydraulically-fractured gas wells to control emissions through flaring until 2015, after which reduced emission (or “green”) completions must be used. The rules also establish specific new requirements, which were effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants, and certain other equipment. On September 23, 2013, the EPA published amendments to the rule which would, among other things, provide additional time for recently constructed, modified or reconstructed storage tanks to install emission controls. The EPA is continuing to consider other aspects of the new rules and may propose additional amendments by the end of 2013 or in early 2014. These rules may require a number of modifications to our clients’ and our own operations, including the installation of new equipment to control emissions. Compliance with such rules could result in additional costs for us and our clients, including increased capital expenditures and operating costs, which may adversely impact our cash flows and results of operations.
The EPA is also developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. The U.S. Department of the Interior has also proposed regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents.
In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our clients. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash flows.
Our operations are subject to the risk of cyber attacks that could have a material adverse effect on our consolidated results of operations and consolidated financial condition.
Our information technology systems are subject to possible breaches and other threats that could cause us harm. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by, among other things, loss or damage of intellectual property, proprietary information, or customer data; interruption of business operations; or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, financial condition and result of operations.

30

Risks Relating to Our Capitalization and Organizational Documents
We do not intend to pay dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our shareholders.
We have not paid or declared any dividends on our common stock and currently intend to retain any earnings to fund our working capital needs, reduce debt and fund growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and restrictions imposed by the Texas Business Organizations Code and other applicable laws and by our Revolving Credit Facility and Senior Notes. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our articles of incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders.
The existence of some provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
•
provisions regulating the ability of our shareholders to nominate candidates for election as directors or to bring matters for action at annual meetings of our shareholders;
•
limitations on the ability of our shareholders to call a special meeting and act by written consent;
•
provisions dividing our board of directors into three classes elected for staggered terms; and
•
the authorization given to our board of directors to issue and set the terms of preferred stock.
Item 1B.
Unresolved Staff Comments
Not applicable.
Item 2.
Properties
For a description of our significant properties, see “Business—General” and “Business—Facilities” in Item 1 of this report. We believe that we have sufficient properties to conduct our operations and that our significant properties are suitable for their intended use.
Item 3.
Legal Proceedings
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers' compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.

31

Item 4. Mine Safety Disclosures
Not applicable.



PART II
Item 5.
Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
As of January 30, 2014, 62,537,694 shares of our common stock were outstanding, held by 383 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
Our common stock trades on the New York Stock Exchange under the symbol “PES.” The following table sets forth, for each of the periods indicated, the high and low sales prices per share: 
 
Low
 
High
Fiscal year ended December 31, 2013
 
 
 
First Quarter
$
7.16

 
$
9.88

Second Quarter
6.53

 
8.50

Third Quarter
6.50

 
7.74

Fourth Quarter
7.05

 
8.74

Fiscal year ended December 31, 2012
 
 
 
First Quarter
$
8.44

 
$
10.35

Second Quarter
6.54

 
8.92

Third Quarter
6.82

 
9.14

Fourth Quarter
6.02

 
7.77

The last reported sales price for our common stock on the New York Stock Exchange on January 30, 2014 was $8.44 per share.
We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions imposed by the Texas Business Organizations Code and other applicable laws and our Revolving Credit Facility and Senior Notes. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.
We did not make any unregistered sales of equity securities during the quarter ended December 31, 2013. The following table provides information relating to our repurchase of common shares during the quarter ended December 31, 2013:
Period
Total Number of
Shares Purchased 
(1)
 
Average Price Paid
per Share
(2)
 
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
 
Maximum Number of
Shares that May Yet Be
Purchased Under the
Plans or Programs
October 1—October 31
104

 
$
7.66

 
—

 
—

November 1—November 30
—

 
$
—

 
—

 
—

December 1—December 31
317

 
$
7.41

 
—

 
—

Total
421

 
$
7.47

 
—

 
—

(1)
The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended December 31, 2013, to satisfy the employees’ tax withholding obligations in connection with the vesting of restricted stock unit awards, which we repurchased based on the fair market value on the date the relevant transaction occurred.
(2)
The calculation of the average price paid per share does not give effect to any fees, commissions or other costs associated with the repurchase of such shares.

33

Performance Graph
The following graph compares, for the periods from December 31, 2008 to December 31, 2013, the cumulative total shareholder return on our common stock with the cumulative total return on the companies that comprise the NYSE Composite Index and a peer group index that includes five companies that provide contract drilling services and/or production services. The companies that comprise the peer group index are Patterson-UTI Energy, Inc., Nabors Industries Ltd., Basic Energy Services, Inc., Precision Drilling Trust and Key Energy Services.
The comparison assumes that $100 was invested on December 31, 2008 in our common stock, the companies that compose the NYSE Composite Index and the peer group index, and further assumes all dividends were reinvested.

34

Item 6.
Selected Financial Data
The following information derives from our audited financial statements. This information should be reviewed in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the financial statements and related notes this report contains.
 
Year ended December 31,
 
2013 (1)
 
2012
 
2011
 
2010
 
2009
 
(In thousands, except per share amounts)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues
$
960,186

 
$
919,443

 
$
715,941

 
$
487,210

 
$
325,537

Income (loss) from operations
(6,229
)
 
81,811

 
57,458

 
(18,572
)
 
(31,840
)
Income (loss) before income taxes
(55,778
)
 
46,386

 
20,833

 
(47,558
)
 
(40,172
)
Net earnings (loss) applicable to common stockholders
(35,932
)
 
30,032

 
11,177

 
(33,261
)
 
(23,215
)
Earnings (loss) per common share-basic
$
(0.58
)
 
$
0.49

 
$
0.19

 
$
(0.62
)
 
$
(0.46
)
Earnings (loss) per common share-diluted
$
(0.58
)
 
$
0.48

 
$
0.19

 
$
(0.62
)
 
$
(0.46
)
Other Financial Data:
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
174,580

 
$
199,366

 
$
144,879

 
$
98,351

 
$
123,313

Net cash used in investing activities
(150,676
)
 
(361,231
)
 
(307,484
)
 
(129,481
)
 
(113,909
)
Net cash provided by financing activities
(20,252
)
 
99,401

 
226,791

 
12,762

 
4,154

Capital expenditures
$
125,420

 
379,272

 
237,787

 
135,151

 
110,453

 
As of December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(In thousands)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Working capital
$
118,547

 
$
62,236

 
$
129,932

 
$
76,142

 
$
90,336

Property and equipment, net
937,657

 
1,014,340

 
793,956

 
655,508

 
637,022

Long-term debt and capital lease obligations, excluding current installments
499,666

 
518,725

 
418,728

 
279,530

 
258,073

Shareholders’ equity
518,433

 
547,680

 
510,445

 
396,333

 
421,448

Total assets
1,229,623

 
1,339,776

 
1,172,754

 
841,343

 
824,955


(1)
The statement of operations and other financial data for the year ended December 31, 2013 reflect the impact of a goodwill impairment charge of $41.7 million and an intangible asset impairment charge of $3.1 million.

35


Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, levels and volatility of oil and gas prices, decisions about exploration and development projects to be made by oil and gas exploration and production companies, economic cycles and their impact on capital markets and liquidity, the continued demand for drilling services or production services in the geographic areas where we operate, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, future compliance with covenants under our senior secured revolving credit facility and our senior notes, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, changes in technology and improvements in our competitors' equipment, the continued availability of drilling rig, well servicing rig, coiled tubing and wireline unit components, the continued availability of qualified personnel, the success or failure of our acquisition strategy, including our ability to finance acquisitions, manage growth and effectively integrate acquisitions, and changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as of the date on which they are made and we undertake no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview
Pioneer Energy Services (formerly called "Pioneer Drilling Company") was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Since September 1999, we have significantly expanded our drilling rig fleet through acquisitions and through the construction of rigs from new and used components. In March 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing, wireline services and fishing and rental services. We have continued to invest in the growth of all our service offerings through acquisitions and organic growth. On December 31, 2011, we acquired the coiled tubing services business of Go-Coil, L.L.C. ("Go-Coil") to expand our existing production services offerings.
In 2012, we changed our company name from "Pioneer Drilling Company" to "Pioneer Energy Services Corp." Our common stock trades on the New York Stock Exchange under the ticker symbol "PES." Our new name reflects our strategy to expand our service offerings beyond drilling services, which has been our core, legacy business. Pioneer Energy Services provides drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. We also provide coiled tubing and wireline services offshore in the Gulf of Mexico. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life of a well site and enable us to meet multiple needs of our clients.

36


Business Segments
We currently conduct our operations through two operating segments: our Drilling Services Segment and our Production Services Segment. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 11, Segment Information, of the Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.
•
Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
14

West Texas
 
18

North Dakota
 
11

Utah
 
7

Appalachia
 
4

Colombia
 
8

 
 
62

In early 2011, we began construction of ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, based on term contracts. We deployed seven of these new-build drilling rigs during 2012, and deployed the final three in early 2013. All of our new-build drilling rigs are currently operating in shale or unconventional plays under long-term drilling contracts.
During the second quarter of 2013, we sold two mechanical drilling rigs that were previously idle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. In September 2013, we decided to sell eight of our mechanical drilling rigs, for which we recognized an impairment charge of $9.2 million dollars during the third quarter. All eight drilling rigs were classified as held for sale at September 30, 2013 and were sold in late October 2013. We did not incur any additional gain or loss upon the sale of these rigs.
As of December 31, 2013, 50 of our 62 drilling rigs are earning revenues under drilling contracts, 39 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working. The remaining rig will begin working under its term contract after it is upgraded from 1,000 horsepower to 1,500 horsepower, which we expect will be completed by the end of the first quarter of 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.

37


•
Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. We provide our services to a diverse group of oil and gas exploration and production companies. The primary production services we offer are the following:
•
Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of December 31, 2013, we operate ninety-nine 550 horsepower rigs and ten 600 horsepower rigs through 11 locations, mostly in the Gulf Coast and ArkLaTex regions, though we also have 14 rigs in North Dakota.
•
Wireline Services. In order for oil and gas exploration and production companies to better understand the reservoirs they are drilling or producing, they require logging services to accurately characterize reservoir rocks and fluids. To complete a well, the production casing must be perforated to establish a flow path between the reservoir and the wellbore. We use our fleet of wireline units to provide these important logging and perforating services. We provide both open and cased-hole logging services, including the latest pulsed-neutron technology. In addition, we provide services which allow oil and gas exploration and production companies to evaluate the integrity of wellbore casing, recover pipe, or install bridge plugs. As of December 31, 2013, we operate through 24 locations with a fleet of 119 wireline units.
•
Coiled Tubing Services. Coiled tubing is an important element of the well servicing industry that allows operators to continue production during service operations without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of December 31, 2013, our coiled tubing business consists of nine onshore and four offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.
•
Fishing and Rental Services. During drilling operations, oil and gas exploration and production companies frequently rent unique equipment such as power swivels, foam circulating units, blow-out preventers, air drilling equipment, pumps, tanks, pipe, tubing and fishing tools. We provide rental services out of three locations in Texas and Oklahoma. As of December 31, 2013 our fishing and rental tools have a gross book value of $17.3 million.

Pioneer Energy Services' corporate office is located at 1250 NE Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (855) 884-0575 and our website address is www.pioneeres.com. We make available free of charge though our website 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 material is electronically filed with the Securities and Exchange Commission (SEC). Information on our website is not incorporated into this report or otherwise made part of this report.
Market Conditions in Our Industry
Demand for oilfield services offered by our industry is a function of our clients’ willingness to make operating expenditures and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected oil and natural gas prices.
From late 2008 and into late 2009, there was substantial volatility and a decline in oil and natural gas prices due to the downturn in the global economic environment. In response, our clients curtailed their drilling programs

38


and reduced their production activities, particularly in natural gas producing regions, which resulted in a decrease in demand and revenue rates for certain of our drilling rigs and production services equipment. Additionally, there was uncertainty in the capital markets and access to financing was limited. These conditions adversely affected our business environment.
With generally increasing oil prices in 2010 and 2011, exploration and production companies increased their exploration and production spending and industry equipment utilization and revenue rates improved, particularly in oil-producing regions and in certain shale regions. During 2012, modest increases in exploration and production spending resulted in modest increases in industry equipment utilization and revenue rates during 2012, as compared to 2011. Despite generally increasing oil prices during 2013, industry equipment utilization levels have been slightly lower than industry levels during 2012, which is partially due to the advancements in technology and efficiency of drilling rigs. In addition, excess natural gas production in the U.S. shale regions continues to depress natural gas prices. If oil and natural gas prices decline, then industry equipment utilization and revenue rates could decrease domestically and in Colombia.
Colombia has experienced significant growth in oil production since 2008 largely due to the infusion of capital by international exploration and production companies as a result of the country's improved regulation and security. Historically, Colombian oil prices have generally trended in line with West Texas Intermediate (WTI) oil prices. However, fluctuations in oil prices have a less significant impact on demand for drilling and production services in Colombia as compared to the impact on demand in North America. Demand for drilling and production services in Colombia is largely dependent upon the national oil company's long-term exploration and production programs.
The trends in spot prices of WTI crude oil and Henry Hub natural gas, and the resulting trends in domestic land rig counts (per Baker Hughes) and domestic well servicing rig counts (per Guiberson/Association of Energy Service Companies) over the last five years are illustrated in the graphs below.
As shown in the charts above, the trends in industry rig counts are influenced by fluctuations in oil and natural gas prices, which affect the levels of capital and operating expenditures made by our clients.
Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Exploration and production spending is generally categorized as either a capital expenditure or operating expenditure.
Capital expenditures by oil and gas exploration and production companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for long periods of time, capital expenditure projects are routinely deferred until prices return to an acceptable level.
In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration as these expenditures are less sensitive to commodity price volatility. Mandatory operating expenditure

39


projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field and are generally evaluated according to a simple short-term payout criterion that is far less dependent on commodity price forecasts.
Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.
Technological advancements and trends in our industry also affect the demand for certain types of equipment. During 2013, the demand for traditional drilling rigs in vertical markets has softened due to increased demand for drilling rigs that are able to drill horizontally. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by a walking or skidding drilling rig at a single pad-site location. Pad drilling has improved the productivity of exploration and production activities which could reduce the demand for drilling rigs, particularly those that do not have the ability to walk or skid and to drill horizontal wells.
For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.
Liquidity and Capital Resources
Sources of Capital Resources
Our principal liquidity requirements have been for working capital needs, debt service, capital expenditures and selective acquisitions. Our principal sources of liquidity consist of cash and cash equivalents (which equaled $27.4 million as of December 31, 2013), cash generated from operations and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).
In July 2011, we obtained $94.3 million in net proceeds from the sale of 6,900,000 shares of our common stock at $14.50 per share, less underwriters’ commissions and other offering costs, pursuant to a public offering under the shelf registration statement which we filed in July 2009. The proceeds from this offering were used to pay down the debt balance outstanding under our Revolving Credit Facility and to fund our new-build drilling rig program. In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of December 31, 2013, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity and/or debt offerings, as appropriate, to meet our liquidity needs.
On March 11, 2010, we issued $250 million of senior notes with a coupon interest rate of 9.875% that are due in 2018 (the "2010 Senior Notes"). We received $234.8 million of net proceeds from the issuance of the 2010 Senior Notes that were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. On November 21, 2011, we issued an additional $175 million of senior notes (the "2011 Senior Notes") with the same terms and conditions as the 2010 Senior Notes. We received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, a portion of which were used to fund the acquisition of Go-Coil in December 2011.
Our Revolving Credit Facility provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $250 million, all of which matures on June 30, 2016. As of December 31, 2013, we had $80.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $156.0 million under our Revolving Credit Facility. There are no limitations on our ability to access the full borrowing availability under the Revolving Credit Facility other than maintaining compliance with the covenants in the Revolving Credit Facility. Additional information regarding these covenants is provided in the Debt Requirements section below. Borrowings under the Revolving Credit Facility are available for selective acquisitions, working capital and other general corporate purposes.

40


We currently expect that cash and cash equivalents, cash generated from operations and available borrowings under our Revolving Credit Facility are adequate to cover our liquidity requirements for at least the next 12 months.
Uses of Capital Resources
For the years ended December 31, 2013 and 2012, our primary uses of capital resources were for property and equipment additions which consisted of the following (amounts in thousands):
 
Year ended December 31,
 
2013
 
2012
Drilling Services Segment:
 
 
 
Routine
$
39,276

 
$
39,051

Discretionary
35,569

 
56,430

Fleet additions
41,679

 
162,677

Total Drilling Services Segment
116,524

 
258,158

Production Services Segment:
 
 
 
Routine
23,053

 
15,311

Discretionary
20,092

 
37,562

Fleet additions
5,687

 
53,293

Total Production Services Segment
48,832

 
106,166

Net cash used for purchases of property and equipment
165,356

 
364,324

Net impact of accruals
(39,936
)
 
14,948

Total Capital Expenditures
$
125,420

 
$
379,272

Our Drilling Services Segment incurred $12.3 million and $173.0 million of costs, including accruals for capital expenditures, on the construction of our new-build drilling rigs during the years ended December 31, 2013 and 2012, respectively. Additionally, during the year ended December 31, 2013, we performed significant upgrade projects to various rigs in our drilling fleet including, among others, the installation of four additional automatic catwalks and two additional walking systems, the upgrade of two drilling rigs to higher horsepower and we upgraded four rigs with higher horsepower mud pumps. During the year ended December 31, 2012, we performed significant upgrade projects to our drilling rigs including, among others, the installation of nine additional automatic catwalks, one additional iron roughneck, one top drive, the upgrade of three drilling rigs to higher horsepower and we upgraded two rigs with higher horsepower mud pumps. In connection with the construction of our new-build drilling rigs and other drilling equipment upgrades, we capitalized $0.9 million and $10.2 million of interest costs during the years ended December 31, 2013 and 2012, respectively.
Our Production Services Segment acquired three wireline units and one well servicing rig during the year ended December 31, 2013. During the year ended December 31, 2012, we acquired 15 wireline units, 19 well servicing rigs, and three coiled tubing units.
Currently, we expect to spend approximately $115 million to $125 million on capital expenditures during 2014. We expect the total capital expenditures for 2014 will be allocated approximately 60% for our Drilling Services Segment and approximately 40% for our Production Services Segment. Our planned capital expenditures for the year ending December 31, 2014 include upgrades to certain drilling rigs, additional production services equipment and routine capital expenditures. Actual capital expenditures may vary depending on the timing of commitments and payments, as well as the level of new-build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund the capital expenditures in 2014 from operating cash flow in excess of our working capital requirements.

41


Working Capital
Our working capital was $118.5 million at December 31, 2013, compared to $62.2 million at December 31, 2012. Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.0 at December 31, 2013 compared to 1.4 at December 31, 2012.
Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our working capital requirements could increase during periods when higher percentages of our drilling contracts are turnkey and footage contracts and when new-build rig construction projects are in progress.
With the completion of our new-build drilling rig program in the first quarter of 2013, we have shifted our near-term focus toward reducing capital expenditures and using excess cash flows from operations to reduce outstanding debt balances. The changes in the components of our working capital were as follows (amounts in thousands):
 
December 31,
2013
 
December 31,
2012
 
Change
Cash and cash equivalents
$
27,385

 
$
23,733

 
$
3,652

Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
115,908

 
115,070

 
838

Unbilled receivables
49,535

 
35,140

 
14,395

Insurance recoveries
8,607

 
6,518

 
2,089

Income taxes and other
2,310

 
2,116

 
194

Deferred income taxes
13,092

 
11,058

 
2,034

Inventory
13,232

 
12,111

 
1,121

Prepaid expenses and other current assets
9,311

 
13,040

 
(3,729
)
Current assets
239,380

 
218,786

 
20,594

Accounts payable
43,718

 
83,823

 
(40,105
)
Current portion of long-term debt
2,847

 
872

 
1,975

Deferred revenues
699

 
3,880

 
(3,181
)
Accrued expenses:
 
 
 
 
 
Payroll and related employee costs
30,020

 
27,991

 
2,029

Insurance premiums and deductibles
10,940

 
9,708

 
1,232

Insurance claims and settlements
8,607

 
6,348

 
2,259

Interest
12,275

 
12,343

 
(68
)
Other
11,727

 
11,585

 
142

Current liabilities
120,833

 
156,550

 
(35,717
)
Working capital
$
118,547

 
$
62,236

 
$
56,311

The increase in cash and cash equivalents during the year ended December 31, 2013 is primarily due to $174.6 million of cash provided by operating activities and $13.8 million of proceeds from the sale of assets, which was mostly offset by $165.4 million used for purchases of property and equipment and $20.9 million used to repay debt, net of additional borrowings during the year.
The net increase in our total trade and unbilled receivables as of December 31, 2013 as compared to December 31, 2012 is primarily due to the timing of the billing and collection cycles for long-term drilling contracts in Colombia, as well as the increase in consolidated revenues of $10.3 million, or 5%, for the quarter ended December 31, 2013 as compared to the quarter ended December 31, 2012.
The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of December 31, 2013 as compared to December 31, 2012 is primarily due to an increase in our insurance company's reserve for workers compensation claims in excess of our deductibles.

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The increase in current deferred income taxes as of December 31, 2013 as compared to December 31, 2012 is due to a movement of our deferred tax assets related to net operating losses from long-term to current, as we expect to realize them in the short term.
The increase in inventory as of December 31, 2013 as compared to December 31, 2012 is due to the expansion of our wireline and coiled tubing operations. Our wireline inventory has increased as activity has increased during the fourth quarter of 2013, as compared to the fourth quarter of 2012, and our coiled tubing inventory has increased with the recent expansion of our operations to provide services using a larger diameter coiled tubing.
The decrease in prepaid expenses and other assets as of December 31, 2013 as compared to December 31, 2012 is primarily due to the amortization of deferred mobilization costs relating to drilling contracts for our new-build drilling rigs and other drilling rigs that moved between geographic regions of the United States and Colombia.
The decrease in accounts payable is primarily due to a $39.9 million decrease in our accruals for capital expenditures as of December 31, 2013 as compared to December 31, 2012, as we completed construction of three of our new-build drilling rigs during the first quarter of 2013.
The current portion of our long-term debt is primarily related to a short-term financing for insurance premiums with monthly payments due through August 2014.
The decrease in deferred revenues is related to the amortization of deferred mobilization revenues relating to drilling contracts for our new-build drilling rigs and other drilling rigs that moved between geographic regions of the United States and Colombia.
The increase in accrued payroll and employee related costs is primarily due to an increase in payroll accruals resulting from more payroll days reflected in the accrued payroll at December 31, 2013 as compared to December 31, 2012, due to the timing of pay periods.
The increase in our accrued insurance premiums and deductibles is primarily due to an increase in our accrual for workers compensation claims and health insurance costs resulting from an increase in our estimated liability for the deductibles under these policies.
The increase in other accrued expenses as of December 31, 2013 as compared to December 31, 2012 is due to an increase in accrued property tax primarily due to the movement of drilling assets from lower taxed regions to higher taxed regions, as well as timing of payments, but which was mostly offset by a decrease in our sales tax accrual which was primarily related to the construction of our new-build drilling rigs that were completed in the first quarter of 2013.
Long-term Debt and Other Contractual Obligations
The following table includes information about the amount and timing of our contractual obligations at December 31, 2013 (amounts in thousands):
 
Payments Due by Period
Contractual Obligations
Total
 
Within 1 Year
 
2 to 3 Years
 
4 to 5 Years
 
Beyond 5 Years
Debt
$
507,927

 
$
2,847

 
$
80,080

 
$
425,000

 
$
—

Interest on debt
194,739

 
44,341

 
87,445

 
62,953

 
—

Purchase commitments
8,781

 
8,781

 
—

 
—

 
—

Operating leases
14,919

 
5,032


5,415


3,106


1,366

Other long-term liabilities
12,266

 
6,172

 
6,094

 
—

 
—

Total
$
738,632

 
$
67,173

 
$
179,034

 
$
491,059

 
$
1,366

At December 31, 2013, long-term debt consists of $425 million face amount outstanding under our Senior Notes, $80.0 million outstanding under our Revolving Credit Facility and $2.9 million of other debt outstanding. The $80.0 million outstanding under our Revolving Credit Facility is due at maturity on June 30, 2016. However, we may make principal payments to reduce the outstanding balance prior to maturity when cash and working capital

43


is sufficient. The $425 million face amount outstanding under our Senior Notes will mature on March 15, 2018. Our Senior Notes have a carrying value of $419.6 million as of December 31, 2013, which represents the $425.0 million face value net of the $6.7 million of original issue discount and $1.3 million of original issue premium, net of amortization, based on the effective interest method.
Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 2.9% interest rate that was in effect at December 31, 2013, and (2) the outstanding balance of $80.0 million at December 31, 2013 to be paid at maturity on June 30, 2016. Interest payment obligations on our Senior Notes are calculated based on the coupon interest rate of 9.875% due semi-annually in arrears on March 15 and September 15 of each year.
Purchase commitments primarily relate to equipment upgrades and purchases of other new equipment.
Operating leases consist of lease agreements for office space, operating facilities, equipment and personal property.
Other long-term liabilities include the net equity tax payable to the Colombian tax authority and long-term incentive compensation which is payable to our employees, generally contingent upon their continued employment through the date of each respective award's payout.
Debt Requirements
The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure. There are no limitations on our ability to access the $250 million borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At December 31, 2013, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.0 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0, and our interest coverage ratio was 5.3 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:
•
A maximum total consolidated leverage ratio that cannot exceed 4.00 to 1.00;
•
A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed 2.50 to 1.00;
•
A minimum interest coverage ratio that cannot be less than 2.50 to 1.00; and
•
If our senior consolidated leverage ratio is greater than 2.00 to 1.00 at the end of any fiscal quarter, our minimum asset coverage ratio cannot be less than 1.00 to 1.00.
The Revolving Credit Facility does not restrict capital expenditures as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures, (b) after giving effect to such capital expenditures there is availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is less than 2.00 to 1.00. If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal to or greater than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital expenditure threshold may be increased by any unused portion of the capital expenditure threshold from the immediate preceding fiscal year up to $30 million.
At December 31, 2013, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.
The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control.

44


Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) was added as a subsidiary guarantor under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.
In addition to the financial covenants under our Revolving Credit Facility, the Indenture for our Senior Notes contains certain restrictions generally on our ability to:
•
pay dividends on stock;
•
repurchase stock or redeem subordinated debt or make other restricted payments;
•
incur, assume or guarantee additional indebtedness or issue disqualified stock;
•
create liens on our assets;
•
enter into sale and leaseback transactions;
•
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
•
consolidate with or merge with or into, or sell all or substantially all of our properties to another person;
•
enter into transactions with affiliates; and
•
enter into new lines of business.

Upon the occurrence of a change of control, holders of the Senior Notes will have the right to require us to purchase all or a portion of the Senior Notes at a price equal to 101% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Under certain circumstances in connection with asset dispositions, we will be required to use the excess proceeds of asset dispositions to make an offer to purchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase.
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by our existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, and by certain of our future domestic subsidiaries. Effective October 1, 2012, the Indenture was supplemented to add Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) as a subsidiary guarantor. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture. In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes.
Our Senior Notes are not subject to any sinking fund requirements. As of December 31, 2013, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company, and we were in compliance with all covenants pertaining to our Senior Notes.

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Results of Operations
Statements of Operations Analysis—Year Ended December 31, 2013 Compared with the Year Ended December 31, 2012
The following table provides information about our operations for the years ended December 31, 2013 and 2012 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
 
Year ended December 31,
 
2013
 
2012
Drilling Services Segment:
 
 
 
Revenues
$
528,327

 
$
498,867

Operating costs
351,630

 
333,846

Drilling Services Segment margin
$
176,697

 
$
165,021

 
 
 
 
Average number of drilling rigs
68.2

 
65.0

Utilization rate
84
%
 
87
%
Revenue days
20,977

 
20,728

 
 
 
 
Average revenues per day
$
25,186

 
$
24,067

Average operating costs per day
16,763

 
16,106

Drilling Services Segment margin per day
$
8,423

 
$
7,961

 
 
 
 
Production Services Segment:
 
 
 
Revenues
$
431,859

 
$
420,576

Operating costs
276,808

 
252,775

Production Services Segment margin
$
155,051

 
$
167,801

 
 
 
 
Combined:
 
 
 
Revenues
$
960,186

 
$
919,443

Operating costs
628,438

 
586,621

Combined margin
$
331,748

 
$
332,822

Adjusted EBITDA
$
234,742

 
$
249,283

Drilling Services Segment margin represents contract drilling revenues less contract drilling operating costs. Production Services Segment margin represents production services revenue less production services operating costs. We believe that Drilling Services Segment margin and Production Services Segment margin are useful measures for evaluating financial performance, although they are not measures of financial performance under U.S. Generally Accepted Accounting Principles (GAAP). However, Drilling Services Segment margin and Production Services Segment margin are common measures of operating performance used by investors, financial analysts, rating agencies and Pioneer’s management. Drilling Services Segment margin and Production Services Segment margin as presented may not be comparable to other similarly titled measures reported by other companies.
Adjusted EBITDA is a financial measure that is not in accordance with GAAP, and should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. We define Adjusted EBITDA as income (loss) before interest income (expense), taxes, depreciation, amortization and any impairments. We use this measure, together with our GAAP financial metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives. We believe that

46


this non-GAAP financial measure is useful to investors and analysts in allowing for greater transparency of our operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies.
A reconciliation of combined Drilling Services Segment margin and Production Services Segment margin to net income (loss), as reported, and a reconciliation of Adjusted EBITDA to net income (loss), as reported, are set forth in the following table.
 
Year ended December 31,
 
2013
 
2012
 
(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net income (loss):
 
 
 
Combined margin
$
331,748

 
$
332,822

General and administrative
(95,000
)
 
(85,603
)
Bad debt (expense) recovery
(767
)
 
440

Other (expense) income
(1,239
)
 
1,624

Adjusted EBITDA
234,742

 
249,283

Depreciation and amortization
(187,918
)
 
(164,717
)
Impairment charges
(54,292
)
 
(1,131
)
Interest expense
(48,310
)
 
(37,049
)
Income tax benefit (expense)
19,846

 
(16,354
)
Net income (loss)
$
(35,932
)
 
$
30,032

Our Drilling Services Segment’s revenues increased by $29.5 million, or 6%, during 2013 as compared to 2012, resulting primarily from an increase in revenues per day of 5%, or $1,119 per day, as well as an increase in revenue days of 1%. Our Drilling Services Segment’s operating costs increased by $17.8 million, or 5%, during 2013 as compared to 2012, primarily resulting from higher operating costs per day which increased by 4%, or $657 per day, and partially due to an increase in revenue days.
The increases in our Drilling Services Segment's revenues and operating costs per day were primarily due to increased utilization in Colombia, where our revenues and costs per day are higher than our domestic drilling rigs, as well as the deployment of all our new-build drilling rigs into areas of the U.S. which experience higher revenues and costs per day, due to higher demand. We deployed seven of our new-build drilling rigs during the second half of 2012, with the remaining three in the first quarter of 2013. The overall increases in revenues and operating costs were partially offset by a slight decrease in utilization for our domestic drilling rigs, despite an increase in revenue days attributable to the operations of our new-build drilling rigs during 2013.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and to improve our Drilling Services Segment’s margins. Turnkey drilling contracts result in higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts. During the years ended December 31, 2013 and 2012, we completed 27 and 11 turnkey contracts, respectively, representing 3% and 3% of our total drilling revenues for each year, respectively.
Our Production Services Segment's revenues increased by $11.3 million, or 3%, during 2013, as compared to 2012, while operating costs increased by $24.0 million, or 10%.
The increase in our Production Services Segment's revenues is primarily due to increased rig hours and pricing in our well servicing operations due to higher demand for these services during 2013, as compared to 2012, while the overall increase was partially offset by a decrease in revenues from our coiled tubing operations. The total rig hours of our well servicing fleet increased by 7% for the year ended December 31, 2013, partly due to expansion of

47


our fleet during 2012 and 2013, while pricing increased by approximately 4%, as compared to 2012. Revenues from our coiled tubing operations decreased as a result of increased competition in the coiled tubing market and our utilization decreased from 59% in 2012 to 47% in 2013.
The increase in our Production Services Segment's operating costs is primarily due to an increase in our operating costs for our wireline operations which incurred higher average costs per job during 2013, as compared to 2012, as well as an increase in costs for our well servicing operations which experienced higher demand during 2013, as compared to 2012. The number of wireline jobs we completed during 2013 was only 1% higher than the number we completed in 2012, while our average cost per job increased by approximately 11%. The increase in our average cost per wireline job during 2013 was primarily due to a greater mix of higher cost jobs performed during the year, as compared to 2012. We also experienced some increase in our operating costs due to modest inflation of labor costs in our Production Services Segment during 2013.
Our general and administrative expense increased by approximately $9.4 million, or 11% during 2013, as compared to 2012, primarily due to the overall expansion of our business in recent years. During 2012, we expanded our well servicing and wireline fleets by approximately 21% and 14%, respectively, and deployed ten new-build drilling rigs during late 2012 and early 2013. The overall expansion of our business increased our general and administrative expense for the year ended December 31, 2013, as compared to 2012, including an increase of $7.0 million in payroll and compensation related expenses primarily resulting from the additional cost of personnel which we have hired over the recent years to support our growth.
Our bad debt recovery for the year ended December 31, 2012 related to the collection of $0.5 million for an account receivable which had been written off prior to 2011.
Our other expense of $1.2 million and other income of $1.6 million for the years ended December 31, 2013 and 2012, respectively, is primarily related to foreign currency exchange gains and losses recognized for our Colombian operations.
Our depreciation and amortization expenses increased by $23.2 million during 2013 as compared to 2012, as a result of our expansion in both our drilling and production services segments. The addition of our new-build drilling rigs that went into service in late 2012 and early 2013 resulted in an increase of approximately $12.1 million during the year ended December 31, 2013, as compared to 2012, while the remaining increase is primarily due to the expansion of our well servicing, wireline and coiled tubing fleets in 2012 and 2013.
We recorded impairment charges on our property and equipment of $9.5 million for the year ended December 31, 2013 in association with our decision to place eight of our mechanical drilling rigs and other production services equipment as held for sale. During the year ended December 31, 2012, we recorded impairment charges on our property and equipment of $1.1 million in association with our decision to retire two mechanical drilling rigs, with most of their components to be used as spare parts, as well as two wireline units and other wireline equipment.
During the year ended December 31, 2013, we recorded $44.8 million of impairment charges to reduce the goodwill and intangible asset carrying values of our coiled tubing reporting unit, which were originally recorded in connection with the acquisition of Go-Coil on December 31, 2011. On June 30, 2013, we performed an impairment analysis that led us to conclude that there would be no remaining implied value attributable to our goodwill and accordingly, we recorded a non-cash charge of $41.7 million for the full impairment of our goodwill. In addition, we performed an intangible asset impairment analysis on June 30, 2013, which resulted in a non-cash impairment charge of $3.1 million to reduce our intangible asset carrying value of client relationships. These impairment charges did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
Our interest expense increased by $11.3 million for the year ended December 31, 2013, as compared to the year ended December 31, 2012, primarily due to less capitalized interest during the year ended December 31, 2013, as compared to 2012, associated with the capital expenditures for our new-build drilling rigs and for upgrades to our drilling rig fleet.

48


Our effective income tax rate for the year ended December 31, 2013 was 36%, which is slightly higher than the federal statutory rate in the United States, due to the impact of state income taxes, and partially offset by the effect of foreign translation, the impact of lower effective tax rates in foreign jurisdictions and other permanent differences.
Statements of Operations Analysis—Year Ended December 31, 2012 Compared with the Year Ended December 31, 2011
The following table provides information about our operations for the years ended December 31, 2012 and 2011 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
 
Year ended December 31,
 
2012
 
2011
Drilling Services Segment:
 
 
 
Revenues
$
498,867

 
$
433,902

Operating costs
333,846

 
292,559

Drilling Services Segment margin
$
165,021

 
$
141,343

 
 
 
 
Average number of drilling rigs
65.0

 
69.3

Utilization rate
87
%
 
73
%
Revenue days
20,728

 
18,383

 
 
 
 
Average revenues per day
$
24,067

 
$
23,603

Average operating costs per day
16,106

 
15,915

Drilling Services Segment margin per day
$
7,961

 
$
7,688

 
 
 
 
Production Services Segment:
 
 
 
Revenues
$
420,576

 
$
282,039

Operating costs
252,775

 
164,365

Production Services Segment margin
$
167,801

 
$
117,674

 
 
 
 
Combined:
 
 
 
Revenues
$
919,443

 
$
715,941

Operating costs
586,621

 
456,924

Combined margin
$
332,822

 
$
259,017

Adjusted EBITDA
$
249,283

 
$
183,870

Drilling Services Segment margin represents contract drilling revenues less contract drilling operating costs. Production Services Segment margin represents production services revenue less production services operating costs. We believe that Drilling Services Segment margin and Production Services Segment margin are useful measures for evaluating financial performance, although they are not measures of financial performance under U.S. Generally Accepted Accounting Principles (GAAP). However, Drilling Services Segment margin and Production Services Segment margin are common measures of operating performance used by investors, financial analysts, rating agencies and Pioneer’s management. Drilling Services Segment margin and Production Services Segment margin as presented may not be comparable to other similarly titled measures reported by other companies.
Adjusted EBITDA is a financial measure that is not in accordance with GAAP, and should not be considered (a) in isolation of, or as a substitute for, net income (loss), (b) as an indication of cash flows from operating activities or (c) as a measure of liquidity. In addition, Adjusted EBITDA does not represent funds available for discretionary use. We define Adjusted EBITDA as income (loss) before interest income (expense), taxes, depreciation, amortization

49


and any impairments. We use this measure, together with our GAAP financial metrics, to assess our financial performance and evaluate our overall progress towards meeting our long-term financial objectives. We believe that this non-GAAP financial measure is useful to investors and analysts in allowing for greater transparency of our operating performance and makes it easier to compare our results with those of other companies within our industry. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies.
A reconciliation of combined Drilling Services Segment margin and Production Services Segment margin to net income (loss), as reported, and a reconciliation of Adjusted EBITDA to net income (loss), as reported, are set forth in the following table.
 
Year ended December 31,
 
2012
 
2011
 
(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net income:
 
 
 
Combined margin
$
332,822

 
$
259,017

General and administrative
(85,603
)
 
(67,318
)
Bad debt recovery (expense)
440

 
(925
)
Other income (expense)
1,624

 
(6,904
)
Adjusted EBITDA
249,283

 
183,870

Depreciation and amortization
(164,717
)
 
(132,832
)
Impairment of equipment
(1,131
)
 
(484
)
Interest expense
(37,049
)
 
(29,721
)
Income tax expense
(16,354
)
 
(9,656
)
Net income
$
30,032

 
$
11,177

Our Drilling Services Segment experienced increases in its revenues and operating costs due to higher demand for our domestic drilling services in 2012 as compared to 2011, as our industry continues to recover from the downturn that bottomed in late 2009. Domestic revenues increased as a result of increasing oil prices and rig utilization and improved revenue rates particularly in oil-producing regions and in certain shale regions. Increases in domestic revenues and operating costs were partially offset by decreases in our international revenues and operating costs due to decreased utilization in Colombia.
Our Drilling Services Segment’s revenues increased by $65.0 million, or 15%, during 2012 as compared to 2011, primarily due to an increase in domestic drilling rig utilization and the addition of seven new-build drilling rigs which began operations during 2012. With the increase in demand for our drilling services during 2012, our revenue days increased by 13% during 2012 as compared to 2011, and our revenues per day increased by 2% or $464 per day, despite a decrease in our utilization in Colombia, where we have higher revenues per day. The increase in our domestic drilling rig utilization rate was also impacted by our decision to dispose of seven drilling rigs in September 2011 and another two drilling rigs in March 2012.
Our Drilling Services Segment’s operating costs increased by $41.3 million, or 14%, during 2012 as compared to 2011, primarily due to the increase in domestic utilization and the addition of seven new-build drilling rigs which began operations during 2012. Our operating costs per day increased by 1% or $191 per day, during 2012 as compared to 2011, primarily due to increases in supplies, repair and maintenance costs and increased mobilization costs for drilling rigs that were moved between our domestic drilling divisions during 2012. The increase in our operating costs per day was partially offset by a decrease in our international operating costs due to decreased utilization in Colombia, where we have higher operating costs per day.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain. As demand for drilling rigs decreases, daywork rates move down and we may switch to performing more turnkey drilling contracts to maintain higher utilization rates and to improve our Drilling Services Segment’s margins. Turnkey drilling contracts result in

50


higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts. During the years ended December 31, 2012 and 2011, we completed 11 and 17 turnkey contracts, respectively, representing 3% and 4% of our total drilling revenues for each year, respectively.
Our Production Services Segment's revenues increased by $138.5 million, or 49%, during 2012 as compared to 2011, while operating costs increased $88.4 million, or 54%. The acquisition of Go-Coil on December 31, 2011 resulted in an increase in our revenues and operating expenses during 2012 of $58.4 million and $40.9 million, respectively. The remaining increases in revenues and operating costs are primarily due to the expansion of our operations through fleet additions as well as higher demand for our wireline and well servicing offerings, which resulted in higher utilization rates and higher revenue rates charged for these services during the year ended December 31, 2012, as compared to 2011. During 2011 and 2012, we acquired a total of 34 well servicing rigs and 36 wireline units, resulting in an increase in both our revenues and operating costs. Utilization of our well servicing fleet also increased to 91% for the year ended December 31, 2012, as compared to 87% during 2011, while pricing increased by approximately 10%. The number of wireline jobs we completed increased by approximately 7% for the year ended December 31, 2012, as compared to 2011, and our average price per job increased by approximately 14%, which is partially due to a greater mix of higher priced jobs performed as well as increased demand.
Our general and administrative expense increased by approximately $18.3 million, or 27%, during 2012 as compared to 2011, primarily due to the overall expansion of our operations in both our drilling and production services segments. The acquisition of Go-Coil on December 31, 2011 resulted in an increase of $7.3 million in our general and administrative expense for the year ended December 31, 2012, as compared to 2011. Additionally, during 2012, we expanded our well servicing and wireline fleets by approximately 21% and 14%, respectively, and deployed seven new-build drilling rigs. The overall expansion of our business increased our general and administrative expense for the year ended December 31, 2012, as compared to 2011, including an increase of $5.5 million in payroll and compensation related expenses primarily resulting from the hiring of additional personnel to support our growth.
Our bad debt recovery for the year ended December 31, 2012 related to the collection of $0.5 million for an account receivable which had been written off prior to 2011.
Our other income for the year ended December 31, 2012 includes $0.6 million recognized for the redemption of certain Auction Rate Preferred Securities ("ARPSs") on October 1, 2012. Our other expense for the year ended December 31, 2011 primarily related to the $7.3 million net-worth tax expense for our Colombian operations, which was assessed on January 1, 2011, and was partially reduced by $0.5 million of income recognized for our ARPSs Call Option in January 2011.
Our depreciation and amortization expenses increased by $31.9 million during 2012, as compared to 2011, as a result of our expansion in both our drilling and production services segments. The expansion of our well servicing and wireline fleets resulted in an increase of approximately $12.5 million during the year ended December 31, 2012, as compared to 2011, and the acquisition of Go-Coil on December 31, 2011 resulted in an increase of $10.3 million. The remaining increase is primarily due to the expansion of our drilling services fleet through the addition of seven new-build drilling rigs that went into service in 2012 as well as capital expenditures for upgrades to our drilling rig fleet during 2012 and late 2011.
During the year ended December 31, 2012, we recorded impairment charges of $1.1 million in association with our decision to retire two drilling rigs, with most of their components to be used as spare parts, and to retire two wireline units and certain wireline equipment.
Our interest expense increased for the year ended December 31, 2012, as compared to the year ended December 31, 2011, primarily due to the issuance of our Senior Notes in November 2011. The issuance of our Senior Notes in November 2011 increased our overall debt balance in 2012. The overall increase in interest expense was partially offset by $10.2 million of capitalized interest during the year ended December 31, 2012, associated with the capital expenditures for upgrades to our drilling rig fleet and for our new-build drilling rigs.
Our effective income tax rate for the year ended December 31, 2012 was 35%, which is the same as the federal statutory rate in the United States, primarily due to the impact of state income taxes that were offset by lower effective tax rates in foreign jurisdictions, the effect of foreign translation and other permanent differences.

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Inflation
Wage rates for our operations personnel are impacted by inflationary pressures when the demand for drilling and production services increases and the availability of personnel is scarce. With the increase in demand from 2010 through 2011, and the resulting tightening of labor markets, we had a wage rate increase of approximately 10% across multiple drilling divisions in January 2012. During 2013, we have experienced modest wage rate increases in our Production Services Segment and we expect similar pressure in 2014.
Costs for rig repairs and maintenance, rig upgrades and new rig construction are also impacted by inflationary pressures when the demand for drilling services increases. We estimate that we experienced an increase in these costs of approximately 5% to 10% during 2012 and 2013, and we estimate that we will experience a more moderate increase in 2014.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
Revenue and Cost Recognition—Our Drilling Services Segment earns revenues by drilling oil and gas wells for our clients under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. Drilling contracts for individual wells are usually completed in less than 60 days. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. All our revenues are recognized net of applicable sales taxes.
Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the client and the possibility of litigation.
If a client defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.
The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.

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With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.
The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-term portions of deferred mobilization costs for certain drilling contracts. The liabilities “deferred revenues” and “other long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized. As of December 31, 2013 we had $0.7 million and $0.9 million of current deferred mobilization revenues and costs, respectively, and $0.4 million and $0.5 million of long-term deferred mobilization revenues and costs, respectively. Our deferred mobilization costs and revenues primarily related to long-term contracts for our new-build drilling rigs and long-term contracts for drilling rigs which we moved between drilling divisions. Amortization of deferred mobilization revenues was $5.3 million, $6.3 million and $5.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Our Production Services Segment earns revenues for well servicing, wireline services, coiled tubing services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.
The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. Our unbilled receivables totaled $49.5 million at December 31, 2013, of which $45.4 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2013 and $4.1 million related to unbilled receivables for our Production Services Segment.
Long-lived tangible and intangible assets—We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well servicing rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline, coiled tubing and fishing and rental services). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our long-lived tangible and intangible assets as of June 30, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was less than the carrying amount at June 30, 2013. We then performed a valuation of the assets which resulted in a non-cash impairment charge of $3.1 million to reduce our intangible asset carrying value of client relationships. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition

53


in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our impairment charge for our long-lived intangible assets of approximately $1 million. Similarly, a decrease of 1% in either of these assumptions would have led to an approximate $1 million increase to our impairment charge. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values and performing the impairment test are inherently uncertain and require management judgment.
Our impairment analysis did not result in any impairment charges to our coiled tubing tangible long-lived assets, substantially all of which was related to the 13 coiled tubing units. As discussed further below, we also recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.
Due to continued increases in competition in certain coiled tubing markets and lower than anticipated operating results, we performed another impairment analysis of our long-lived tangible and intangible assets as of December 31, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was in excess of the carrying amount and concluded that no impairment existed as of December 31, 2013. The future undiscounted cash flows used in our impairment analysis include projected increases in utilization and pricing from what we have historically experienced. If we fail to meet the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services, then we may incur a future impairment.
In September 2013, we evaluated the drilling rigs in our fleet and decided to place eight of our mechanical drilling rigs as held for sale and recognized an impairment charge to reduce the carrying value of these assets to their estimated fair value, which was based on their sales price. The decision to sell these drilling rigs was primarily due to a decrease in demand for non-top drive mechanical rigs that drill vertical oil and gas wells. Our remaining drilling rig fleet includes mechanical rigs that are currently working, but which may have reduced utilization if demand for vertical drilling continues to soften. We performed an impairment evaluation on the remaining drilling rigs in our fleet which are similar to those that we decided to sell. In order to estimate our future undiscounted cash flows from the use and eventual disposition of these assets, we incorporated probabilities of selling these rigs in the near term, versus working them through the end of their remaining useful lives. Our analysis led us to conclude that no impairment presently exists for the remaining similar drilling rigs. If the demand for vertical drilling continues to soften and these remaining mechanical rigs become idle for an extended amount of time, then the probability of a near term sale may increase, which would likely result in an impairment charge, based on the current market value of these drilling rigs. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.
Goodwill—Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million of goodwill at December 31, 2011, all of which was allocated to the coiled tubing services reporting unit within our Production Services Segment.
We perform a qualitative assessment of goodwill annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. In addition, these circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment of goodwill.

54


If our qualitative assessment of goodwill indicates a possible impairment, we test for goodwill impairment using a two-step process. First, the fair value of each reporting unit with goodwill is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value.
When estimating fair values of a reporting unit for our goodwill impairment test, we use an income approach which provides an estimated fair value based on the reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted at a rate that is based on our weighted average cost of capital and estimated industry average rates for cost of capital. To ensure the reasonableness of the estimated fair value of our reporting units, we consider current industry market multiples and we perform a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units.
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our goodwill as of June 30, 2013. We determined that the fair value of our coiled tubing services reporting unit was less than its carrying value, including goodwill, and therefore, we performed the second step of the goodwill impairment test which led us to conclude that there would be no remaining implied fair value attributable to goodwill. Accordingly, we recorded a non-cash impairment charge of $41.7 million to reduce the carrying value of our goodwill to zero. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services and the weighted average cost of capital (discount rate) used in order to calculate the discounted cash flows for the reporting unit. These inputs are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. We assumed a 13% discount rate to estimate the fair value of the coiled tubing services reporting unit. A decrease in this assumption of 5% would have resulted in a decrease to our goodwill impairment charge of approximately $3.5 million. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our goodwill impairment charge of approximately $2 million or $3 million, respectively. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.
Deferred taxes—We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, well servicing rigs, wireline units and coiled tubing units over 2 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, well servicing rigs, wireline units and coiled tubing units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, well servicing rig, wireline unit or coiled tubing unit, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.
Accounting estimates—Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful

55


accounts, our determination of depreciation and amortization expenses, our estimates of fair value for impairment evaluations, our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, and our estimate of compensation related accruals.
We consider the recognition of revenues and costs on turnkey and footage contracts to be critical accounting estimates. For these types of contracts, we recognize revenues and accrue estimated costs based on our estimate of the number of days to complete each contract and our estimate of the total costs to complete the contract. Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released.
Our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. However, our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.
We believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make reasonable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. However, during periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.
During the year ended December 31, 2013, we experienced a loss of approximately $17,000 on one turnkey contract completed. We did not experience a loss on any of the turnkey contracts completed during 2012. During 2011, we experienced a loss of $1.5 million on two turnkey contracts completed. As of December 31, 2013, we did not have any turnkey contracts in progress.
We estimate an allowance for doubtful accounts based on the creditworthiness of our clients as well as general economic conditions. We evaluate the creditworthiness of our clients based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the client. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new clients to establish escrow accounts or make prepayments. We had an allowance for doubtful accounts of $1.4 million at December 31, 2013.
Our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes is also a critical accounting estimate. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, production, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 2 to 25 years. We record the same depreciation expense whether a drilling rig, well servicing rig, wireline unit or coiled tubing unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our more than 40 years of experience in the oilfield services industry with similar equipment.
As of December 31, 2013, we had $98.0 million of deferred tax assets related to foreign and domestic net operating loss and AMT credit carryforwards available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against the current year taxable income and taxable income that we have estimated in future periods.

56


Our accrued insurance premiums and deductibles as of December 31, 2013 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $3.1 million and our workers’ compensation, general liability and auto liability insurance of approximately $7.3 million. We have stop-loss coverage of $150,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company's historical claim development data, and we accrue the costs of administrative services associated with claims processing.
Our stock-based compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our stock-based compensation expense, employee related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
We are subject to interest rate market risk on our variable rate debt. As of December 31, 2013, we had $80.0 million outstanding under our Revolving Credit Facility, which is our only variable rate debt. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or decrease, respectively, in interest expense of approximately $0.8 million, and a corresponding increase or decrease, respectively, in net income of approximately $0.5 million during the year ended December 31, 2013. This potential increase or decrease is based on the simplified assumption that the level of variable rate debt remains constant with an immediate across-the-board interest rate increase or decrease as of January 1, 2013.
Foreign Currency Risk
While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar has and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in our consolidated financial statements.
The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in foreign currency losses of $2.7 million for the year ended December 31, 2013.


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Item 8.
Financial Statements and Supplementary Data

PIONEER ENERGY SERVICES CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 



58


Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Pioneer Energy Services Corp.:
We have audited the accompanying consolidated balance sheets of Pioneer Energy Services Corp. and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 Pioneer Energy Services Corp. and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Energy Services Corp.’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 13, 2014 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
San Antonio, Texas
February 13, 2014



59


Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Pioneer Energy Services Corp.:
We have audited Pioneer Energy Services Corp.'s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Energy Services Corp.’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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pioneer Energy Services Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Energy Services Corp. and subsidiaries as of December 31, 2013 and 2011, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2013, and our report dated February 13, 2014 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
San Antonio, Texas
February 13, 2014


60


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
December 31,
2013
 
December 31,
2012
 
(In thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
27,385

 
$
23,733

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
115,908

 
115,070

Unbilled receivables
49,535

 
35,140

Insurance recoveries
8,607

 
6,518

Income taxes and other
2,310

 
2,116

Deferred income taxes
13,092

 
11,058

Inventory
13,232

 
12,111

Prepaid expenses and other current assets
9,311

 
13,040

Total current assets
239,380

 
218,786

Property and equipment, at cost
1,724,124

 
1,698,517

Less accumulated depreciation
786,467

 
684,177

Net property and equipment
937,657

 
1,014,340

Intangible assets
32,269

 
43,843

Goodwill
—

 
41,683

Noncurrent deferred income taxes
1,156

 
5,519

Other long-term assets
19,161

 
15,605

Total assets
$
1,229,623

 
$
1,339,776

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
43,718

 
$
83,823

Current portion of long-term debt
2,847

 
872

Deferred revenues
699

 
3,880

Accrued expenses:
 
 
 
Payroll and related employee costs
30,020

 
27,991

Insurance premiums and deductibles
10,940

 
9,708

Insurance claims and settlements
8,607

 
6,348

Interest
12,275

 
12,343

Other
11,727

 
11,585

Total current liabilities
120,833

 
156,550

Long-term debt, less current portion
499,666

 
518,725

Noncurrent deferred income taxes
84,636

 
108,838

Other long-term liabilities
6,055

 
7,983

Total liabilities
711,190

 
792,096

Commitments and contingencies (Note 12)

 

Shareholders’ equity:
 
 
 
Preferred stock, 10,000,000 shares authorized; none issued and outstanding
—

 
—

Common stock $.10 par value; 100,000,000 shares authorized; 62,534,636 and 62,032,517 shares outstanding at December 31, 2013 and 2012, respectively
6,275

 
6,217

Additional paid-in capital
456,812

 
449,554

Treasury stock, at cost; 219,304 and 134,612 shares at December 31, 2013 and 2012, respectively
(1,895
)
 
(1,264
)
Accumulated earnings
57,241

 
93,173

Total shareholders’ equity
518,433

 
547,680

Total liabilities and shareholders’ equity
$
1,229,623

 
$
1,339,776


See accompanying notes to consolidated financial statements.

61


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 
 
Year ended December 31,
 
2013
 
2012
 
2011
 
(In thousands, except per share data)
Revenues:
 
 
 
 
 
Drilling services
$
528,327

 
$
498,867

 
$
433,902

Production services
431,859

 
420,576

 
282,039

Total revenues
960,186

 
919,443

 
715,941

Costs and expenses:
 
 
 
 

Drilling services
351,630

 
333,846

 
292,559

Production services
276,808

 
252,775

 
164,365

Depreciation and amortization
187,918

 
164,717

 
132,832

General and administrative
95,000

 
85,603

 
67,318

Bad debt expense (recovery)
767

 
(440
)
 
925

Impairment charges
54,292

 
1,131

 
484

Total costs and expenses
966,415

 
837,632

 
658,483

Income (loss) from operations
(6,229
)
 
81,811

 
57,458

Other (expense) income:
 
 
 
 

Interest expense
(48,310
)
 
(37,049
)
 
(29,721
)
Other
(1,239
)
 
1,624

 
(6,904
)
Total other expense
(49,549
)
 
(35,425
)
 
(36,625
)
Income (loss) before income taxes
(55,778
)
 
46,386

 
20,833

Income tax benefit (expense)
19,846

 
(16,354
)
 
(9,656
)
Net income (loss)
$
(35,932
)
 
$
30,032

 
$
11,177

 
 
 
 
 
 
Income (loss) per common share—Basic
$
(0.58
)
 
$
0.49

 
$
0.19

 
 
 
 
 
 
Income (loss) per common share—Diluted
$
(0.58
)
 
$
0.48

 
$
0.19

 
 
 
 
 
 
Weighted average number of shares outstanding—Basic
62,213

 
61,780

 
57,390

 
 
 
 
 
 
Weighted average number of shares outstanding—Diluted
62,213

 
62,762

 
58,779












See accompanying notes to consolidated financial statements.

62


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
 
Shares
 
Amount
 
Additional Paid In Capital
 
Accumulated Earnings
 
Total Shareholders' Equity
Common
 
Treasury
Common
 
Treasury
 
(In thousands)
Balance as of December 31, 2010
54,253

 
(25
)
 
$
5,425

 
$
(161
)
 
$
339,105

 
$
51,964

 
$
396,333

Net income
—

 
—

 
—

 
—

 
—

 
11,177

 
11,177

Sale of common stock, net of offering costs
6,900

 
—

 
690

 
—

 
93,653

 
—

 
94,343

Exercise of options and related income tax effect
517

 
—

 
52

 
—

 
2,832

 
—

 
2,884

Purchase of treasury stock
—

 
(70
)
 
—

 
(743
)
 
—

 
—

 
(743
)
Income tax effect of stock option forfeitures and expirations
—

 
—

 
—

 
—

 
(254
)
 
—

 
(254
)
Issuance of restricted stock
207

 
—

 
21

 
—

 
(21
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
6,705

 
—

 
6,705

Balance as of December 31, 2011
61,877

 
(95
)
 
$
6,188

 
$
(904
)
 
$
442,020

 
$
63,141

 
$
510,445

Net income
—

 
—

 
—

 
—

 
—

 
30,032

 
30,032

Exercise of options and related income tax effect
172

 
—

 
17

 
—

 
676

 
—

 
693

Purchase of treasury stock
—

 
(40
)
 
—

 
(360
)
 
—

 
—

 
(360
)
Income tax effect of stock option forfeitures and expirations
—

 
—

 
—

 
—

 
(449
)
 
—

 
(449
)
Issuance of restricted stock
117

 
—

 
12

 
—

 
(12
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
7,319

 
—

 
7,319

Balance as of December 31, 2012
62,166

 
(135
)
 
$
6,217

 
$
(1,264
)
 
$
449,554

 
$
93,173

 
$
547,680

Net loss
—

 
—

 
—

 
—

 
—

 
(35,932
)
 
(35,932
)
Exercise of options and related income tax effect
271

 
—

 
27

 
—

 
1,239

 
—

 
1,266

Purchase of treasury stock
—

 
(85
)
 
—

 
(631
)
 
—

 
—

 
(631
)
Income tax effect of restricted stock vesting
—

 
—

 
—

 
—

 
(265
)
 
—

 
(265
)
Income tax effect of stock option forfeitures and expirations
—

 
—

 
—

 
—

 
(56
)
 
—

 
(56
)
Issuance of restricted stock
316

 
—

 
31

 
—

 
(31
)
 
—

 
—

Stock-based compensation expense
—

 
—

 
—

 
—

 
6,371

 
—

 
6,371

Balance as of December 31, 2013
62,753

 
(220
)
 
$
6,275

 
$
(1,895
)
 
$
456,812

 
$
57,241

 
$
518,433
















See accompanying notes to consolidated financial statements.

63


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Year ended December 31,
 
2013
 
2012
 
2011
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
 
Net income (loss)
$
(35,932
)
 
$
30,032

 
$
11,177

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
187,918

 
164,717

 
132,832

Allowance for doubtful accounts
801

 
76

 
787

(Gain) loss on dispositions of property and equipment
(1,421
)
 
(1,199
)
 
151

Stock-based compensation expense
6,371

 
7,319

 
6,705

Amortization of debt issuance costs, discount and premium
3,095

 
2,985

 
3,302

Impairment charges
54,292

 
1,131

 
484

Deferred income taxes
(22,125
)
 
13,303

 
8,098

Change in other long-term assets
(5,741
)
 
(3,865
)
 
2,828

Change in other long-term liabilities
(1,928
)
 
(1,173
)
 
(623
)
Changes in current assets and liabilities:
 
 
 
 
 
Receivables
(16,168
)
 
(12,807
)
 
(46,802
)
Inventory
(1,121
)
 
(927
)
 
(2,161
)
Prepaid expenses and other current assets
3,729

 
(1,266
)
 
(1,965
)
Accounts payable
(166
)
 
2,431

 
9,331

Deferred revenues
(3,181
)
 
(86
)
 
297

Accrued expenses
6,157

 
(1,305
)
 
20,438

Net cash provided by operating activities
174,580

 
199,366

 
144,879

 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
Acquisition of production services business of Go-Coil
—

 
—

 
(109,035
)
Acquisition of other production services businesses
—

 
—

 
(6,502
)
Purchases of property and equipment
(165,356
)
 
(364,324
)
 
(210,066
)
Proceeds from sale of property and equipment
13,836

 
3,093

 
5,550

Proceeds from sale of auction rate securities
—

 
—

 
12,569

Proceeds from insurance recoveries
844

 
—

 
—

Net cash used in investing activities
(150,676
)
 
(361,231
)
 
(307,484
)
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
Debt repayments
(60,874
)
 
(874
)
 
(113,158
)
Proceeds from issuance of debt
40,000

 
100,000

 
250,750

Debt issuance costs
(13
)
 
(58
)
 
(7,285
)
Proceeds from exercise of options
1,266

 
693

 
2,884

Proceeds from common stock, net of offering costs of $5,707
—

 
—

 
94,343

Purchase of treasury stock
(631
)
 
(360
)
 
(743
)
Net cash provided by (used in) financing activities
(20,252
)
 
99,401

 
226,791

 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
3,652

 
(62,464
)
 
64,186

Beginning cash and cash equivalents
23,733

 
86,197

 
22,011

Ending cash and cash equivalents
$
27,385

 
$
23,733

 
$
86,197

 
 
 
 
 
 
Supplementary disclosure:
 
 
 
 
 
Interest paid
$
46,274

 
$
44,317

 
$
26,955

Income tax paid
$
3,154

 
$
731

 
$
952

 
See accompanying notes to consolidated financial statements.

64


PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.    Organization and Summary of Significant Accounting Policies
Business
Pioneer Energy Services provides drilling services and production services to a diverse group of independent and large oil and gas exploration and production companies throughout much of the onshore oil and gas producing regions of the United States and internationally in Colombia. We also provide coiled tubing and wireline services offshore in the Gulf of Mexico.
Our Drilling Services Segment provides contract land drilling services with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
Drilling Division
Rig Count
South Texas
14

West Texas
18

North Dakota
11

Utah
7

Appalachia
4

Colombia
8

 
62

In early 2011, we began construction of ten new-build AC drilling rigs that are fit for purpose for domestic shale plays, based on term contracts. We deployed seven of these new-build drilling rigs during 2012, and deployed the final three in early 2013. All of our new-build drilling rigs are currently operating in shale or unconventional plays under long-term drilling contracts.
During the second quarter of 2013, we sold two mechanical drilling rigs that were previously idle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. In September 2013, we decided to sell eight of our mechanical drilling rigs, for which we recognized an impairment charge of $9.2 million dollars during the third quarter. All eight drilling rigs were classified as held for sale at September 30, 2013 and were sold in late October 2013. We did not incur any additional gain or loss upon the sale of these rigs.
As of December 31, 2013, 50 of our 62 drilling rigs are earning revenues under drilling contracts, 39 of which are under term contracts, and we are actively marketing all of our idle drilling rigs. All eight of our drilling rigs in Colombia are currently under term contracts that extend through the end of 2014, seven of which are currently working. The remaining rig will begin working under its term contract after it is upgraded from 1,000 horsepower to 1,500 horsepower, which we expect will be completed by the end of the first quarter of 2014.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with existing or potential clients. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed.
Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of December 31, 2013, we have a fleet of 109 well servicing rigs consisting of ninety-nine 550 horsepower rigs and ten 600 horsepower

65


rigs, all of which are currently operating or are being actively marketed. We currently provide wireline services and coiled tubing services with a fleet of 119 wireline units and 13 coiled tubing units, and we provide rental services with a gross book value of $17.3 million in fishing and rental tools.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of Pioneer Energy Services Corp. and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.
In preparing the accompanying consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our determination of depreciation and amortization expenses, our estimates of fair value for impairment evaluations, our estimate of deferred taxes, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, and our estimate of compensation related accruals.
In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred after December 31, 2013, through the filing of this Form 10-K, for inclusion as necessary.
Drilling Contracts
Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used, and the anticipated duration of the work to be performed. Spot market contracts generally provide for the drilling of a single well and typically permit the client to terminate on short notice. During periods of high rig demand, or for our newly constructed rigs, we enter into longer-term drilling contracts. Currently, we have contracts with terms of six months to four years in duration. As of December 31, 2013, we have 39 drilling rigs operating under term contracts, which if not renewed at the end of their terms, will expire as follows:
 
 
 
 
Term Contract Expiration by Period
 
 
Total
Term Contracts
 
Within
6 Months
 
6 Months
to 1 Year
 
1 Year to
18 Months
 
18 Months
to 2 Years
 
2 to 4 Years
United States
 
33

 
18

 
4

 
5

 
1

 
5

Colombia
 
6

 
—

 
6

 
—

 
—

 
—

 
 
39

 
18

 
10

 
5

 
1

 
5

Foreign Currencies
Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense.
Revenue and Cost Recognition
Drilling Services—Our Drilling Services Segment earns revenues by drilling oil and gas wells for our clients under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. Drilling contracts for individual wells are usually completed in less than 60 days. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. All our revenues are recognized net of applicable sales taxes.

66


Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the client and the possibility of litigation.
If a client defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.
The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.
The assets “prepaid expenses and other current assets” and “other long-term assets” include the current and long-term portions of deferred mobilization costs for certain drilling contracts. The liabilities “deferred revenues” and “other long-term liabilities” include the current and long-term portions of deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized. As of December 31, 2013 we had $0.7 million and $0.9 million of current deferred mobilization revenues and costs, respectively, and $0.4 million and $0.5 million of long-term deferred mobilization revenues and costs, respectively. Our deferred mobilization costs and revenues primarily related to long-term contracts for our new-build drilling rigs and long-term contracts for drilling rigs which we moved between drilling divisions. Amortization of deferred mobilization revenues was $5.3 million, $6.3 million and $5.1 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Production Services—Our Production Services Segment earns revenues for well servicing, wireline services, coiled tubing services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.

67


Cash and Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at December 31, 2013 and 2012 were $0.7 million and $3.1 million, respectively.
Trade Accounts Receivable
We record trade accounts receivable at the amount we invoice our clients. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our clients and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.
We review our allowance for doubtful accounts on a monthly basis. Our typical drilling contract provides for payment of invoices in 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. Our production services terms generally provide for payment of invoices in 30 days. Balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our clients.
The changes in our allowance for doubtful accounts consist of the following (amounts in thousands):
 
Year ended December 31,
 
2013
 
2012
 
2011
Balance at beginning of year
$
1,044

 
$
994

 
$
712

Increase in allowance charged to expense
801

 
76

 
787

Accounts charged against the allowance, net of recoveries
(489
)
 
(26
)
 
(505
)
Balance at end of year
$
1,356

 
$
1,044

 
$
994

Unbilled Accounts Receivable
The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services completed but not yet invoiced. We typically invoice our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract. Turnkey and footage drilling contracts are invoiced upon completion of the contract.
Our unbilled receivables totaled $49.5 million at December 31, 2013, of which $45.4 million represented revenue recognized but not yet billed on daywork drilling contracts in progress at December 31, 2013 and $4.1 million related to unbilled receivables for our Production Services Segment.
Inventories
Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services Segment’s operations in Colombia and supplies held for use by our Production Services Segment’s operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets include items such as insurance, rent deposits and fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Prepaid expenses and other current assets also include the current portion of deferred mobilization costs for certain drilling contracts that are recognized on a straight-line basis over the contract term.

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Investments
At December 31, 2010, we held $15.9 million (par value) of auction rate preferred securities (“ARPSs”), which were variable-rate preferred securities with a long-term maturity that were classified as held for sale. On January 19, 2011, we entered into an agreement with a financial institution to sell the ARPSs for $12.6 million, which represented 79% of the par value, plus accrued interest. The $3.3 million difference between the ARPSs’ par value of $15.9 million and the sales price of $12.6 million represented an other-than-temporary impairment of the ARPSs investment which was reflected as an impairment of investments in our consolidated statement of operations for the year ended December 31, 2010.
Under the ARPSs sales agreement, we retained the unilateral right for a period ending January 7, 2013 to: (a) repurchase all the ARPSs that were sold at the $12.6 million price at which they were initially sold to the financial institution; and (b) if not repurchased, receive additional proceeds from the financial institution upon redemption of the ARPSs by the original issuer of these securities (collectively, the “ARPSs Call Option”). Upon origination, the fair value of the ARPSs Call Option was estimated to be $0.6 million and was recognized as other income in our consolidated statement of operations for 2011. The ARPSs Call Option was subsequently carried at fair value on our consolidated balance sheets with changes in fair value recognized as "other income (loss)" in our consolidated statement of operations.
On October 1, 2012, we received proceeds of $0.6 million from the redemption of certain ARPSs by the original issuer of the securities, which we recognized as other income in our consolidated statement of operations for the year ended December 31, 2012. The ARPSs Call Option had a fair value of zero as of December 31, 2012 and expired on January 7, 2013.
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated useful lives of the assets using the straight-line method. We record the same depreciation expense whether a rig is idle or working. We charge our expenses for maintenance and repairs to operating costs. We capitalize expenditures for renewals and betterments to the appropriate property and equipment accounts.
We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well servicing rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline, coiled tubing and fishing and rental services). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.

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Intangible Assets
Our intangible assets consist of the following components as of December 31, 2013 and 2012 (amounts in thousands):
 
December 31,
 
2013
 
2012
Cost:
 
 
 
Client relationships
$
63,168

 
$
66,273

Non-compete agreements
1,355

 
1,355

Trademarks / trade names
575

 
568

Accumulated amortization:
 
 
 
Client relationships
(31,584
)
 
(23,667
)
Non-compete agreements
(745
)
 
(436
)
Trademarks / trade names
(500
)
 
(250
)
 
$
32,269

 
$
43,843

Substantially all of our intangible assets were recorded in connection with the acquisitions of production services businesses and are subject to amortization. The cost of our client relationships, trademarks and trade names are amortized using the straight-line method over their respective estimated economic useful lives which range from two to nine years. Amortization expense for our non-compete agreements is calculated using the straight-line method over the period of the agreements which range from three to seven years. Amortization expense was $8.5 million, $8.7 million and $4.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. Amortization expense is estimated to be approximately $8.0 million, $7.9 million, $5.1 million, $3.8 million and $3.8 million for the years ending December 31, 2014, 2015, 2016, 2017 and 2018, respectively. Actual amortization amounts may be different due to future acquisitions, impairments, changes in amortization periods, or other factors.
We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well servicing rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline, coiled tubing and fishing and rental services). If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.

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Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our long-lived tangible and intangible assets as of June 30, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was less than the carrying amount at June 30, 2013. We then performed a valuation of the assets which resulted in a non-cash impairment charge of $3.1 million to reduce our intangible asset carrying value of client relationships. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our impairment charge for our long-lived intangible assets of approximately $1 million. Similarly, a decrease of 1% in either of these assumptions would have led to an approximate $1 million increase to our impairment charge. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values and performing the impairment test are inherently uncertain and require management judgment.
As of December 31, 2013, our carrying value of intangible assets related to the acquisition of Go-Coil was $21.8 million. Due to continued increases in competition in certain coiled tubing markets and lower than anticipated operating results, we performed another impairment analysis of our long-lived tangible and intangible assets as of December 31, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was in excess of the carrying amount and concluded that no impairment existed as of December 31, 2013. The future undiscounted cash flows used in our impairment analysis include projected increases in utilization and pricing from what we have historically experienced. If we fail to meet the projected increases in utilization and pricing for our coiled tubing services, or in the event of significant unfavorable changes in the forecasted cash flows or key assumptions used in our analysis, the most significant of these being the projected utilization and pricing of our coiled tubing services, then we may incur a future impairment.
Our impairment analysis did not result in any impairment charges to our coiled tubing tangible long-lived assets, substantially all of which was related to the 13 coiled tubing units. As discussed further below, we also recorded a non-cash impairment charge to reduce the carrying value of goodwill to zero.
Goodwill
Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. In connection with the acquisition of the production services business from Go-Coil, we recorded $41.7 million of goodwill at December 31, 2011, all of which was allocated to the coiled tubing services reporting unit within our Production Services Segment.
We perform a qualitative assessment of goodwill annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. In addition, these circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment of goodwill.
If our qualitative assessment of goodwill indicates a possible impairment, we test for goodwill impairment using a two-step process. First, the fair value of each reporting unit with goodwill is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, then the fair value of the reporting unit's goodwill is determined by allocating the unit's fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the

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impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value.
When estimating fair values of a reporting unit for our goodwill impairment test, we use an income approach which provides an estimated fair value based on the reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted at a rate that is based on our weighted average cost of capital and estimated industry average rates for cost of capital. To ensure the reasonableness of the estimated fair value of our reporting units, we consider current industry market multiples and we perform a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units.
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our goodwill as of June 30, 2013. We determined that the fair value of our coiled tubing services reporting unit was less than its carrying value, including goodwill, and therefore, we performed the second step of the goodwill impairment test which led us to conclude that there would be no remaining implied fair value attributable to goodwill. Accordingly, we recorded a non-cash impairment charge of $41.7 million to reduce the carrying value of our goodwill to zero. This impairment charge did not have an impact on our liquidity or debt covenants; however, it was a reflection of the increased competition in certain coiled tubing markets where we operate and a decline in our projected cash flows for the coiled tubing reporting unit.
The most significant inputs used in our impairment analysis include the projected utilization and pricing of our coiled tubing services and the weighted average cost of capital (discount rate) used in order to calculate the discounted cash flows for the reporting unit. These inputs are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. We assumed a 13% discount rate to estimate the fair value of the coiled tubing services reporting unit. A decrease in this assumption of 5% would have resulted in a decrease to our goodwill impairment charge of approximately $3.5 million. An increase of 1% in either the utilization or pricing assumptions would have resulted in a decrease to our goodwill impairment charge of approximately $2 million or $3 million, respectively. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.
Other Long-Term Assets
Other long-term assets consist of cash deposits related to the deductibles on our workers’ compensation insurance policies, the long-term portion of deferred mobilization costs, debt issuance costs, net of amortization, and noncurrent prepaid taxes in Colombia which are creditable against future income taxes.
Other Current Liabilities
Our other accrued expenses include accruals for items such as property tax, sales tax, professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Our other accrued expenses also consist of the current portion of the Colombian net equity tax.
Other Long-Term Liabilities
Our other long-term liabilities consist of the noncurrent portion of deferred mobilization revenues, liabilities associated with our long-term compensation plans, the noncurrent portion of the Colombia net equity tax and other deferred liabilities.

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Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired common stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of treasury stock shares are credited or charged to additional paid in capital using the average cost method.
Stock-based Compensation
We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.
We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the market price of our common stock on the exercise date over the exercise price of the stock options. We report all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows.
Income Taxes
We follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. The effect of a change in tax rates on deferred tax assets and liabilities is reflected in income in the period during which the change occurs. A recent change in Colombia tax rates is described in more detail in Note 6, Income Taxes.
Reclassifications
Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.
2.    Acquisitions
On December 31, 2011, we acquired Go-Coil, L.L.C., a Louisiana limited liability company (“Go-Coil”) which provided coiled tubing services with a fleet of seven onshore units and three offshore units through its facilities in Louisiana, Texas, Oklahoma and Pennsylvania. The aggregate purchase price for the acquisition was approximately $110.4 million, which consisted of assets acquired of $114.9 million and liabilities assumed of $4.5 million. We funded the acquisition with cash on hand that was primarily generated from the proceeds of the Senior Notes issued in November 2011, as described in Note 3, Long-term Debt.

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The following table summarizes the allocation of the purchase price to the estimated fair value of the assets acquired and liabilities assumed as of the date of acquisition (amounts in thousands):
Cash acquired
$
313

Other current assets
9,068

Property and equipment
30,103

Intangibles and other assets
33,695

Goodwill
41,683

Total assets acquired
$
114,862

Current liabilities
4,337

Long-term debt
131

Total liabilities assumed
4,468

Net assets acquired
$
110,394

The following unaudited pro forma consolidated summary financial information gives effect of the acquisition of the production services business from Go-Coil as though it was effective as of the beginning of the year ended December 31, 2011. Pro forma adjustments primarily relate to additional depreciation, amortization, interest and tax expenses, as well as the removal of approximately $14.1 million of nonrecurring costs, primarily related to discontinued compensation arrangements and acquisition related costs. The pro forma information reflects our company’s historical data and Go-Coil's historical data for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed the acquisition on January 1, 2011, or what we may achieve in the future and should be read in conjunction with the accompanying financial statements.
 
Pro Forma
 
For the year ended December 31, 2011
 
(in thousands)
Total revenues
$
762,978

Net earnings
$
8,412

Earnings per common share:
 
Basic
$
0.15

Diluted
$
0.14

The acquisition of the coiled tubing services business from Go-Coil was accounted for as an acquisition of a business in accordance with ASC Topic 805, Business Combinations. The purchase price allocation for the Go-Coil acquisition was finalized as of June 30, 2012. Goodwill was recognized as part of the Go-Coil acquisition, since the purchase price exceeded the estimated fair value of the assets acquired and liabilities assumed. We believe that the goodwill relates to the acquired workforce, future synergies between our existing service offerings and the ability to expand our service offerings.
Prior to the Go-Coil acquisition, we completed four separate acquisitions in 2011 of other production services businesses for a total of $6.5 million in cash. The identifiable assets recorded in connection with these acquisitions included fixed assets of $5.2 million, representing six wireline units and two well servicing rigs, and intangible assets of $1.3 million representing client relationships and non-competition agreements. We did not recognize any goodwill in conjunction with these acquisitions and no contingent assets or liabilities were assumed. These four acquisitions have been accounted for as acquisitions of businesses in accordance with ASC Topic 805, Business Combinations.

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3.    Property and Equipment
As of December 31, 2013, the estimated useful lives and costs of our asset classes are as follows:
 
Lives    
 
Cost
 
 
 
(amounts in
 thousands)
Drilling rigs and equipment
3 - 25
 
$
1,223,621

Well servicing rigs and equipment
3 - 20
 
205,409

Wireline units and equipment
2 - 10
 
128,800

Coiled tubing units and equipment
1 - 7
 
47,761

Fishing and rental tools and equipment
3 - 15
 
17,264

Vehicles
3 - 20
 
65,796

Office equipment
3 - 10
 
9,274

Buildings and improvements
3 - 40
 
23,931

Land
—
 
2,268

 
 
 
$
1,724,124

As of December 31, 2013 and 2012, we had incurred $19.4 million and $134.9 million, respectively, in construction costs for ongoing projects, primarily for our new-build drilling rigs and additions to our production services fleets. During the years ended December 31, 2013, 2012 and 2011, we capitalized $0.9 million, $10.2 million and $2.3 million, respectively, of interest costs incurred primarily during the construction periods of new-build drilling rigs and other drilling equipment.
We recorded gains on disposition of our property and equipment of $1.4 million, gains of $1.2 million and losses of $0.2 million during the years ended December 31, 2013, 2012 and 2011, respectively, in our drilling and production services costs and expenses. During the second quarter of 2013, we sold two mechanical drilling rigs that were previously idle in our East Texas division, for which we recognized an associated gain of approximately $0.8 million. Additionally, we disposed of a total of four wireline units during 2013, as well as other wireline equipment.
We recorded impairment charges on our property and equipment of $9.2 million, $1.1 million and $0.5 million for the year ended December 31, 2013, 2012 and 2011, respectively. During the third quarter of 2013, we decided to place eight of our mechanical drilling rigs as held for sale, and we recognized an impairment loss of $9.2 million in order to reduce the carrying value of these assets to their estimated fair value, based on their sales price. The sales of all eight drilling rigs were completed in late October 2013 and we did not incur any additional gain or loss upon the sale of these rigs. We also recorded an impairment of $0.3 million during the third quarter of 2013 in association with our decision to sell certain production services equipment. In March 2012, we retired two mechanical drilling rigs, with most of their components to be used as spare parts, as well as two wireline units and other wireline equipment, and recognized an associated impairment charge of $1.1 million. In September 2011, we decided to place six mechanical drilling rigs as held for sale and to retire another drilling rig from our fleet, with most of its components to be used as spare parts. Sales of all six mechanical drilling rigs were completed by mid November 2011 and we recognized an impairment charge of $0.5 million in September 2011 in association with our decision to dispose of these seven drilling rigs.
We evaluate for potential impairment of long-lived tangible and intangible assets subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and well servicing rigs. In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of long-lived tangible and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for the individual reporting units (well servicing, wireline, coiled tubing and fishing and rental services). For

75


our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we would determine the fair value of the asset group. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment.
In September 2013, we evaluated the drilling rigs in our fleet and decided to place eight of our mechanical drilling rigs as held for sale and recognized an impairment charge to reduce the carrying value of these assets to their estimated fair value, which was based on their sales price. The decision to sell these drilling rigs was primarily due to a decrease in demand for non-top drive mechanical rigs that drill vertical oil and gas wells. Our remaining drilling rig fleet includes mechanical rigs that are currently working, but which may have reduced utilization if demand for vertical drilling continues to soften. We performed an impairment evaluation on the remaining drilling rigs in our fleet which are similar to those that we decided to sell. In order to estimate our future undiscounted cash flows from the use and eventual disposition of these assets, we incorporated probabilities of selling these rigs in the near term, versus working them through the end of their remaining useful lives. Our analysis led us to conclude that no impairment presently exists for the remaining similar drilling rigs. If the demand for vertical drilling continues to soften and these remaining mechanical rigs become idle for an extended amount of time, then the probability of a near term sale may increase, which would likely result in an impairment charge, based on the current market value of these drilling rigs. Although we believe the assumptions and estimates used in our analysis are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.
Due to several significant adverse factors affecting our coiled tubing services reporting unit, including increased competition in certain coiled tubing markets, turnover of key personnel and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our long-lived tangible and intangible assets as of June 30, 2013. We determined that the sum of the estimated future undiscounted net cash flows for our coiled tubing services reporting unit was less than the carrying amount, and recorded impairment charges to reduce the carrying value of our goodwill to zero and to reduce the carrying value of our intangibles to estimated fair value as of June 30, 2013. However, our impairment analysis did not result in any impairment charges to our coiled tubing property and equipment.
4.     Debt
Our debt consists of the following (amounts in thousands):
 
December 31, 2013
 
December 31, 2012
Senior secured revolving credit facility
$
80,000

 
$
100,000

Senior notes
419,586

 
418,617

Other
2,927

 
980

 
502,513

 
519,597

Less current portion
(2,847
)
 
(872
)
 
$
499,666

 
$
518,725

Senior Secured Revolving Credit Facility
We have a credit agreement, as amended on June 30, 2011, with Wells Fargo Bank, N.A. and a syndicate of lenders which provides for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line loans, of up to an aggregate principal amount of $250 million, all of which matures on June 30, 2016 (the “Revolving Credit Facility”). The Revolving Credit Facility contains customary mandatory prepayments from the proceeds of certain asset dispositions or debt issuances, which are applied to reduce outstanding revolving and swing-line loans and letter of credit exposure, but in no event will reduce the borrowing availability under the Revolving Credit Facility to less than $250 million.

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Borrowings under the Revolving Credit Facility bear interest, at our option, at the LIBOR rate or at the bank prime rate, plus an applicable per annum margin that ranges from 2.50% to 3.25% and 1.50% to 2.25%, respectively. The LIBOR margin and bank prime rate margin currently in effect are 2.75% and 1.75%, respectively. The Revolving Credit Facility requires a commitment fee due quarterly based on the average daily unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a quarterly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period.
Our obligations under the Revolving Credit Facility are secured by substantially all of our domestic assets (including equity interests in Pioneer Global Holdings, Inc. and 65% of the outstanding equity interests of any first-tier foreign subsidiaries owned by Pioneer Global Holdings, Inc., but excluding any equity interest in, and any assets of, Pioneer Services Holdings, LLC) and are guaranteed by certain of our domestic subsidiaries, including Pioneer Global Holdings, Inc. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) was added as a subsidiary guarantor under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.

As of December 31, 2013, we had $80.0 million outstanding under our Revolving Credit Facility and $14.0 million in committed letters of credit, which resulted in borrowing availability of $156.0 million under our Revolving Credit Facility. There are no limitations on our ability to access this borrowing capacity other than maintaining compliance with the covenants under the Revolving Credit Facility. At December 31, 2013, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 2.0 to 1.0, our senior consolidated leverage ratio was 0.4 to 1.0, and our interest coverage ratio was 5.3 to 1.0. The financial covenants contained in our Revolving Credit Facility include the following:
•
A maximum total consolidated leverage ratio that cannot exceed 4.00 to 1.00;
•
A maximum senior consolidated leverage ratio, which excludes unsecured and subordinated debt, that cannot exceed 2.50 to 1.00;
•
A minimum interest coverage ratio that cannot be less than 2.50 to 1.00; and
•
If our senior consolidated leverage ratio is greater than 2.00 to 1.00 at the end of any fiscal quarter, our minimum asset coverage ratio cannot be less than 1.00 to 1.00.
The Revolving Credit Facility does not restrict capital expenditures as long as (a) no event of default exists under the Revolving Credit Facility or would result from such capital expenditures, (b) after giving effect to such capital expenditures there is availability under the Revolving Credit Facility equal to or greater than $25 million and (c) the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is less than 2.00 to 1.00. If the senior consolidated leverage ratio as of the last day of the most recent reported fiscal quarter is equal to or greater than 2.00 to 1.00, then capital expenditures are limited to $100 million for the fiscal year. The capital expenditure threshold may be increased by any unused portion of the capital expenditure threshold from the immediate preceding fiscal year up to $30 million.
At December 31, 2013, our senior consolidated leverage ratio was not greater than 2.00 to 1.00 and therefore, we were not subject to the capital expenditure threshold restrictions listed above.
The Revolving Credit Facility has additional restrictive covenants that, among other things, limit the incurrence of additional debt, investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the Revolving Credit Facility contains customary events of default, including without limitation, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control.

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Senior Notes
On March 11, 2010, we issued $250 million of unregistered senior notes with a coupon interest rate of 9.875% that are due in 2018 (the “2010 Senior Notes”). The 2010 Senior Notes were sold with an original issue discount of $10.6 million that was based on 95.75% of their face value, which will result in an effective yield to maturity of approximately 10.677%. On March 11, 2010, we received $234.8 million of net proceeds from the issuance of the 2010 Senior Notes after deductions were made for the $10.6 million of original issue discount and $4.6 million for underwriters’ fees and other debt offering costs. The net proceeds were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility.
On November 21, 2011, we issued $175 million of unregistered Senior Notes (the “2011 Senior Notes”). The 2011 Senior Notes have the same terms and conditions as the 2010 Senior Notes. The 2011 Senior Notes were sold with an original issue premium of $1.8 million that was based on 101% of their face value, which will result in an effective yield to maturity of approximately 9.66%. On November 21, 2011, we received $172.7 million of net proceeds from the issuance of the 2011 Senior Notes, including the original issue premium, and after $4.1 million of deductions were made for underwriters' fees and other debt offering costs. A portion of the net proceeds were used to fund the acquisition of Go-Coil in December 2011.
In accordance with a registration rights agreement with the holders of both our 2010 Senior Notes and 2011 Senior Notes, we filed exchange offer registration statements on Form S-4 with the Securities and Exchange Commission that became effective on September 2, 2010 and July 13, 2012, respectively. These exchange offer registration statements enabled the holders of both our 2010 Senior Notes and 2011 Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “2010 Senior Notes” and “2011 Senior Notes” herein include the senior notes issued in the exchange offers.
The 2010 and 2011 Senior Notes (the “Senior Notes”) are reflected on our consolidated balance sheet at December 31, 2013 with a total carrying value of $419.6 million, which represents the $425.0 million total face value net of the $6.7 million unamortized portion of original issue discount and $1.3 million unamortized portion of original issue premium. The original issue discount and premium are being amortized over the term of the Senior Notes based on the effective interest method.
The Senior Notes will mature on March 15, 2018 with interest due semi-annually in arrears on March 15 and September 15 of each year. We have the option to redeem the Senior Notes, in whole or in part, at any time on or after March 15, 2014 in each case at the redemption price specified in the Indenture dated March 11, 2010 (the “Indenture”) together with any accrued and unpaid interest to the date of redemption. Prior to March 15, 2014, we may also redeem the Senior Notes, in whole or in part, at a “make-whole” redemption price specified in the Indenture, together with any accrued and unpaid interest to the date of redemption.
Upon the occurrence of a change of control, holders of the Senior Notes will have the right to require us to purchase all or a portion of the Senior Notes at a price equal to 101% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase. Under certain circumstances in connection with asset dispositions, we will be required to use the excess proceeds of asset dispositions to make an offer to purchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, together with any accrued and unpaid interest to the date of purchase.

78


The Indenture contains certain restrictions generally on our and certain of our subsidiaries’ ability to:
•
pay dividends on stock;
•
repurchase stock or redeem subordinated debt or make other restricted payments;
•
incur, assume or guarantee additional indebtedness or issue disqualified stock;
•
create liens on our assets;
•
enter into sale and leaseback transactions;
•
pay dividends, engage in loans, or transfer other assets from certain of our subsidiaries;
•
consolidate with or merge with or into, or sell all or substantially all of our properties to another person;
•
enter into transactions with affiliates; and
•
enter into new lines of business.
We were in compliance with these covenants as of December 31, 2013. The Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries. Effective October 1, 2012, Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) was added as a subsidiary guarantor under the Indenture. (See Note 14, Guarantor/Non-Guarantor Condensed Consolidated Financial Statements.)
Other Debt
Our other debt represents a short-term financing of insurance premiums with monthly payments due through August 2014 and a capital lease obligation for equipment with monthly payments due through November 2016.
Debt Issuance Costs
Costs incurred in connection with the Revolving Credit Facility were capitalized and are being amortized using the straight-line method over the term of the Revolving Credit Facility which matures in June 2016. Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the straight-line method (which approximates the use of the interest method) over the term of the Senior Notes which mature in March 2018.
Capitalized debt costs related to the issuance of our long-term debt were approximately $7.5 million and $9.6 million as of December 31, 2013 and 2012, respectively. We recognized approximately $2.1 million, $2.1 million and $1.8 million of associated amortization during the years ended December 31, 2013, 2012 and 2011, respectively. During 2011, we recognized additional amortization expense for the write-off of $0.6 million of debt issuance costs representing the portion of unamortized debt issuance costs associated with certain syndicate lenders who are no longer participating in the Revolving Credit Facility as amended on June 30, 2011.
5.
Leases
We lease our corporate office facilities in San Antonio, Texas at a payment escalating from $40,373 per month in January 2014 to $46,920 per month in December 2020 pursuant to a lease which extends through December 2020, but which is cancelable as early as December 2016 with applicable penalties. We recognize rent expense on a straight-line basis for our corporate office lease. We also lease real estate at 52 other locations, which are primarily used for field offices and storage and maintenance yards, and we lease vehicles, office and other equipment under non-cancelable operating leases, most of which contain renewal options and some of which contain escalation clauses.

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Future lease obligations required under non-cancelable operating leases as of December 31, 2013 were as follows (amounts in thousands):
Year ended December 31,
 
2014
$
5,032

2015
2,987

2016
2,428

2017
2,024

2018
1,082

Thereafter
1,366

 
$
14,919

Rent expense under operating leases for the years ended December 31, 2013, 2012 and 2011 was $6.0 million, $5.6 million and $3.6 million, respectively.
6.
Income Taxes
The jurisdictional components of income (loss) before income taxes consist of the following (amounts in thousands): 
 
Year ended December 31,
 
2013
 
2012
 
2011
Domestic
$
(66,147
)
 
$
42,194

 
$
23,396

Foreign
10,369

 
4,192

 
(2,563
)
Income (loss) before income tax
$
(55,778
)
 
$
46,386

 
$
20,833

The components of our income tax expense (benefit) consist of the following (amounts in thousands): 
  
Year ended December 31,
  
2013
 
2012
 
2011
Current tax:
 
 
 
 
 
Federal
$
(380
)
 
$
236

 
$
716

State
879

 
1,214

 
1,090

Foreign
2,302

 
1,479

 
1,301

 
2,801

 
2,929

 
3,107

Deferred taxes:
 
 
 
 
 
Federal
(21,034
)
 
15,013

 
7,199

State
(3,520
)
 
(749
)
 
102

Foreign
1,907

 
(839
)
 
(752
)
 
(22,647
)
 
13,425

 
6,549

Income tax expense (benefit)
$
(19,846
)
 
$
16,354

 
$
9,656


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The difference between the income tax expense (benefit) and the amount computed by applying the federal statutory income tax rate of 35% to income (loss) before income taxes consists of the following (amounts in thousands): 
 
Year ended December 31,
 
2013
 
2012
 
2011
Expected tax expense (benefit)
$
(19,522
)
 
$
16,235

 
$
7,291

State income taxes
(1,717
)
 
302

 
775

Incentive stock options
66

 
43

 
41

Net tax benefits and nondeductible expenses in foreign jurisdictions
525

 
(881
)
 
1,391

Nondeductible expenses for tax purposes
863

 
770

 
567

Valuation allowance
—

 
(206
)
 
—

Other, net
(61
)
 
91

 
(409
)
Income tax expense (benefit)
$
(19,846
)
 
$
16,354

 
$
9,656

Income tax expense (benefit) was allocated as follows (amounts in thousands): 
 
Year ended December 31,
 
2013
 
2012
 
2011
Results of operations
$
(19,846
)
 
$
16,354

 
$
9,656

Stockholders' equity
321

 
449

 
254

Income tax expense (benefit)
$
(19,525
)
 
$
16,803

 
$
9,910

Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. The components of our deferred income tax assets and liabilities were as follows (amounts in thousands):
 
Year ended December 31,
 
2013
 
2012
Deferred tax assets:
 
 
 
Capital loss carryforward
$
1,008

 
$
1,008

Intangibles
36,442

 
19,918

Employee benefits and insurance claims accruals
9,332

 
8,273

Accounts receivable reserve
501

 
370

Employee stock-based compensation
8,905

 
8,225

Accrued expenses not deductible for tax purposes
749

 
1,066

Accrued revenue not income for book purposes
942

 
1,399

Federal and state net operating loss and AMT credit carryforward
94,605

 
69,160

Foreign net operating loss carryforward
3,411

 
5,361

 
155,895

 
114,780

Valuation allowance
(1,008
)
 
(1,008
)
Total deferred tax assets
154,887

 
113,772

Deferred tax liabilities:
 
 
 
Property and equipment
225,275

 
206,033

Total deferred tax liabilities
225,275

 
206,033

Net deferred tax liabilities
$
70,388

 
$
92,261


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In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Based on the expectation of future taxable income and that the deductible temporary differences will offset existing taxable temporary differences, we believe it is more likely than not that we will realize the benefits of these deductible temporary differences, with the exception of the valuation allowance recorded to fully offset our deferred tax asset for a capital loss carryforward related to the unrealized loss on the impairment of our ARPS securities.
As of December 31, 2013, we had a $1.0 million deferred tax asset related to the sale of our ARPSs which will represent a capital loss for tax treatment purposes. We can recognize a tax benefit associated with this loss to the extent of capital gains we expect to earn in future periods. We recorded a valuation allowance to fully offset our deferred tax asset relating to this capital loss since we believe capital gains are not likely in future periods.
As of December 31, 2013, we had $94.6 million and $3.4 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the jurisdiction in future periods. We estimate that our operations will result in taxable income in excess of our net operating losses and we expect to apply the net operating losses against taxable income that we have estimated in future periods. The domestic net operating losses can be used to offset future domestic taxable income through 2033, while the majority of the foreign net operating losses can be carried forward indefinitely.
Deferred income taxes have not been provided on the future tax consequences attributable to difference between the financial statements carrying amounts of existing assets and liabilities and the respective tax bases of our foreign subsidiary based on the determination that such differences are essentially permanent in duration in that the earnings of the subsidiary is expected to be indefinitely reinvested in foreign operations. As of December 31, 2013, the cumulative undistributed earnings/loss of the subsidiary was approximately a $18.0 million loss. If earnings were not considered indefinitely reinvested, deferred income taxes would have been recorded after consideration of foreign tax credits. It is not practicable to estimate the amount of additional tax that might be payable on earnings, if distributed.
On December 26, 2012, Colombia enacted a tax reform bill that, among other things, decreased the corporate tax rate from 33% to 25%, but also added a new 9% tax for equality, which results in a combined tax rate of 34%. Net operating losses cannot be utilized against the new 9% tax for equality, and therefore the associated deferred tax asset must now be based on the lower 25% corporate tax rate only. Other deferred tax assets and liabilities must now be based on the higher combined tax rate of 34%. Included in our 2012 deferred foreign tax expense (benefit) is a $1.7 million expense to adjust our Colombian net deferred tax assets and liabilities for the change in rates.
We have no unrecognized tax benefits relating to ASC Topic 740 and no unrecognized tax benefit activity during the year ended December 31, 2013.
We adopted a policy to record interest and penalty expense related to income taxes as interest and other expense, respectively. At December 31, 2013, no interest or penalties have been or are required to be accrued. Our open tax years for our federal income tax returns in the United States are for the years ended December 31, 2010 to 2012. Our open tax years for our income tax returns in Colombia are for the years ended December 31, 2008 to 2012.
7.
Fair Value of Financial Instruments
ASC Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value.
At December 31, 2013 and December 31, 2012, our financial instruments consist primarily of cash, trade and other receivables, trade payables, and long-term debt. The carrying value of cash, trade and other receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

82


The fair value of our long-term debt is estimated using a discounted cash flow analysis, based on rates that we believe we would currently pay for similar types of debt instruments. This discounted cash flow analysis is based on inputs defined by ASC Topic 820 as level 2 inputs, which are observable inputs for similar types of debt instruments. The following table presents the supplemental fair value information about long-term debt at December 31, 2013 and December 31, 2012 (amounts in thousands):
 
December 31, 2013
 
December 31, 2012
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Total debt
$
502,513

 
$
538,074

 
$
519,597

 
$
565,257

8.
Earnings Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic income per share and diluted income per share computations (amounts in thousands, except per share data):
 
Year ended December 31,
 
2013
 
2012
 
2011
Basic
 
 
 
 
 
Net income (loss)
$
(35,932
)
 
$
30,032

 
$
11,177

Weighted-average shares
62,213

 
61,780

 
57,390

Income (loss) per share
$
(0.58
)
 
$
0.49

 
$
0.19

Diluted
 
 
 
 
 
Net income (loss)
$
(35,932
)
 
$
30,032

 
$
11,177

Weighted average shares:
 
 
 
 
 
Outstanding
62,213

 
61,780

 
57,390

Diluted effect of stock options, restricted stock,
and restricted stock unit awards
—

 
982

 
1,389

 
62,213

 
62,762

 
58,779

Income (loss) per share
$
(0.58
)
 
$
0.48

 
$
0.19

Potentially dilutive stock options, restricted stock and restricted stock unit awards representing a total of 5,507,765, 4,311,645 and 2,430,141 shares of common stock for the years ended December 31, 2013, 2012 and 2011, respectively, were excluded from the computation of diluted weighted average shares outstanding due to their antidilutive effect.
9.
Equity Transactions and Stock-Based Compensation Plans
Equity Transactions
In July 2011, we obtained $94.3 million in net proceeds from the sale of 6,900,000 shares of our common stock at $14.50 per share, less underwriters’ commissions and other offering costs, pursuant to a public offering under the shelf registration statement which we filed in July 2009.
In May 2012, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of December 31, 2013, the entire $300 million under the shelf registration statement is available for equity or debt offerings. In the future, we may consider equity or debt offerings, as appropriate, to meet our liquidity needs.
Stock-based Compensation Plans
We have stock-based award plans that are administered by the Compensation Committee of our Board of Directors, which selects persons eligible to receive awards and determines the number of stock options, restricted

83


stock, or restricted stock units subject to each award and the terms, conditions and other provisions of the awards. At December 31, 2013, the total shares available for future grants to employees and directors under existing plans were 1,182,475, of which no more than 856,866 may be granted in the form of restricted stock or restricted stock unit awards.
We grant stock option and restricted stock awards with vesting based on time of service conditions. We also grant restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. We recognize compensation cost for stock option, restricted stock and restricted stock unit awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards.
The following table summarizes the compensation expense recognized for stock option, restricted stock and restricted stock unit awards during the years ended December 31, 2013, 2012 and 2011 (amounts in thousands):
 
Year ended December 31,
 
2013
 
2012
 
2011
Stock option awards
$
1,771

 
$
2,962

 
$
3,720

Restricted stock awards
576

 
628

 
1,030

Restricted stock unit awards
4,024

 
3,729

 
1,955

 
$
6,371

 
$
7,319

 
$
6,705

Stock Options
We grant stock option awards which generally become exercisable over a three-year period and expire ten years after the date of grant. Our stock-based compensation plans require that all stock option awards have an exercise price that is not less than the fair market value of our common stock on the date of grant. We issue shares of our common stock when vested stock option awards are exercised.
We estimate the fair value of each option grant on the date of grant using a Black-Scholes option pricing model. The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the years ended December 31, 2013, 2012 and 2011:
 
 
Year ended December 31,
 
2013
 
2012
 
2011
Expected volatility
66
%
 
70
%
 
65
%
Risk-free interest rates
1.0
%
 
0.8
%
 
1.5
%
Expected life in years
5.53

 
5.12

 
4.33

Grant-date fair value
$4.36
 
$5.02
 
$4.69

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The assumptions used in the Black-Scholes option pricing model are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.
The following table represents stock option activity from December 31, 2011 through December 31, 2013:
 
Number of
Shares
 
Weighted-Average
Exercise Price
Per Share
 
Weighted-Average
Remaining Contract
Life in Years
Outstanding stock options as of December 31, 2011
5,563,348
 
$10.20
 
 
Granted
530,156
 
8.72
 
 
Forfeited
(271,097)
 
13.60
 
 
Exercised
(172,416)
 
4.02
 
 
Outstanding stock options as of December 31, 2012
5,649,991
 
$10.09
 
 
Granted
220,656
 
7.58
 
 
Forfeited
(67,500)
 
16.02
 
 
Exercised
(270,934)
 
4.67
 
 
Outstanding stock options as of December 31, 2013
5,532,213
 
$10.18
 
5.1
Stock options exercisable as of December 31, 2013
4,775,172
 
$10.45
 
4.6
At December 31, 2013, the aggregate intrinsic value of stock options outstanding was $4.9 million and the aggregate intrinsic value of stock options exercisable was $4.8 million. Intrinsic value is the difference between the exercise price of a stock option and the closing market price of our common stock, which was $8.01 on December 31, 2013.
The following table summarizes our nonvested stock option activity from December 31, 2011 through December 31, 2013:
 
Number of
Shares
 
Weighted-Average Grant-Date
Fair Value Per Share
Nonvested stock options as of December 31, 2011
1,531,237
 
$3.98
Granted
530,156
 
5.02
Vested
(901,817)
 
3.42
Forfeited
(28,732)
 
4.74
Nonvested stock options as of December 31, 2012
1,130,844
 
$4.89
Granted
220,656
 
4.36
Vested
(594,459)
 
4.88
Nonvested stock options as of December 31, 2013
757,041
 
$4.74
At December 31, 2013, there was $0.8 million of unrecognized compensation cost relating to stock options which is expected to be recognized over a weighted-average period of 0.6 years.
In January 2014, our Board of Directors approved the grant of stock options representing 221,440 shares of common stock to officers and employees that will vest over a three-year period.

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Restricted Stock
Historically, we have generally granted restricted stock awards that vest over a three-year period with a fair value based on the closing price of our common stock on the date of the grant. However, beginning in 2013, we began granting restricted stock awards with a vesting period of one year. When restricted stock awards are granted, or when restricted stock unit awards are converted to restricted stock, shares of our common stock are considered issued, but subject to certain restrictions.
The following table summarizes our restricted stock activity from December 31, 2011 through December 31, 2013:
 
Number of
Shares
 
Weighted-Average
Grant-Date
Fair Value per Share
Nonvested restricted stock as of December 31, 2011
281,836
 
$7.18
Granted
49,748
 
8.04
Vested
(184,081)
 
6.21
Forfeited
(4,683)
 
8.86
Nonvested restricted stock as of December 31, 2012
142,820
 
$8.67
Granted
61,248
 
7.51
Vested
(98,864)
 
8.47
Nonvested restricted stock as of December 31, 2013
105,204
 
$8.18
At December 31, 2013, there was $0.3 million of unrecognized compensation cost relating to restricted stock awards which is expected to be recognized over a weighted-average period of 0.5 years.
Restricted Stock Units
We grant restricted stock unit awards with vesting based on time of service conditions only (“time-based RSUs”), and we grant restricted stock unit awards with vesting based on time of service, which are also subject to performance and market conditions (“performance-based RSUs”). Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.
Our time-based RSUs generally vest over a three-year period, with fair values based on the closing price of our common stock on the date of grant.
Our performance-based RSUs generally cliff vest after 39 months from the date of grant and are granted at a target number of issuable shares, for which the final number of shares of common stock is adjusted based on our actual achievement levels that are measured against predetermined performance conditions. The number of shares of common stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the performance period, generally three years.
Approximately one-third of the performance-based RSUs are subject to a market condition, based on total shareholder return, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensation expense for awards with a market condition is reduced only for estimated forfeitures; no adjustment to expense is otherwise made, regardless of the number of shares issued, if any. The remaining two-thirds of the performance-based RSUs are subject to performance conditions, based on EBITDA and return on capital employed, and therefore the fair value is based on the closing price of our common stock on the date of grant, applied to the estimated number of shares that will be awarded. Compensation expense ultimately recognized for awards with performance conditions will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions.
As of December 31, 2013, we estimated that our actual achievement level for the performance-based RSUs granted during 2011, 2012 and 2013 will be approximately 120%, 110% and 100% of the predetermined performance conditions, respectively. Therefore, the outstanding 673,762 restricted stock units would be adjusted to represent

86


721,751 shares of our common stock if these achievement levels are maintained through the applicable performance periods.
The following table summarizes our restricted stock unit activity from December 31, 2011 through December 31, 2013:
 
Time-Based Award
 
Performance-Based Award
 
Number of
Time-Based
Award Units
 
Weighted-Average
Grant-Date
Fair Value 
per Unit
 
Number of
Performance-Based
Award Units
 
Weighted-Average
Grant-Date
Fair Value 
per Unit
Nonvested restricted stock units as of December 31, 2011
272,951

 
$10.76
 
139,089

 
$10.23
Granted
356,813

 
8.21
 
221,495

 
9.85
Vested
(72,259)

 
10.07

 
—

 
—

Forfeited
(25,979)

 
10.34
 
(5,533)

 
10.23
Nonvested restricted stock units as of December 31, 2012
531,526

 
$9.16
 
355,051

 
$9.99
       Granted
406,027

 
7.59
 
346,731

 
8.34
Vested
(254,629)

 
9.82
 
—

 
—

       Forfeited
(55,212)

 
8.60
 
(28,020)

 
8.81
Nonvested restricted stock units as of December 31, 2013
627,712

 
$7.93
 
673,762

 
$9.19
At December 31, 2013, there was $4.8 million of unrecognized compensation cost relating to restricted stock unit awards which is expected to be recognized over a weighted-average period of 1.3 years.
In January 2014, our Board of Directors approved the grant of restricted stock units representing 669,051 shares of common stock to officers and employees that will vest over a three-year period.
10.
Employee Benefit Plans and Insurance
We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may make a matching contribution, on a discretionary basis, equal to a percentage of each eligible employee’s annual contribution, which we determine annually. Our matching contributions for the years ended December 31, 2013, 2012 and 2011 were $6.0 million, $4.6 million and $2.6 million, respectively.
We maintain a self-insurance program, for major medical and hospitalization coverage for employees and their dependents, which is partially funded by employee payroll deductions. We have provided for reported claims costs as well as incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $150,000 per covered individual per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Insurance premiums and deductibles accruals at December 31, 2013 and 2012 include $3.1 million and $2.5 million, respectively, for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.
We are self-insured for up to $500,000 per incident for all workers’ compensation claims submitted by employees for on-the-job injuries. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance. We accrue our workers’ compensation claim cost estimates based on historical claims development data and we accrue the cost of administrative services associated with claims processing. Insurance premiums and deductibles accruals at December 31, 2013 and 2012 include $7.3 million and $6.1 million, respectively, for our estimate of costs relative to the self-insured portion of our workers’ compensation, general liability and auto liability insurance. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.

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11.
Segment Information
We have two operating segments referred to as the Drilling Services Segment and the Production Services Segment which is the basis management uses for making operating decisions and assessing performance.
Drilling Services Segment—Our Drilling Services Segment provides contract land drilling services to a diverse group of oil and gas exploration and production companies with its fleet of 62 drilling rigs which are currently assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
14

West Texas
 
18

North Dakota
 
11

Utah
 
7

Appalachia
 
4

Colombia
 
8

 
 
62

Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services, coiled tubing services, and fishing and rental services. Our production services operations are concentrated in the major United States onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. As of December 31, 2013, we have a fleet of 109 well servicing rigs consisting of ninety-nine 550 horsepower rigs and ten 600 horsepower rigs. We provide wireline services and coiled tubing services with a fleet of 119 wireline units and 13 coiled tubing units, and we provide rental services with a gross book value of $17.3 million in fishing and rental tools.
The following tables set forth certain financial information for our two operating segments and corporate as of and for the years ending December 31, 2013, 2012 and 2011 (amounts in thousands):
 
As of and for the year ended December 31, 2013
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
791,820

 
$
395,219

 
$
42,584

 
$
1,229,623

Revenues
$
528,327

 
$
431,859

 
$
—

 
$
960,186

Operating costs
351,630

 
276,808

 
—

 
628,438

Segment margin
$
176,697

 
$
155,051

 
$
—

 
$
331,748

Depreciation and amortization
$
122,201

 
$
64,604

 
$
1,113

 
$
187,918

Capital expenditures
$
78,708

 
$
44,541

 
$
2,171

 
$
125,420

 
As of and for the year ended December 31, 2012
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
867,526

 
$
439,113

 
$
33,137

 
$
1,339,776

Revenues
$
498,867

 
$
420,576

 
$
—

 
$
919,443

Operating costs
333,846

 
252,775

 
—

 
586,621

Segment margin
$
165,021

 
$
167,801

 
$
—

 
$
332,822

Depreciation and amortization
$
108,151

 
$
55,693

 
$
873

 
$
164,717

Capital expenditures
$
265,966

 
$
110,813

 
$
2,493

 
$
379,272


88


 
As of and for the year ended December 31, 2011
 
Drilling
Services
Segment
 
Production
Services
Segment
 
Corporate
 
Total
Identifiable assets
$
667,588

 
$
398,128

 
$
107,038

 
$
1,172,754

Revenues
$
433,902

 
$
282,039

 
$
—

 
$
715,941

Operating costs
292,559

 
164,365

 
—

 
456,924

Segment margin
$
141,343

 
$
117,674

 
$
—

 
$
259,017

Depreciation and amortization
$
99,302

 
$
32,683

 
$
847

 
$
132,832

Capital expenditures
$
168,120

 
$
68,908

 
$
759

 
$
237,787

The following table reconciles the segment profits reported above to income from operations as reported on the consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 (amounts in thousands):
 
Year ended December 31,
 
2013
 
2012
 
2011
Segment margin
$
331,748

 
$
332,822

 
$
259,017

Depreciation and amortization
(187,918
)
 
(164,717
)
 
(132,832
)
General and administrative
(95,000
)
 
(85,603
)
 
(67,318
)
Bad debt recovery (expense)
(767
)
 
440

 
(925
)
Impairment charges
(54,292
)
 
(1,131
)
 
(484
)
Income (loss) from operations
$
(6,229
)
 
$
81,811

 
$
57,458

The following table sets forth certain financial information for our international operations in Colombia as of and for the years ended December 31, 2013, 2012 and 2011 (amounts in thousands):
 
As of and for the year ended December 31,
 
2013
 
2012
 
2011
Identifiable assets
$
150,719

 
$
148,567

 
$
151,448

Revenues
$
115,631

 
$
95,338

 
$
109,539

Identifiable assets for our international operations in Colombia include five drilling rigs that are owned by our Colombia subsidiary and three drilling rigs that are owned by one of our domestic subsidiaries and leased to our Colombia subsidiary.
12.
Commitments and Contingencies
In connection with our operations in Colombia, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $60.4 million relating to our performance under these bonds as of December 31, 2013.
Due to the nature of our business, we are, from time to time, involved in litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations.

89


13.
Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for the years ended December 31, 2013 and 2012 (in thousands, except per share data):
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
Total
Year ended December 31, 2013
 
 
 
 
 
 
 
 
 
Revenues
$
229,670

 
$
248,354

 
$
243,979

 
$
238,183

 
$
960,186

Income (loss) from operations
10,445

 
(27,268
)
 
1,870

 
8,724

 
(6,229
)
Income tax (expense) benefit
546

 
14,953

 
3,614

 
733

 
19,846

Net income (loss)
(1,292
)
 
(25,895
)
 
(6,230
)
 
(2,515
)
 
(35,932
)
Earnings (loss) per share:
 
 
 
 
 
 
 
 
 
Basic
$
(0.02
)
 
$
(0.42
)
 
$
(0.10
)
 
$
(0.04
)
 
$
(0.58
)
Diluted
$
(0.02
)
 
$
(0.42
)
 
$
(0.10
)
 
$
(0.04
)
 
$
(0.58
)
 
 
 
 
 
 
 
 
 
 
Year ended December 31, 2012
 
 
 
 
 
 
 
 
 
Revenues
$
231,978

 
$
229,824

 
$
229,773

 
$
227,868

 
$
919,443

Income from operations
29,748

 
23,312

 
13,222

 
15,529

 
81,811

Income tax (expense) benefit
(6,953
)
 
(5,997
)
 
(1,461
)
 
(1,943
)
 
(16,354
)
Net income (loss)
14,172

 
9,685

 
2,615

 
3,560

 
30,032

Earnings (loss) per share:
 
 
 
 
 
 
 
 
 
Basic
$
0.23

 
$
0.16

 
$
0.04

 
$
0.06

 
$
0.49

Diluted
$
0.23

 
$
0.15

 
$
0.04

 
$
0.06

 
$
0.48


90


14.
Guarantor/Non-Guarantor Condensed Consolidated Financial Statements
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all existing domestic subsidiaries, except for Pioneer Services Holdings, LLC, and certain of our future domestic subsidiaries. Effective October 1, 2012, the Indenture was supplemented to add Pioneer Coiled Tubing Services, LLC (formerly Go-Coil, L.L.C.) as a subsidiary guarantor. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture.
In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of December 31, 2013, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.
As a result of the guarantee arrangements, we are presenting the following condensed consolidated balance sheets, statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.

91


CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited, in thousands)
 
December 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
28,368

 
$
(2,059
)
 
$
1,076

 
$
—

 
$
27,385

Receivables, net of allowance
905

 
125,979

 
49,476

 
—

 
176,360

Intercompany receivable (payable)
(24,837
)
 
52,671

 
(27,834
)
 
—

 
—

Deferred income taxes
1,143

 
8,005

 
3,944

 
—

 
13,092

Inventory
—

 
7,415

 
5,817

 
—

 
13,232

Prepaid expenses and other current assets
1,013

 
7,094

 
1,204

 
—

 
9,311

Total current assets
6,592

 
199,105

 
33,683

 
—

 
239,380

Net property and equipment
4,531

 
846,632

 
87,244

 
(750
)
 
937,657

Investment in subsidiaries
939,091

 
120,630

 
—

 
(1,059,721
)
 
—

Intangible assets, net of accumulated amortization
75

 
32,194

 
—

 
—

 
32,269

Noncurrent deferred income taxes
78,486

 
—

 
1,156

 
(78,486
)
 
1,156

Other long-term assets
7,513

 
2,009

 
9,639

 
—

 
19,161

Total assets
$
1,036,288

 
$
1,200,570

 
$
131,722

 
$
(1,138,957
)
 
$
1,229,623

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
757

 
$
37,797

 
$
5,164

 
—

 
$
43,718

Current portion of long-term debt
—

 
2,847

 
—

 
—

 
2,847

Deferred revenues
—

 
699

 
—

 
—

 
699

Accrued expenses
16,368

 
51,739

 
5,462

 
—

 
73,569

Total current liabilities
17,125

 
93,082

 
10,626

 
—

 
120,833

Long-term debt, less current portion
499,586

 
80

 
—

 
—

 
499,666

Noncurrent deferred income taxes
—

 
163,122

 
—

 
(78,486
)
 
84,636

Other long-term liabilities
394

 
5,195

 
466

 
—

 
6,055

Total liabilities
517,105

 
261,479

 
11,092

 
(78,486
)
 
711,190

Total shareholders’ equity
519,183

 
939,091

 
120,630

 
(1,060,471
)
 
518,433

Total liabilities and shareholders’ equity
$
1,036,288

 
$
1,200,570

 
$
131,722

 
$
(1,138,957
)
 
$
1,229,623

 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
18,479

 
$
(5,401
)
 
$
10,655

 
$
—

 
$
23,733

Receivables, net of allowance
440

 
129,570

 
29,128

 
(294
)
 
158,844

Intercompany receivable (payable)
(124,516
)
 
146,652

 
(22,136
)
 
—

 
—

Deferred income taxes
869

 
8,162

 
2,027

 
—

 
11,058

Inventory
—

 
5,956

 
6,155

 
—

 
12,111

Prepaid expenses and other current assets
655

 
9,163

 
3,222

 
—

 
13,040

Total current assets
(104,073
)
 
294,102

 
29,051

 
(294
)
 
218,786

Net property and equipment
3,474

 
921,393

 
90,223

 
(750
)
 
1,014,340

Investment in subsidiaries
1,122,814

 
114,416

 
—

 
(1,237,230
)
 
—

Intangible assets, net of accumulated amortization
68

 
43,775

 
—

 
—

 
43,843

Goodwill
—

 
41,683

 
—

 
—

 
41,683

Noncurrent deferred income taxes
51,834

 
—

 
5,519

 
(51,834
)
 
5,519

Other long-term assets
9,582

 
2,340

 
3,683

 
—

 
15,605

Total assets
$
1,083,699

 
$
1,417,709

 
$
128,476

 
$
(1,290,108
)
 
$
1,339,776

LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
 
 
 
Accounts payable
$
1,558

 
$
76,828

 
$
5,437

 
$
—

 
$
83,823

Current portion of long-term debt
—

 
872

 
—

 
—

 
872

Deferred revenues
—

 
1,954

 
1,926

 
—

 
3,880

Accrued expenses
14,905

 
48,892

 
4,472

 
(294
)
 
67,975

Total current liabilities
16,463

 
128,546

 
11,835

 
(294
)
 
156,550

Long-term debt, less current portion
518,618

 
107

 
—

 
—

 
518,725

Noncurrent deferred income taxes
(4
)
 
160,676

 
—

 
(51,834
)
 
108,838

Other long-term liabilities
192

 
5,566

 
2,225

 
—

 
7,983

Total liabilities
535,269

 
294,895

 
14,060

 
(52,128
)
 
792,096

Total shareholders’ equity
548,430

 
1,122,814

 
114,416

 
(1,237,980
)
 
547,680

Total liabilities and shareholders’ equity
$
1,083,699

 
$
1,417,709

 
$
128,476

 
$
(1,290,108
)
 
$
1,339,776


92


CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited, in thousands)
 
Year ended December 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
844,555

 
$
115,631

 
$
—

 
$
960,186

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
547,528

 
80,910

 
—

 
628,438

Depreciation and amortization
1,113

 
173,516

 
13,289

 
—

 
187,918

General and administrative
25,272

 
66,779

 
3,501

 
(552
)
 
95,000

Intercompany leasing
—

 
(4,860
)
 
4,860

 
—

 
—

Bad debt expense (recovery)
67

 
700

 
—

 
—

 
767

Impairment charges
—

 
54,292

 
—

 
—

 
54,292

Total costs and expenses
26,452

 
837,955

 
102,560

 
(552
)
 
966,415

Income (loss) from operations
(26,452
)
 
6,600

 
13,071

 
552

 
(6,229
)
Other (expense) income:
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
11,861

 
6,260

 
—

 
(18,121
)
 
—

Interest expense
(48,302
)
 
(37
)
 
29

 
—

 
(48,310
)
Other
9

 
1,990

 
(2,686
)
 
(552
)
 
(1,239
)
Total other (expense) income
(36,432
)
 
8,213

 
(2,657
)
 
(18,673
)
 
(49,549
)
Income (loss) before income taxes
(62,884
)
 
14,813

 
10,414

 
(18,121
)
 
(55,778
)
Income tax (expense) benefit
26,952

 
(2,952
)
 
(4,154
)
 
—

 
19,846

Net income (loss)
$
(35,932
)
 
$
11,861

 
$
6,260

 
$
(18,121
)
 
$
(35,932
)
 
 
 
 
 
 
 
 
 
 
 
Year ended December 31, 2012
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
779,163

 
$
140,280

 
$
—

 
$
919,443

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
485,342

 
101,279

 
—

 
586,621

Depreciation and amortization
873

 
142,972

 
20,872

 
—

 
164,717

General and administrative
22,212

 
54,715

 
9,228

 
(552
)
 
85,603

Intercompany leasing
—

 
(4,860
)
 
4,860

 
—

 
—

Bad debt expense (recovery)
—

 
(612
)
 
172

 
—

 
(440
)
Impairment charges
—

 
1,131

 
—

 
—

 
1,131

Total costs and expenses
23,085

 
678,688

 
136,411

 
(552
)
 
837,632

Income (loss) from operations
(23,085
)
 
100,475

 
3,869

 
552

 
81,811

Other (expense) income:
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
68,352

 
4,029

 
—

 
(72,381
)
 
—

Interest expense
(37,011
)
 
(59
)
 
21

 
—

 
(37,049
)
Other
268

 
940

 
968

 
(552
)
 
1,624

Total other (expense) income
31,609

 
4,910

 
989

 
(72,933
)
 
(35,425
)
Income (loss) before income taxes
8,524

 
105,385

 
4,858

 
(72,381
)
 
46,386

Income tax (expense) benefit
21,508

 
(37,033
)
 
(829
)
 
—

 
(16,354
)
Net income (loss)
$
30,032

 
$
68,352

 
$
4,029

 
$
(72,381
)
 
$
30,032

 
 
 
 
 
 
 
 
 
 
 
Year ended December 31, 2011
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues
$
—

 
$
606,402

 
$
109,539

 
$
—

 
$
715,941

Costs and expenses:
 
 
 
 
 
 
 
 
 
Operating costs
—

 
372,945

 
83,979

 
—

 
456,924

Depreciation and amortization
847

 
119,520

 
12,465

 
—

 
132,832

General and administrative
19,797

 
45,152

 
2,921

 
(552
)
 
67,318

Intercompany leasing
—

 
(4,860
)
 
4,857

 
3

 
—

Bad debt expense (recovery)
—

 
925

 
—

 
—

 
925

Impairment of equipment
—

 
484

 
—

 
—

 
484

Total costs and expenses
20,644

 
534,166

 
104,222

 
(549
)
 
658,483

Income (loss) from operations
(20,644
)
 
72,236

 
5,317

 
549

 
57,458

Other (expense) income:
 
 
 
 
 
 
 
 
 
Equity in earnings of subsidiaries
43,182

 
(2,982
)
 
—

 
(40,200
)
 
—

Interest expense
(29,497
)
 
(248
)
 
24

 
—

 
(29,721
)
Other
311

 
1,163

 
(7,829
)
 
(549
)
 
(6,904
)
Total other (expense) income
13,996

 
(2,067
)
 
(7,805
)
 
(40,749
)
 
(36,625
)
Income (loss) before income taxes
(6,648
)
 
70,169

 
(2,488
)
 
(40,200
)
 
20,833

Income tax expense (benefit)
17,825

 
(26,987
)
 
(494
)
 
—

 
(9,656
)
Net income (loss)
$
11,177

 
$
43,182

 
$
(2,982
)
 
$
(40,200
)
 
$
11,177


93


CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
 
Year ended December 31, 2013
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
Cash flows from operating activities
$
31,908

 
$
142,225

 
$
447

 
$
174,580

Cash flows from investing activities:
 
 
 
 
 
 
 
Purchases of property and equipment
(2,649
)
 
(151,363
)
 
(11,344
)
 
(165,356
)
Proceeds from sale of property and equipment
8

 
12,510

 
1,318

 
13,836

Proceeds from insurance recoveries
—

 
844

 
—

 
844

 
(2,641
)
 
(138,009
)
 
(10,026
)
 
(150,676
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Debt repayments
(60,000
)
 
(874
)
 
—

 
(60,874
)
Proceeds from issuance of debt
40,000

 
—

 
—

 
40,000

Debt issuance costs
(13
)
 
—

 
—

 
(13
)
Proceeds from exercise of options
1,266

 
—

 
—

 
1,266

Purchase of treasury stock
(631
)
 
—

 
—

 
(631
)
 
(19,378
)
 
(874
)
 
—

 
(20,252
)
Net increase (decrease) in cash and cash equivalents
9,889

 
3,342

 
(9,579
)
 
3,652

Beginning cash and cash equivalents
18,479

 
(5,401
)
 
10,655

 
23,733

Ending cash and cash equivalents
$
28,368

 
$
(2,059
)
 
$
1,076

 
$
27,385

 
 
 
 
 
 
 
 
 
Year ended December 31, 2012
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
Cash flows from operating activities
$
(171,541
)
 
$
338,418

 
$
32,489

 
$
199,366

Cash flows from investing activities:
 
 
 
 
 
 
 
Purchases of property and equipment
(2,187
)
 
(332,082
)
 
(30,055
)
 
(364,324
)
Proceeds from sale of property and equipment
—

 
2,998

 
95

 
3,093

 
(2,187
)
 
(329,084
)
 
(29,960
)
 
(361,231
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Debt repayments
—

 
(856
)
 
(18
)
 
(874
)
Proceeds from issuance of debt
100,000

 
—

 
—

 
100,000

Debt issuance costs
(58
)
 
—

 
—

 
(58
)
Proceeds from exercise of options
693

 
—

 
—

 
693

Purchase of treasury stock
(360
)
 
—

 
—

 
(360
)
 
100,275

 
(856
)
 
(18
)
 
99,401

Net increase (decrease) in cash and cash equivalents
(73,453
)
 
8,478

 
2,511

 
(62,464
)
Beginning cash and cash equivalents
91,932

 
(13,879
)
 
8,144

 
86,197

Ending cash and cash equivalents
$
18,479

 
$
(5,401
)
 
$
10,655

 
$
23,733

 
 
 
Year ended December 31, 2011
 
Parent
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
Cash flows from operating activities
$
(164,032
)
 
$
300,198

 
$
8,713

 
$
144,879

Cash flows from investing activities:
 
 
 
 
 
 
 
Acquisition of production services business of Go-Coil
—

 
(109,035
)
 
—

 
(109,035
)
Acquisition of other production services businesses
—

 
(6,502
)
 
—

 
(6,502
)
Purchases of property and equipment
(485
)
 
(200,887
)
 
(8,694
)
 
(210,066
)
Proceeds from sale of property and equipment
7

 
5,532

 
11

 
5,550

Proceeds from sale of auction rate securities
12,569

 
—

 
—

 
12,569

 
12,091

 
(310,892
)
 
(8,683
)
 
(307,484
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Debt repayments
(111,813
)
 
(1,345
)
 
—

 
(113,158
)
Proceeds from issuance of debt
250,750

 
—

 
—

 
250,750

Debt issuance costs
(7,285
)
 
—

 
—

 
(7,285
)
Proceeds from exercise of options
2,884

 
—

 
—

 
2,884

Proceeds from common stock, net of offering costs of $5,707
94,343

 
—

 
—

 
94,343

Purchase of treasury stock
(743
)
 
—

 
—

 
(743
)
 
228,136

 
(1,345
)
 
—

 
226,791

Net increase (decrease) in cash and cash equivalents
76,195

 
(12,039
)
 
30

 
64,186

Beginning cash and cash equivalents
15,737

 
(1,840
)
 
8,114

 
22,011

Ending cash and cash equivalents
$
91,932

 
$
(13,879
)
 
$
8,144

 
$
86,197


94


Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Not applicable.

Item 9A.
Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2013, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Pioneer Energy Services Corp. is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer Energy Services Corp.'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 Pioneer Energy Services Corp. 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.
Pioneer Energy Services Corp.’s management assessed the effectiveness of Pioneer Energy Services Corp.’s internal control over financial reporting as of December 31, 2013. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (1992). Based on our assessment we have concluded that, as of December 31, 2013, Pioneer Energy Services Corp.’s internal control over financial reporting was effective based on those criteria.
KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pioneer Energy Services Corp. included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of Pioneer Energy Services Corp.’s internal control over financial reporting as of December 31, 2013. This report is included in Item 8, Financial Statements and Supplementary Data.
Item 9B.
Other Information
Not Applicable.



95


PART III
In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2014 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC on or about April 9, 2014.

Item 10.
Directors, Executive Officers and Corporate Governance
Please see the information appearing under the headings “Proposal 1—Election of Directors,” “Executive Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Business Conduct and Ethics and Corporate Governance Guidelines” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the definitive proxy statement for our 2014 Annual Meeting of Shareholders for the information this Item 10 requires.
Item 11.
Executive Compensation
Please see the information appearing under the headings “Compensation Discussion and Analysis,” “Director Compensation,” “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in the definitive proxy statement for our 2014 Annual Meeting of Shareholders for the information this Item 11 requires.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
Please see the information appearing under the headings “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2014 Annual Meeting of Shareholders for the information this Item 12 requires.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Please see the information appearing under the headings “Proposal 1—Election of Directors” and “Certain Relationships and Related Transactions” in the definitive proxy statement for our 2014 Annual Meeting of Shareholders for the information this Item 13 requires.
Item 14.
Principal Accountant Fees and Services
Please see the information appearing under the heading “Proposal 3—Ratification of the Appointment of our Independent Registered Public Accounting Firm” in the definitive proxy statement for our 2014 Annual Meeting of Shareholders for the information this Item 14 requires.


96


PART IV
Item 15.
Exhibits and Financial Statement Schedules
(1) Financial Statements.
See Index to Consolidated Financial Statements included in Item 8, Financial Statements and Supplementary Data.
(2) Financial Statement Schedules
No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
(3) Exhibits.
The following exhibits are filed as part of this report:
Exhibit
Number
 
Description
 
 
 
3.1*
-
Restated Articles of Incorporation of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.1)).
 
 
 
3.2*
-
Amended and Restated Bylaws of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.2)).
 
 
 
4.1*
-
Form of Certificate representing Common Stock of Pioneer Energy Services Corp. (Form 10-Q dated August 7, 2012 (File No. 1-8182, Exhibit 4.1)).
 
 
 
4.2*
-
Indenture, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.1)).
 
 
 
4.3*
-
Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.2)).
 
 
 
4.4*
-
First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.2)).
 
 
 
4.5*
-
Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.3)).
 
 
 
4.6*
-
Second Supplemental Indenture, dated October 1, 2012, among Pioneer Coiled Tubing Services, LLC, Pioneer Energy Services Corp., the other subsidiary guarantors and Wells Fargo Bank, National Association, as trustee (Form 10-Q dated November 1, 2012 (File No. 1-8182, Exhibit 4.6)).
 
 
 
10.1*
-
Purchase Agreement, dated March 4, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 5, 2010 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.2*
-
Purchase Agreement, dated November 15, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 16, 2011 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.3*+
-
Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.4+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.2)).
 
 
 
10.5+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.3)).

97


 
 
 
10.6+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.4)).
 
 
 
10.7+*
-
Pioneer Drilling Company Amended and Restated Key Executive Severance Plan (Form 10-Q for the dated August 5, 2008 (File No. 1-8182, Exhibit 10.4)).
 
 
 
10.8+*
-
Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K dated June 22, 2001 (File No. 1-8182, Exhibit 10.5)).
 
 
 
10.9+*
-
Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K dated June 22, 2001 (File No. 1-8182, Exhibit 10.7)).
 
 
 
10.10+*
-
Pioneer Drilling Company 2003 Stock Plan (Form S-8 dated November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
 
 
 
10.11+*
-
Pioneer Drilling Company Amended and Restated 2007 Incentive Plan (Form 10-Q dated November 3, 2011 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.12+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Stock Option Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.13+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)).
 
 
 
10.14+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)).
 
 
 
10.15+*
-
Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.16+*
-
Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).
 
 
 
10.17*
-
Amended and Restated Credit Agreement, dated as of June 30, 2011 among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated July 5, 2011 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.18+*
-
Employment Letter, effective March 1, 2008, from Pioneer Drilling Company to Joseph B. Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.19+*
-
Confidentiality and Non-Competition Agreement, dated February 29, 2008, by and between Pioneer Drilling Company, Pioneer Production Services, Inc. and Joe Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.2)).
 
 
 
10.20+*
-
Employment Letter, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.21+*
-
Pioneer Energy Services Corp. Nonqualified Retirement Savings and Investment Plan (Form 8-K dated January 30, 2013 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.22+*
-
Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 12, 2013 (File No. 1-8182, Exhibit 10.1)).
 
 
 
12.1**
-
Computation of ratio of earnings to fixed charges.
 
 
 
21.1**
-
Subsidiaries of Pioneer Energy Services Corp.
 
 
 
23.1**
-
Consent of Independent Registered Public Accounting Firm.
 
 
 
31.1**
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
 
 
 
31.2**
-
Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
 
 
 

98


32.1#
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
32.2#
-
Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
101**
-
The following financial statements from Pioneer Energy Services Corp.’s Form 10-K for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Shareholders' Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.
 _______________
*
Incorporated by reference to the filing indicated.
**
Filed herewith.
#
Furnished herewith.
+
Management contract or compensatory plan or arrangement.


99


SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
 
PIONEER ENERGY SERVICES CORP.
 
 
 
February 13, 2014
 
/S/    WM. STACY LOCKE
 
 
Wm. Stacy Locke
Chief Executive Officer and President



Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
 
 
 
 
 
Signature
 
Title
 
Date
/S/    DEAN A. BURKHARDT
 
Chairman
 
February 13, 2014
Dean A. Burkhardt
 
 
 
 
/S/    WM. STACY LOCKE
 
President, Chief Executive Officer and Director
(Principal Executive Officer)
 
February 13, 2014
Wm. Stacy Locke
 
 
 
 
/S/    LORNE E. PHILLIPS
 
Executive Vice President and Chief Financial Officer (Principal Accounting Officer)
 
February 13, 2014
Lorne E. Phillips
 
 
 
 
/S/    C. JOHN THOMPSON
 
Director
 
February 13, 2014
C. John Thompson
 
 
 
 
/S/    JOHN MICHAEL RAUH
 
Director
 
February 13, 2014
John Michael Rauh
 
 
 
 
/S/    SCOTT D. URBAN
 
Director
 
February 13, 2014
Scott D. Urban
 
 
 
 



100


Index to Exhibits

Exhibit
Number
 
Description
 
 
 
3.1*
-
Restated Articles of Incorporation of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.1)).
 
 
 
3.2*
-
Amended and Restated Bylaws of Pioneer Energy Services Corp. (Form 8-K dated July 30, 2012 (File No. 1-8182, Exhibit 3.2)).
 
 
 
4.1*
-
Form of Certificate representing Common Stock of Pioneer Energy Services Corp. (Form 10-Q dated August 7, 2012 (File No. 1-8182, Exhibit 4.1)).
 
 
 
4.2*
-
Indenture, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.1)).
 
 
 
4.3*
-
Registration Rights Agreement, dated March 11, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 12, 2010 (File No. 1-8182, Exhibit 4.2)).
 
 
 
4.4*
-
First Supplemental Indenture, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.2)).
 
 
 
4.5*
-
Registration Rights Agreement, dated November 21, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 21, 2011 (File No. 1-8182, Exhibit 4.3)).
 
 
 
4.6*
-
Second Supplemental Indenture, dated October 1, 2012, among Pioneer Coiled Tubing Services, LLC, Pioneer Energy Services Corp., the other subsidiary guarantors and Wells Fargo Bank, National Association, as trustee (Form 10-Q dated November 1, 2012 (File No. 1-8182, Exhibit 4.6)).
 
 
 
10.1*
-
Purchase Agreement, dated March 4, 2010, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated March 5, 2010 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.2*
-
Purchase Agreement, dated November 15, 2011, by and among Pioneer Drilling Company, the subsidiary guarantors party thereto and the initial purchasers party thereto (Form 8-K dated November 16, 2011 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.3*+
-
Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.4+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.2)).
 
 
 
10.5+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Award Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.3)).
 
 
 
10.6+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Restricted Stock Unit Agreement (Form 10-Q dated August 5, 2010 (File No. 1-8182, Exhibit 10.4)).
 
 
 
10.7+*
-
Pioneer Drilling Company Amended and Restated Key Executive Severance Plan (Form 10-Q for the dated August 5, 2008 (File No. 1-8182, Exhibit 10.4)).
 
 
 
10.8+*
-
Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K dated June 22, 2001 (File No. 1-8182, Exhibit 10.5)).
 
 
 
10.9+*
-
Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K dated June 22, 2001 (File No. 1-8182, Exhibit 10.7)).
 
 
 
10.10+*
-
Pioneer Drilling Company 2003 Stock Plan (Form S-8 dated November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
 
 
 

101


10.11+*
-
Pioneer Drilling Company Amended and Restated 2007 Incentive Plan (Form 10-Q dated November 3, 2011 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.12+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Stock Option Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.13+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)).
 
 
 
10.14+*
-
Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)).
 
 
 
10.15+*
-
Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.16+*
-
Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).
 
 
 
10.17*
-
Amended and Restated Credit Agreement, dated as of June 30, 2011 among Pioneer Drilling Company, the lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent, issuing lender and swing line lender (Form 8-K dated July 5, 2011 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.18+*
-
Employment Letter, effective March 1, 2008, from Pioneer Drilling Company to Joseph B. Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.19+*
-
Confidentiality and Non-Competition Agreement, dated February 29, 2008, by and between Pioneer Drilling Company, Pioneer Production Services, Inc. and Joe Eustace (Form 8-K dated March 5, 2008 (File No. 1-8182, Exhibit 10.2)).
 
 
 
10.20+*
-
Employment Letter, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.21+*
-
Pioneer Energy Services Corp. Nonqualified Retirement Savings and Investment Plan (Form 8-K dated January 30, 2013 (File No. 1-8182, Exhibit 10.1)).
 
 
 
10.22+*
-
Amended and Restated Pioneer Energy Services Corp. 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 12, 2013 (File No. 1-8182, Exhibit 10.1)).
 
 
 
12.1**
-
Computation of ratio of earnings to fixed charges.
 
 
 
21.1**
-
Subsidiaries of Pioneer Energy Services Corp.
 
 
 
23.1**
-
Consent of Independent Registered Public Accounting Firm.
 
 
 
31.1**
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
 
 
 
31.2**
-
Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
 
 
 
32.1#
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
32.2#
-
Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
 
101**
-
The following financial statements from Pioneer Energy Services Corp.’s Form 10-K for the year ended December 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Shareholders' Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements.
*    Incorporated by reference to the filing indicated.
**    Filed herewith.
#    Furnished herewith.
+    Management contract or compensatory plan or arrangement.

102