10-K 1 a2014q410k.htm 10-K Form 10K - 2014

 
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, 2014
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  þ
 
 
 
Accelerated filer  o
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, 2014) was approximately $1.1 billion.
As of January 29, 2015, there were 63,867,955 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 2015 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:
general economic and business conditions and industry trends;
levels and volatility of oil and gas prices;
the continued demand for drilling services or production services in the geographic areas where we operate;
decisions about exploration and development projects to be made by oil and gas exploration and production companies;
the highly competitive nature of our business;
technological advancements and trends in our industry, and improvements in our competitors' equipment;
the loss of one or more of our major clients or a decrease in their demand for our services;
future compliance with covenants under our senior secured revolving credit facility and our senior notes;
operating hazards inherent in our operations;
the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry;
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;
the political, economic, regulatory and other uncertainties encountered by our operations, 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. 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.”

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Item 1.
Business
General
Pioneer Energy Services Corp. (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 and wireline services. Through these purchases, we also acquired fishing and rental services operations, which were subsequently sold on September 17, 2014. We also acquired a coiled tubing services business at the end of 2011, to expand our existing production services offerings. We have continued to invest in the growth of all our core service offerings through acquisitions and organic growth.
Pioneer Energy Services Corp. 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 through our six drilling divisions in the US and internationally in Colombia. 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 or turnkey 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.
Since October 2014, domestic and international oil prices have declined significantly to historically low price levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our long-lived assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0 million of impairment charges to reduce the carrying value of our 31 mechanical and lower horsepower electric drilling rigs to their estimated fair value.
Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically the first rigs to become idle. As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower electric drilling rigs, which includes the nine rigs that were idle and classified as held for sale as of year-end and 15 rigs that we expect to place as held for sale during the first quarter of 2015, after their current contracts are completed. In January and February 2015, we sold six of these drilling rigs.
The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015, as well as our expected count at March 31, 2015.
 
 
Drilling Rigs Owned
 
Drilling Rigs Held for Sale
 
Drilling Rig Fleet Count
As of December 31, 2014
 
62

 
(9
)
 
53

As of February 1, 2015
 
59

 
(12
)
 
47

Expected at March 31, 2015
 
56

 
(18
)
 
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As of February 1, 2015, the drilling rigs in our fleet are assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
13

West Texas
 
10

North Dakota
 
9

Utah
 
4

Appalachia
 
3

Colombia
 
8

 
 
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We are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver and begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during the second quarter, two rigs in the third quarter, and the final rig by the end of the year. Excluding the rigs which we expect to sell in the near-term and considering the five new-build drilling rigs under construction, we expect to end 2015 with a drilling fleet of 43 rigs.
As of February 1, 2015, 40 of our 47 drilling rigs are earning revenues under drilling contracts, 29 of which are earning under term contracts. Four of our drilling rigs in Colombia are currently working under term contracts that extend through mid-2015 and we are actively marketing our other four rigs to multiple clients to diversify our client base in Colombia.
In response to the dramatic decline in oil prices during recent months, we have received early termination notices for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will be released upon completion of their current wells, all of which are expected to be completed by the end of the first quarter 2015, resulting in approximately $43.5 million of early termination payments which will be recognized as revenue over the remaining term of the contracts, $0.3 million of which was recognized in 2014.
Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing 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. On September 17, 2014, we completed the sale of our fishing and rental services operations. 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 February 1, 2015, we operate 107 rigs with 550 horsepower and 10 rigs with 600 horsepower through 11 locations, mostly in the Gulf Coast states, as well as in Arkansas and 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, 2014, we have four wireline units placed as held for sale, for which we recognized approximately $0.3 million of impairment charges to reduce their carrying values to fair value. As of February 1, 2015, we operate a fleet of 128 wireline units through 24 locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.
Coiled Tubing. 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

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number of horizontal well applications such as milling temporary plugs between frac stages. As of February 1, 2015, our coiled tubing business consists of 12 onshore and five offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.
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 through 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.
In recent years, generally increasing oil prices drove industry equipment utilization and revenue rates up, particularly in oil-producing regions and certain shale regions. Even though advancements in technology have improved the efficiency of drilling rigs, demand remained steady, particularly for drilling rigs that are able to drill horizontally. Beginning in October 2014, domestic and international oil prices have significantly declined to historically low price levels. If oil prices continue to decline, or if oil and natural gas prices remain at current levels for an extended period of time, then industry equipment utilization and revenue rates will further decrease, both domestically and in Colombia.
While drilling and production services have historically trended similarly in response to fluctuations in commodity prices, because exploration and production companies often adjust their budgets for exploratory drilling first in response to a shift in commodity prices, the demand for drilling services is generally impacted first and to a greater extent than the demand for production services which is more dependent on expenditures to sustain production.
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 are forecasted to 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.
Capital expenditures by exploration and production companies for the drilling of exploratory wells or new wells in proven areas are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices. In contrast, 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, which requires a range of production services, are relatively stable and more predictable.

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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 three years are illustrated in the graphs below.
As shown in the charts above, the trends in industry rig counts are influenced primarily by fluctuations in oil prices, which affect the levels of capital and operating expenditures made by our clients.
Colombian oil prices have historically 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 its national oil company's long-term exploration and production programs.
Technological advancements and trends in our industry also affect the demand for certain types of equipment. In recent years, and especially during the recent downturn, demand has significantly decreased for certain mechanical and /or lower horsepower drilling rigs, particularly in vertical well markets. The decline is primarily due to higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities. This trend has resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells, and could further reduce the overall demand for all drilling rigs. Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically the first rigs to become idle.
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.
Competitive Strengths
Our competitive strengths include:
One of the Leading Providers in the Most Attractive Regions. Our drilling rigs operate in many of the most attractive producing regions in the Americas, including the Bakken, Marcellus and Eagle Ford shales, and the Permian Basin, 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. Excluding all of the drilling rigs that we expect to sell in the near-term, over 85% of our drilling fleet was purchased or built new within the last 15 years, ten of which are AC drilling rigs which we constructed during 2011 to 2013. Additionally, we are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver and begin operating under long-term drilling contracts in 2015. Over 90% of our drilling rigs, excluding those that we expect to sell, are capable of drilling horizontal wells, and approximately 75% are equipped with either a walking or skidding system for pad drilling. Over 75% 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.

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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 2014 total recordable incident rate was one of the lowest we have achieved since our company's inception. 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 over 35 years of industry experience. Our President of Drilling Services, Brian Tucker, and our President of Production Services, Joe Eustace, have over 45 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 11.9% of our 2014 consolidated revenues, Apache Corporation, Hess Corporation, Penn Virginia Oil & Gas, LP and Continental Resources. We also maintain a good relationship with Ecopetrol, which accounted for approximately 9.9% of our 2014 consolidated revenues. We believe our relationships with our clients are strong 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 the Bakken, Marcellus and Eagle Ford shales and the Permian Basin. All of the ten drilling rigs we constructed in 2011 to 2013 are currently operating in domestic shale and unconventional plays and we expect that our five new-build drilling rigs currently under construction will be deployed to these regions as well. Additionally, we have added significant capacity in recent years to our production services fleets, which we believe are well positioned to further capitalize on shale development.

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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. With natural gas prices at historically low levels in recent years, we intentionally increased our exposure to oil-related activities by redeploying certain of our assets into predominately oil-producing regions. With the recent decline in oil prices, we believe our fleets are highly capable and well positioned for deployment to whichever market is most profitable.
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. Four of our drilling rigs in Colombia are currently working under term contracts that extend through mid-2015 and we are actively marketing our other four rigs to multiple clients to diversify our client base in Colombia.
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. We acquired a coiled tubing services business to expand our existing production services offerings at the end of 2011. Since the beginning of 2010, we have added significant capacity to our other production services fleets through the addition of 65 wireline units, 43 well servicing rigs and we have constructed ten AC drilling rigs, all of which are currently operating in domestic shale or unconventional plays. We are currently constructing five new-build AC rigs which we expect to deliver and begin operating under long-term drilling contracts in 2015.
With the recent decline in oil prices and the expected reductions in our rig utilization and revenue rates in 2015, our near-term goals are to maintain a strong balance sheet and ample liquidity. Management efforts are focused on stringent cost control measures, the liquidation of nonstrategic or under-performing assets and continued emphasis on the execution and performance of our core businesses. We are currently executing limited organic growth through select fleet additions which were ordered prior to the decline in oil prices. We believe these near-term goals will position us to take advantage of future business opportunities and continue our long-term growth strategy.
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

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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 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 41 rigs (with seven additional spare top drives available for installation), iron roughnecks on 42 rigs (with 16 additional spare iron roughnecks available for installation), walking/skidding systems on 31 rigs and automatic catwalks on 33 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 well 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.

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The following table sets forth historical information regarding utilization for our drilling rig fleet:
 
Year ended December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
Average number of operating rigs for the period
62.0

 
68.2

 
65.0

 
69.3

 
71.0

Average utilization rate
87
%
 
84
%
 
87
%
 
73
%
 
59
%
As of December 31, 2014, we had 53 drilling rigs in our fleet and nine drilling rigs classified as held for sale which were idle as of year-end. We expect to place a total of 15 additional rigs as held for sale during the first quarter of 2015. Excluding the rigs which we expect to sell in the near-term and considering the five new-build drilling rigs under construction, we expect to end 2015 with a drilling fleet of 43 rigs. The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015, as well as our expected count at March 31, 2015.
 
 
Drilling Rigs Owned
 
Drilling Rigs Held for Sale
 
Drilling Rig Fleet Count
As of December 31, 2014
 
62

 
(9
)
 
53

As of February 1, 2015
 
59

 
(12
)
 
47

Expected at March 31, 2015
 
56

 
(18
)
 
38

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 and upgrades 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.
Our drilling contracts generally provide for compensation on either a daywork or turnkey 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. We enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of high rig demand. Currently, we have contracts with original terms of six months to four years in duration.
As of February 1, 2015, we have 29 drilling rigs earning under term contracts, which if not renewed prior to 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
 
25

 
13

 
6

 
4

 
2

 

Colombia
 
4

 
4

 

 

 

 

 
 
29

 
17

 
6

 
4

 
2

 

In response to the dramatic decline in oil prices during recent months, we have received early termination notices for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will be released upon completion of their current wells, all of which are expected to be completed by the end of the first quarter 2015, resulting in approximately $43.5 million of early termination payments which will be recognized as revenue over the remaining term of the contracts, $0.3 million of which was recognized in 2014.
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.

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During the last three fiscal years, our drilling contracts have primarily been for daywork drilling. 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
2014
 
2013
 
2012
    Daywork
1,001

 
970

 
881

    Turnkey
106

 
27

 
11

Total number of wells
1,107

 
997

 
892

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.
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.

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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 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 February 1, 2015, our fleet of well servicing rigs totaled 117 rigs, which we operate through 11 locations, mostly in the Gulf Coast states, as well as in Arkansas and North Dakota. Our fleet is among the newest in the industry, consisting of 107 rigs with 550 horsepower and 10 rigs with 600 horsepower 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 February 1, 2015, our wireline services fleet totaled 128 wireline units, including six offshore units, which we operate through 24 locations in Texas, Kansas, Colorado, Montana, North Dakota, Louisiana, Oklahoma and Wyoming.
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 February 1, 2015, our coiled tubing business consists of 12 onshore and five offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.

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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 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, 2014
 
Whiting Petroleum Company
11.9
%
Ecopetrol
9.9
%
Penn Virginia Oil & Gas, LP
6.0
%
 
 
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
%
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.

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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, including safety record. 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 many clients are willing to pay a slight premium for the quality and safe, 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 need for well servicing, wireline and coiled tubing 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.
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

13



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 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 $101 million per occurrence and in the aggregate, with a deductible of $250,000 per occurrence. We also carry insurance coverage for pollution liability up to $20 million with a deductible of $500,000. 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.

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Employees
We currently have approximately 3,400 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 66 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 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 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

15



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 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.
On June 2, 2014, the EPA issued a proposed rule to limit carbon dioxide emissions from existing electric utility generating units. Under the EPA's current proposal, nationwide emissions of carbon dioxide from the power sector would be cut by up to 30% from the 2005 baseline by the year 2030. The required emission reductions would vary state-by-state, and the proposed rule provides each State flexibility in determining how the emission reductions would be achieved.
On January 14, 2015, the EPA announced that it plans to implement additional steps to reduce methane and VOC emissions from the oil and gas industry. Proposed regulations are planned for the summer of 2015 and are expected to address new and modified oil and gas sources, but may also be extended to certain existing sources located in areas not meeting federal standards for ozone.
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

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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.
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. Several proposals are being considered by the EPA and other federal agencies that, if implemented, would impose additional requirements on the practice of hydraulic fracturing. Several states are considering legislation to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to concerns regarding potential environmental and physical impacts, including groundwater and drinking water impacts, as well as whether such activities may cause minor earthquakes.
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. A Progress Report was issued by the EPA in May 2014; peer review of the information provided in the Progress Report is underway. 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. On December 19, 2014, the EPA published a final rule clarifying certain aspects of the new rules. On January 14, 2015, the EPA announced that it plans to propose and implement new regulations to further reduce methane and VOC emissions from the oil and gas industry. It is also possible that the EPA will propose additional amendments to its existing oil and gas regulations. 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 early 2015. 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 and has conducted hearings on a possible rule to reduce flaring and venting associated with oil and gas operations on public lands.
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 continued to see strong public opposition, and has resulted in delays of well permits in some areas.
On June 30, 2014, the State of New York’s Court of Appeals upheld the right of individual municipalities in the State of New York to ban hydraulic fracturing using zoning restrictions. In December 2014, New York State Governor Cuomo announced that hydraulic fracturing will be permanently banned in the state. Similarly situated municipalities in other

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states may seek to ban or restrict resource extraction operations within their borders using zoning restrictions, which could adversely affect the ability of resource extraction enterprises to operate in certain parts of the country, and thus adversely affect demand for our services, which may in turn adversely affect our future results of operations.
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.
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. Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. Worldwide political, economic, and military events as well as natural disasters have contributed to oil and gas price volatility historically, and are likely to continue to do so in the future. Many factors beyond our control affect oil and gas prices, including:
the foreign supply of oil and gas;
the cost of exploring for, producing and delivering oil and gas;
the discovery rate of new oil and gas reserves;
the rate of decline of existing and new oil and gas reserves;
available pipeline and other oil and gas transportation capacity;
the levels of oil and gas storage;
the ability of oil and gas exploration and production companies to raise capital;
economic conditions in the United States and elsewhere;
actions by the Organization of Petroleum Exporting Countries, which we refer to as OPEC;
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;
weather conditions in the United States and elsewhere;
the pace adopted by foreign governments for the exploration, development and production of their national reserves;
the price of foreign imports of oil and gas; and
the overall supply and demand for oil and gas.

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As a result of the recent declines in oil prices that began in late 2014 and have continued into 2015, our clients will likely reduce spending on exploration and production projects, resulting in a decrease in demand for our services.
Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling and production services activities. Reduced demand for oil and natural gas generally results in lower prices for these commodities and often impacts the economics of planned drilling projects and ongoing production projects, resulting in the curtailment, reduction, delay or postponement of such projects for an indeterminate period of time. When drilling and production activity and spending declines, both dayrates and utilization historically decline as well.
In recent months, beginning in October 2014, oil prices worldwide have dropped significantly. If the current depressed oil and natural gas prices persist for a prolonged period, or further decline, oil and gas exploration and production companies are likely to cancel or curtail their drilling programs and lower production spending on existing wells, thereby reducing demand for our services.
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;
the collectability of our receivables; and
our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.
If any of the foregoing were to occur, it could have a material adverse effect on 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 and coiled tubing units, 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.

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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:
the type and condition of each of the competing drilling rigs, well servicing rigs, wireline units and coiled tubing units;
the mobility and efficiency of the equipment;
the quality of service and experience of the crews;
the safety record of the company providing the services;
the offering of ancillary services; and
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 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:
better withstand industry downturns;
compete more effectively on the basis of price and technology;
retain skilled 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.
Technological advancements and trends in our industry affect the demand for certain types of equipment.
Technological advancements and trends in our industry affect the demand for certain types of equipment. In recent years, and especially during the recent downturn, demand has significantly decreased for certain mechanical and /or lower horsepower drilling rigs, particularly in vertical well markets. The decline is primarily due to higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities. This trend has resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells, and could further reduce the overall demand for all drilling rigs. Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically the first rigs to become idle.
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.

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We derive a significant portion of our revenue from a limited number of major clients, and our business, financial condition and results of operations could be materially adversely affected if we are unable to maintain relationships with these clients, or if their demand for our services decreases.
In the past, we have derived a significant portion of our revenue from a limited number of major clients. For the years ended December 31, 2014, 2013 and 2012, our drilling and production services to our top three clients accounted for approximately 28%, 29%, and 25%, respectively, of our revenue, and in 2014, 2013 and 2012, one client, Whiting Petroleum Company, accounted for 12%, 13% and 10%, respectively, of our revenue.  The loss of one or more of our major clients, or their decrease in demand for our services, could have a material adverse effect on our business, financial condition and results of operations.
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 February 1, 2015, our total debt balance of $450.1 million primarily consists of $300 million outstanding under our Senior Notes and $150 million outstanding under our Revolving Credit Facility. At February 1, 2015, we had borrowing availability of $181.5 million under our Revolving Credit Facility.
Our current and future indebtedness could have important consequences, including:
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;
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 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, proceeds from the expected sales of certain non-strategic assets 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.

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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.
Our Revolving Credit Facility and our Senior Notes impose significant covenants 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 covenants 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 limits 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 the 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.
The failure to comply with any of these covenants 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 covenants 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.
Unexpected cost overruns on our turnkey drilling jobs 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

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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. 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 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.
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:
blowouts;
cratering;
fires and explosions;
loss of well control;
collapse of the borehole;
damaged or lost drilling equipment; 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 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, 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.

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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 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. 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;
potential losses of key employees and clients of the acquired businesses;
risks of entering markets in which we have limited prior experience; and
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.

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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.
Our cash and cash equivalents and short term investments could be adversely affected if the financial institutions in which we hold our cash and cash equivalents fail.
We maintain cash balances at third-party financial institutions in excess of the Federal Deposit Insurance Corporation insurance limit. While we monitor the cash balances in the operating accounts and adjust the balances as appropriate, we may incur a loss to the extent such loss exceeds the insurance limitation, and there could be a material impact on our business, if one of more of the financial institutions with which we deposit fails or is subject to other adverse conditions in the financial or credit markets and bank regulators elect to impose losses on uninsured depositors. To date, we have experienced no loss or lack of access to our invested cash or cash equivalents. However, we can provide no assurance that access to our invested cash and cash equivalents will not be impacted by adverse conditions in the financial and credit markets.
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;
employee strikes, work stoppages, labor disputes and other slowdowns;
expropriation, confiscation or nationalization of our assets;
renegotiation or nullification of contracts;
foreign taxation, such as the tax for equality and the net-worth tax recently enacted in Colombia;
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;
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;
the risks associated with any lack of compliance with the Foreign Corrupt Practices Act of 1977 ("FCPA") or other anti-corruption laws;
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 currently all 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.

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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;
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 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

27



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 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.
On June 2, 2014, the EPA issued a proposed rule to limit carbon dioxide emissions from existing electric utility generating units. Under the EPA's current proposal, nationwide emissions of carbon dioxide from the power sector would be cut by up to 30% from the 2005 baseline by the year 2030. The required emission reductions would vary state-by-state, and the proposed rule provides each State flexibility in determining how the emission reductions would be achieved.
On January 14, 2015, the EPA announced that it plans to implement additional steps to reduce methane and VOC emissions from the oil and gas industry. Proposed regulations are planned for the summer of 2015 and are expected to address new and modified oil and gas sources, but may also be extended to certain existing sources located in areas not meeting federal standards for ozone.

28



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.
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.
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. Several proposals are being considered by the EPA and other federal agencies that, if implemented, would impose additional requirements on the practice of hydraulic fracturing. Several states are considering legislation to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to concerns regarding potential environmental and physical impacts, including groundwater and drinking water impacts, as well as whether such activities may cause minor earthquakes.

29



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. A Progress Report was issued by the EPA in May 2014; peer review of the information provided in the Progress Report is underway. 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. On December 19, 2014, the EPA published a final rule clarifying certain aspects of the new rules. On January 14, 2015, the EPA announced that it plans to propose and implement new regulations to further reduce methane and VOC emissions from the oil and gas industry. It is also possible that the EPA will propose additional amendments to its existing oil and gas regulations. 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 early 2015. 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 and has conducted hearings on a possible rule to reduce flaring and venting associated with oil and gas operations on public lands.
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 continued to see strong public opposition, and has resulted in delays of well permits in some areas.
On June 30, 2014, the State of New York’s Court of Appeals upheld the right of individual municipalities in the State of New York to ban hydraulic fracturing using zoning restrictions. In December 2014, New York State Governor Cuomo announced that hydraulic fracturing will be permanently banned in the state. Similarly situated municipalities in other states may seek to ban or restrict resource extraction operations within their borders using zoning restrictions, which could adversely affect the ability of resource extraction enterprises to operate in certain parts of the country, and thus adversely affect demand for our services, which may in turn adversely affect our future results of operations.
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

30



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.
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.


31




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.

Item 4.
Mine Safety Disclosures
Not applicable.

32



PART II
Item 5.
Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
As of January 29, 2015, 63,867,955 shares of our common stock were outstanding, held by 367 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, 2014
 
 
 
First Quarter
$
7.72

 
$
12.95

Second Quarter
12.11

 
17.54

Third Quarter
13.70

 
18.38

Fourth Quarter
4.22

 
13.06

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

The last reported sales price for our common stock on the New York Stock Exchange on January 29, 2015 was $4.10 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, 2014. The following table provides information relating to our repurchase of common shares during the quarter ended December 31, 2014:
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

 
$
12.41

 

 

November 1—November 30
 

 
$

 

 

December 1—December 31
 
317

 
$
5.79

 

 

Total
 
421

 
$
7.43

 

 

(1)
The shares indicated consist of shares of our common stock tendered by employees to the Company during the three months ended December 31, 2014, 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, 2009 to December 31, 2014, 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, 2009 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,
 
2014 (1)
 
2013 (2)
 
2012
 
2011
 
2010
 
(In thousands, except per share amounts)
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Revenues
$
1,055,223

 
$
960,186

 
$
919,443

 
$
715,941

 
$
487,210

Income (loss) from operations
23,984

 
(6,229
)
 
81,811

 
57,458

 
(18,572
)
Income (loss) before income taxes
(49,322
)
 
(55,778
)
 
46,386

 
20,833

 
(47,558
)
Net earnings (loss) applicable to common stockholders
(38,018
)
 
(35,932
)
 
30,032

 
11,177

 
(33,261
)
Earnings (loss) per common share-basic
$
(0.60
)
 
$
(0.58
)
 
$
0.49

 
$
0.19

 
$
(0.62
)
Earnings (loss) per common share-diluted
$
(0.60
)
 
$
(0.58
)
 
$
0.48

 
$
0.19

 
$
(0.62
)
Other Financial Data:
 
 
 
 
 
 
 
 
 
Net cash provided by operating activities
$
233,041

 
$
174,580

 
$
199,366

 
$
144,879

 
$
98,351

Net cash used in investing activities
(151,918
)
 
(150,676
)
 
(361,231
)
 
(307,484
)
 
(129,481
)
Net cash provided by (used in) financing activities
(73,584
)
 
(20,252
)
 
99,401

 
226,791

 
12,762

Capital expenditures
$
188,121

 
125,420

 
379,272

 
237,787

 
135,151

 
As of December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
 
(In thousands)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Working capital
$
121,882

 
$
118,547

 
$
62,236

 
$
129,932

 
$
76,142

Property and equipment, net
856,541

 
937,657

 
1,014,340

 
793,956

 
655,508

Long-term debt and capital lease obligations, excluding current installments
455,053

 
499,666

 
518,725

 
418,728

 
279,530

Shareholders’ equity
495,064

 
518,433

 
547,680

 
510,445

 
396,333

Total assets
1,171,589

 
1,229,623

 
1,339,776

 
1,172,754

 
841,343

(1)
The statement of operations and other financial data for the year ended December 31, 2014 reflect the impact of impairment charges on our property and equipment of $73.0 million.
(2)
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, the continued demand for drilling services or production services in the geographic areas where we operate, decisions about exploration and development projects to be made by oil and gas exploration and production companies, the highly competitive nature of our business, technological advancements and trends in our industry and improvements in our competitors' equipment, the loss of one or more of our major clients or a decrease in their demand for our services, future compliance with covenants under our senior secured revolving credit facility and our senior notes, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing and wireline units within the industry, 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, the political, economic, regulatory and other uncertainties encountered by our operations, 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 Corp. (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 and wireline services. Through these purchases, we also acquired fishing and rental services operations, which were subsequently sold on September 17, 2014. We also acquired a coiled tubing services business at the end of 2011, to expand our existing production services offerings. We have continued to invest in the growth of all our core service offerings through acquisitions and organic growth.
Pioneer Energy Services Corp. 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 through our six drilling divisions in the US and internationally in Colombia. 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 or turnkey 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.
Since October 2014, domestic and international oil prices have declined significantly to historically low price levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our long-lived assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0 million of impairment charges to reduce the carrying value of our 31 mechanical and lower horsepower electric drilling rigs to their estimated fair value.
As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower electric drilling rigs, which includes the nine rigs that were idle and classified as held for sale as of year-end and 15 rigs that we expect to place as held for sale during the first quarter of 2015, after their current contracts are completed. In January and February 2015, we sold six of these drilling rigs.
The following is a summary of our drilling rig counts as of December 31, 2014 and February 1, 2015, as well as our expected count at March 31, 2015.
 
 
Drilling Rigs Owned
 
Drilling Rigs Held for Sale
 
Drilling Rig Fleet Count
As of December 31, 2014
 
62

 
(9
)
 
53

As of February 1, 2015
 
59

 
(12
)
 
47

Expected at March 31, 2015
 
56

 
(18
)
 
38

As of February 1, 2015, the drilling rigs in our fleet are assigned to the following divisions:
Drilling Division
 
Rig Count
South Texas
 
13

West Texas
 
10

North Dakota
 
9

Utah
 
4

Appalachia
 
3

Colombia
 
8

 
 
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We are currently constructing five new-build 1,500 horsepower AC drilling rigs which we expect to deliver and begin operating under long-term drilling contracts in 2015, with the first two rigs to be deployed during the second quarter, two rigs in the third quarter, and the final rig by the end of the year. Excluding the rigs which we expect to sell in the near-term and considering the five new-build drilling rigs under construction, we expect to end 2015 with a drilling fleet of 43 rigs.

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As of February 1, 2015, 40 of our 47 drilling rigs are earning revenues under drilling contracts, 29 of which are earning under term contracts. Four of our drilling rigs in Colombia are currently working under term contracts that extend through mid-2015 and we are actively marketing our other four rigs to multiple clients to diversify our client base in Colombia.
In response to the dramatic decline in oil prices during recent months, we have received early termination notices for 12 of our 29 drilling rigs that are earning revenues under term contracts. These 12 drilling rigs will be released upon completion of their current wells, all of which are expected to be completed by the end of the first quarter 2015, resulting in approximately $43.5 million of early termination payments which will be recognized as revenue over the remaining term of the contracts, $0.3 million of which was recognized in 2014.
Production Services Segment—Our Production Services Segment provides a range of services to exploration and production companies, including well servicing, wireline services and coiled tubing 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. On September 17, 2014, we completed the sale of our fishing and rental services operations. 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 February 1, 2015, we operate 107 rigs with 550 horsepower and 10 rigs with 600 horsepower through 11 locations, mostly in the Gulf Coast states, as well as in Arkansas and 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, 2014, we have four wireline units placed as held for sale, for which we recognized approximately $0.3 million of impairment charges to reduce their carrying values to fair value. As of February 1, 2015, we operate a fleet of 128 wireline units through 24 locations in the Gulf Coast, Mid-Continent and Rocky Mountain states.
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 February 1, 2015, our coiled tubing business consists of 12 onshore and five offshore coiled tubing units which are currently deployed through three locations in Texas and Louisiana.

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 through 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.

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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.
In recent years, generally increasing oil prices drove industry equipment utilization and revenue rates up, particularly in oil-producing regions and certain shale regions. Even though advancements in technology have improved the efficiency of drilling rigs, demand remained steady, particularly for drilling rigs that are able to drill horizontally. Beginning in October 2014, domestic and international oil prices have significantly declined to historically low price levels. If oil prices continue to decline, or if oil and natural gas prices remain at current levels for an extended period of time, then industry equipment utilization and revenue rates will further decrease, both domestically and in Colombia.
While drilling and production services have historically trended similarly in response to fluctuations in commodity prices, because exploration and production companies often adjust their budgets for exploratory drilling first in response to a shift in commodity prices, the demand for drilling services is generally impacted first and to a greater extent than the demand for production services which is more dependent on expenditures to sustain production. We expect an increase in pricing pressure and a highly competitive production services environment in 2015, but we believe our high-quality equipment and services are well positioned to compete.
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 are forecasted to 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.
Capital expenditures by exploration and production companies for the drilling of exploratory wells or new wells in proven areas are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices. In contrast, 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, which requires a range of production services, are relatively stable and more predictable.

39




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 three years are illustrated in the graphs below.
As shown in the charts above, the trends in industry rig counts are influenced primarily by fluctuations in oil prices, which affect the levels of capital and operating expenditures made by our clients.
Colombian oil prices have historically 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 its national oil company's long-term exploration and production programs.
Technological advancements and trends in our industry also affect the demand for certain types of equipment. In recent years, and especially during the recent downturn, demand has significantly decreased for certain mechanical and /or lower horsepower drilling rigs, particularly in vertical well markets. The decline is primarily due to higher demand for drilling rigs that are able to drill horizontally and the increased use of "pad drilling." Pad drilling enables a series of horizontal wells to be drilled in succession by a walking or skidding drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities. This trend has resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells, and could further reduce the overall demand for all drilling rigs. Mechanical and lower horsepower drilling rigs are the most impacted by the industry downturn and are typically the first rigs to become idle.
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 $34.9 million as of December 31, 2014), cash generated from operations, including payments from the early terminations of drilling contracts, proceeds from sales of certain non-strategic assets and the unused portion of our senior secured revolving credit facility (the “Revolving Credit Facility”).
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 February 1, 2015, 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.
In March 2010, we issued $250 million of senior notes with a coupon interest rate of 9.875% that were set to mature in 2018 (the "2010 Senior Notes"), the net proceeds from which were used to repay a portion of the borrowings outstanding under our Revolving Credit Facility. In November 2011, we issued an additional $175 million of senior

40




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 our coiled tubing business in December 2011. In March 2014, we issued $300 million of unregistered senior notes with a coupon interest rate of 6.125% that are due in 2022 (the “2014 Senior Notes”), the net proceeds from which, combined with cash on hand, were used to fund the repayment of $300 million of aggregate principal amount of 2010 and 2011 Senior Notes in March and May 2014. In October 2014, we redeemed the remaining $125.0 million in aggregate principal amount of the 2010 and 2011 Senior Notes, primarily funded by proceeds from our revolving credit facility and through cash on hand.
Our Revolving Credit Facility, as amended on September 22, 2014, 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 $350 million, all of which matures in September 2019. In addition, at our request, and with the lenders' consent, the aggregate commitments of the lenders under the Revolving Credit Facility may be increased up to an additional $100 million provided that no default exists, all representations and warranties are true and correct, and compliance with financial covenants as set forth in the Revolving Credit Facility is met immediately prior to and after giving effect thereto. As of February 1, 2015, we had $150 million outstanding under our Revolving Credit Facility and $18.5 million in committed letters of credit, which resulted in borrowing availability of $181.5 million under our Revolving Credit Facility. There are no limitations on our ability to access this borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. 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.
We currently expect that cash and cash equivalents, cash generated from operations, including payments from the early terminations of drilling contracts, proceeds from sales of certain non-strategic assets 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, 2014 and 2013, our primary uses of capital resources were for property and equipment additions which consisted of the following (amounts in thousands):
 
Year ended December 31,
 
2014
 
2013
Drilling Services Segment:
 
 
 
Routine
$
43,403

 
$
39,276

Discretionary
24,340

 
35,569

Fleet additions
34,618

 
41,679

Total Drilling Services Segment
102,361

 
116,524

Production Services Segment:
 
 
 
Routine
22,927

 
23,053

Discretionary
21,854

 
20,092

Fleet additions
28,236

 
5,687

Total Production Services Segment
73,017

 
48,832

Net cash used for purchases of property and equipment
175,378

 
165,356

Net impact of accruals
12,743

 
(39,936
)
Total Capital Expenditures
$
188,121

 
$
125,420

Our Drilling Services Segment incurred $37.8 million and $12.3 million of costs, including accruals for capital expenditures, on the construction of our new-build drilling rigs during the years ended December 31, 2014 and 2013, respectively. Additionally, during the year ended December 31, 2014, we performed significant upgrade projects to various rigs in our drilling fleet including, among others, the installation of five additional walking systems, three

41




additional automatic catwalks and one additional top drive, the upgrade of one drilling rig to higher horsepower, and we upgraded four rigs with higher horsepower mud pumps. 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. In connection with drilling equipment upgrades and the construction of new-build drilling rigs, we capitalized $0.7 million and $0.9 million of interest costs during the years ended December 31, 2014 and 2013, respectively.
Our Production Services Segment acquired six wireline units, seven well servicing rigs and four coiled tubing units during the year ended December 31, 2014. During the year ended December 31, 2013, we acquired three wireline units and one well servicing rig.
Currently, we expect to spend approximately $165 million to $180 million on capital expenditures during 2015. We expect the total capital expenditures for 2015 will be allocated approximately 70% for our Drilling Services Segment and approximately 30% for our Production Services Segment. Our planned capital expenditures for the year ending December 31, 2015 include the remaining payments for five new-build drilling rigs, nine well servicing rigs, eight wireline units, routine capital expenditures and certain drilling equipment which was ordered in 2014 but requires long lead-time orders. 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 capital expenditures in 2015 from operating cash flow in excess of our working capital requirements, including payments from the early terminations of drilling contracts, proceeds from sales of certain non-strategic assets and from borrowings under our Revolving Credit Facility, if necessary.
Working Capital
Our working capital was $121.9 million at December 31, 2014, compared to $118.5 million at December 31, 2013. Our current ratio, which we calculate by dividing current assets by current liabilities, was 1.8 at December 31, 2014 compared to 2.0 at December 31, 2013.
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 new-build rig construction projects are in progress or when higher percentages of our drilling contracts are turnkey contracts.

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The changes in the components of our working capital were as follows (amounts in thousands):
 
December 31,
2014
 
December 31,
2013
 
Change
Cash and cash equivalents
$
34,924

 
$
27,385

 
$
7,539

Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
136,161

 
115,908

 
20,253

Unbilled receivables
38,002

 
49,535

 
(11,533
)
Insurance recoveries
10,900

 
8,607

 
2,293

Income taxes and other
5,138

 
2,310

 
2,828

Deferred income taxes
10,998

 
13,092

 
(2,094
)
Inventory
14,117

 
13,232

 
885

Assets held for sale
9,909

 

 
9,909

Prepaid expenses and other current assets
8,925

 
9,311

 
(386
)
Current assets
269,074

 
239,380

 
29,694

Accounts payable
64,305

 
43,718

 
20,587

Current portion of long-term debt
27

 
2,847

 
(2,820
)
Deferred revenues
3,315

 
699

 
2,616

Accrued expenses:
 
 
 
 
 
Payroll and related employee costs
40,058

 
30,020

 
10,038

Insurance premiums and deductibles
12,829

 
10,940

 
1,889

Insurance claims and settlements
10,900

 
8,607

 
2,293

Interest
5,432

 
12,275

 
(6,843
)
Other
10,326

 
11,727

 
(1,401
)
Current liabilities
147,192

 
120,833

 
26,359

Working capital
$
121,882

 
$
118,547

 
$
3,335

The increase in cash and cash equivalents during the year ended December 31, 2014 is primarily due to $233.0 million of cash provided by operating activities, $15.1 million of proceeds from the sale of our fishing and rental services operations and $8.4 million of proceeds from the sale of assets, partially offset by $175.4 million used for purchases of property and equipment and $73.6 million of cash used in our financing activities.
The net increase in our total trade and unbilled receivables as of December 31, 2014 as compared to December 31, 2013 is primarily the result of the increase in consolidated revenues of $44.9 million, or 19%, for the quarter ended December 31, 2014 as compared to the quarter ended December 31, 2013, and due to the timing of the billing and collection cycles for long-term drilling contracts in Colombia.
The increase in both our insurance recoveries receivables and our insurance claims and settlements accrued expenses as of December 31, 2014 as compared to December 31, 2013 is primarily due to an increase in our insurance company's reserve for workers' compensation claims in excess of our deductibles.
The increase in income taxes and other receivables as of December 31, 2014 as compared to December 31, 2013 is primarily due to the movement of $1.5 million in prepaid taxes associated with our Colombian operations from noncurrent to current receivables, as we expect to utilize them in the near term, as well as a $1.4 million receivable from the settlement of litigation in our favor.
The current portion of our long-term debt as of December 31, 2013 was primarily related to short-term financing for insurance premiums which were repaid in 2014.
The increase in accounts payable as of December 31, 2014 as compared to December 31, 2013 is due to an increase in our accruals for capital expenditures as of December 31, 2014 as compared to December 31, 2013, and due to the 18% increase in our operating costs for the quarter ended December 31, 2014 as compared to the quarter ended December 31, 2013.

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The increase in deferred revenues as of December 31, 2014 as compared to December 31, 2013 is primarily related to prepayments made related to ongoing drilling contracts and the deferral of early termination fees on one term contract.
As of December 31, 2014, our consolidated balance sheet reflects assets held for sale of $9.9 million, which represents the fair value of nine drilling rigs, four wireline units, two real estate properties and other drilling equipment.
The increase in accrued payroll and employee related costs as of December 31, 2014 as compared to December 31, 2013 is primarily due to higher accruals for our 2014 annual bonuses at above target achievement levels, as compared to 2013 bonuses which were earned at an amount below the target level, as well as an increase due to timing of pay periods.
The increase in insurance premiums and deductibles as of December 31, 2014 as compared to December 31, 2013 is primarily due to an increase in our accrual for workers compensation insurance costs resulting from an increase in our estimated liability for the deductibles under these policies.
The decrease in accrued interest expense as of December 31, 2014 as compared to December 31, 2013 is primarily due to the repayment of $425 million of our 2010 and 2011 Senior Notes in 2014 with proceeds from our Revolving Credit Facility and our 2014 Senior Notes which incur interest at a lower rate.
The decrease in other accrued expenses as of December 31, 2014 as compared to December 31, 2013 is primarily due to a decrease in the Colombian equity tax obligation and a decrease in property taxes due to the timing of payments, partially offset by an increase in our sales tax accrual.
Long-term Debt and Other Contractual Obligations
The following table includes information about the amount and timing of our contractual obligations at December 31, 2014 (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
$
455,080

 
$
27

 
$
53

 
$
155,000

 
$
300,000

Interest on debt
155,553

 
22,130

 
44,254

 
43,231

 
45,938

Purchase commitments
114,717

 
90,846

 
23,871

 

 

Operating leases
14,934

 
4,441


5,991


2,993


1,509

Incentive compensation and severance
13,701

 
7,757

 
5,944

 

 

Total
$
753,985

 
$
125,201

 
$
80,113

 
$
201,224

 
$
347,447

At December 31, 2014, debt obligations consist of $300 million of principal amount outstanding under our Senior Notes, $155.0 million outstanding under our Revolving Credit Facility and $0.1 million of other debt outstanding. The $155.0 million outstanding under our Revolving Credit Facility is due at maturity on September 22, 2019. However, we may make principal payments to reduce the outstanding balance prior to maturity when cash and working capital is sufficient. The $300 million principal amount outstanding under our 2014 Senior Notes will mature on March 15, 2022.
Interest payment obligations on our Revolving Credit Facility are estimated based on (1) the 2.4% interest rate that was in effect at December 31, 2014, and (2) the outstanding balance of $155.0 million at December 31, 2014 to be paid at maturity on September 22, 2019. Interest payment obligations on our 2014 Senior Notes are calculated based on the coupon interest rate of 6.125% due semi-annually in arrears on March 15 and September 15 of each year.
Purchase commitments primarily relate to components ordered for our new-build drilling rigs, purchases of other new equipment and equipment upgrades. The total estimated cost, excluding capitalized interest, for the five new-build drilling rigs is approximately $125 million, of which $37.2 million has already been incurred, and $59.7 million of which is reflected in the purchase commitments table above. In addition, $42.7 million of the purchase commitments in the table above represent obligations for well servicing rigs and other drilling equipment that were ordered during 2014, but which require long lead-time orders.

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Operating leases consist of lease agreements for office space, operating facilities, equipment and personal property.
Incentive compensation 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 $350 million borrowing capacity provided there is no default, all representations and warranties are true and correct, and compliance with financial covenants under the Revolving Credit Facility is maintained. At December 31, 2014, we were in compliance with our financial covenants under the Revolving Credit Facility. Our total consolidated leverage ratio was 1.8 to 1.0, our senior consolidated leverage ratio was 0.7 to 1.0, and our interest coverage ratio was 6.7 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, 2014, 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, 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.
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. Borrowings under the Revolving Credit Facility are available for acquisitions, working capital and other general corporate purposes.

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In addition to the financial covenants under our Revolving Credit Facility, the Indenture governing our Senior Notes both contain certain restrictions generally on our ability to:
pay dividends on stock, repurchase stock, redeem subordinated indebtedness or make other restricted payments and investments;
incur, assume or guarantee additional indebtedness or issue preferred or disqualified stock;
create liens on our assets;
enter into sale and leaseback transactions;
sell or transfer assets;
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 any other person;
enter into transactions with affiliates; and
enter into new lines of business.
If we experience a change of control (as defined in the Indenture), we will be required to make an offer to each holder of the Senior Notes to repurchase all or any part of the Senior Notes at a purchase price equal to 101% of the principal amount of each Senior Note, plus accrued and unpaid interest, if any to the date of repurchase. If we engage in certain asset sales, within 365 days of such sale we will be required to use the net cash proceeds from such sale, to the extent we do not reinvest those proceeds in our business, to make an offer to repurchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, plus accrued and unpaid interest to the repurchase date.
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. 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, 2014, 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, 2014 Compared with the Year Ended December 31, 2013
The following table provides information about our operations for the years ended December 31, 2014 and 2013 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue day information).
 
Year ended December 31,
 
2014
 
2013
Drilling Services Segment:
 
 
 
Revenues
$
516,473

 
$
528,327

Operating costs
345,862

 
351,630

Drilling Services Segment margin
$
170,611

 
$
176,697

 
 
 
 
Average number of drilling rigs
62.0

 
68.2

Utilization rate
87
%
 
84
%
Revenue days
19,602

 
20,977

 
 
 
 
Average revenues per day
$
26,348

 
$
25,186

Average operating costs per day
17,644

 
16,763

Drilling Services Segment margin per day
$
8,704

 
$
8,423

 
 
 
 
Production Services Segment:
 
 
 
Revenues
$
538,750

 
$
431,859

Operating costs
340,102

 
277,625

Production Services Segment margin
$
198,648

 
$
154,234

 
 
 
 
Combined:
 
 
 
Revenues
$
1,055,223

 
$
960,186

Operating costs
685,964

 
629,255

Combined margin
$
369,259

 
$
330,931

Adjusted EBITDA
$
277,081

 
$
234,742

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 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 represents income (loss) before interest income (expense), taxes, depreciation, amortization, loss on extinguishment of debt and impairments. We use this non-GAAP 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 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 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. Adjusted EBITDA may not be comparable to other similarly titled measures reported by other companies.

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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,
 
2014
 
2013
 
(amounts in thousands)
Reconciliation of combined margin and Adjusted EBITDA to net loss:
 
 
 
Combined margin
$
369,259

 
$
330,931

General and administrative
(103,385
)
 
(94,183
)
Bad debt expense
(1,445
)
 
(767
)
Gain on sale of fishing and rental services operations
10,702

 

Gain on settlement of litigation
5,254
 

Other expense
(3,304
)
 
(1,239
)
Adjusted EBITDA
277,081

 
234,742

Depreciation and amortization
(183,376
)
 
(187,918
)
Impairment charges
(73,025
)
 
(54,292
)
Interest expense
(38,781
)
 
(48,310
)
Loss on extinguishment of debt
(31,221
)
 

Income tax benefit
11,304

 
19,846

Net loss
$
(38,018
)
 
$
(35,932
)
Our Drilling Services Segment’s revenues decreased by $11.9 million, or 2%, during 2014 as compared to 2013, resulting primarily from a decrease in revenue days of 7%, partially offset by an increase in revenues per day of 5%, or $1,162 per day. Our Drilling Services Segment’s operating costs decreased by $5.8 million, or 2%, during 2014 as compared to 2013, primarily resulting from a decrease in revenue days, partially offset by higher operating costs per day which increased by 5%, or $881 per day. Revenue days decreased primarily due to the sale of eight drilling rigs in October 2013, some of which had been earning a standby dayrate during 2013, and due to lower utilization in Colombia where we experienced downtime primarily due to client delays in preparing well sites during the first half of 2014. Overall decreases in revenues and operating costs were partially offset by an increase in domestic revenues and operating costs per day during 2014.
Our average revenues per day increased by 5% or $1,162 per day, while our average operating costs per day increased by 5% or $881 per day, during 2014, as compared to 2013. Our average revenues and operating costs per day increased primarily due to increased turnkey work performed during 2014 as well as higher labor costs during 2014 which are reimbursed by the client, resulting in higher average revenues and 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 higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts. During the years ended December 31, 2014 and 2013, we completed 106 and 27 turnkey contracts, respectively, representing 6% and 3% of our total drilling revenues for each year, respectively. During 2014, we experienced an increase in demand for turnkey programs using lower horsepower rigs to drill a series of surface holes on pad sites.
Our Production Services Segment's revenues increased by $106.9 million, or 25%, during 2014, as compared to 2013, while operating costs increased by $62.5 million, or 23%. The increases in our Production Services Segment's revenues and operating costs are primarily a result of the increased demand for our services. The number of wireline jobs we completed increased by 3% during 2014, as compared to 2013. The total rig hours for our well servicing fleet increased by 12%, during 2014, as compared to 2013. Our coiled tubing utilization increased to 51% during 2014 from 47% during 2013. Increased pricing for these services also contributed to the increase in revenues, which was primarily due to a greater mix of higher priced jobs performed in our wireline and coiled tubing businesses. The greater mix of

48




higher cost wireline and coiled tubing jobs performed also resulted in the increase in operating costs during 2014, as compared to 2013.
Our general and administrative expense increased by approximately $9.2 million, or 10%, during 2014, as compared to 2013, primarily due to an increase in payroll and compensation related expenses as we are projecting higher incentive compensation based on our company's performance, as well as $1.9 million of severance costs.
In September 2014, we sold our fishing and rental services operations for total consideration of $16.1 million, resulting in a net pretax gain of $10.7 million.
We recorded gains of $5.3 million related to settlements of litigation in our favor related to non-compete agreements during the year ended December 31, 2014.
Our other expense of $3.3 million for 2014 is primarily related to net foreign currency loss recognized for our Colombian operations due to the rise in the value of the U.S. dollar relative to the Colombian peso.
Our depreciation and amortization expenses decreased by $4.5 million during 2014 as compared to 2013, primarily as a result of the sales of equipment during 2013, as well as the impairment charge to write down coiled tubing intangible assets to fair value as of June 30, 2013.
During the year ended December 31, 2014, we recorded $71.0 million of impairment charges to reduce the carrying values of our 31 mechanical and lower horsepower electric drilling rigs to their estimated fair value. This impairment charge is not expected to have an impact on our liquidity or debt covenants; however, it is a reflection of the overall downturn in our industry, drop in oil prices in the fourth quarter of 2014 and decline in our projected future cash flows. Additionally, we recorded $2.0 million of impairment charges during the year ended December 31, 2014 to reduce the carrying values of certain other assets, which were placed as held for sale during the year, to their estimated fair values, based on expected sales price.
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, L.L.C. 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 decreased by $9.5 million during 2014, as compared to 2013, primarily due to the repayment of 2010 and 2011 Senior Notes which incurred interest at a higher rate than the 2014 Senior Notes which we issued in March 2014.
Our loss on debt extinguishment during the year ended December 31, 2014 represents the tender and redemption premiums and the write-off of net unamortized debt discount and debt issuance costs associated with the 2010 and 2011 Senior Notes that were redeemed in 2014.
Our effective income tax rate for the year ended December 31, 2014 was 23%, which is lower than the federal statutory rate in the United States, primarily due to the effect of foreign currency translation, other permanent differences, valuation allowance and the impact of state income taxes. Items such as non-deductible expenses and state income taxes had a reverse effect on the income tax rate due to the negative pre-tax earnings.

49




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
277,625

 
252,775

Production Services Segment margin
$
154,234

 
$
167,801

 
 
 
 
Combined:
 
 
 
Revenues
$
960,186

 
$
919,443

Operating costs
629,255

 
586,621

Combined margin
$
330,931

 
$
332,822

Adjusted EBITDA
$
234,742

 
$
249,283

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
$
330,931

 
$
332,822

General and administrative
(94,183
)
 
(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


50




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 $24.9 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 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 labor costs in our Production Services Segment during 2013.
Our general and administrative expense increased by approximately $8.6 million, or 10% 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.

51




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.
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.
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. We experienced modest wage rate increases in our Production Services Segment during 2013 and 2014.
Costs for equipment repairs and maintenance, upgrades and new equipment 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 a more moderate increase during 2014.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.

52




Critical Accounting Policies and Estimates
Revenue and Cost RecognitionOur Drilling Services Segment earns revenues by drilling oil and gas wells for our clients under daywork or turnkey 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 contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. All of 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 contracts. Although our turnkey 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 contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey 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 contract.
The risks to us under a turnkey contract 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 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 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.
With most long-term drilling contracts, we are entitled to receive a full or reduced rate of revenue from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Generally, these revenues are billed and collected over the remaining term of the contract, as the rig is placed on standby rather than fully released from the contract, and thus may go back to work at the client's decision any time before the end of the contract. Some of our drilling contracts contain "make-whole" provisions whereby if we are able to secure additional work for the rig with another client, then each party is entitled to a make-whole payment. If the dayrates under the new contract are less than the dayrates in the original contract, we would be entitled to a reduced revenue dayrate from the terminating client, and likewise, the terminating client may be entitled to a payment from us if the new contract dayrates exceed those of the original contract. A client may also choose to early terminate the contract and make an upfront early termination payment based on a per day rate for the remaining term of the contract. Revenues derived from rigs

53




placed on standby or from the early termination of long-term drilling contracts are deferred and recognized as the amounts become fixed or determinable, over the remainder of the original term or when the rig is sold.
Our Production Services Segment earns revenues for well servicing, wireline services and coiled tubing 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.
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. 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 and coiled tubing). For our Drilling Services Segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual domestic drilling rig assets and for our Colombian drilling rig assets as a group. 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.
Since October 2014, domestic and international oil prices have declined significantly to historically low price levels resulting in a downturn in our industry. As a result, we performed an impairment evaluation of all our long-lived assets, in accordance with ASC Topic 360, Property, Plant and Equipment, which resulted in $71.0 million of impairment charges to reduce the carrying value of our 31 mechanical and lower horsepower electric drilling rigs to their estimated fair value. Additionally, we recorded $2.0 million of impairment charges during the year ended December 31, 2014 to reduce the carrying values of certain other assets, which were placed as held for sale during the year, to their estimated fair values, based on expected sales price.
As of December 31, 2014, we owned a total of 31 mechanical and lower horsepower electric drilling rigs, which includes the nine rigs that were idle and classified as held for sale as of year-end and 15 rigs that we expect to place as held for sale during the first quarter of 2015, after their current contracts are completed. With the significant decline in oil prices over the recent months, we performed impairment testing on all the mechanical and lower horsepower drilling rigs in our fleet. 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 at a significantly reduced expected rate of utilization through the end of their remaining useful lives. Our testing indicated that the carrying value of these assets was more than our estimated undiscounted cash flows, resulting in a total impairment of $71.0 million to reduce the carrying value of these assets to their estimated fair value of $34.0 million, which was based on market appraisals, which are considered Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. This impairment charge is not expected to have an impact on our liquidity or debt covenants; however, it is a reflection of the overall downturn in our industry, drop in oil prices in the fourth quarter of 2014 and decline in our projected future cash flows. We also performed an impairment test on our drilling rigs in Colombia. Our net book value in these rigs was $87.5 million as of December 31, 2014 and our analysis indicated that no impairment exists.
The most significant assumptions used in our analysis are the expected margin per day and utilization, as well as the estimated proceeds upon any future sale or disposal of the rig. 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.
If the demand for our drilling services remains at current levels or declines further and any of our rigs become idle for an extended amount of time, then our estimated cash flows may further decrease, and the probability of a near term sale may increase. If any of the foregoing were to occur, we may incur additional impairment charges.

54




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 1 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 estimatesMaterial 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.
We consider the recognition of revenues and costs on turnkey 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 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 contracts takes such risks into consideration. We are more likely to encounter losses on turnkey 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 contracts has historically exceeded our profitability on daywork contracts.
We incurred a total loss of $1.2 million on 13 of the 106 turnkey contracts which were initiated and completed during the year ended December 31, 2014. During the year ended December 31, 2013, we experienced a loss of approximately $17,000 on one turnkey contract completed and we did not experience a loss on any of the turnkey contracts completed during 2012. As of December 31, 2014, we had $0.8 million of unbilled receivables related to four turnkey contracts that were in progress at year-end, which were completed prior to the issuance of these financial statements.
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 $2.5 million at December 31, 2014.

55




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 1 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 45 years of experience in the oilfield services industry with similar equipment.
With the significant decline in oil prices over the recent months, we performed impairment testing on all the mechanical and lower horsepower drilling rigs in our fleet. 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 at a significantly reduced expected rate of utilization through the end of their remaining useful lives. The most significant assumptions used in our analysis are the expected margin per day and utilization, as well as the estimated proceeds upon any future sale or disposal of the rig. 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.
As of December 31, 2014, we had $87.3 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.
Our accrued insurance premiums and deductibles as of December 31, 2014 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $3.4 million and our workers’ compensation, general liability and auto liability insurance of approximately $9.0 million. We have stop-loss coverage of $200,000 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.
Recently Issued Accounting Standards
Discontinued Operations. In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-08, Discontinued Operations (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update, among other things, raises the threshold for a disposal to qualify for discontinued operations accounting and requires additional disclosures about disposals. We chose early adoption of this guidance beginning July 1, 2014.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance. The standard outlines a single comprehensive model for revenue recognition based on the core principle that a company will recognize revenue when promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. We are required to apply this new standard beginning with our first quarterly filing in 2017. We are currently evaluating the potential impact of this guidance, but at this time, do not expect that the adoption of this new standard will have a material effect on our financial position or results of operations.

56



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, 2014, we had $155.0 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 $1.6 million, and a corresponding increase or decrease, respectively, in net income of approximately $1.0 million during the year ended December 31, 2014. 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, 2014.
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 have 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 $5.8 million for the year ended December 31, 2014.

57




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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2014, 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, 2014, 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 17, 2015 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for discontinued operations in 2014 due to the adoption of Accounting Standards Update No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.
/s/ KPMG LLP
San Antonio, Texas
February 17, 2015



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, 2014, 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, 2014, 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, 2014 and 2013, 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, 2014, and our report dated February 17, 2015 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
San Antonio, Texas
February 17, 2015


60




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 
December 31,
2014
 
December 31,
2013
 
(in thousands, except share data)
ASSETS
 
Current assets:
 
 
 
Cash and cash equivalents
$
34,924

 
$
27,385

Receivables:
 
 
 
Trade, net of allowance for doubtful accounts
136,161

 
115,908

Unbilled receivables
38,002

 
49,535

Insurance recoveries
10,900

 
8,607

Income taxes and other
5,138

 
2,310

Deferred income taxes
10,998

 
13,092

Inventory
14,117

 
13,232

Assets held for sale
9,909

 

Prepaid expenses and other current assets
8,925

 
9,311

Total current assets
269,074

 
239,380

Property and equipment, at cost
1,702,273

 
1,724,124

Less accumulated depreciation
845,732

 
786,467

Net property and equipment
856,541

 
937,657

Intangible assets, net of accumulated amortization
24,223

 
32,194

Noncurrent deferred income taxes
2,753

 
1,156

Other long-term assets
18,998

 
19,236

Total assets
$
1,171,589

 
$
1,229,623

 
 
 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
64,305

 
$
43,718

Current portion of long-term debt
27

 
2,847

Deferred revenues
3,315

 
699

Accrued expenses:
 
 
 
Payroll and related employee costs
40,058

 
30,020

Insurance premiums and deductibles
12,829

 
10,940

Insurance claims and settlements
10,900

 
8,607

Interest
5,432

 
12,275

Other
10,326

 
11,727

Total current liabilities
147,192

 
120,833

Long-term debt, less current portion
455,053

 
499,666

Noncurrent deferred income taxes
69,578

 
84,636

Other long-term liabilities
4,702

 
6,055

Total liabilities
676,525

 
711,190

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; 63,820,126 and 62,534,636 shares outstanding at December 31, 2014 and 2013, respectively
6,414

 
6,275

Additional paid-in capital
472,457

 
456,812

Treasury stock, at cost; 317,103 and 219,304 shares at December 31, 2014 and 2013, respectively
(3,030
)
 
(1,895
)
Accumulated earnings
19,223

 
57,241

Total shareholders’ equity
495,064

 
518,433

Total liabilities and shareholders’ equity
$
1,171,589

 
$
1,229,623




See accompanying notes to consolidated financial statements.

61




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

 
Year ended December 31,
 
2014
 
2013
 
2012
 
(in thousands, except per share data)
Revenues:
 
 
 
 
 
Drilling services
$
516,473

 
$
528,327

 
$
498,867

Production services
538,750

 
431,859

 
420,576

Total revenues
1,055,223

 
960,186

 
919,443

Costs and expenses:
 
 
 
 

Drilling services