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EX-32.2 - EXHIBIT 32.2 - PIONEER ENERGY SERVICES CORPexhibit3224q2017.htm
EX-32.1 - EXHIBIT 32.1 - PIONEER ENERGY SERVICES CORPexhibit3214q2017.htm
EX-31.2 - EXHIBIT 31.2 - PIONEER ENERGY SERVICES CORPexhibit3124q2017.htm
EX-31.1 - EXHIBIT 31.1 - PIONEER ENERGY SERVICES CORPexhibit3114q2017.htm
EX-23.1 - EXHIBIT 23.1 - PIONEER ENERGY SERVICES CORPexhibit231-consentq42017.htm
EX-21.1 - EXHIBIT 21.1 - PIONEER ENERGY SERVICES CORPexhibit211-subsidiariesq42.htm
EX-12.1 - EXHIBIT 12.1 - PIONEER ENERGY SERVICES CORPexhibit121-fixedchargesrat.htm
 
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, 2017
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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  o
 
 
 
Accelerated filer  þ
Non-accelerated filer o
 
(Do not check if a smaller reporting company)
 
Smaller reporting company o
 
 
 
 
Emerging growth company o
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
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, 2017) was approximately $154.7 million.
As of January 31, 2018, there were 77,794,527 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 2018 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.
Item 16.




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 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. 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. 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 base forward-looking statements on our current expectations and assumptions about future events. While our management considers the 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 term loan, ABL facility and senior notes;
operating hazards inherent in our operations;
the supply of marketable drilling rigs, well servicing rigs, coiled tubing units and wireline units within the industry;
the continued availability of new components for drilling rigs, well servicing rigs, coiled tubing units and wireline units;
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 obligation 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) recognize 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
Company Overview
Pioneer Energy Services Corp. provides land-based drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. We also provide two of our services (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.
Drilling Services— From 1999 to 2011, we significantly expanded our fleet through acquisitions and the construction of new drilling rigs. As our industry changed with the evolution of shale drilling, we began a transformation process in 2011 by selectively disposing of our older, less capable rigs, while we continued to invest in our rig building program to construct more technologically advanced, pad-optimal rigs to meet the changing needs of our clients.
Today, our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. We have 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. The removal of older, less capable rigs from our fleet and investments in the construction of new drilling rigs has transformed our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market. We believe this positions us to compete well, grow our presence in the significant shale basins in the US, and improve profitability.
In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. The drilling rigs in our fleet are currently deployed through our division offices in the following regions:
 
 
Rig Count
Domestic drilling
 
 
Marcellus/Utica
 
6

Eagle Ford
 
1

Permian Basin
 
7

Bakken
 
2

International drilling
 
8

 
 
24

Production Services— In 2008, we acquired two production services companies which significantly expanded our service offerings to include well servicing and wireline services, and at the end of 2011, we acquired a coiled tubing services business to further expand our production services offerings. Since the acquisitions of these businesses, we continued to invest in their organic growth and significantly expanded all our production services fleets. Although we temporarily suspended organic growth during the recent downturn, we continue to selectively update our fleets.
Today, our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore. The primary production services we offer are the following:
Well Servicing. A range of services are required in order to establish production in newly-drilled wells and to maintain production over the useful lives of active wells. We use our well servicing rig fleet to provide these necessary services, including the completion of newly-drilled wells, maintenance and workover of active wells, and plugging and abandonment of wells at the end of their useful lives. As of December 31, 2017, we have a fleet of 113 rigs with 550 horsepower and 12 rigs with 600 horsepower with operations in 10 locations, mostly in the Gulf Coast states, as well as in Arkansas, North Dakota, and Colorado.
Wireline Services. Oil and gas exploration and production companies require wireline services to better understand the reservoirs they are drilling or producing, and use logging services to accurately characterize reservoir rocks and fluids. To complete a cased-hole 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 in addition to a range of other mechanical services that are needed in order to place equipment in or retrieve equipment or debris from the wellbore, install bridge plugs and control pressure. As of December 31, 2017, we

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have a fleet of 112 wireline units in 17 operating locations in the Gulf Coast, Mid-Continent and Rocky Mountain states. Additionally, we ordered two new greaseless wireline units in 2017 which we placed in service in January 2018, specifically designed to reduce noise when operating in proximity to urban areas.
Coiled Tubing Services. Coiled tubing is another important element of the well servicing industry that allows operators to continue production during service operations on a well under pressure without shutting in the well, thereby reducing the risk of formation damage. Coiled tubing services involve the use of a continuous metal pipe spooled on a large reel for oil and natural gas well applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, formation stimulation utilizing acid, chemical treatments and fracturing. Coiled tubing is also used for a number of horizontal well applications such as milling temporary plugs between frac stages. As of December 31, 2017, our coiled tubing business consists of 10 onshore and four offshore coiled tubing units which are deployed through three operating locations that provide services in Texas, Louisiana, Wyoming and surrounding areas. We currently have one additional larger diameter coiled tubing unit on order for delivery in mid-2018.
Pioneer Energy Services Corp. was incorporated under the laws of the State of Texas in 1979 as the successor to a business that had been operating since 1968. Over the last 15 years, we have significantly expanded and transformed our business through acquisitions and organic growth. Our business is comprised of two business lines Drilling Services and Production Services. We report our Drilling Services business as two reportable segments: (i) Domestic Drilling and (ii) International Drilling. We report our Production Services business as three reportable segments: (i) Well Servicing, (ii) Wireline Services, and (iii) Coiled Tubing Services. We revised our reportable business segments as of the fourth quarter of 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. Financial information about our operating segments is included in Note 10, 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.
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 is primarily driven by current and expected oil and natural gas prices.
Our business is influenced substantially by exploration and production companies’ spending that is generally categorized as either a capital expenditure or an 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 months or years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate over the amount of time necessary to plan and execute a capital expenditure project (such as a drilling program for a number of wells in a certain area). When commodity prices are depressed for longer 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 less dependent on commodity price forecasts.
Capital expenditures for the drilling and completion of exploratory and development 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, operating expenditures for the maintenance of existing wells, for which a range of production services are required in order to maintain production, are relatively more stable and predictable.
Drilling and production services have historically trended similarly in response to fluctuations in commodity prices. However, because exploration and production companies often adjust their budgets for exploration and development 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 ongoing expenditures that are necessary to maintain production. Additionally, within the range of production services businesses, those that derive more revenue from

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production related activity, as opposed to completion of new wells, tend to be less affected by fluctuations in commodity prices and temporary reductions in industry activity.
However, in a severe downturn that is prolonged, both operating and capital expenditures are significantly reduced, and the demand for all our service offerings is significantly impacted. After a prolonged downturn, among the production services, the demand for completion-oriented services generally improves first, as exploration and production companies begin to complete wells that were previously drilled but not completed during the downturn, and to complete newly drilled wells as the demand for drilling services improves during recovery.
Our industry experienced a severe down cycle that began in late 2014 and which persisted through 2016 with WTI oil prices that dipped below $30 in early 2016. A modest recovery in commodity prices began in the latter half of 2016 which continued through 2017, with average oil prices during the last quarter of 2017 averaging approximately $55 per barrel. 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.
a3yrspotprices2017.jpg
Colombian oil prices have historically trended in line with West Texas Intermediate (WTI) oil prices. Demand for drilling and production services in Colombia is largely dependent upon its national oil company’s long-term exploration and production programs, and to a lesser extent, additional activity from other producers in the region.
Technological advancements and trends in our industry also affect the demand for certain types of equipment, and can affect the overall demand for equipment in our industry. For several years, prior to late 2014, higher oil prices drove industry equipment utilization and revenue rates up, particularly in oil-producing regions and certain shale regions. However, advancements in technology improved the efficiency of drilling rigs and overall demand remained steady, while the demand for certain drilling rigs decreased, particularly in vertical well markets. The decline was a result of higher demand for drilling rigs that are able to drill horizontally and the increased use of “pad drilling” which enables a series of horizontal wells to be drilled in succession by walking or skidding a drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities and minimizing mobilization costs. This trend, then coupled with the downturn, resulted in significantly reduced demand for drilling rigs that do not have the ability to walk or skid and to drill horizontal wells.
For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends in our industry, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.
Competitive Strengths
Our competitive strengths include:
High Quality Assets. Our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. We have 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. Our well servicing fleet is 100% tall-masted, 550 to 600 horsepower rigs, and 60% of our onshore coiled tubing units offer larger diameter coil. We believe that our modern and well maintained fleet allows us to realize higher utilization and pricing because we are able to offer our clients technologically advanced equipment that allows them to operate with less downtime and greater efficiency.

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A Leading Provider in Domestic Shale Regions. Our drilling and production services fleets operate in many of the most attractive producing regions in the United States, including the Utica, Marcellus, Eagle Ford, Niobrara, multiple shales in the Permian Basin, SCOOP/STACK and Bakken. We believe our drilling rigs are particularly well suited to these areas where the optimal rig configuration is dictated by local geology and market conditions, and we have focused the expansion of our production services fleets to these regions with the most opportunity for growth. All our fleet equipment is mobile between domestic regions, diversifying our geographic exposure and limiting the impact of any regional slowdown.
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 business performs work prior to initial production, and our production services business 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, which has allowed us to generate more business from existing clients and increase our profits as we expand our services within existing markets.
Industry-Leading Safety Record. Our safety program called “LiveSafe” focuses on creating an environment where everyone is committed to and recognizes the possibility of always working without incident or injury. The commitment to LiveSafe helps keep our employees safe and reduces our business risk. In 2017, we lowered our lost time incident rates for the fourth consecutive year, achieving the lowest in our company’s history. In 2016, our coiled tubing services segment won the AESC Gold Safety Award, and our wireline services segment won the Bronze Safety Award. In 2015, we were recognized by the International Association of Drilling Contractors as the safest land contract driller of the 15 busiest contractors, with a total recordable incident rate 46% lower than the industry average, and our wireline services segment won the AESC Gold Safety award. Our excellent safety record and reputation are critical to winning new business and expanding our relationships with existing clients.
Skilled Management Team. We believe that an important competitive factor in achieving long-term client relationships includes having an experienced and skilled management team, with a focus on the growth and development of our leadership team, maintaining employee continuity and effective succession planning. Our CEO, Wm. Stacy Locke, joined Pioneer in 1995 as President and has over 35 years of industry 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 seek to minimize employee turnover, invest in the growth of our employees, and recruit new talent through our focus on employee training and development, safety and competitive compensation.
Longstanding and Diversified Clients. We maintain long-standing, high quality client relationships with a diverse group of oil and gas exploration and production companies. Our largest three clients, Apache Corporation, Extraction Oil & Gas, LLC and Whiting Petroleum Corporation, accounted for approximately 7%, 6% and 6%, respectively, of our 2017 consolidated revenues. We believe our relationships with our clients are strong and the diversity of our client base offers numerous opportunities for growth as our industry continues to improve.
Strategy
Our strategy is to be a premier land drilling and production services company through steady and disciplined growth, which we executed through the acquisition and building of our high quality drilling rig fleet and production services businesses. In 2011, we shifted our approach to accommodate changes in the industry, which resulted in a period of combined growth and rejuvenation through the disposition of assets which use older technology. Today, we provide drilling and production services in many of the most attractive hydrocarbon producing markets throughout the United States, and provide drilling services in Colombia.
Through the downturn that began in late 2014 and the early stages of recovery that began in late 2016, our recent efforts have been focused on:
Reducing Costs and Improving Profitability. During 2015 and 2016, we reduced our total headcount by over 50%, reduced wage rates for our operations personnel, reduced incentive compensation, eliminated certain employment benefits and closed ten field offices to reduce overhead and reduce associated lease payments. In 2016, we lowered our capital expenditures by 77% from the prior year, limiting our capital spending to primarily routine expenditures to maintain our equipment and deferring discretionary upgrades and additions except those that we committed to in 2014

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before the market slowdown. As our industry continues to recover from the downturn, we remain prudent in our efforts to preserve the benefits of our reduced cost structure, in order to capture the full impact of increasing activity and improving profitability.
Improving Liquidity and Financial Flexibility. In December 2016, we sold 12.1 million shares of common stock in a public offering, and applied the net proceeds to reduce our outstanding debt under our revolving credit facility. In November 2017, we entered into a new senior secured asset-based lending facility (the “ABL Facility”) and a term loan agreement (the “Term Loan”), the proceeds of which were used to repay and extinguish our prior revolving credit facility which was set to mature in 2019. The ABL Facility and Term Loan provide us greater financial flexibility and increased liquidity. We currently have availability for equity or debt offerings up to $234.6 million under our shelf registration statement, subject to the limitations imposed by our Term Loan, ABL Facility and Senior Notes.
Liquidating Nonstrategic Assets. Since the beginning of 2015, we have sold 37 drilling rigs and other drilling equipment for aggregate net proceeds in excess of $65 million, and have four domestic drilling rigs held for sale, along with other drilling equipment, at December 31, 2017. In 2017, we sold 16 of our older wireline units and two of our smaller diameter coiled tubing units for $1.3 million, and have two wireline units and one coiled tubing unit and spare equipment remaining held for sale at December 31, 2017. Subsequently, we sold six wireline units that were not previously held for sale in January 2018. We continue to evaluate our domestic and international fleets for additional drilling rigs or equipment for which a near term sale would be favorable.
Selectively Optimizing our Fleets. As our vendors and competitors have experienced financial pressure resulting from the industry downturn, we took advantage of favorable asset pricing conditions to enhance our production services fleets, including the exchange of 20 older well servicing rigs for 20 new-model rigs and the purchase of four new wireline units. In January 2018, we added two new greaseless electric wireline units specifically designed to reduce noise when operating in proximity to urban areas, and have one large diameter coiled tubing unit on order for delivery in 2018.
We continue to evaluate our business and look for opportunities to further achieve these goals, which we believe will position us to take advantage of future business opportunities and maintain our long-term growth strategy.
Our long-term strategy as a premier land drilling and production services company is to further leverage 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:
Performance in our Core Businesses. We maintain a continual focus on our relationships with our clients and vendors, and our commitment to safety and service quality goals. In 2017, we lowered our lost time incident rates for the fourth consecutive year, achieving the lowest in our company’s history. In 2016, our coiled tubing services segment won the AESC Gold Safety Award, and our wireline services segment won the Bronze Safety Award. In 2015, we were recognized by the International Association of Drilling Contractors as the safest land contract driller of the 15 busiest contractors, with a total recordable incident rate 46% lower than the industry average, and our wireline services segment won the AESC Gold Safety award. Our excellent safety record and reputation are critical to winning new business and expanding our relationships with existing clients.
Investments in Our Business. We have historically invested in the growth and technological advancement of our business by engaging in select rig building opportunities and acquisitions, strategically upgrading our existing assets and disposing of assets which use older technology.
Since the beginning of 2010, we have added significant capacity to our production services offerings through the addition of 49 wireline units, 51 well servicing rigs and 14 coiled tubing units. From 2011 to 2015, we constructed 15 walking AC drilling rigs. During 2015 and 2016, we removed all 31 of our mechanical and lower horsepower electric drilling rigs from our fleet, which were the most negatively impacted by the industry downturn, as well as all 12 domestic SCR rigs in our fleet. We achieved this by selling a total of 37 drilling rigs, retiring two, and placing the remaining four as held for sale.
Today, our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. We have 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. The removal of older, less capable rigs from our fleet and investments in the construction of new drilling rigs has transformed our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market. We believe this positions us to compete well, grow our presence in the significant shale basins in the US, and improve profitability.

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A Leading Provider in Domestic Shale Regions. The investments we’ve made in our business have been focused on increasing our presence in regions where demand benefits from shale development. Shale plays are increasingly important to domestic hydrocarbon production, and not all rigs are capable of successfully working in these unconventional producing regions. Our domestic drilling and production services fleets are highly capable and designed for operation in today’s long lateral environment.
We are currently operating in the Utica, Marcellus, Eagle Ford, Niobrara, multiple shales in the Permian Basin, SCOOP/STACK and Bakken. With the expectation that the modest recovery experienced in 2017 will continue to bring improved activity and pricing to our industry, we are allocating our resources to the markets with the best opportunities for increased activity and reactivating units in those areas with increasing demand.
Overview of Our Segments and Services
Our business is comprised of two business lines Drilling Services and Production Services. We report our Drilling Services business as two reportable segments: (i) Domestic Drilling and (ii) International Drilling. We report our Production Services business as three reportable segments: (i) Well Servicing, (ii) Wireline Services, and (iii) Coiled Tubing Services. We revised our reportable business segments as of the fourth quarter of 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. Financial information about our operating segments is included in Note 10, 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
A land drilling rig consists of power generation system(s), a hoisting system, a rotating system, pumps and related equipment to circulate and clean drilling fluid, blowout preventers, and other related equipment. Generally, our land drilling rigs operate with crews of five to six persons, and 100% of our drilling rigs have the ability to drill multiple well bores from a single surface location as discussed in more detail below.
There are numerous factors that differentiate land drilling rigs, such as the type of power used, drilling depth capabilities or drawworks horsepower, mud pump pressure rating, and the ability to drill multiple well bores from a single surface location or pad. 
Regarding the type of power used, mechanical rigs are generally less expensive than their electric counterparts. Mechanical rigs use torque converters, clutches, chains, belts, and transmissions to couple engines directly to various types of equipment. Mechanical rigs are considered less efficient and less precise than SCR and AC rigs, which are electric rigs that generate electrical power through one or more engine generator sets. SCR rigs utilize direct current to supply and control DC motors coupled to the various drilling equipment, while AC rigs utilize alternating current and AC motors. Both types of electric rigs are considered safer, more reliable, and more efficient than mechanical rigs. AC rigs are considered to be more energy efficient and provide more precise control of equipment than their SCR counterparts, which enhances rig safety and reduces drilling time. 
The following table summarizes our current rig fleet composition by segment:
 
Multi-well, Pad-capable
 
SCR rigs
AC rigs
Total
Domestic drilling

16

16
International drilling
8


8
 
 
 
24
Technological advancements and trends in our industry affect the demand for certain types of equipment. Every drilling rig in our fleet is equipped with at least 1,500 horsepower drawworks, a top drive, an iron roughneck, an automatic catwalk, and a walking or skidding system. This equipment, which is described in more detail below, provides our clients with drilling rigs that have more varied capabilities for drilling in unconventional plays and improves 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 which increases the degree of control afforded the operator, and reduces the difficulties encountered while drilling horizontal wells. 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

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collars, casing, and other necessary items to the drilling rig floor. Its function has significant safety advantages and can reduce the overall time required to complete the well.
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 walking or skidding a 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 and ancillary systems such as engines and mud tanks remain stationary, thus reducing move times and costs. Our omnidirectional walking systems enable the drilling rig to move forward, backward, and side to side which affords the operator additional flexibility. The removal of older, less capable rigs from our fleet and investments in the construction of new drilling rigs has transformed our fleet into a highly capable, pad optimal fleet focused on the horizontal drilling market.
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.
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 a daywork 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. Drilling contracts for individual wells are usually completed in less than 30 days. We typically enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of high rig demand.
Production Services
Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore.
Newly drilled wells require completion services to prepare the well for production. 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, replacing defective tubing in a gas well, cleaning a live well, and servicing mechanical issues. Our maintenance services involve relatively low-cost, short-duration jobs which are part of normal well operating costs. The need for maintenance does not directly depend on the level of drilling activity, although it is somewhat impacted by short-term fluctuations in oil and gas prices. Accordingly, maintenance services generally experience relatively stable demand; however, when oil or gas prices are too low to justify additional expenditures, operating companies may choose to temporarily shut in producing wells rather than incur additional maintenance costs.
In addition to periodic maintenance, producing oil and gas wells occasionally require major repairs or modifications called workovers, which are typically more complex and more time consuming than maintenance operations. Workover services include extensions of existing wells to drain new formations either through perforating the well casing to expose additional productive zones not previously produced, deepening well bores to new zones or the drilling of lateral well bores to improve reservoir drainage patterns. 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. 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.

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At the end of the well life cycle, a process is required to permanently close oil and gas wells that are 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.
As of December 31, 2017, the fleet count and composition for each of our production services business segments is as follows:
 
550 HP
600 HP
Total
Well servicing rigs, by horsepower (HP) rating
113

12

125

 
 
 
 
 
Offshore
Onshore
Total
Wireline units
4

108
112

Coiled tubing units
4

10

14

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.
Well servicing rigs are frequently used to complete newly drilled wells to minimize the use of higher cost drilling rigs in the completion process. 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. 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. We also perform plugging and abandonment work throughout our core areas of operation in conjunction with equipment provided by other service companies.
We believe that our well servicing fleet is among the newest in the industry, consisting entirely of tall-masted rigs with at least 550 horsepower, capable of working at depths of over 20,000 feet. These specifications allow us to operate in areas with deeper well depths and perform jobs that rigs with lesser capabilities cannot. In 2017, we traded in 20 of our older 550 horsepower well servicing rigs for 20 new-model rigs, further improving the quality of our rig fleet, enhancing our ability to recruit crew talent and competitively positioning us for new service opportunities as the market continues to improve.
Our well servicing operations are deployed through 10 locations, mostly in the Gulf Coast states, as well as in Arkansas, North Dakota, and Colorado.
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. Other applications for wireline tools include placing equipment in or retrieving equipment (or debris) 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.
Our wireline operations are deployed through 17 locations in Texas, Kansas, Colorado, Montana, North Dakota, Louisiana, Oklahoma and Wyoming.
Coiled Tubing Services. Coiled tubing is another important element of the well servicing industry that allows operators to continue production during service operations on a well under pressure 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

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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.
Our coiled tubing operations are deployed through three operating locations that provide services in Texas, Louisiana, Wyoming and surrounding areas.
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 oil and gas exploration and production companies. 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
Year ended December 31, 2017
 
Apache Corporation
7.5
%
Extraction Oil & Gas, LLC
6.4
%
Whiting Petroleum Corporation
6.3
%
 
 
Year ended December 31, 2016
 
Apache Corporation
11.9
%
Whiting Petroleum Corporation
10.1
%
PDC Energy, Inc
4.4
%
 
 
Year ended December 31, 2015
 
Whiting Petroleum Corporation
17.8
%
Ecopetrol
6.1
%
Apache Corporation
4.6
%
Competition
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 our services short-lived.
Most drilling services contracts and production services contracts are awarded on the basis of competitive bids, which also results in price competition. In addition to pricing and equipment availability, we believe the following factors are also important to our clients in determining which drilling services or production services provider to select:
the type, capability 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 reputation and safety record of the company providing the services;
the offering of integrated and/or 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.

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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 generally causes greater price competition and reduced profitability.
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 following is an overview of the market for each of our services:
Domestic and International Drilling. Our principal domestic drilling competitors are Helmerich & Payne, Inc., Precision Drilling Corporation, Patterson-UTI Energy, Inc. and Nabors Industries Ltd. In Colombia, we primarily compete with Tuscany International Drilling, Nabors Industries Ltd., and Estrella International Energy Services Ltd. Our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling, which we believe positions us well to compete and expand our presence in predominant shale regions.
Well Servicing. The largest well servicing providers that we compete with are Key Energy Services, Basic Energy Services, C&J Energy Services, Superior Energy Services and Forbes Energy Services. As compared to the other large competitors in this industry, we believe our fleet is one of the youngest, most uniform fleets, which in addition to our safety performance and service quality, has historically allowed us to operate at utilization and hourly rates that are among the highest of our peers.
Wireline. The wireline market in the United States is dominated by a small number of companies, including ourselves. These competitors include Allied-Horizontal Wireline Services, Renegade Services, C&J Energy Services, Nine Energy Services, and Quintana Energy Services. Additional competitors include Schlumberger Ltd., Halliburton Company and other independents. The market for wireline services is very competitive, but historically we have competed effectively with our competitors because of the diversified services we provide, our performance and strong client service.
Coiled Tubing. The market for coiled tubing has expanded within the oilfield services market over recent years due to technological advances which increased the number of applications for the coiled tubing unit, and due to the increase in deep well and horizontal drilling. Our primary competitors in the coiled tubing services market currently include C&J Energy Services, Superior Energy Services, Key Energy Services, Schlumberger Ltd., Halliburton Company, Quintana Energy Services and RPC, Inc.
In addition, there are numerous smaller companies that compete in all of our services markets. 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.
The need for our 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. 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, cement and other job materials such as explosives, perforating guns and

11



coiled tubing. We do not rely on a single source of supply for any of these items. From time to time, there have been shortages of drilling and production services equipment and supplies during periods of high demand. Shortages could result in increased prices for 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 equipment or supplies could limit our operations and jeopardize our relations with clients. In addition, shortages of 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.
Operating Risks and Insurance
Our operations are subject to the many hazards inherent in exploration and production activity, 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.
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 of no more than $750,000 per drilling rig and a deductible on production services equipment of $100,000 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 and an additional $250,000 annual aggregate deductible. 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.
Employees
We currently have approximately 2,300 employees, the majority of which work in our drilling and production services operations 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 results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. From time to time, shortages of qualified personnel have occurred in our industry. If we should suffer any material

12



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 50 other real estate locations, of which we own 12, located throughout the United States in Texas, Oklahoma, Colorado, Montana, North Dakota, Pennsylvania, Wyoming, Mississippi, Arkansas, Louisiana and Kansas, and one property is located internationally in Colombia. These real estate locations are primarily used for regional offices and storage and maintenance yards.
Governmental Regulation
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.
Environment Protection. 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 the laws, rules and regulations applicable to our industry 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 wastes and/or 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.
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.
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 earthquakes. 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

13



could cause a decrease in the completion of new oil and natural gas wells and an associated decrease in demand for our drilling and well servicing activities, any or all of which could adversely affect our financial position, results of operations and cash flows.
Our 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.
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.
See Item 1A—“Risk Factors” in Part I of this Annual Report on Form 10-K for a detailed discussion of risks we face concerning laws and governmental regulations.
Transportation. 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.
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 worldwide supply and demand for 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 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, or their investments in oil and gas reserves located in other countries; and
the price of foreign imports of oil and gas.

14



Additionally, the above factors can also be affected by technological advances affecting energy consumption and the supply and demand within the market for renewable energy resources.
As a result of the decline in oil prices that began in late 2014, our clients reduced spending on exploration and production projects in 2015 and 2016, resulting in a significant decrease in demand for our services, which has improved during 2017.
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.
Beginning in October 2014, oil prices worldwide dropped significantly. Our clients significantly reduced both their operating and capital expenditures during 2015 and 2016, which adversely affected our business. In 2017, our clients modestly increased their spending as compared to 2016 levels, and we expect continued increases in 2018. However, if the oil and natural gas prices again decline, oil and gas exploration and production companies may cancel or curtail their drilling programs and further reduce production spending on existing wells, thereby reducing demand for our services. If the reduction in the overall level of exploration and development activities, whether resulting from changes in oil and gas prices or otherwise, continues or worsens, it could materially and adversely affect us further 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 or make acquisitions, and the cost of that capital;
the collectability of our receivables; and
our ability to retain skilled operations personnel.
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 our services short-lived.
Most drilling services contracts and production services contracts are awarded on the basis of competitive bids, which also results in price competition. In addition to pricing and equipment availability, we believe the following factors are also important to our clients in determining which drilling services or production services provider to select:
the type, capability 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;

15



the quality of service and experience of the crews;
the reputation and safety record of the company providing the services;
the offering of integrated and/or 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 generally causes greater price competition and reduced 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 also affect the demand for certain types of equipment, and can affect the overall demand for equipment in our industry.
Technological advancements and trends in our industry also affect the demand for certain types of equipment, and can affect the overall demand for equipment in our industry. For several years, prior to late 2014, higher oil prices drove industry equipment utilization and revenue rates up, particularly in oil-producing regions and certain shale regions. However, advancements in technology improved the efficiency of drilling rigs and overall demand remained steady, while the demand for certain drilling rigs decreased, particularly in vertical well markets. The decline was a result of higher demand for drilling rigs that are able to drill horizontally and the increased use of “pad drilling” which enables a series of horizontal wells to be drilled in succession by walking or skidding a drilling rig at a single pad-site location, thereby improving the productivity of exploration and production activities and minimizing mobilization costs. This trend, then coupled with the downturn, 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.
In drilling, all rig classes were severely impacted by the industry downturn. However, AC drilling rigs equipped with either a walking or skidding system are the best suited for horizontal pad drilling and we believe they are the most desirable rig design available.
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.
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, 2017, 2016 and 2015, our drilling and production services to our top three clients accounted for approximately 20%, 26%, and 29%, 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. We experienced significantly reduced demand for our services during 2015 and 2016 from all clients, including our major clients, but we experienced a modest recovery in demand during 2017. For a detail of our three largest clients as a percentage of our total revenues during the last three fiscal years, see Item 1—“Business” in Part I of this Annual Report on Form 10-K.

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Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
Our indebtedness is primarily a result of the acquisitions of the well servicing and wireline services businesses which we acquired in 2008 and the coiled tubing business that we acquired in 2011, as well as organic growth investments. At December 31, 2017, our total debt consists of $300 million outstanding under our Senior Notes and $175 million outstanding under our Term Loan, with additional borrowing availability under our ABL 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 currently expect that cash and cash equivalents, cash generated from operations, proceeds from sales of certain non-strategic assets, and available borrowings under our ABL Facility are adequate to cover our liquidity requirements for at least the next 12 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, subject to the limitations imposed by our Term Loan, ABL Facility and Senior Notes, 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; and/or
seeking to raise additional capital.
However, we may be unable to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, and any such alternative financing plans might be insufficient to allow us to meet our debt obligations. If we are unable to generate sufficient cash flow or are otherwise unable to obtain the funds required to make principal and interest payments on our indebtedness, or if we otherwise fail to comply with the various covenants in our Term Loan, ABL Facility, and Senior Notes, we could be in default under the terms of such instruments. In the event of a default, our lenders could elect to declare all the loans made under our Term Loan, ABL Facility, and Senior Notes to be due and payable together with accrued and unpaid interest and terminate their commitments thereunder and we or one or more of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

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Our Term Loan, ABL Facility, and Senior Notes impose significant covenants on us that may affect our ability to successfully operate our business.
Our Term Loan contains customary restrictions that, among other things, and subject to certain exceptions, limit our ability to:
incur additional debt;
incur or permit liens on assets;
make investments and acquisitions;
consolidate or merge with another company;
engage in asset sales; and
pay dividends or make distributions.
In addition, our Term Loan 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.
Our ABL Facility contains restrictive covenants that, among other things, and subject to certain exceptions, limit our ability to:
declare dividends and make other distributions;
issue or sell certain equity interests;
optionally prepay, redeem or repurchase certain of our subordinated indebtedness;
make loans or investments (including acquisitions);
incur additional indebtedness or modify the terms of permitted indebtedness;
grant liens;
change our business or the business of our subsidiaries;
merge, consolidate, reorganize, recapitalize, or reclassify our equity interests;
sell our assets, and
enter into certain types of transactions with affiliates.
The Indenture governing our Senior Notes, among other things, limits us and certain of our subsidiaries, subject to certain exceptions, in 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 or their assets;
enter into sale and leaseback transactions;
sell or transfer assets;
borrow, pay dividends, 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.
The failure to comply with any of these covenants would cause an event of default under our Term Loan, ABL Facility, or 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 Term Loan, ABL Facility, and Senior Notes.
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 exploration and production activity, including the risks of:
blowouts;
cratering;
fires and explosions;
loss of well control;

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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.
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 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 equipment or supplies could limit our operations and jeopardize our relations with clients. In addition, shortages of 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 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.
A component of our long-term business strategy is a pursuit of acquisitions of complementary assets and businesses, subject to the limitations imposed by our Term Loan, ABL Facility, and Senior Notes. This acquisition strategy in general involves 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;

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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 or at all.
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 or 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, in the future, our invested cash and cash equivalents could be adversely affected by adverse conditions in the financial and credit markets.
Our international operations are subject to political, economic and other uncertainties not generally 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 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, and higher rates of inflation as compared to our domestic operations;
difficulty in collecting international accounts receivable; and
potentially longer payment cycles.

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Additionally, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.
We are committed to doing business in accordance with applicable anti-corruption laws and our code of conduct and ethics. We are subject, however, to the risk that our employees and agents may take action determined to be in violation of anti-corruption laws, including the FCPA or other similar laws. Any violation of the FCPA or other applicable anti-corruption laws could result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and might materially adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.
Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:
environmental quality;
pollution control;
remediation of contamination;
preservation of natural resources;
transportation; and
worker safety.
Environment Protection. 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 the laws, rules and regulations applicable to our industry 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 wastes and/or 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; 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 (CERCLA); the Safe Drinking Water Act (SDWA); the federal Outer Continental Shelf Lands Act; the Occupational Safety and Health Act (OSHA); regulations implementing these federal statutes (such as the 2015 Waters of the United States rule, which may be rescinded pursuant to a proposal issued in June 2017); 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 (EPA) “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. 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

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defenses exist to the liability imposed by many 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 at the international level is the United Nations Framework Convention on Climate Change, which produced the “Kyoto Protocol” (an internationally applied protocol, which has been ratified in Colombia, which is a location where we provide drilling services) in 1992. More recently, in December 2015, 195 countries adopted under the Framework Convention a resolution known as the “Paris Agreement” to reduce emissions of greenhouse gases with a goal of limiting global warming to below 2 °C (3.6 °F). The Paris Agreement does not establish enforceable emissions reduction targets, but countries may establish greenhouse gas reduction measures pursuant to the agreement. The agreement went into effect in November 2016. The United States ratified the Paris Agreement in September 2016. It has since notified the United Nations of its intent to withdraw from the Paris Agreement, but under the terms of the agreement the U.S. will remain a party until approximately August 2020.
In addition, 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. Also, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. There have been two multi-state organizations devoted to climate action. The Regional Greenhouse Gas Initiative (RGGI) is located in the Northeastern and Mid-Atlantic United States. The Western Regional Climate Action Initiative once included multiple U.S. states and much of Canada but is now comprised of California, British Columbia, Manitoba, Ontario, and Quebec.
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. In December 2009, the EPA responded to this 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. In June 2014, the U.S. Supreme Court invalidated elements of the greenhouse gas permitting rule; however, the EPA can still impose certain greenhouse gas control requirements for certain large stationary sources. 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 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.
In August 2015, the EPA finalized rules to limit carbon dioxide emissions from new and existing electric utility generating units. New units must meet specified carbon dioxide emissions limitations. The rules for existing units, known as the “Clean Power Plan,” were to require by 2030 an overall reduction in carbon dioxide emissions of 32% below the amount of carbon dioxide emitted in 2005. Although the EPA proposed repeal of the Clean Power Plan in October and December 2017, on December 28, 2017, the EPA issued an Advance Notice of Proposed Rulemaking soliciting comments on emissions reductions that might be promulgated in place of the Clean Power Plan.

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In May 2016, the EPA issued a rule to reduce methane (a greenhouse gas) and VOC emissions from additional oil and gas operations. Among other requirements, the rules impose standards for hydraulically fractured oil wells and equipment leaks at oil and gas production sites and extend certain existing standards to downstream oil and gas operations. In April 2017, the EPA granted reconsideration of aspects of this rule.
Although it is not possible at this time to predict whether proposed climate change initiatives 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.
Transportation. 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. Federal agencies have adopted new rules, such as the Bureau of Land Management’s (BLM) hydraulic fracturing rule finalized in March 2015, that impose additional requirements on the practice of hydraulic fracturing. In December 2017, the BLM rescinded this rule, but there may be litigation to reinstate the rule. In October 2016, the BLM updated its rules to restrict flaring associated with the development of oil and natural gas on public lands, including through hydraulic fracturing. Portions of the rule have been suspended until January 2019, but there may be litigation to reinstate the rule.

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Additional federal regulations may also be developed. 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 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 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. For example, in May 2014, the EPA responded to a petition by environmental groups by issuing an Advanced Notice of Proposed Rulemaking to solicit input regarding whether the agency should require manufacturers and processors of hydraulic fracturing chemicals to report composition and usage of such chemicals and to disclose associated health and safety studies.
Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having completed a multi-year study of the potential environmental impacts of hydraulic fracturing. The Final Report issued by the EPA in December 2016 concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances and identified conditions under which impacts can be more frequent or severe. In addition, in April 2012, the EPA issued the first federal air standards for natural gas wells that are hydraulically fractured, which 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 or reduced emission (or “green”) completions. 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. The EPA has amended these rules several times. In May 2016, the EPA finalized a rule to reduce methane (a greenhouse gas) and VOC emissions from oil and gas operations. It is also possible that the EPA will further amend its 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 has also developed effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities to publicly owned treatment works (POTW). The agency’s final regulations, published on June 28, 2016, prohibited any discharge of wastewater pollutants from onshore unconventional oil and gas extraction facilities to a POTW. The EPA will also be assessing whether oil and gas wastes should continue to be exempt from being considered hazardous waste under the federal Resource Conservation and Recovery Act, pursuant to a Consent Decree with environmental groups approved in federal court in December 2016. The U.S. Department of the Interior has also finalized regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents (i.e. the BLM’s hydraulic fracturing rule issued in March 2015) and has finalized, in October 2016, a rule to reduce flaring and venting associated with oil and gas operations on public lands. The BLM rules have since been rescinded or delayed, but it is possible that they will be reinstated through litigation.
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.
In June 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 and/or setback

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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.
Our operations are subject to cybersecurity risks.
Our operations are increasingly dependent on information technologies and services.  Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow, and include, among other things, storms and natural disasters, terrorist attacks, utility outages, theft, viruses, malware, design defects, human error, or complications encountered as existing systems are maintained, repaired, replaced, or upgraded. Risks associated with these threats include, among other things:
loss, corruption, or misappropriation of intellectual property, or other proprietary or confidential information (including client, supplier, or employee data);
disruption or impairment of our and our customers’ business operations and safety procedures;
loss or damage to our worksite data delivery systems; and
increased costs to prevent, respond to or mitigate cybersecurity events.
Although we utilize various procedures and controls to mitigate our exposure to such risk, cybersecurity attacks and other cyber events are evolving and unpredictable. Moreover, we do not have control over the information technology systems of our clients, suppliers, and others with which our systems may connect and communicate. As a result, the occurrence of a cyber incident could go unnoticed for a period time. Any such incident could have a material adverse effect on our business, financial condition and results of operations.
Our ability to use our net operating loss and tax credit carryforwards might be limited.
Section 382 of the U.S. Internal Revenue Code contains rules that limit the ability of a company that undergoes an ownership change to utilize its net operating losses and tax credit carryforwards existing as of the date of such ownership change. Under the rules, such an ownership change is generally any change in ownership of more than 50% of a company’s stock within a rolling three-year period. The rules generally operate by focusing on changes in ownership among shareholders owning, directly or indirectly, 5% or more of the stock of a company and any change in ownership arising from new issuances of stock by the company.
If we were to undergo one or more “ownership changes” as defined by Section 382, our net operating losses and certain of our tax credits existing as of the date of each ownership change may be unavailable, in whole or in part, to offset U.S. federal income tax resulting from our operations or any gains from the disposition of any of our assets and/or business, which could result in increased U.S. federal income tax liability.
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 Term Loan, ABL Facility, and Senior Notes. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.

25



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; however, our issuance of preferred stock is subject to the limitations imposed on us by our ABL Facility and Senior Notes. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders.
The existence of some provisions in our organizational documents could delay or prevent a change in control of our company even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
provisions regulating the ability of our shareholders to nominate candidates for election as directors or to bring matters for action at annual meetings of our shareholders;
limitations on the ability of our shareholders to call a special meeting and act by written consent;
provisions dividing our board of directors into three classes elected for staggered terms; and
the authorization given to our board of directors to issue and set the terms of preferred stock.

ITEM 1B.
UNRESOLVED STAFF COMMENTS
Not applicable.

ITEM 2.
PROPERTIES
For a description of our significant properties, see “Business—General” and “Business—Facilities” in Item 1 of this report. We believe that we have sufficient properties to conduct our operations and that our significant properties are suitable for their intended use.

ITEM 3.
LEGAL PROCEEDINGS
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.

ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.


26




PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of January 31, 2018, 77,794,527 shares of our common stock were outstanding, held by 300 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
Year ended December 31, 2017
 
 
 
First Quarter
$
3.65

 
$
7.20

Second Quarter
1.70

 
4.50

Third Quarter
1.60

 
2.65

Fourth Quarter
1.70

 
3.20

 
 
 
 
Year ended December 31, 2016
 
 
 
First Quarter
$
0.95

 
$
2.46

Second Quarter
1.98

 
5.05

Third Quarter
2.64

 
4.89

Fourth Quarter
3.35

 
7.15

The last reported sales price for our common stock on the New York Stock Exchange on January 31, 2018 was $3.25 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 Term Loan, ABL Facility, and Senior Notes. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock.
We did not make any unregistered sales of equity securities during the quarter ended December 31, 2017. No shares of our common stock were purchased by or on behalf of our company or any affiliated purchaser during the quarter ended December 31, 2017.

27



Performance Graph
The following graph compares, for the periods from December 31, 2012 to December 31, 2017, 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., Key Energy Services and Precision Drilling Corporation, and have been weighted according to each company’s stock market capitalization. Two of the companies in the peer group, Basic Energy Services, Inc. and Key Energy Services, filed for bankruptcy protection in 2016 under Chapter 11 of the United States Bankruptcy Code, which significantly decreased the market capitalization of these peers, as well as their impact on the total return calculated for the peer group.
The comparison assumes that $100 was invested on December 31, 2012 in our common stock, the companies that compose the NYSE Composite Index and the peer group index, and further assumes all dividends were reinvested.
tsrperformancegraph.jpg



28



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,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In thousands, except per share amounts)
Statement of Operations Data (1)
 
 
 
 
 
 
 
 
 
Revenues
$
446,455

 
$
277,076

 
$
540,778

 
$
1,055,223

 
$
960,186

Income (loss) from operations
(51,230
)
 
(113,448
)
 
(166,700
)
 
23,984

 
(6,229
)
Income (loss) before income taxes
(79,321
)
 
(139,123
)
 
(192,719
)
 
(49,322
)
 
(55,778
)
Net earnings (loss) applicable to common shareholders
(75,118
)
 
(128,391
)
 
(155,140
)
 
(38,018
)
 
(35,932
)
Earnings (loss) per common share-basic
$
(0.97
)
 
$
(1.96
)
 
$
(2.41
)
 
$
(0.60
)
 
$
(0.58
)
Earnings (loss) per common share-diluted
$
(0.97
)
 
$
(1.96
)
 
$
(2.41
)
 
$
(0.60
)
 
$
(0.58
)
 
 
 
 
 
 
 
 
 
 
Other Financial Data (1)
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
(5,817
)
 
$
5,131

 
$
142,719

 
$
233,041

 
$
174,580

Net cash used in investing activities
(47,364
)
 
(24,767
)
 
(101,656
)
 
(151,918
)
 
(150,676
)
Net cash provided by (used in) financing activities
118,635

 
15,670

 
(61,827
)
 
(73,584
)
 
(20,252
)
Capital expenditures
61,447

 
32,556

 
142,907

 
188,121

 
125,420

 
As of December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In thousands)
Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Working capital
$
130,645

 
$
47,994

 
$
45,226

 
$
121,882

 
$
118,547

Property and equipment, net
549,623

 
584,080

 
702,585

 
856,541

 
937,657

Long-term debt, excluding current portion, debt issuance costs and discount
475,000

 
346,000

 
395,000

 
455,053

 
499,666

Shareholders’ equity
210,096

 
281,398

 
342,643

 
495,064

 
518,433

Total assets
766,869

 
700,102

 
821,975

 
1,171,589

 
1,229,623


(1) 
The statement of operations and other financial data reflect the impact of impairment charges as follows:
 
Year ended December 31,
 
2017
 
2016
 
2015
 
2014
 
2013
 
(In thousands)
Property and equipment
$
1,902

 
$
12,815

 
$
114,813

 
$
73,025

 
$
9,492

Intangible assets

 

 
14,339

 

 
3,100

Goodwill

 

 

 

 
41,700




29




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 debt agreements, including our senior secured term loan, our senior secured revolving asset-based credit facility, and our senior notes, operating hazards inherent in our operations, the supply of marketable drilling rigs, well servicing rigs, coiled tubing units and wireline units within the industry, the continued availability of new components for drilling rigs, well servicing rigs, coiled tubing units and wireline units, 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. 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. 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) recognize 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. provides land-based drilling services and production services to a diverse group of oil and gas exploration and production companies in the United States and internationally in Colombia. We also provide two of our services (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.
Business Segments

Our business is comprised of two business lines Drilling Services and Production Services. We report our Drilling Services business as two reportable segments: (i) Domestic Drilling and (ii) International Drilling. We report our Production Services business as three reportable segments: (i) Well Servicing, (ii) Wireline Services, and (iii) Coiled Tubing Services. We revised our reportable business segments as of the fourth quarter of 2017 to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. Financial information about our operating segments is included in Note 10, 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— Our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. We have 16 AC rigs in the US and eight SCR rigs in Colombia, all of which have 1,500 horsepower or greater drawworks. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.

30




The drilling rigs in our fleet are currently deployed through our division offices in the following regions:
 
 
Rig Count
Domestic drilling
 
 
Marcellus/Utica
 
6

Eagle Ford
 
1

Permian Basin
 
7

Bakken
 
2

International drilling
 
8

 
 
24

Production Services— Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of exploration and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain states and in the Gulf Coast, both onshore and offshore.
As of December 31, 2017, the fleet count and composition for each of our production services business segments is as follows:
 
550 HP
600 HP
Total
Well servicing rigs, by horsepower (HP) rating
113

12

125

 
 
 
 
 
Offshore
Onshore
Total
Wireline services units
4

108
112

Coiled tubing services units
4

10

14

Market Conditions in Our Industry
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 is primarily driven by current and expected oil and natural gas prices.
Our business is influenced substantially by exploration and production companies’ spending that is generally categorized as either a capital expenditure or an operating expenditure. Capital expenditures for the drilling and completion of exploratory and development 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, operating expenditures for the maintenance of existing wells, for which a range of production services are required in order to maintain production, are relatively more stable and predictable.
Drilling and production services have historically trended similarly in response to fluctuations in commodity prices. However, because exploration and production companies often adjust their budgets for exploration and development 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 ongoing expenditures that are necessary to maintain production. Additionally, within the range of production services businesses, those that derive more revenue from production related activity, as opposed to completion of new wells, tend to be less affected by fluctuations in commodity prices and temporary reductions in industry activity.
However, in a severe downturn that is prolonged, both operating and capital expenditures are significantly reduced, and the demand for all our service offerings is significantly impacted. After a prolonged downturn, among the production services, the demand for completion-oriented services generally improves first, as exploration and production companies begin to complete wells that were previously drilled but not completed during the downturn, and to complete newly drilled wells as the demand for drilling services improves during recovery.
For additional information concerning the effects of the volatility in oil and gas prices and the effects of technological advancements and trends in our industry, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.

31




Market Conditions — Our industry experienced a severe down cycle that began in late 2014 and which persisted through 2016 with WTI oil prices that dipped below $30 in early 2016. A modest recovery in commodity prices began in the latter half of 2016 which continued through 2017, with average oil prices during the last quarter of 2017 averaging approximately $55 per barrel.
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.
a3yrspotprices1a01.jpg
The trends in commodity pricing and domestic rig counts over the last 12 months are illustrated below:
a1yrspotprices1.jpg
With the increases in commodity prices that began in late 2016, we experienced a resulting increase in activity and revenue rates for our services during 2017.
Our well servicing rig hours, number of wireline jobs completed, and coiled tubing revenue days during the quarter ended December 31, 2017 increased by 2%, 11%, and 27%, respectively, as compared to the fourth quarter of 2016, while average revenues for services performed (on a per hour, job and day basis, respectively) during this same period increased as well, largely due to an increase in the proportion of the work performed attributable to completion-related activity and larger diameter coiled tubing services.
A year ago, the utilization of our AC fleet was 81% and there were four rigs earning revenues in Colombia. Since then, all of our idle domestic rigs have been placed on new contracts and the current utilization of our AC rig fleet is 100%. Of the eight rigs in Colombia, six are earning revenues, five of which are under term contracts. The term contracts in Colombia are cancelable by our clients without penalty, although the contract would still require payment for demobilization services and requires 30 days notice. We are actively marketing our idle drilling rigs in Colombia to various operators and we are evaluating other options, including the possibility of the sale of some or all of our assets in Colombia.

32




As of December 31, 2017, 22 of our 24 drilling rigs are earning revenues, 19 of which are under term contracts which if not canceled or renewed prior to the end of their terms, will expire as follows:
 
Spot Market Contracts
 
 
 
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
Domestic rigs
2

 
14

 
4

 
8

 
1

 
1

 

International rigs
1

 
5

 

 
2

 
1

 
1

 
1

 
3

 
19

 
4

 
10

 
2

 
2

 
1

Absent a significant decline in commodity prices, we expect continued improvement in activity and pricing during 2018. Although we expect a highly competitive environment will continue in 2018, we believe our high-quality equipment, services and safety record make us well positioned to compete.
Liquidity and Capital Resources
Sources of Capital Resources
Our principal sources of liquidity currently consist of:
cash and cash equivalents ($73.6 million as of December 31, 2017);
cash generated from operations;
proceeds from sales of certain non-strategic assets; and
the unused portion of our asset-based lending facility (the “ABL Facility”).
Senior Secured Term Loan Our senior secured term loan (the “Term Loan”) entered into on November 8, 2017 provided for one drawing in the amount of $175 million, net of a 2% original issue discount. Proceeds from the issuance of the Term Loan were used to repay the entire outstanding balance under our Revolving Credit Facility, plus fees and accrued and unpaid interest, as well as the fees and expenses associated with entering into the Term Loan and ABL Facility, which is further described below. The remainder of the proceeds are available to be used for other general corporate purposes. The Term Loan is set to mature on November 8, 2022, or earlier, subject to certain circumstances as described in the agreement, and including an earlier maturity date if the outstanding balance of the Senior Notes exceeds $15.0 million on December 14, 2021, at which time the Term Loan would then mature. The Term Loan contains certain covenants which are described in more detail in the Debt Compliance Requirements section below.
Asset-based Lending Facility In addition to entering into the Term Loan, on November 8, 2017, we also entered into a senior secured revolving asset-based credit facility (the “ABL Facility”) providing for borrowings in the aggregate principal amount of up to $75 million, subject to a borrowing base and including a $30 million sub-limit for letters of credit. The ABL Facility bears interest, at our option, at the LIBOR rate or the base rate as defined in the ABL Facility, plus an applicable margin ranging from 1.75% to 3.25%, based on average availability on the ABL Facility. The ABL Facility is generally set to mature 90 days prior to the maturity of the Term Loan, subject to certain circumstances, including the future repayment, extinguishment or refinancing of our Term Loan and/or Senior Notes prior to their respective maturity dates. We have not drawn upon the ABL Facility to date. As of December 31, 2017, we had $9.7 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $53.1 million. Borrowings available under the ABL Facility are available for general corporate purposes and there are no limitations on our ability to access the borrowing capacity provided there is no default and compliance with the covenants under the ABL Facility is maintained. Additional information regarding these covenants is provided in the Debt Compliance Requirements section below.
Shelf Registration Statement — In the future, we may also consider equity and/or debt offerings, as appropriate, to meet our liquidity needs. On May 15, 2015, we filed a registration statement that permits us to sell equity or debt in one or more offerings up to a total dollar amount of $300 million. As of December 31, 2017, $234.6 million under the shelf registration statement is available for equity or debt offerings, subject to the limitations imposed by our Term Loan, ABL Facility and Senior Notes.
We currently expect that cash and cash equivalents, cash generated from operations, proceeds from sales of certain non-strategic assets, and available borrowings under our ABL Facility are adequate to cover our liquidity requirements for at least the next 12 months.

33




Uses of Capital Resources
For the years ended December 31, 2017 and 2016, our primary uses of capital resources were for property and equipment additions, which consisted of the following (amounts in thousands):
 
Year ended December 31,
 
2017
 
2016
Drilling services business:
 
 
 
Routine
$
16,793

 
$
4,948

Discretionary
4,010

 
2,454

Fleet additions and major components
7,337

 
12,464

 
28,140

 
19,866

Production services business:
 
 
 
Routine
13,185

 
8,259

Discretionary
7,826

 
4,256

Fleet additions
14,126

 

 
35,137

 
12,515

Net cash used for purchases of property and equipment
63,277

 
32,381

Net impact of accruals
(1,830
)
 
175

Total capital expenditures
$
61,447

 
$
32,556

In 2016, we lowered our capital expenditures by 77% from the prior year, limiting our capital spending to primarily routine expenditures to maintain our equipment and deferring discretionary upgrades and additions except those that we committed to in 2014 before the market slowdown. In 2017, we maintained capital discipline by limiting our capital spending to primarily routine expenditures while also engaging in select asset acquisitions to optimize our production services fleets, including the exchange of 20 older well servicing rigs for 20 new-model rigs, the purchase of seven new wireline units, and installments on one coiled tubing unit. Routine expenditures in 2017 primarily included refurbishments and start-up costs to redeploy assets that had been idle, including two drilling rigs in Colombia.
Currently, we expect to spend approximately $55 million on capital expenditures during 2018, which we expect will be allocated approximately 35% for our drilling services business segments and approximately 65% for our production services business segments. Our total planned capital expenditures include $15 million of discretionary spending for the purchase of one large-diameter coiled tubing unit and remaining payments on three wireline units, two of which were delivered in January, and additional drilling and production services equipment. Actual capital expenditures may vary depending on the climate of our industry and any resulting increase or decrease in activity levels, the timing of commitments and payments, and the level of rig build and other expansion opportunities that meet our strategic and return on capital employed criteria. We expect to fund the capital expenditures in 2018 from operating cash flow in excess of our working capital requirements, proceeds from sales of certain non-strategic assets, remaining proceeds from our Term Loan issuance, and from available borrowings under our ABL Facility, if necessary.
Working Capital — Our working capital was $130.6 million at December 31, 2017, compared to $48.0 million at December 31, 2016. Our current ratio, which we calculate by dividing current assets by current liabilities, was 2.5 at December 31, 2017, as compared to 1.7 at December 31, 2016.
Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our working capital requirements generally increase during periods when rig construction projects are in progress or during periods of expansion in our production services business, at which times we have been more likely to access capital through equity or debt financing. Additionally, our working capital needs may increase in periods of increasing activity following a sustained period of low activity, which is the primary reason for the $5.8 million of net cash used in operating activities during the year ended December 31, 2017. During periods of sustained low activity and pricing, we may access additional capital through the use of available funds under our ABL Facility.

34




The changes in the components of our working capital were as follows (amounts in thousands), and as described below:
 
December 31,
2017
 
December 31,
2016
 
Change
Cash and cash equivalents
$
73,640

 
$
10,194

 
$
63,446

Restricted cash
2,008

 

 
2,008

Receivables:
 
 
 
 
 
Trade, net of allowance for doubtful accounts
79,592

 
38,764

 
40,828

Unbilled receivables
16,029

 
7,417

 
8,612

Insurance recoveries
13,874

 
17,003

 
(3,129
)
Other receivables
3,510

 
8,939

 
(5,429
)
Inventory
14,057

 
9,660

 
4,397

Assets held for sale
6,620

 
15,093

 
(8,473
)
Prepaid expenses and other current assets
6,229

 
6,926

 
(697
)
Current assets
215,559

 
113,996

 
101,563

Accounts payable
29,538

 
19,208

 
10,330

Deferred revenues
905

 
1,449

 
(544
)
Accrued expenses:
 
 
 
 
 
Payroll and related employee costs
21,023

 
14,813

 
6,210

Insurance premiums and deductibles
6,742

 
6,446

 
296

Insurance claims and settlements
13,289

 
13,667

 
(378
)
Interest
6,624

 
5,395

 
1,229

Other
6,793

 
5,024

 
1,769

Current liabilities
84,914

 
66,002

 
18,912

Working capital
$
130,645

 
$
47,994

 
$
82,651

Cash and cash equivalents During 2017, we used $63.3 million of cash for the purchases of property and equipment and used $5.8 million in operating activities, primarily funded by $119.2 million of net borrowings (net of debt issuance costs), $12.6 million of proceeds from the sale of assets, as well as $3.3 million of insurance proceeds received from drilling rig and wireline unit damages. Cash used in operations during 2017 was primarily for increased working capital due to the recent increase in activity.
Restricted cash Our restricted cash balance at December 31, 2017 reflects the portion of net proceeds from the issuance of our Term Loan which are currently held in a restricted account until the completion of certain administrative tasks related to providing access rights to certain of our real property, which we expect to complete within 12 months. Accordingly, the related restricted cash is presented as current in the accompanying consolidated balance sheets.
Trade and unbilled receivables The net increase in our total trade and unbilled receivables during 2017 is primarily due to the 77% increase in our revenues during the quarter ended December 31, 2017, as compared to the quarter ended December 31, 2016, as well as the timing of billing and collection cycles for long-term drilling contracts in Colombia. Our domestic trade receivables generally turn over within 90 days, and our Colombian trade receivables generally turn over within 120 days, which can take more time when setting up the billing process with new clients.
Insurance recoveriesThe decrease in our insurance recoveries receivables during 2017 is primarily due to an insurance claim receivable of $3.1 million for a drilling rig that was damaged during 2016, for which the proceeds were received in early 2017.
Other receivablesThe decrease in other receivables during 2017 is primarily due to the sale of two drilling rigs in December 2016, for which the proceeds of $6.3 million were received in January 2017. This decrease is partially offset by an increase in net income tax receivables for Colombia as well as $0.6 million remaining of a short-term note receivable from the sales of two mechanical drilling rigs that were sold during the third quarter of 2017.
InventoryThe increase in inventory during 2017 is primarily due to the increase in activity for our Colombian operations, as well as purchases of supplies and job materials for our wireline and coiled tubing operations.

35




Assets held for saleAs of December 31, 2017, our consolidated balance sheet reflects assets held for sale of $6.6 million, which primarily represents the fair value of three domestic SCR drilling rigs and one domestic mechanical drilling rig, as well as other drilling equipment, two wireline units and one coiled tubing unit and spare equipment. The decrease in assets held for sale as of December 31, 2017, when comparing to December 31, 2016, is primarily due to 20 older well servicing rigs that were designated as held for sale that were traded in for 20 new-model rigs in the first quarter of 2017, as well as the sale of two mechanical drilling rigs and 13 wireline units.
Prepaid expenses and other current assets The decrease in prepaid expenses and other current assets during 2017 is primarily due to the amortization of mobilization costs for several domestic and international drilling rigs which were mobilized under new contracts in late 2016 and early 2017. For more information about rig mobilization service revenues and costs, see Note 1, Organization and Summary of Significant Accounting Policies, 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.
Accounts payableOur accounts payable generally turn over within 90 days. The increase in accounts payable during 2017 is primarily due to the 64% increase in our operating costs for the quarter ended December 31, 2017 as compared to the quarter ended December 31, 2016, resulting from an increase in activity, and partially offset by a decrease of $1.8 million in our accruals for capital expenditures.
Accrued payroll and related employee costs — The increase in accrued payroll and related employee costs during 2017 is primarily due to an increase in the accrual for our 2017 annual bonuses due to improved company performance, as well as an increase in accrued salaries and wages due to a 25% increase in headcount during 2017 to accommodate the increased demand for our services.
Accrued interest — The increase in accrued interest expense during 2017 is primarily due to increased amount of debt outstanding as a result of the issuance of our Term Loan, from which a portion of the proceeds were used to repay and retire our Revolving Credit Facility, and for which interest incurs at a higher rate.
Other accrued expenses The increase in other accrued expenses during 2017 is primarily due to an increase in our accrued liability for value-added tax obligations (“VAT”) in Colombia as a result of an increase in activity in 2017.
Debt and Other Contractual ObligationsThe following table includes information about the amount and timing of our contractual obligations at December 31, 2017 (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
$
475,000

 
$

 
$

 
$
475,000

 
$

Interest on debt
144,899

 
34,108

 
68,215

 
42,576

 

Purchase commitments
8,170

 
8,170

 

 

 

Operating leases
9,902

 
3,081

 
3,534

 
1,441

 
1,846

Incentive compensation
15,722

 
4,637

 
11,085

 

 

 
$
653,693

 
$
49,996

 
$
82,834

 
$
519,017

 
$
1,846

Debt Debt obligations at December 31, 2017 consisted of $300 million of principal amount outstanding under our Senior Notes which mature on March 15, 2022 and $175 million of principal amount outstanding under our Term Loan which is expected to mature on December 14, 2021. As of December 31, 2017, we had no debt outstanding under our ABL Facility.
Interest on debt Interest payment obligations on our 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 until maturity on March 15, 2022. Interest payment obligations on our Term Loan were estimated based on (1) the 9.0% interest rate that was in effect at December 31, 2017, and (2) the principal balance of $175 million at December 31, 2017, and assuming repayment of the outstanding balance occurs at December 14, 2021.
Purchase commitments Purchase commitments primarily pertain to deposits on one new coiled tubing unit, which was ordered in the fourth quarter of 2017, remaining installments on three new wireline units that were on order for delivery in 2018, as well as routine capital expenditures and inventory.

36




Operating leasesOur operating leases consist of lease agreements for office space, operating facilities, field personnel housing, and office equipment.
Incentive compensationIncentive compensation is payable to our employees, generally contingent upon their continued employment through the date of each respective award’s payout. A portion of our long-term incentive compensation is performance-based and therefore the final amount will be determined based on our actual performance relative to a pre-determined peer group over the performance period.
Debt Compliance RequirementsThe following is a summary of our debt compliance requirements including covenants, restrictions and guarantees, all of which are described in more detail in Note 3, Debt, and Note 13, Guarantor/Non-Guarantor Condensed Consolidating Financial Statements, 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.
The Term Loan contains a financial covenant requiring the ratio of (i) the net orderly liquidation value of our fixed assets (based on appraisals obtained as required by our lenders), on a consolidated basis, in which the lenders under the Term Loan maintain a first priority security interest, plus proceeds of asset dispositions not required to be used to effect a prepayment of the Term Loan to (ii) the outstanding principal amount of the Term Loan, to be at least equal to 1.50 to 1.00 as of any June 30 or December 31 of any calendar year through maturity. As of December 31, 2017, the asset coverage ratio, as calculated under the Term Loan, was 2.05 to 1.00.
The Term Loan contains customary mandatory prepayments from the proceeds of certain transactions including certain asset dispositions and debt issuances, and has additional customary restrictions that limit our ability to enter into various transactions. In addition, the Term Loan contains customary events of default, upon the occurrence and during the continuation of any of which the applicable margin would increase by 2% per year. Our obligations under the Term Loan are guaranteed by our wholly-owned domestic subsidiaries, and are secured by substantially all of our domestic assets, in each case, subject to certain exceptions and permitted liens.
The ABL Facility also contains customary restrictive covenants which, subject to certain exceptions, limit, among other things, our ability to enter into certain transactions. Additionally, if our availability under the ABL Facility is less than 15% of the maximum amount, we are required to maintain a minimum fixed charge coverage ratio, as defined in the ABL Facility, of at least 1.00 to 1.00, measured on a trailing 12 month basis.
Our obligations under the ABL Facility are guaranteed by us and our domestic subsidiaries, subject to certain exceptions, and are secured by (i) a first-priority perfected security interest in all inventory and cash, and (ii) a second-priority perfected security in substantially all of our tangible and intangible assets, in each case, subject to certain exceptions and permitted liens.
The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. Our Senior Notes are not subject to any sinking fund requirements. The Indenture governing our Senior Notes contains additional restrictive covenants that limit our ability to enter into various transactions.
As of December 31, 2017, we were in compliance with all covenants required by our Term Loan, ABL Facility and Senior Notes.

37




Results of Operations
Statements of Operations Analysis - Year Ended December 31, 2017 Compared with Year Ended December 31, 2016
The following table provides certain information about our operations, including a detail of each of our business segments’ revenues, operating costs and gross margin, and the percentage of the consolidated amount of each which is attributable to each business segment, for the years ended December 31, 2017 and 2016 (amounts in thousands, except percentages):
 
Year ended December 31,
 
2017
 
2016
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
129,276

 
29
%
 
$
112,399

 
41
 %
International drilling
41,349

 
9
%
 
6,808

 
2
 %
Drilling services
170,625

 
38
%
 
119,207

 
43
 %
Well servicing
77,257

 
17
%
 
71,491

 
26
 %
Wireline services
163,716

 
37
%
 
67,419

 
24
 %
Coiled tubing services
34,857

 
8
%
 
18,959

 
7
 %
Production services
275,830

 
62
%
 
157,869

 
57
 %
Consolidated revenues
$
446,455

 
100
%
 
$
277,076

 
100
 %
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
83,122

 
25
%
 
$
63,686

 
31
 %
International drilling
31,994

 
10
%
 
9,465

 
5
 %
Drilling services
115,116

 
35
%
 
73,151

 
36
 %
Well servicing
56,379

 
17
%
 
53,208

 
26
 %
Wireline services
128,137

 
39
%
 
57,634

 
28
 %
Coiled tubing services
31,248

 
9
%
 
19,956

 
10
 %
Production services
215,764

 
65
%
 
130,798

 
64
 %
Consolidated operating costs
$
330,880

 
100
%
 
$
203,949

 
100
 %
 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
46,154

 
40
%
 
$
48,713

 
67
 %
International drilling
9,355

 
8
%
 
(2,657
)
 
(4
)%
Drilling services
55,509

 
48
%
 
46,056

 
63
 %
Well servicing
20,878

 
18
%
 
18,283

 
25
 %
Wireline services
35,579

 
31
%
 
9,785

 
13
 %
Coiled tubing services
3,609

 
3
%
 
(997
)
 
(1
)%
Production services
60,066

 
52
%
 
27,071

 
37
 %
Consolidated gross margin
$
115,575

 
100
%
 
$
73,127

 
100
 %
 
 
 
 
 
 
 
 
Consolidated:
 
 
 
 
 
 
 
Net loss
$
(75,118
)
 
 
 
$
(128,391
)
 
 
Adjusted EBITDA (1)
$
49,873

 
 
 
$
14,237

 
 
(1)    Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, loss on extinguishment of debt and impairments. Adjusted EBITDA is a non-GAAP measure that our management uses to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our core 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.

38




A reconciliation of net loss, as reported, to Adjusted EBITDA, and a reconciliation of net loss, as reported, to consolidated gross margin are set forth in the following table.
 
Year ended December 31,
 
2017
 
2016
 
(amounts in thousands)
Reconciliation of net loss and Adjusted EBITDA to consolidated gross margin:
 
 
 
Net loss
$
(75,118
)
 
$
(128,391
)
Depreciation and amortization
98,777

 
114,312

Impairment
1,902

 
12,815

Interest expense
27,039

 
25,934

Loss on extinguishment of debt
1,476

 
299

Income tax benefit
(4,203
)
 
(10,732
)
Adjusted EBITDA
49,873

 
14,237

General and administrative
69,681

 
61,184

Bad debt expense
53

 
156

Gain on dispositions of property and equipment, net
(3,608
)
 
(1,892
)
Other income
(424
)
 
(558
)
Consolidated gross margin
$
115,575

 
$
73,127

Consolidated gross margin Our consolidated gross margin increased by 58% during 2017, as compared to 2016, as a result of higher activity for each of our drilling and production services business segments during the year ended December 31, 2017, as compared to 2016, as our industry continues to recover from an industry downturn. Spot prices have also improved for all of our business segments throughout 2017. Of the $42.4 million increase in consolidated gross margin, 78% is attributable to our production services segments, primarily due to improved demand for our wireline services, while the remaining increase attributable to our drilling services business segments is primarily due to higher activity for our international drilling operations.
Drilling Services Our drilling services revenues increased by $51.4 million, or 43%, during 2017, as compared to 2016, while operating costs increased by $42.0 million, or 57%. The increases in our drilling services revenues and operating costs primarily resulted from a 42% increase in revenue days due to the increasing demand in our industry, especially in Colombia.

39




The following table provides operating statistics for each of our drilling services segments for the years ended December 31, 2017 and 2016:
 
Year ended December 31,
 
2017
 
2016
Domestic drilling:
 
 
 
Average number of drilling rigs
16

 
23

Utilization rate
95
%
 
55
%
Revenue days
5,524

 
4,628

 
 
 
 
Average revenues per day
$
23,403

 
$
24,287

Average operating costs per day
15,047

 
13,761

Average margin per day
$
8,356

 
$
10,526

 
 
 
 
International drilling:
 
 
 
Average number of drilling rigs
8

 
8

Utilization rate
46
%
 
7
%
Revenue days
1,345

 
218

 
 
 
 
Average revenues per day
$
30,743

 
$
31,229

Average operating costs per day
23,787

 
43,417

Average margin per day
$
6,956

 
$
(12,188
)
Our domestic drilling fleet utilization reached 100% by mid-2017, and remained fully utilized through December 31, 2017. Our domestic drilling average revenues per day during 2017, as compared to 2016, decreased, while our average operating costs per day increased, due to the expiration of term contracts during 2016 that were entered into prior to the downturn at higher revenue rates, many of which were terminated early. Thus, there were more revenue days during 2017 attributable to daywork activity versus revenue days associated with rigs that were earning but not working and incurring minimal operating costs during 2016.
Demand for drilling rigs influences the types of drilling contracts we are able to obtain, and the type of revenues we earn under our drilling contracts. As a result of the downturn in our industry, several of our clients terminated a number of their drilling contracts with us. Drilling rigs under contracts which are terminated early earn lower standby revenue rates, as compared to daywork rates, and incur minimal operating costs. The following table provides the percentages of our consolidated drilling services revenues by contract type for the years ended December 31, 2017 and 2016:
 
Year ended December 31,
 
2017
 
2016
Daywork contracts (not terminated early)
100
%
 
89
%
Daywork contracts terminated early
%
 
11
%
Our international drilling fleet utilization steadily improved throughout 2017, culminating in a 75% utilization rate at the end of 2017, versus 50% utilization at December 31, 2016, which resulted in a significant increase in our average margin per day. The substantial increase in average margin per day is largely a result of the low utilization in 2016, during which time we incurred certain fixed costs, as well as additional costs during the fourth quarter of 2016 to mobilize previously stacked rigs under new contracts, which resulted in a negative average margin per day during 2016.
Production Services Our revenues from production services increased by $118.0 million, or 75%, during 2017, as compared to 2016, while operating costs increased by $85.0 million, or 65%, respectively. The increases in revenues and operating costs in our production services segments are a result of the increased demand for our services, particularly those that perform completion-related activities.

40




The following table provides operating statistics for each of our production services segments for the years ended December 31, 2017 and 2016:
 
Year ended December 31,
 
2017
 
2016
 
 
 
 
Well servicing:
 
 
 
Average number of rigs
125

 
125

Utilization rate
43
%
 
41
%
Rig hours
150,240

 
144,151

Average revenue per hour
$
514

 
$
496

 
 
 
 
Wireline services:
 
 
 
Average number of units
115

 
122

Number of jobs
11,139

 
8,169

Average revenue per job
$
14,698

 
$
8,253

 
 
 
 
Coiled tubing services:
 
 
 
Average number of units
16

 
17

Revenue days
1,529

 
1,352

Average revenue per day
$
22,797

 
$
14,023

Increases in production services revenues and operating costs were led by our wireline services business segment, which experienced a significant increase in completion-related activity as wells that were drilled but not completed during the downturn created higher demand for completion services as our industry continues to recover. The number of wireline jobs we completed increased by 36% during 2017, as compared to 2016 while average revenue per job increased by 78%, which is largely due to completion-related jobs that earn higher revenue rates but also incur higher costs for the job materials consumed on these types of jobs.
Our well servicing and coiled tubing services business segments experienced a more moderate increase in demand. Well servicing utilization increased to 43% during 2017, from 41% during 2016, representing a 4% increase in well servicing rig hours, while average revenue per hour also increased by 4%. Our coiled tubing revenue days increased by 13%, while the average revenue per day increased by 63%, which was primarily due to a larger proportion of the work performed with larger diameter coiled tubing units which typically earn higher revenue rates as compared to smaller diameter coiled tubing units.
Depreciation and amortization expense — Our depreciation and amortization expense decreased by $15.5 million during 2017, as compared to 2016, primarily as a result of the impairments, dispositions of various equipment, and assets we placed as held for sale during 2016, as well as reduced capital expenditures during 2016 and 2017 due to the downturn. During the year ended December 31, 2016, we recognized $11.6 million of depreciation on drilling and well servicing rigs, wireline units, and certain other equipment which were subsequently sold or placed as held for sale, and $1.3 million of amortization expense for certain intangible assets that were fully amortized by the end of 2016.
Impairment During the years ended December 31, 2017 and 2016, we recognized impairment charges of $1.9 million and $12.8 million, respectively, primarily to reduce the carrying values of certain assets which were classified as held for sale, to their estimated fair values based on expected sale prices. For more detail, see Note 2, Property and Equipment, 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.
Interest expense Our interest expense increased by $1.1 million during the year ended December 31, 2017, as compared to 2016, primarily due to the increased interest rate under our Revolving Credit Facility, which was amended in June 2016, and the issuance of our Term Loan in November 2017. Proceeds from the issuance of our Term Loan were used to repay and retire the Revolving Credit Facility, and resulted in an increase in our total debt outstanding, as well as an increased rate applicable to the outstanding borrowings. Weighted average debt outstanding under our Revolving Credit Facility and/or Term Loan (beginning in November 2017) was approximately $95.4 million and $96.0 million during the years ended December 31, 2017 and 2016, respectively, while the weighted average interest rate on these borrowings during these periods was approximately 6.9% and 5.7%, respectively.

41




Loss on extinguishment of debtOur loss on extinguishment of debt in 2017 represents the write-off of net unamortized debt issuance costs associated with the extinguishment of our Revolving Credit Facility in November 2017. Our 2016 loss on debt extinguishment represents the write-off of net unamortized debt issuance costs resulting from the reduction of borrowing capacity under our Revolving Credit Facility when it was amended in 2016.
Income tax benefit Our effective income tax rate for the year ended December 31, 2017 was lower than the federal statutory rate in the United States primarily due to effects of recent tax law changes, valuation allowances, foreign currency translation, state taxes, and other permanent differences. For more detail, see Note 5, Income Taxes, 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.
General and administrative expense — Our general and administrative expense increased by approximately $8.5 million, or 14%, during 2017, as compared to 2016, primarily related to increased compensation costs. The increase in compensation cost was primarily due to a $7.1 million increase in salary, employee benefits and bonus expense during the year ended December 31, 2017, partially as a result of increased headcount to accommodate higher activity levels, as well as increased incentive compensation based on improved company performance.
Gain on dispositions of property and equipment, net — Our net gain of $3.6 million on the disposition of various property and equipment during the year ended December 31, 2017 included sales of drilling and coiled tubing equipment and vehicles, as well as the loss of drill pipe in operation, for which we were reimbursed by our client. Net gains in 2017 also included the disposal of three cranes that were damaged, for which we received $0.2 million of the $0.8 million of insurance proceeds and expect to receive the remaining proceeds in early 2018. Our net gain of $1.9 million on the disposition of property and equipment during 2016 was primarily related to a net gain on the sale of drilling rigs and the disposal of excess drill pipe. These gains during 2016 were partially offset by a loss on the disposition of damaged drilling equipment.
Other income (expense), net Our other income is primarily related to net foreign currency gains recognized for our Colombian operations.

42




Statements of Operations Analysis - Year Ended December 31, 2016 Compared with Year Ended December 31, 2015
The following table provides certain information about our operations, including a detail of each of our business segments’ revenues, operating costs and gross margin, and the percentage of the consolidated amount of each which is attributable to each business segment, for the years ended December 31, 2016 and 2015 (amounts in thousands, except percentages):
 
Year ended December 31,
 
2016
 
2015
Revenues:
 
 
 
 
 
 
 
Domestic drilling
$
112,399

 
41
 %
 
$
205,440

 
38
%
International drilling
6,808

 
2
 %
 
43,878

 
8
%
Drilling services
119,207

 
43
 %
 
249,318

 
46
%
Well servicing
71,491

 
26
 %
 
133,440

 
25
%
Wireline services
67,419

 
24
 %
 
120,387

 
22
%
Coiled tubing services
18,959

 
7
 %
 
37,633

 
7
%
Production services
157,869

 
57
 %
 
291,460

 
54
%
Consolidated revenues
$
277,076

 
100
 %
 
$
540,778

 
100
%
 
 
 
 
 
 
 
 
Operating costs:
 
 
 
 
 
 
 
Domestic drilling
$
63,686

 
31
 %
 
$
108,602

 
30
%
International drilling
9,465

 
5
 %
 
35,594

 
10
%
Drilling services
73,151

 
36
 %
 
144,196

 
40
%
Well servicing
53,208

 
26
 %
 
91,125

 
25
%
Wireline services
57,634

 
28
 %
 
88,848

 
26
%
Coiled tubing services
19,956

 
10
 %
 
33,847

 
9
%
Production services
130,798

 
64
 %
 
213,820

 
60
%
Consolidated operating costs
$
203,949

 
100
 %
 
$
358,016

 
100
%
 
 
 
 
 
 
 
 
Gross margin:
 
 
 
 
 
 
 
Domestic drilling
$
48,713

 
67
 %
 
$
96,838

 
53
%
International drilling
(2,657
)
 
(4
)%
 
8,284

 
5
%
Drilling services
46,056

 
63
 %
 
105,122

 
58
%
Well servicing
18,283

 
25
 %
 
42,315

 
23
%
Wireline services
9,785

 
13
 %
 
31,539

 
17
%
Coiled tubing services
(997
)
 
(1
)%
 
3,786

 
2
%
Production services
27,071

 
37
 %
 
77,640

 
42
%
Consolidated gross margin
$
73,127

 
100
 %
 
$
182,762

 
100
%
 
 
 
 
 
 
 
 
Consolidated:
 
 
 
 
 
 
 
Net loss
$
(128,391
)
 
 
 
$
(155,140
)
 
 
Adjusted EBITDA (1)
$
14,237

 
 
 
$
110,780

 
 
(1)    Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, loss on extinguishment of debt and impairments. Adjusted EBITDA is a non-GAAP measure that our management uses to facilitate period-to-period comparisons of our core operating performance and to evaluate our long-term financial performance against that of our peers. We believe that this measure is useful to investors and analysts in allowing for greater transparency of our core 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.

43




A