UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark one)
ýANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20172019
or
oTRANSITION 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

Registrant’s telephone number, including area code: (855) 884-0575
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(b) of the Act
Title of each classTrading Symbol(s)Name of each exchange on which registered
Securities registered pursuant to Section 12(g) of the Act: 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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ No¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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  o
 
AcceleratedNon-accelerated filer þ
Non-accelerated filer o
(Do not check if a smaller reporting company)
Smaller reporting company oþ
 
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 nonaffiliatesnon-affiliates 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)2019) was approximately $154.7 million.$19.0 million.
As of January 31, 2018,February 28, 2020, there were 77,794,52779,579,571 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
PortionsItems 10, 11, 12, 13 and 14 of the proxy statement related to the registrant’s 2018 Annual Meeting of Shareholders arePart III will be incorporated by reference into Part III of this report.from the Form 10-K/A to be filed with the Securities and Exchange Commission.
 

TABLE OF CONTENTS
 

















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:
our ability to obtain the Bankruptcy Court’s approval with respect to motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases, including maintaining strategic control as debtor-in-possession, and the outcomes of Bankruptcy Court rulings and the Chapter 11 Cases in general;
delays in the Chapter 11 Cases;
our ability to consummate the Plan;
our ability to achieve our stated goals and continue as a going concern;
risks that our assumptions and analyses in the Plan are incorrect;
our ability to fund our liquidity requirements during the Chapter 11 Cases;
our ability to comply with the covenants under our DIP Facility;
the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents;
the actions and decisions of creditors, regulators and other third parties that have an interest in the Chapter 11 Cases;
restrictions imposed on us by the Bankruptcy Court;
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 unitsequipment within the industry;
the continued availability of new components for drilling rigs, well servicing rigs, coiled tubing units and wireline units;our fleets;
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.environment
the occurrence of cybersecurity incidents;
the success or failure of future acquisitions or dispositions;
future compliance with covenants under our debt arrangements; and



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the impact of not having our common stock listed on a national securities exchange.
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
Recent Developments
Reorganization, Chapter 11 Proceedings, and Going Concern
On March 1, 2020 (the “Petition Date”), Pioneer Energy Services Corp. (“Pioneer”) and its affiliates Pioneer Coiled Tubing Services, LLC, Pioneer Drilling Services, Ltd., Pioneer Fishing & Rental Services, LLC, Pioneer Global Holdings, Inc., Pioneer Production Services, Inc., Pioneer Services Holdings, LLC, Pioneer Well Services, LLC, Pioneer Wireline Services Holdings, Inc., Pioneer Wireline Services, LLC (collectively with Pioneer, the “Pioneer RSA Parties”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Chapter 11 proceedings are being jointly administered under the caption In re Pioneer Energy Services Corp. et al (the “Chapter 11 Cases”).
Since the commencement of the Chapter 11 Cases, the Pioneer RSA Parties have continued to operate our business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Bankruptcy Petitions constitute an event of default that accelerated our obligations under the following debt instruments (the “Debt Instruments”):
Term Loan Agreement, dated as of November 8, 2017, by and among Pioneer, as the borrower, the lenders party thereto and Wilmington Trust, National Association, as administrative agent (the “Term Loan”);
Credit Agreement, dated as of November 8, 2017, by and among Pioneer, as the parent and a borrower, the other borrowers party thereto, Wells Fargo, National Association, as administrative agent and collateral agent, and the other lenders party thereto (the “Prepetition ABL Facility”); and
6.125% Senior Notes due 2022 issued by Pioneer pursuant to the Indenture, dated March 18, 2014, by and among Pioneer, as the issuer, the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee (the “Senior Notes”).
Under the Bankruptcy Code, holders of our Senior Notes and the lenders under our Term Loan and the Prepetition ABL Facility are stayed from taking any action against us as a result of this event of default.
In connection with the Bankruptcy Petitions, the Pioneer RSA Parties entered into a restructuring support agreement (the “RSA”) with holders of approximately 99% in aggregate principal amount of our outstanding Term Loan (the “Consenting Term Lenders”) and holders of approximately 75% in aggregate principal amount of our Senior Notes (the “Consenting Noteholders” and together with the Consenting Term Lenders, the “Consenting Creditors”). The RSA incorporates economic terms regarding a restructuring of the Pioneer RSA Parties agreed to by the parties reflected in a term sheet attached as Exhibit B to the RSA. Pursuant to the RSA, the Consenting Creditors and the Pioneer RSA Parties made certain customary commitments to each other, including the Consenting Noteholders committing to vote for, and the Consenting Creditors committing to support, the restructuring transactions (the “Restructuring”) to be effectuated through a plan of reorganization that incorporates the economic terms included in the RSA (the “Plan”). The Pioneer RSA Parties filed the Plan with the Bankruptcy Court on March 2, 2020.
Debtor-in-Possession Financing and New Revolver
On February 28, 2020, we received commitments pursuant to a commitment letter (“the Commitment Letter”) from PNC Bank, N.A. for a $75 million asset-based revolving loan debtor-in-possession financing facility (the “DIP Facility”) and a $75 million asset-based revolving exit financing facility (the “New Revolver”). On March 3, 2020, with the approval of the Bankruptcy Court, we entered into the DIP Facility and used the proceeds of the initial extensions of credit thereunder to refinance all outstanding letters of credit under the Prepetition ABL Facility in connection with the termination of the Prepetition ABL Facility and to pay fees and expenses in connection with the Chapter 11 Cases and transactional and professional fees related thereto.
The DIP Facility has a 5-month maturity, bears interest at a rate of LIBOR plus 200 basis points per annum, and contains customary covenants and events of default. The borrowers and guarantors under the DIP Facility are the same as the borrowers and guarantors under the Prepetition ABL Facility. Subject to certain exceptions, our obligations under the DIP Facility are superpriority administrative expenses in the Chapter 11 Cases and are secured by a first-priority lien on inventory and cash and a second-priority lien on all other assets of the borrowers and guarantors thereunder.



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The Commitment Letter contemplates that upon our emergence from the Chapter 11 Cases, subject to the satisfaction of certain customary conditions, the DIP Facility will “roll” into the New Revolver. Subject to the terms and conditions of the Commitment Letter, the New Revolver will have a 5-year maturity, will bear interest at a rate per annum between LIBOR plus 175 basis points and LIBOR plus 225 basis points (depending on the average excess availability under the New Revolver), and will contain customary covenants and events of default. Subject to certain exceptions and permitted liens, the obligations of the borrowers and guarantors under the New Revolver will be secured by a first-priority lien on inventory and cash and a second-priority lien on substantially all other assets of the borrowers and guarantors thereunder. We anticipate that the proceeds of the New Revolver will be used to repay in full all amounts outstanding under the DIP Facility and for general corporate purposes.
Going Concern and Financial Reporting in Reorganization
The risks and uncertainties surrounding the Chapter 11 Cases, the defaults under our Debt Instruments, and the weak industry conditions impacting our business raise substantial doubt as to our ability to continue as a going concern. Accordingly, the audit report issued by our independent registered public accounting firm contains an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, which contemplate our continuation as a going concern. For additional information concerning our bankruptcy proceedings under Chapter 11, see Note 2, Going Concern and Subsequent Events,of the Notes to Consolidated Financial Statements included in Part II, Item 8 Financial Statements and Supplementary Data, and Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.
Delisting of our Common Stock from the New York Stock Exchange (the “NYSE”)
Our common stock traded on the New York Stock Exchange (NYSE) under the symbol “PES” until August 15, 2019, at which time it was removed from trading on the NYSE due to our inability to satisfy the continued listing requirements of the NYSE. Our common stock subsequently traded on the OTC Markets under the symbol “PESX” until March 3, 2020, at which time, due to our voluntary filing of the Chapter 11 Cases, our common stock commenced trading on the OTC Pink marketplace under the trading symbol “PESXQ”.
Company Overview
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. Since then, we have significantly expanded and transformed our business through acquisitions and organic growth.
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/Utica6
Eagle Ford1
Permian Basin7
Bakken2
International drilling8
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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.
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 10,12, 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 landWe provide a comprehensive service offering which includes the drilling rig, consistscrews, supplies, and most of power generation system(s), a hoisting system, a rotating system, pumps and relatedthe ancillary equipment needed 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 haverigs. Our current drilling rig fleet is 100% pad-capable and offers the ability to drill multiple well bores from a single surface location as discussedlatest advancements in more detail below.pad drilling. The following table summarizes our current rig fleet composition by segment and region:
There


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 Multi-well, Pad-capable
 SCR rigs AC rigs Total
Domestic drilling     
Marcellus/Utica
 5
 5
Permian Basin and Eagle Ford
 10
 10
Bakken
 2
 2
      
International drilling8
 
 8
     25
Technological advancements and trends in our industry affect the demand for certain types of equipment and there are numerous factors that differentiate land drilling rigs, such as the type of power used, drilling depth capabilities or drawworks horsepower,hook load capacity, 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 theirEvery drilling rig in our fleet is 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 thaneither AC or 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 electricpowered. Electric rigs are considered safer, more reliable and more efficient than mechanical rigs.mechanically powered rigs, while AC rigs are considered to be more energy efficient and provide more precise control of equipment than their SCR counterparts, which enhancesfurther enhancing rig safety and reducesreducing drilling time.
The following table summarizesAll but one of our current rig fleet composition by segment:
 Multi-well, Pad-capable
 SCR rigsAC rigsTotal
Domestic drilling
16
16
International drilling8

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   24
Technological advancementsrigs has 750,000 pounds or greater of hook load capacity, and trends in our industry affect the demand for certain types of equipment. Everyevery 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.safety, as described in more detail below.  
InTop drives can be used in horizontal well drilling operators can utilize top drives to reach formations that may not be accessible with conventional rotary drilling. Top drivesdrilling because they 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 handlingpipe-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 handlingpipe-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, oilOil and gas exploration and production companies have increased thetypically prefer to use of “pad drilling” wherebywhich allows a series of horizontal wells areto be 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,Daywork contracts are comprehensive agreements under which we provide a comprehensive service offering, including the drilling crewsrig, crew, supplies, and most of the ancillary equipment needednecessary to operate the rig. Generally, our land drilling rigs.rigs operate with crews of five to six persons. 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. Wedays, but we typically enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of highhigher rig demand.



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Production Services
Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of explorationproducers primarily in Texas and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain statesregions, as well as in North Dakota, Louisiana and in the Gulf Coast, both onshore and offshore.Mississippi.
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, 2017,2019, the fleet count and compositioncounts for each of our production services business segments isare as follows:
 550 HP600 HPTotal
Well servicing rigs, by horsepower (HP) rating113
12
125
    
 OffshoreOnshoreTotal
Wireline units4
108112
Coiled tubing units4
10
14
 550 HP 600 HP Total
Well servicing rigs, by horsepower (HP) rating112 12 124
      
     Total
Wireline services units 93
Coiled tubing services units 9
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



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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 20Our fleet consists of our older112 rigs with 550 horsepower well servicingand 12 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 operationswith 600 horsepower which are deployed through 109 operating locations mostlyconcentrated in the Gulf Coast states,Texas, as well as in Arkansas, North Dakota, Colorado and Colorado.Mississippi.
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 openopen- 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 fleet of 93 wireline operations areunits, includes 2 greaseless, EcoQuietTM units designed to reduce noise when operating in proximity to urban areas as well as 6 units that offer greaseless electric wireline used to reach further depths in longer laterals. Our fleet is deployed through 1710 operating locations concentrated in Texas Kansas, Colorado, Montana,and the Rocky Mountain and Mid-Continent regions, as well as in Louisiana and North Dakota, Louisiana, Oklahoma and Wyoming.Dakota.
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 flexible metal pipe which is spooled on a large reel forand inserted into the wellbore to perform a variety of 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 operationsfleet consists of 4 small-diameter and 5 large-diameter (larger than two inches) units, which are deployed through three2 operating locations that provide services in Texas, Louisiana, Wyoming and surrounding areas.
Industry Overview
Demand for oilfield services offered by our industry is a function of our clients’ willingness and ability 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.
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 drillingis influenced substantially by exploration and production services to numerouscompanies’ spending that is generally categorized as either a capital expenditure or an operating expenditure.
Capital expenditures by oil and gas exploration and production companies. The following table shows our three largest clientscompanies 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 percentagedrilling 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 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



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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 change 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 total revenueservice offerings is significantly impacted. After a prolonged downturn, among the production services, the demand for eachcompletion-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.
The level of exploration and production activity within a region can fluctuate due to a variety of factors which may directly or indirectly impact our operations in the region. From time to time, temporary regional slowdowns or constraints occur in our industry due to a variety of factors, including, among others, infrastructure or takeaway capacity limitations, labor shortages, increased regulatory or environmental pressures, or an influx of competitors in a particular region. Any of these factors can influence the profitability of operations in the affected region. However, term contract coverage for our drilling services business and the mobility of all our equipment between regions reduces our exposure to the impact of regional constraints and fluctuations in demand.
Additionally, because our business depends on the level of spending by our clients, we are also affected by our clients’ ability to access the capital markets. After several consecutive years without significant improvement in commodity prices, many exploration and production companies have limited their spending to a level which can be supported by net operating cash flows alone, as access to the capital markets through debt or equity financings has become more challenging in our industry.
Our industry experienced a severe down cycle from late 2014 through 2016, during which WTI oil prices dipped below $30 per barrel in early 2016. A modest recovery in commodity prices began in the latter half of 2016 with WTI oil prices steadily increasing from just under $50 per barrel at the end of June 2016 to approximately $60 per barrel at the end of 2017. WTI oil prices continued to increase to a high of $75 per barrel in October 2018, but then decreased to $45 per barrel at the end of 2018. Despite some improvement in 2019, WTI oil prices have, on average, remained in the $55 to $60 per barrel range. However, in early 2020, oil and gas prices have fallen below $50 per barrel, largely in response to concerns about coronavirus and its potential impact on worldwide demand for oil.



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The trends in spot prices of WTI crude oil and Henry Hub natural gas, and the resulting trends in domestic land rig counts (per Baker Hughes) and domestic well servicing rig counts (per Guiberson/Association of Energy Service Companies) over the last three fiscal years.years are illustrated in the graphs below.
a3yrspotpricesandrigcountq45.jpg
Total Revenue
Percentage
Year ended December 31, 2017
Apache Corporation7.5%
Extraction Oil & Gas, LLC6.4%
Whiting Petroleum Corporation6.3%
Year ended December 31, 2016
Apache Corporation11.9%
Whiting Petroleum Corporation10.1%
PDC Energy, Inc4.4%
Year ended December 31, 2015
Whiting Petroleum Corporation17.8%
Ecopetrol6.1%
Apache Corporation4.6%
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 the services our industry provides. Enhanced directional and horizontal drilling techniques have allowed exploration and production operators to drill increasingly longer lateral wellbores which enable higher hydrocarbon production per well and reduce the overall number of wells needed to achieve the desired production. The trend in our industry toward fewer, but longer, lateral wellbores has led to an overall reduction in drilling and completion activity and demand for the equipment in our industry that is more heavily weighted toward the more specialized equipment available, such as high-spec drilling rigs, higher horsepower well servicing rigs equipped with taller masts, larger diameter coiled tubing units, and other higher power ancillary equipment, which is needed to drill, complete, and provide services to the full length of the wellbore. Our domestic drilling and production services fleets are highly capable and designed for operation in today’s long lateral, pad-oriented environment.
For additional information concerning the potential effects of volatility in oil and gas prices and other industry trends, see Item 1A – “Risk Factors” in Part I and in the section entitled “Market Conditions and Outlook” in Part II, Item 7 of this Annual Report on Form 10-K.
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



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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 price is generally the primary factor, we believe our clients consider all of these factors price is generally the primary factor in determining which service provider is awarded the work. However, we believework, and 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,Helmerich & Payne, Inc., Nabors Industries Ltd., Weatherford International plc, Petrex S.A., Independence Drilling S.A., Erazo Valencia S.A., Tuscany International Drilling 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 primarily compete with are Key Energy Services, Basic Energy Services, C&J EnergyNexTier Oilfield Services, Superior Energy Services, and Forbes Energy Services.Services and Ranger Energy Services, Inc. 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 GR Energy Services, Allied-Horizontal Wireline Services, Renegade Services, C&J EnergyNexTier Oilfield Services, Nine Energy Services, and Quintana Energy Services. Additional competitors include Baker Hughes Company, 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 whichthat increased the numbervariety 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 EnergyNexTier Oilfield Services, Superior Energy Services, Key Energy Services, Schlumberger Ltd., Halliburton Company, Quintana Energy Services and RPC, Inc.



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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;
better attract and 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.”
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 two fiscal years.
Total Revenue
Percentage
Year ended December 31, 2019
Apache Corporation7.1%
Continental Resources, Inc.5.7%
Gran Tierra Energy, Inc.5.6%
Year ended December 31, 2018
Gran Tierra Energy, Inc.8.1%
Apache Corporation5.9%
QEP Energy Company5.8%
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, holidays, and early exhaustion of our clients’ budgets. While 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.
Employees
We currently have approximately 2,100 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. Additionally, we may experience employee attrition as a result of the Chapter 11 Cases. If we should suffer any material loss of personnel 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 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.



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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

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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,clients and could substantially lengthen the delivery times for equipment and supplies can be substantially longer.supplies. 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 suppliesclients and could delay and adversely affect our ability to obtain new contracts for our rigs, whichrigs. Any of the above could have a material adverse effect on our financial condition and results of operations.
Facilities
Our operations are headquartered in San Antonio, Texas and we conduct our business operations through 25 regional offices located throughout the United States in Texas, Oklahoma, Colorado, North Dakota, Pennsylvania, Wyoming, Mississippi, Louisiana and Kansas, and internationally in Colombia. These operating locations typically include leased real estate properties which are used for regional offices, storage and maintenance yards and employee housing sufficient to support our operations in the area. We own 10 real estate properties associated with our regional 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$750,000 per drilling rig and a deductible on production services equipment of $100,000$250,000 per occurrence.occurrence, with an additional $350,000 annual aggregate deductible. Our third-party liability insurance coverage is $101$101 million per occurrence and in the aggregate, with a deductible of $250,000$250,000 per occurrence and an additional $250,000 annual aggregate deductible. We also carry insurance coverage for pollution liability up to $20$20 million with a deductible of $500,000.$500,000. We believe that we are adequately insured for public liability and property damage to others with



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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

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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

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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



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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.
Worker safety. Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits. An accident or other event resulting in significant environmental or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local authorities. Such an accident or other event could cause us to incur substantial expenses in connection with the investigation, remediation and resolution, as well as cause lasting damage to our reputation, loss of customers and an inability to obtain insurance.
Available Information
Our Websitewebsite 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 Websitewebsite 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 Websitewebsite our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Business Conduct and Ethics; Rules of Conduct Applicable to All Employees; Corporate Governance Guidelines; and Company Contact Information. Information on our website is not incorporated into this report or otherwise made part of this report.



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ITEM 1A.
RISK FACTORS
The information set forth in this Item 1A should be read in conjunction with the rest of the information included in this report, including “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and the financial statements and related notes this report contains. While we attempt to identify, manage and mitigate risks and uncertainties associated with our business to the extent practical under the circumstances, some level of risk and uncertainty will always be present. Additional risks and uncertainties that are not presently known to us or that we currently believe are immaterial also may negatively impact our business, financial condition or operating results.
Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operations and cash flows.
Risks Relating to Our Chapter 11 Proceedings
On March 1, 2020, Pioneer Energy Services and certain of its U.S. subsidiaries filed voluntary petitions commencing the Chapter 11 Cases under the Bankruptcy Code. The Chapter 11 Cases and the Restructuring may have a material adverse impact on our business, financial condition, results of operations, and cash flows. In addition, the Chapter 11 Cases and the Restructuring may have a material adverse impact on the trading price of our common stock and ultimately are expected to result in the cancellation and discharge of our securities, including our common stock. The Plan governs distributions to and the recoveries of holders of our securities.
In 2019, we engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness in private transactions. These restructuring efforts led to the execution of the RSA and commencement of the Chapter 11 Cases in the Bankruptcy Court on March 1, 2020.
The Chapter 11 Cases could have a material adverse effect on our business, financial condition, results of operations and liquidity. Bankruptcy Court protection also may make it more difficult to retain management and the key personnel necessary to the success and profitability of our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our clients and suppliers might lose confidence in our ability to reorganize our business successfully and may seek to establish alternative commercial relationships.
Other significant risks include or relate to the following:
our ability to obtain the Bankruptcy Court’s approval with respect to motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases, including maintaining strategic control as debtor-in-possession;
delays in the Chapter 11 Cases;
our ability to consummate the Plan;
our ability to achieve our stated goals and continue as a going concern;
the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents, including our shareholders, clients, suppliers, service providers, and employees;
the high costs of bankruptcy proceedings and related advisory costs to effect our reorganization;
our ability to maintain relationships with clients, suppliers, service providers, employees and other third parties as a result of the Chapter 11 Cases;
our ability to maintain contracts that are critical to our operations;
our ability to fund and execute our business plan;
our ability to obtain acceptable and appropriate financing;
Bankruptcy Court rulings in the Chapter 11 Cases as well as the outcome of the Chapter 11 Cases in general;
the length of time that we will operate with Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;
our ability to confirm and consummate a plan of reorganization with respect to the Chapter 11 Cases, views and objections of creditors and other parties in interest that may make it difficult to consummate a plan in a timely manner;



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the ability of third parties to seek and obtain Bankruptcy Court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization, to appoint a U.S. trustee or to convert the Chapter 11 Cases to cases under Chapter 7 of the Bankruptcy Code (“Chapter 7”);
third-party motions in the Chapter 11 Cases, which may interfere with our ability to consummate the Plan; and
the potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations.
Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.
Delays in the Chapter 11 Cases may increase the risks of our being unable to reorganize our business and emerge from bankruptcy and may increase our costs associated with the bankruptcy process.
The RSA contemplates the consummation of the Plan through an orderly prepackaged plan of reorganization, but there can be no assurance that we will be able to consummate the Plan. A prolonged Chapter 11 proceeding could adversely affect our relationships with clients, suppliers, service providers, and employees, among other third parties, which in turn could adversely affect our business, competitive position, financial condition, liquidity and results of operations and our ability to continue as a going concern. A weakening of our financial condition, liquidity and results of operations could adversely affect our ability to implement the Plan (or any other plan of reorganization). If we are unable to consummate the Plan, we may be forced to liquidate our assets.
In addition, the occurrence of the effective date of the Plan is subject to certain conditions and requirements that may not be satisfied or waived.
The Plan may not become effective.
The Plan may not become effective because it is subject to the satisfaction of certain conditions precedent (some of which are beyond our control). There can be no assurance that such conditions will be satisfied or waived and, therefore, that the Plan will become effective and that we will emerge from the Chapter 11 Cases as contemplated by the Plan. If the effective date of the Plan is delayed, we may not have sufficient cash available to operate our business. In that case, we may need new or additional post-petition financing, which may increase the cost of consummating the Plan. There is no assurance of the terms on which such financing may be available or if such financing will be available. If the transactions contemplated by the Plan are not completed, it may become necessary to amend the Plan. The terms of any such amendment are uncertain and could result in material additional expense and result in material delays to the Chapter 11 Cases.
We may not be able to obtain Bankruptcy Court confirmation of the Plan or may have to modify the terms of the Plan.
Even if the Plan is approved by each class of holders of claims and interests entitled to vote (a “Voting Class”), the Bankruptcy Court, which, as a court of equity, may exercise substantial discretion and may choose not to confirm the Plan. Bankruptcy Code Section 1129 requires, among other things, a showing that confirmation of the Plan will not be followed by liquidation or the need for further financial reorganization for us, and that the value of distributions to dissenting holders of claims and interests will not be less than the value such holders would receive if we, the debtors, liquidated under Chapter 7 of the Bankruptcy Code. Although we believe that the Plan will satisfy such tests, there can be no assurance that the Bankruptcy Court will reach the same conclusion.
Confirmation of the Plan will also be subject to certain conditions. These conditions may not be met and there can be no assurance that the Consenting Creditors will agree to modify or waive such conditions. Further, changed circumstances may necessitate changes to the Plan. Any such modifications could result in less favorable treatment than the treatment currently anticipated to be included in the Plan based upon the agreed terms of the RSA. Such less favorable treatment could include a distribution of property (including the new common stock) to the class affected by the modification of a lesser value than currently anticipated to be included in the Plan or no distribution of property whatsoever under the Plan. Changes to the Plan may also delay the confirmation of the Plan and our emergence from bankruptcy, which could result in, among other things, incurred costs and expenses to the estates of the debtors.



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Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and continue as a going concern.
Even if the Plan, or any other plan of reorganization, is consummated, we may continue to face a number of risks, such as further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our services and increasing expenses. Accordingly, we cannot guarantee that the Plan, or any other plan of reorganization, will achieve our stated goals.
Furthermore, even if our debts are reduced through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms.
The Plan or another plan of reorganization that we may implement will be based upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, we may not be able to successfully execute such plan.
The Plan or any other plan of reorganization that we may implement will affect both our capital structure and the ownership, structure and operation of our business and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (i) our ability to substantially change our capital structure; (ii) our ability to obtain adequate liquidity and financing sources; (iii) our ability to maintain clients’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them; (iv) our ability to retain key employees, and (v) the overall strength and stability of general economic conditions and conditions of the oil and gas industry. The failure of any of these factors could materially adversely affect the successful reorganization of our business.
In addition, the Plan or any other plan of reorganization, will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. In our case, the forecasts are even more speculative than normal, because they involve fundamental changes in the nature of our capital structure. Accordingly, we expect that our actual financial condition and results of operations will differ, perhaps materially, from what we have anticipated. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us or our business or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of our plan of reorganization.
Our cash flows may not provide sufficient liquidity during the Chapter 11 Cases. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.
Our ability to fund our operations and our capital expenditures requires a significant amount of cash. Our current principal sources of liquidity include the available borrowing capacity under our DIP Facility and cash flow generated from operations. If our cash flow from operations decreases, we may not have the ability to expend the capital necessary to maintain or improve our current operations, negatively impacting our future revenues.
We face uncertainty regarding the adequacy of our liquidity and capital resources and have limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. Although we expect the Chapter 11 Cases to be completed as quickly as 60 days based on the milestones in the RSA, we may not be able to comply with the covenants of our DIP Facility and our cash on hand and cash flow from operations may not be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 Cases until we are able to emerge from the Chapter 11 Cases.
Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of our DIP Facility agreements, (ii) our ability to comply with



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the terms and conditions of any cash collateral order that may be entered by the Bankruptcy Court in connection with the Chapter 11 Cases, (iii) our ability to maintain adequate cash on hand, (iv) our ability to generate cash flow from operations, (v) our ability to confirm and consummate the Plan or other alternative restructuring transaction and (vi) the cost, duration and outcome of the Chapter 11 Cases.
We may be unable to comply with restrictions or with budget, liquidity, or other covenants imposed by the agreements governing our DIP Facility. Such non-compliance could result in an event of default under the terms of the DIP Facility that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.
Covenants of the DIP Facility will include general affirmative covenants, as well as negative covenants such as prohibiting us from incurring or permitting debt, investments, liens or dispositions unless specifically permitted. Our ability to comply with these provisions may be affected by events beyond our control and our failure to comply, or obtain a waiver in the event we cannot comply with a covenant, could result in an event of default under the DIP Facility and permit the lenders thereunder to accelerate the loans and otherwise exercise remedies allowable by the agreements governing the DIP Facility.
Termination of our exclusive right to file a Chapter 11 plan and the exclusive right to solicit acceptances could result in competing plans of reorganization, which could have less favorable terms or result in significant litigation and expenses.
We currently have the exclusive right to file a Chapter 11 plan through June 28, 2020, and the exclusive right to solicit acceptances of any such plan through August 28, 2020. Such deadlines may be extended from time to time “for cause” (as permitted by section 1121(d) of the Bankruptcy Code) with the approval of the Bankruptcy Court. However, it is also possible that (a) parties in interest could seek to shorten or terminate such exclusive plan filing and solicitation periods “for cause” (as permitted by section 1121(d) of the Bankruptcy Code) or (b) that such periods could expire without extension.
Although we expect the Chapter 11 Cases to be completed as quickly as 60 days based on the milestones in the RSA, if our exclusive plan filing and solicitation periods expire or are terminated, other parties in interest will be permitted to file alternative plans of reorganization. An alternative plan of reorganization could contemplate us continuing as a going concern, us being broken up, us or our assets being acquired by a third party, us being merged with a competitor, or some other proposal. There can be no assurances that recoveries under any such alternative plan would be as favorable to creditors as the Plan. In addition, the proposal of competing plans of reorganization may entail significant litigation and significantly increase the expenses of administration of the Chapter 11 Cases, which could deplete creditor recoveries under any plan.
As a result of the Chapter 11 Cases, our historical financial information may not be indicative of our future performance, which may be volatile.
During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the filing of the Chapter 11 Cases. In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to our historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to the Plan. We expect we will be required to adopt the fresh start accounting rules, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets and our financial results after the application of fresh start accounting may be different from historical trends.
Trading in our securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks. The Plan will result in the cancellation of our common stock.
Under the Plan, all existing equity interests in the Company will be extinguished, although holders of equity interests will be receiving some recovery under the Plan if the class of equityholders votes in favor of the Plan. Amounts invested by the holders of our common stock will not be recoverable and such securities will have no value. Trading prices for



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our common stock bear no relationship to the actual recovery, if any, by the holders thereof in the Chapter 11 Cases. Accordingly, we urge extreme caution with respect to existing and future investments in our existing common stock.
If the RSA is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.
The RSA contains a number of termination events, upon the occurrence of which certain parties to the RSA may terminate the agreement. If the RSA is terminated as to all parties thereto, each of the parties thereto will be released from its obligations in accordance with the terms of the RSA. Such termination may result in the loss of support for the Plan by the parties to the RSA, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated, there can be no assurance that the Chapter 11 Cases would not be converted to Chapter 7 liquidation cases or that any new Plan would be as favorable to holders of claims against the Pioneer RSA Parties as contemplated by the RSA.
In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.
Upon a showing of cause, the Bankruptcy Court may convert the Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in the Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of executory contracts in connection with a cessation of operations.
We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.
The Bankruptcy Court provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to consummation of a plan of reorganization. With few exceptions, all claims that arose prior to March 1, 2020 or before consummation of the Plan (i) would be subject to compromise and/or treatment under the Plan and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the Plan. Any claims not ultimately discharged pursuant to the Plan could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.
The Chapter 11 Cases limit the flexibility of our management team in running our business.
While we operate our business as debtor-in-possession under supervision by the Bankruptcy Court, we are required to obtain the approval of the Bankruptcy Court and, in some cases, the Consenting Creditors, prior to engaging in activities or transactions outside the ordinary course of business. Bankruptcy Court approval of non-ordinary course activities entails preparation and filing of appropriate motions with the Bankruptcy Court, negotiation with the creditors’ committee (if any) and other parties-in-interest and one or more hearings. The creditors’ committees and other parties-in interest may be heard at any Bankruptcy Court hearing and may raise objections with respect to these motions.
This process may delay major transactions and limit our ability to respond in a timely manner to adapt to changing market or industry conditions or to take advantage of certain opportunities. Furthermore, in the event the Bankruptcy Court does not approve a proposed activity or transaction, we would be prevented from engaging in activities and transactions that we believe to be beneficial to us.
The commencement of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management and will impact how our business is conducted, which may have an adverse effect on our business and results of operations.
The requirements of the Chapter 11 Cases have consumed and will continue to consume a substantial portion of our management’s time and attention and leave them with less time to devote to the operation of our business. This diversion of attention may materially adversely affect the conduct of our business and, as a result, our financial condition and results of operations.



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We may experience employee attrition as a result of the Chapter 11 Cases.
As a result of the Chapter 11 Cases, we may experience employee attrition, and our employees may face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which could have a material adverse effect on our financial condition, liquidity and results of operations.
On the effective date of the Plan, the composition of our board of directors will change substantially.
Under the Plan, the composition of our board of directors will change substantially. Pursuant to the Plan, our new board of directors will be appointed by the required consenting noteholders under the RSA in consultation with our management, and the numbers of directors will also be determined by the required consenting noteholders. Our Chief Executive Officer will be a member of the board of directors. Accordingly, almost all of our board members will be new to the Company. Any new directors are likely to have different backgrounds, experiences and perspectives from those individuals who previously served on the board of directors and, thus, may have different views on the issues that will determine our future. As a result, our future strategy and plans may differ materially from those of the past.
Adverse publicity in connection with the Chapter 11 Cases or otherwise could negatively affect our businesses.
Adverse publicity or news coverage relating to us, including, but not limited to, publicity or news coverage in connection with the Chapter 11 Cases, may negatively impact our efforts to establish and promote name recognition and a positive image after emergence from the Chapter 11 Cases.
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 or global health concerns, including the outbreak of contagious or pandemic diseases, such as the recent coronavirus;
domestic and foreign tax policy;
weather conditions in the United States and elsewhere;



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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.

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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.
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 OctoberIn late 2014, oil prices worldwide dropped significantly. Ourbegan to drop significantly and as a result, our clients significantly reduced both their operating and capital expenditures during 2015 and 2016, which adversely affected our business. In 2017 and 2018, our clients modestly increased their spending as compared to 2016 levels, and we expect continued increasesour business trended upward as a result. However, in 2018. However, if thelate 2018, oil and natural gas prices again began to decline and despite some improvement in early 2019, have since languished without significant improvement. As a result, oil and gas exploration and production companies may cancel or curtailhave continued to limit their drilling programs and further reduce production spending on existing wells, thereby reducing demand for our services.
Additionally, because our business depends on the level of spending by our clients, we are also affected by our clients’ ability to access the capital markets. After several consecutive years without significant improvement in commodity prices, many exploration and production companies have limited their spending to a level which can be supported by net operating cash flows alone, as access to the capital markets through debt or equity financings has become more challenging in our industry.
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;fleets;
our ability to maintain or increase our borrowing capacity;obtain additional debt financing;
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 rigsour equipment and services or an increase in the supply of drilling rigs, whether through new constructioncomparable equipment in our industry or refurbishment, couldany particular regional market would likely decrease the dayratespricing and utilization rates for our drilling services,affected service offerings, which would adversely affect our revenues and profitability. An increaseThe continuing trend toward longer lateral wellbores and the enhanced efficiency of the equipment in supplyour industry, in combination with current commodity prices and more disciplined spending by exploration and production companies, has contributed to an oversupply of well servicing rigs, wireline unitsequipment in our industry, declining rig counts and coiled tubing units, without a corresponding increase in demand, could similarly decrease the pricingdayrates, and utilization rates of our production services, which would adversely affect our revenues and profitability.reduced completion activity.
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



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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;

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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;
better attract and 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 inthe services our industry.industry provides.
Technological advancements and trends in our industry also affect the demand for certain types of equipment, and can affect the overall demand for the services our industry provides. Enhanced directional and horizontal drilling techniques have allowed exploration and production operators to drill increasingly longer lateral wellbores which enable higher hydrocarbon production per well and reduce the overall number of wells needed to achieve the desired production. The trend in our industry toward fewer, but longer, lateral wellbores has led to an overall reduction in drilling and completion activity and demand for the equipment in our industry. For several years, prior to late 2014, higher oil prices drove industry that is more heavily weighted toward the more specialized equipment utilization and revenue rates up, particularly in oil-producing regions and certain shale regions. However, advancements in technology improved the efficiency ofavailable, such as high-spec drilling rigs, and overall demand remained steady, while the demand for certain drilling rigs decreased, particularly in verticalhigher horsepower 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 drillingservicing rigs equipped with either a walking or skidding system aretaller masts, larger diameter coiled tubing units, and other higher power ancillary equipment, which is needed to drill, complete, and provide services to the best suited for horizontal padfull length of the wellbore.
Our domestic drilling and we believe theyproduction services fleets are the most desirable rig design available.
highly capable and designed for operation in today’s long lateral, pad-oriented environment. Although we take measures to ensure that we use advanced technologies for drilling and production services equipment, changes in technology or improvements in our competitors’ equipment could make our equipment less competitive or require significant capital investments to keep our equipment competitive, which could have an adverse effect on our financial condition and operating results.



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We derive a significant portion of our revenue from a limited number of major clients, and our business, financial condition and results of operations could be materially adversely affected if we are unable to maintain relationships with these clients, or if their demand for our services decreases.
In the past,Historically, we have derived a significant portion of our revenue from a limited number of major clients. For the years ended December 31, 2017, 20162019 and 20152018, our drilling and production services to our top three clients accounted for approximately 20%, 26%,18% and 29%20%, 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 threetwo fiscal years, see Item 1—“Business” in Part I of this Annual Report on Form 10-K.

Certain of our contracts are subject to cancellation by our clients without penalty and/or with little or no notice.
16Some of our current drilling contracts, and some drilling contracts that we may enter into in the future, may include terms allowing our clients to terminate the contracts without cause, with little or no prior notice and/or without penalty or early termination payments. The likelihood that a client may seek to terminate a contract is increased during periods of market weakness.



Our indebtedness could restrictIn periods of extended market weakness, our operationsclients may not be able to honor the terms of existing contracts, may terminate contracts even where there may be onerous termination fees, or may seek to renegotiate contract dayrates and make us more vulnerable to adverse economicterms in light of depressed market conditions.
Our indebtedness is primarily During depressed market conditions, as a result of commodity prices, restricted credit markets, economic downturns, changes in priorities or strategy or other factors beyond our control, a client may no longer want or need a drilling rig that is currently under contract or may be able to obtain a comparable drilling rig at a lower dayrate. For these reasons, clients may seek to renegotiate 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 areasterms of our business because we must dedicate a substantial portion of these fundsexisting drilling contracts, terminate our contracts without justification, leverage their termination rights in an effort 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 reasonablerenegotiate contract 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 withperform their obligations under our contracts.
Our clients may also seek to terminate contracts for cause, such as the various covenantsloss of or major damage to the drilling unit or other events that cause the suspension of drilling operations beyond a specified period of time. If we experience operational problems or if our equipment fails to function properly and cannot be repaired promptly, our clients will not be able to engage in our Term Loan, ABL Facility,drilling operations and Senior Notes, we could bemay have the right to terminate the contracts. If equipment is not timely delivered to a client or does not pass acceptance testing, a client may in default undercertain circumstances have the terms of such instruments. right to terminate the contract.
In the event of a default, our lenders could elect to declare allcancellation, 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 wepayment of a termination fee may not fully compensate us for the loss of the contract. Additionally, the early termination of a contract may result in a drilling rig or oneother equipment being idle for an extended period of time. The cancellation or morerenegotiation of a number of our subsidiaries could be forced into bankruptcy or liquidation. Any of the foregoing consequencescontracts 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,revenues 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.profitability.
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.



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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. Additionally, trade and economic sanctions or other restrictions imposed by the United States or other countries could also affect the supply of equipment and supplies which are needed in our operations. 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,clients and could substantially lengthen the delivery times for equipment and supplies can be substantially longer.supplies. 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 suppliesclients and could delay and adversely affect our ability to obtain new contracts for our rigs, whichrigs. Any of the above 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 providingprovide 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. ShortagesFrom time to time, shortages of qualified personnel have occurred in our industry. Additionally, we may experience employee attrition as a result of the Chapter 11 Cases. 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;
taxation;
the inability to repatriate earnings or capital due to laws limiting the right and ability of foreign subsidiaries to pay dividends and remit earnings to affiliated companies;
changing political conditions and changing laws and policies affecting trade and investment;
trade and economic sanctions or other restrictions imposed by the United States or other countries;
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;



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the risks associated with any lack of compliance with the Foreign Corrupt Practices Act of 1977 (“FCPA”) or other anti-corruption laws;
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“Navigable Waters of the United States rule, which may be rescinded pursuant to a proposalProtection Rule” issued in June 2017)on January 23, 2020); 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



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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 certain hazardous substances into the environment. These persons generally 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)2°C (36°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 AugustNovember 4, 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 allowance trading is now comprisedlimited to only California and Quebec, with a separate trading program administered for the province of California, British Columbia, Manitoba, Ontario, and Quebec.Nova Scotia.
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 Subsequently, the EPA adopted two setshas a number of climate change 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 gascontrol and 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 monitoringsources, fuel economy standards for vehicles and reporting of greenhouse gases from certain sources, including, among others, onshore oil and natural gas production facilities.emissions standards for power plants.
In April 2012, the EPA issued regulations specifically applicableSpecific to the oil and gas industry, that require operatorsin April 2012, the EPA issued regulations 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. In March 2018, the EPA finalized two minor amendments to the rule but also announced that it is continuing to examine other rule issues.



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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.
Oil and gas development restrictions are also possible due to voter initiatives. For example, in 2018, Colorado voted on Proposition 112, which would have increased drilling location setbacks from 500 feet to 2,500 feet, severely limiting access to oil and gas minerals. Although Proposition 112 was defeated, future voter initiatives are possible in certain jurisdictions. For example, at least six oil and gas ballot initiatives have already been submitted for Colorado’s November ballot with some that are similar to Proposition 112 from 2018. Further, state legislators and regulators could seek to impose similar restrictions.
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.
Worker safety. Our ability to retain existing customers and attract new business is dependent on many factors, including our ability to demonstrate that we can reliably and safely operate our business in a manner that is consistent with applicable laws, rules and permits. An accident or other event resulting in significant environmental or property damage, or injuries or fatalities involving our employees or other persons could also trigger investigations by federal, state or local authorities. Such an accident or other event could cause us to incur substantial expenses in connection with the investigation, remediation and resolution, as well as cause lasting damage to our reputation, loss of customers and an inability to obtain insurance.



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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 has since rescinded much of the BLM rescinded this2016 rule, but there may be litigation to reinstatechallenging the rule.replacement rule is pending. 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. PortionsThe BLM has since proposed rescinding portions of the rule and portions of the rule have been suspended until January 2019, but there may bepending the outcome of litigation to reinstateconcerning 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 willwas also be assessingrequired, pursuant to a Consent Decree with environmental groups, to reevaluate whether oil and gas wastes should continue to be exempt from being considered hazardous waste underwastes. Although the federal Resource Conservation and Recovery Act, pursuantEPA concluded in April 2019 that no changes to a Consent Decree with environmental groups approvedthe existing exemption are needed, similar lawsuits could be brought in federal court in December 2016.the future. 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.



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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’clients’ 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.
Future acquisitions or dispositions may not result in the realization of savings and efficiencies, the generation of cash flow or income, or the reduction of risk as contemplated by management, and may have a material adverse effect on our liquidity, results of operations and financial condition.
From time to time and subject to any limitations set forth in our debt financing agreements, we may seek opportunities to maximize efficiency and value through various transactions including the sale of assets or businesses, or the pursuit of acquisitions of complementary assets or businesses. These transactions are subject to inherent risks, including:
the use of capital for acquisitions may adversely affect our cash available for other uses;
unanticipated costs, assumption of liabilities or exposure to unforeseen liabilities of acquired businesses;
difficulties in integrating the operations, assets and employees of the acquired business;
difficulties in maintaining an effective internal control environment over an acquired business;
risks of entering markets in which we have limited prior experience;
decreased earnings, revenues or cash flow resulting from dispositions; and
increases in our expenses and working capital requirements.



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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 fleets 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.
The uncertainty regarding the potential phase-out of LIBOR may negatively impact our operating results.
On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR, the London Interbank Offer Rate, as a benchmark by the end of 2021, when private-sector banks are no longer required to report the information used to set the rate. LIBOR is the basic rate of interest used in lending between banks on the London interbank market and is widely used as a reference for setting the interest rate on loans globally. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. At this time, no consensus exists as to what rate or rates will become accepted alternatives to LIBOR, although the U.S. Federal Reserve is considering replacing U.S. dollar LIBOR with a newly created index called the Broad Treasury Financing Rate, calculated with a broad set of short-term repurchase agreements backed by treasury securities. In the future, we may need to renegotiate our current debt arrangements or incur other indebtedness, and the phase-out of LIBOR may negatively impact the terms of such indebtedness. In addition, the overall financial market may be disrupted as a result of the phase-out or replacement of LIBOR. Disruption in the financial market could have a material adverse effect on our financial position, results of operations, and liquidity.
Risks Relating to Our Capital Resources and Organization
We have a significant amount of debt and despite our current level of indebtedness, we may still be able to incur more debt. Our debt levels and the restrictions imposed on us by our DIP Facility may have significant consequences, including limiting our liquidity and flexibility for successfully operating our business, pursuing business opportunities, and obtaining additional financing.
Prior to our bankruptcy filing, we were a highly leveraged company. At December 31, 2019, our total debt consists of $300 million outstanding under our Senior Notes and $175 million outstanding under our Term Loan. After our expected emergence from bankruptcy, we may continue to have a substantial amount of indebtedness.
Our level of indebtedness could prevent us from engaging in transactions that might otherwise be beneficial to us and could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. Because we may have to dedicate a substantial portion of our operating cash flow to make interest and principal payments, we could be limited in our ability to:
make investments in working capital or capital expenditures;
obtain additional financing that may be necessary to fund or expand our operations; and
withstand and respond to changes or events in our business, our industry or the economy in general.
The incurrence of additional indebtedness could exacerbate the above risks and make it more difficult to satisfy our existing financial obligations.
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 DIP Facility that, among other things, and subject to certain exceptions, limit our ability to:
engage in asset sales or dispositions;
consolidate or merge with another company;



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make certain investments (including acquisitions);
incur or permit liens on assets; and
incur additional debt or equity financing.
The failure to comply with any of these covenants would cause an event of default under our DIP Facility which if not waived, could result in acceleration of the outstanding indebtedness under our DIP Facility, 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.
We may be unable to repay or refinance our debt as it becomes due, whether at maturity or as a result of acceleration.
Our ability to meet our debt service obligations depends on our ability to generate positive cash flows from operations. We have in the past incurred, and may incur in the future, negative cash flows from our operating activities. Our ability to generate positive cash flows in the future will be influenced by:
general industry, economic and financial conditions;
the level of commodity prices in our industry and the level of demand for our services;
competition in the markets where we operate; and
other factors affecting our operations, many of which are beyond our control.
If our business does not generate sufficient cash flow from operations to service our outstanding indebtedness, we may have to undertake alternative financing plans, such as:
refinancing or restructuring our debt;
selling assets;
reducing or delaying capital investments, including maintenance or refurbishment of our equipment; and/or
seeking to raise additional capital.
We may not be able to repay our debt as it comes due, or to refinance our debt on a timely basis or on terms acceptable to us and within the limitations contained in our DIP Facility or our New Revolver when payment obligations are no longer automatically stayed under the provisions of the Bankruptcy Code. Failure to repay or to timely refinance any portion of our debt could result in a default under the terms of all our debt instruments and the acceleration of all indebtedness outstanding.
As of March 1, 2020, we were in default under our Term Loan, Prepetition ABL Facility, and Senior Notes. Filing the Chapter 11 Cases accelerated our Term Loan, Prepetition ABL Facility, and Senior Notes obligations. Additionally, events of default under the credit agreements governing our Term Loan and Prepetition ABL Facility and the indenture governing our Senior notes have occurred and are continuing, including as a result of cross-defaults between such credit agreements and indenture. However, any efforts to enforce such payment obligations are automatically stayed under the provisions of the Bankruptcy Code.
Our current operations and future growth may require significant additional capital, and the amount and terms of our indebtedness could impair our ability to fund our capital requirements. The DIP Facility may be insufficient to fund our cash requirements through emergence from bankruptcy.
Our business requires substantial capital, and we may require additional capital in the event of significant departures from our current business plan, unanticipated maintenance or capital requirements, or to pursue growth opportunities. However, additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in our debt arrangements. Failure to obtain additional financing, should the need for it develop, could impair our ability to fund working capital and capital expenditure requirements and meet debt service requirements, which could have a material adverse impact on our business. Further, for the duration of the Chapter 11 Cases, we will be subject to various additional risks including the inability to maintain or obtain sufficient financing sources for operations, to fund the plan of reorganization and to meet future obligations, including increased legal and other professional costs associated with the Chapter 11 Cases and our reorganization. Further, if the transactions contemplated by the Plan are not completed such that the effective date of the Plan occurs prior to the maturity of the DIP Facility, we may need to refinance the DIP Facility. We may not be able to obtain any such financing on acceptable terms, or at all.



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We expect that our ability to use our net operating losses and certain other tax attributes will be substantially limited as a result of transfers or issuances of our equity in connection with the Chapter 11 Cases.
Our ability to utilize our net operating loss carryforwards and certain other tax credit carryforwards might be limited.
attributes to offset future taxable income and to reduce our U.S. federal income tax liability is subject to certain governing rules and restrictions. Section 382 of the U.S. Internal Revenue Code (“Section 382”) contains rules that limit the ability of a company that undergoes an ownership change“ownership change” to utilize its net operating losses and certain other tax credit carryforwardsattributes existing as of the date of such ownership change. Under the rules,Generally, under Section 382, an “ownership change” is deemed to have occurred if one or more shareholders owning 5% or more of a company’s common stock have aggregate increases in their ownership of such an ownership change is generally any change in ownershipstock of more than 50% over the prior three-year period. Upon experiencing an ownership change, absent any exception allowable under Section 382, the amount of a company’s stock within a rolling three-year period. The rulesnet operating losses and certain other tax attributes that may be utilized to offset future taxable income will generally operate by focusing on changesbe subject to an annual limitation; however, the annual limitation does not limit the ability to use net operating losses in ownership among shareholders owning, directly or indirectly, 5% or moreoffsetting cancellation of indebtedness income pursuant to Section 108 of the stockU.S. Internal Revenue Code.
Following the implementation of our Plan, we expect that an “ownership change” will be deemed to have occurred and, absent any exception allowable under Section 382, our net operating losses and certain other tax attributes will, post-emergence, be subject to substantial annual limitation, which could have a companynegative impact on our financial position and any change in ownership arising from new issuancesresults of stock by the company.
operations. If we were to undergo one or more “ownership changes” as defined by Section 382,additional ownership changes subsequent to our emergence from the Chapter 11 Cases, our ability to use our net operating lossesloss carryforwards and certain other tax attributes may become subject to further limitation.
Our shares of common stock are not listed for trading on a national securities exchange and thus the market for our common stock is limited, sporadic, and volatile which may impact the value of our tax credits existing asshares and your ability to sell your shares.
We are quoted on the OTC Pink marketplace under the trading symbol “PESXQ” and are not traded or listed on a national securities exchange. Investments in securities trading on the OTC Pink marketplace are generally less liquid than investments in securities trading on a national securities exchange. We can provide no assurance that our common stock will continue to trade on the OTC Pink marketplace, whether broker-dealers will continue to provide public quotes of our common stock on the dateOTC Pink marketplace, or whether the trading volume of each ownership changeour common stock will be sufficient to provide for an efficient trading market.
This may result in limited shareholder interest, including that of institutional investors, and it may be unavailable, in wholedifficult for our shareholders to sell their shares, without depressing the market price for our shares, or in part, to offset U.S. federal income tax resulting from our operations or any gains fromat all, which could further depress the disposition of anytrading price of our assets and/common stock. An inactive market or business,depressed trading price could also impair our ability to raise capital by selling shares of our common stock and thus impair our ability to enter into strategic transactions which could resultotherwise have been executed using shares of our common stock as consideration. In addition, the trading of our common stock on the OTC Pink marketplace could have other negative implications, including the potential loss of confidence in increased U.S. federal income tax liability.us by suppliers, clients and employees.
Risks RelatingThere can be no assurance that any public market for our new common stock will exist in the future or that we will be able to Our Capitalization and Organizational Documentsobtain a listing of our new common stock on the New York Stock Exchange (NYSE) or the OTC Markets.
If we are unable to obtain a listing for our new common stock on the NYSE, we will instead seek to have our new common stock quoted on the OTC Markets until such time as we are able to obtain a NYSE listing for our new common stock. However, we may not be successful in obtaining a listing of our new common stock. Furthermore, even if our new common stock is approved for listing on the NYSE or is traded on the OTC Markets, we are not certain that any trading market will develop or, if it develops, whether such trading market will be sustained.



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We do not intend to pay dividends on our new common stock in the foreseeable future, and therefore only appreciation of the price of our new common stock will provide a return to our shareholders.
We havedo not paidintend to pay or declareddeclare any dividends on our new 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, ABLDIP Facility and Senior Notes.any other debt arrangements. Our debt arrangements includeDIP Facility includes provisions that generally prohibit us from paying dividends on our capital stock, including our new common stock.

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We may issue preferred stock whose terms could adversely affect the voting power or value of our new 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 new 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.debt arrangements. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our new 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 theour new 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.
If we implement an enterprise resource planning system, such implementation could expose us to certain risks commonly associated with the conversion of existing data and processes to a new system.
We are currently in the evaluation phase of implementing a company-wide enterprise resource planning (ERP) system to upgrade, replace and integrate certain existing business, operational and financial processes and systems, upon which we rely. ERP implementations are expensive, complex and time-consuming projects that require transformations of business and finance processes in order to reap the benefits of an integrated ERP system. Due to our liquidity issues, we may not have sufficient funds to implement the ERP system. Additionally, any such project involves certain risks inherent in the conversion, including loss of information and potential disruption to normal operations and finance functions. Additionally, if the ERP system is not effectively implemented as planned, or the system does not operate as intended, the effectiveness of our internal control over financial reporting could be adversely affected or our ability to assess those controls adequately could be delayed. In addition, if we experience interruptions in service or operational difficulties and are unable to effectively manage our business during or following the implementation of the ERP system, our business and results of operations could be adversely impacted.



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ITEM 1B.UNRESOLVED STAFF COMMENTS
Not applicable.

ITEM 2.PROPERTIES
Our principal executive offices are located at 1250 N.E. Loop 410, Suite 1000, San Antonio, Texas 78209. For a description of our significant properties, see “Business—General”Company Overview and “Business—Facilities”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 and adequate for their intended use.

ITEM 3.LEGAL PROCEEDINGS
Due to the nature of our business, we are, fromFrom time to time, we are involved in routine litigation or subject to disputes or claims related toarising out of 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.operations or cash flows. For information on Legal Proceedings, see Note 13, Commitments and Contingencies, 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.
On March 1, 2020, the Pioneer RSA Parties filed a voluntary petition under chapter 11 of the United States Bankruptcy Code. For information on the Chapter 11 Cases, see “Business—Recent Developments” in Item 1 of this Annual Report on Form 10-K.

ITEM 4.MINE SAFETY DISCLOSURES
Not applicable.


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PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock previously traded on the New York Stock Exchange (NYSE) under the symbol “PES.” As a result of our abnormally low trading price levels, the NYSE delisted our common stock on August 14, 2019. Our common stock subsequently traded on the OTC Markets under the symbol “PESX” until March 3, 2020, at which time, due to our voluntary filing of the Chapter 11 Cases, our common stock commenced trading on the OTC Pink marketplace under the trading symbol “PESXQ”. Any over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.
As of January 31, 2018,February 28, 2020, 77,794,52779,579,571 shares of our common stock were outstanding, held by 300285 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 Quarter1.70
 4.50
Third Quarter1.60
 2.65
Fourth Quarter1.70
 3.20
    
Year ended December 31, 2016   
First Quarter$0.95
 $2.46
Second Quarter1.98
 5.05
Third Quarter2.64
 4.89
Fourth Quarter3.35
 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 andlaws. Additionally, 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, 2017.2019. 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.

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Performance Graph2019.
The following graph compares, forAs discussed in “Business—Recent Developments” in Item 1 of this Annual Report on Form 10-K, in connection with the periods from December 31, 2012 to December 31, 2017, the cumulative total shareholder return onChapter 11 Cases, our common stock with the cumulative total returnwill be extinguished without recovery 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. Twoeffective date 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 Plan.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.



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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 activities118,635
 15,670
 (61,827) (73,584) (20,252)
Capital expenditures61,447
 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, net549,623
 584,080
 702,585
 856,541
 937,657
Long-term debt, excluding current portion, debt issuance costs and discount475,000
 346,000
 395,000
 455,053
 499,666
Shareholders’ equity210,096
 281,398
 342,643
 495,064
 518,433
Total assets766,869
 700,102
 821,975
 1,171,589
 1,229,623
Not applicable.

(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

35



ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements made in good faith that are subject to risks, uncertainties and assumptions. These forward-looking statements are based on our current beliefs, intentions, and expectations and are not guarantees or indicators of future performance. 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 risks related to our ability to obtain the Bankruptcy Court’s approval with respect to motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases, including maintaining strategic control as debtor-in-possession, and the outcomes of Bankruptcy Court rulings and the Chapter 11 Cases in general, delays in the Chapter 11 Cases, our ability to consummate the Plan, our ability to achieve our stated goals and continue as a going concern, risks that our assumptions and analyses in the Plan are incorrect, our ability to fund our liquidity requirements during the Chapter 11 Cases, our ability to comply with the covenants under our DIP Facility, the effects of the filing of the Chapter 11 Cases on our business and the interest of various constituents, the actions and decisions of creditors, regulators and other third parties that have an interest in the Chapter 11 Cases, restrictions imposed on us by the Bankruptcy Court, 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 unitsequipment within the industry, the continued availability of new components for drilling rigs, well servicing rigs, coiled tubing units and wireline units,our fleets, 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.environment, the occurrence of cybersecurity incidents, the success or failure of future dispositions or acquisitions, future compliance with our debt agreements, and the impact of not having our common stock listed on a national securities exchange. We have discussed many of these factors in more detail elsewhere in this report, and, including under the headings “Risk Factors” in Item 1A and “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A.I. 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.



36



Recent Developments
Reorganization, Chapter 11 Proceedings, and Going Concern
In an effort to achieve liquidity that would be sufficient to meet all of our commitments, we have undertaken a number of actions, including minimizing capital expenditures and reducing recurring expenses. However, we believe that even after taking these actions, we will not have sufficient liquidity to satisfy all of our future financial obligations, comply with our debt covenants, and execute our business plan. As a result, the Pioneer RSA Parties filed a petition for reorganization under Chapter 11 of the Bankruptcy Code on March 1, 2020.
As a result of the commencement of the Chapter 11 Cases on March 1, 2020, we are operating as a debtor-in-possession pursuant to the authority granted under Chapter 11 of the Bankruptcy Code. Pursuant to the Chapter 11 Cases, we intend to significantly de-leverage our balance sheet and reduce overall indebtedness upon completion of that process. Additionally, as a debtor-in-possession, certain of our activities are subject to review and approval by the Bankruptcy Court, including, among other things, the incurrence of secured indebtedness, material asset dispositions, and other transactions outside the ordinary course of business. There can be no guarantee that the Chapter 11 Cases will be completed successfully or in the time frame contemplated by the RSA. In connection with the Bankruptcy Petitions, we entered into the RSA with the Consenting Creditors. Pursuant to the RSA, the Consenting Creditors and the Pioneer RSA Parties made certain customary commitments to each other, including the Consenting Noteholders committing to vote for, and the Consenting Creditors committing to support, the Restructuring to be effectuated through the Plan to be proposed by the Pioneer RSA Parties.
The risks and uncertainties surrounding the Chapter 11 Cases, the defaults under our Debt Instruments, and the weak industry conditions impacting our business raise substantial doubt as to our ability to continue as a going concern. Accordingly, the audit report issued by our independent registered public accounting firm contains an explanatory paragraph expressing substantial doubt about our ability to continue as a going concern. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, which contemplate our continuation as a going concern.
For additional information concerning our bankruptcy proceedings under Chapter 11, see Note 2, Going Concern and Subsequent Events,of the Notes to Consolidated Financial Statements included in Part II, Item 8 Financial Statements and Supplementary Data, and Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.
Company Overview

and Business Segments
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 10,12, 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.



37



Drilling Services—Services — Our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. We have 16drilling, with 17 AC rigs in the US and eight8 SCR rigs in Colombia, all ofColombia. We provide a comprehensive service offering which have 1,500 horsepower or greater drawworks. In addition to our drilling rigs, we provideincludes the drilling rig, crews, supplies, and most of the ancillary equipment needed to operate our drilling rigs.

30




The drilling rigs, in our fleetwhich are currently deployed through our division offices in the following regions:
  Rig Count
Domestic drillingdrilling:  
Marcellus/Utica 6
Eagle Ford15
Permian Basin and Eagle Ford 710
Bakken 2
International drilling 8
  2425
Production Services—Services — Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of explorationproducers primarily in Texas and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain statesregions, as well as in North Dakota, Louisiana and in the Gulf Coast, both onshore and offshore.
Mississippi. As of December 31, 2017,2019, the fleet count and compositioncounts for each of our production services business segments isare as follows:
550 HP600 HPTotal550 HP 600 HP Total
Well servicing rigs, by horsepower (HP) rating113
12
125
112 12 124
  
OffshoreOnshoreTotal Total
Wireline services units4
108112
Wireline services units 93
Coiled tubing services units4
10
14
Coiled tubing services units 9
Market Conditions in Our Industryand Outlook
Industry Overview — Demand for oilfield services offered by our industry is a function of our clients’ willingness and ability 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 shiftchange 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 relatedproduction-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.
The level of exploration and production activity within a region can fluctuate due to a variety of factors which may directly or indirectly impact our operations in the region. From time to time, temporary regional slowdowns or constraints occur in our industry due to a variety of factors, including, among others, infrastructure or takeaway capacity limitations, labor shortages, increased regulatory or environmental pressures, or an influx of competitors in a particular region. Any of these



38



factors can influence the profitability of operations in the affected region. However, term contract coverage for our drilling services business and the mobility of all our equipment between regions reduces our exposure to the impact of regional constraints and fluctuations in demand.
Additionally, because our business depends on the level of spending by our clients, we are also affected by our clients’ ability to access the capital markets. After several consecutive years without significant improvement in commodity prices, many exploration and production companies have limited their spending to a level which can be supported by net operating cash flows alone, as access to the capital markets through debt or equity financings has become more challenging 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 the services our industry provides. Enhanced directional and horizontal drilling techniques have allowed exploration and production operators to drill increasingly longer lateral wellbores which enable higher hydrocarbon production per well and reduce the overall number of wells needed to achieve the desired production. The trend in our industry toward fewer, but longer, lateral wellbores has led to an overall reduction in drilling and completion activity and demand for the equipment in our industry that is more heavily weighted toward the more specialized equipment available, such as high-spec drilling rigs, higher horsepower well servicing rigs equipped with taller masts, larger diameter coiled tubing units, and other higher power ancillary equipment, which is needed to drill, complete, and provide services to the full length of the wellbore. Our domestic drilling and production services fleets are highly capable and designed for operation in today’s long lateral, pad-oriented environment.
For additional information concerning the potential effects of the volatility in oil and gas prices and the effects of technological advancements andother industry trends, in our industry, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.

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Market Conditions and OutlookOur industry experienced a severe down cycle that began infrom late 2014 and which persisted through 2016, withduring which WTI oil prices that dipped below $30 per barrel in early 2016. A modest recovery in commodity prices began in the latter half of 2016 which continued through 2017, with averageWTI oil prices duringsteadily increasing from just under $50 per barrel at the last quarterend of 2017 averagingJune 2016 to approximately $60 per barrel at the end of 2017. WTI oil prices continued to increase to a high of $75 per barrel in October 2018, but then decreased to $45 per barrel at the end of 2018. Despite some improvement in 2019, WTI oil prices have, on average, remained in the $55 to $60 per barrel.barrel range. However, in early 2020, oil and gas prices have fallen below $50 per barrel, largely in response to concerns about coronavirus and its potential impact on worldwide demand for oil.
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.
a3yrspotpricesandrigcountq45.jpg



39



The trends in commodity pricing and domestic rig counts over the last 12 months are illustrated below:
a1yrspotpricesandrigcountq42.jpg
WithThe continuing trend toward longer lateral wellbores and the increasesenhanced efficiency of the equipment in our industry, in combination with current commodity prices that beganand more disciplined spending by exploration and production companies, has contributed to an oversupply of equipment in late 2016, weour industry, declining rig counts and dayrates, and reduced completion activity.
As a result, our drilling services experienced a resulting increaseslight decline in activityboth our average domestic revenues per day and revenue rates for our services during 2017.
Our well servicing rig hours, number of wireline jobs completed, and coiled tubing revenue daysinternational utilization during the fourth quarter ended December 31, 2017 increased by 2%, 11%, and 27%, respectively,of 2019, 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




third quarter. As of December 31, 2017, 222019, 18 of our 2425 drilling rigs are earning revenues, 1915 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 PeriodSpot 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 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 rigs2
 14
 4
 8
 1
 1
 
3
 12
 5
 6
 
 
 1
International rigs1
 5
 
 2
 1
 1
 1
International rigs:             
Earning under contract
 3
 
 3
 
 
 
On standby (not earning)
 2
 2
 
 
 
 
3
 19
 4
 10
 2
 2
 1
3
 17
 7
 9
 
 
 1
AbsentUnlike our domestic term contracts, our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 30 days notice and payment for demobilization services. The spot contracts for our domestic drilling rigs are also terminable by our client with 30 days notice and include a significantrequired payment for demobilization services. We are actively marketing our idle drilling rigs, as well as those that have terms expiring in the near term or that we otherwise expect to complete their current contracts in the short term.
As compared to our drilling services businesses which generally perform one type of service under longer-term contracts, our production services businesses perform a range of services that are more short-term in nature, and for which demand can, at times, experience quicker adjustments to regional demand and capacity. As compared to the third quarter of 2019, demand for our production services declined as the total number of well servicing rig hours, wireline jobs, and coiled tubing revenue days decreased by 3%, 20%, and 18%, respectively, despite slight pricing improvements in both our well servicing and wireline businesses. The overall decline in commodity prices,activity in the fourth quarter was driven by typical seasonal impacts combined with increased competition in the markets we expect continued improvementserve, especially as it relates to the market for coiled tubing services for which an influx of equipment has led to excess capacity and increased competition in activitythe South Texas and pricing during 2018. Rocky Mountain regions.
Although we expect a highly competitive market environment and some additional clients to decrease their activity during 2020 as their new annual budgets will continue in 2018,reflect the recent market softening, we remain focused on improving margins through realignment of certain businesses and reducing costs, and we believe our high-quality equipment, services, and excellent safety record makeposition us well positioned to compete.



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Liquidity and Capital Resources
As a result of the commencement of the Chapter 11 Cases on March 1, 2020, we are operating as a debtor-in-possession pursuant to the authority granted under Chapter 11 of the Bankruptcy Code. Pursuant to the Chapter 11 Cases, we intend to significantly de-leverage our balance sheet and reduce overall indebtedness upon completion of that process. Additionally, as a debtor-in-possession, certain of our activities are subject to review and approval by the Bankruptcy Court, including, among other things, the incurrence of secured indebtedness, material asset dispositions, and other transactions outside the ordinary course of business. There can be no guarantee that the Chapter 11 Cases will be completed successfully or in the time frame contemplated by the RSA.
The commencement of the Chapter 11 Cases also constituted an event of default under certain of our debt instruments that accelerated our obligations under our Senior Notes, the Prepetition ABL Facility, and Term Loan. Under the Bankruptcy Code, holders of our Senior Notes and the lenders under our Term Loan and the Prepetition ABL Facility are stayed from taking any action against us as a result of this event of default.
Sources of Capital Resources
Our principal sources of liquidity currently consist of:
cash and cash equivalents ($73.6 million as of December 31, 2017);equivalents;
cash generated from operations; and
the availability under our DIP Facility.
Debtor-in-Possession Financing and New Revolver — On February 28, 2020, we received commitments pursuant to the Commitment Letter from PNC Bank, N.A. for a $75 million asset-based revolving loan debtor-in-possession financing facility and a $75 million asset-based revolving exit financing facility. On March 3, 2020, with the approval of the Bankruptcy Court, we entered into the DIP Facility and used the proceeds of the initial extensions of credit thereunder to refinance all outstanding letters of credit under the Prepetition ABL Facility in connection with the termination of the Prepetition ABL Facility and to pay fees and expenses in connection with the Chapter 11 Cases and transactional and professional fees related thereto.
The DIP Facility has a 5-month maturity, bears interest at a rate of LIBOR plus 200 basis points per annum, and contains customary covenants and events of default. The borrowers and guarantors under the DIP Facility are the same as the borrowers and guarantors under the Prepetition ABL Facility. Subject to certain exceptions, our obligations under the DIP Facility are superpriority administrative expenses in the Chapter 11 Cases and are secured by a first-priority lien on inventory and cash and a second-priority lien on all other assets of the borrowers and guarantors thereunder.
The Commitment Letter contemplates that upon our emergence from salesthe Chapter 11 Cases, subject to the satisfaction of certain non-strategic assets;customary conditions, the DIP Facility will “roll” into the New Revolver. Subject to the terms 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 conditions of the Term Loan wereCommitment Letter, the New Revolver will have a 5-year maturity, will bear interest at a rate per annum between LIBOR plus 175 basis points and LIBOR plus 225 basis points (depending on the average excess availability under the New Revolver), and will contain customary covenants and events of default. Subject to certain exceptions and permitted liens, the obligations of the borrowers and guarantors under the New Revolver will be secured by a first-priority lien on inventory and cash and a second-priority lien on substantially all other assets of the borrowers and guarantors thereunder. We anticipate that the proceeds of the New Revolver will be used to repay in full all amounts outstanding under the entire outstanding balance under our Revolving CreditDIP 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.

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Uses of Capital Resources
For the years ended December 31, 2017 and 2016, our primary uses of Our principal liquidity requirements are currently for:
capital resources were for property and equipment additions, which consisted of the following (amounts in thousands):expenditures;
 Year ended December 31,
 2017 2016
Drilling services business:   
Routine$16,793
 $4,948
Discretionary4,010
 2,454
Fleet additions and major components7,337
 12,464
 28,140
 19,866
Production services business:   
Routine13,185
 8,259
Discretionary7,826
 4,256
Fleet additions14,126
 
 35,137
 12,515
Net cash used for purchases of property and equipment63,277
 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,needs; 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.debt service.
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



41



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.activity. During periods of sustained low activity and pricing, we may also access additional capital through the use of available funds under our ABLthe DIP Facility.

Capital Expenditures — For the year ended December 31, 2019 and 2018, our primary uses of capital resources were for property and equipment additions, for which we paid $50.0 million and $67.1 million, respectively. In recent years, we have limited our capital spending to primarily routine expenditures and select asset acquisitions to optimize our fleets. In 2019, two-thirds of our total spending related to routine expenditures to maintain our fleets, including fleet upgrades, refurbishments and purchases of replacement supporting equipment. We reduced our capital expenditures in 2019 by 25% from the prior year, primarily in our production services businesses, as our fleet expansion and other discretionary spending in these businesses decreased by a total of $15.4 million. Capital expenditures for fleet additions of approximately $7.5 million and $18.5 million in 2019 and 2018, respectively, included the construction of our 17th AC domestic drilling rig, which we began in 2018 and deployed in early 2019, the purchase of a coiled tubing unit in 2018, and the remaining installments on certain fleet additions which were ordered in 2017 but delivered in 2018, including one coiled tubing unit and three wireline units. Other discretionary spending during 2019 and 2018 primarily related to select domestic drilling rig upgrades and the purchase of new support equipment.
34




The changesCurrently, we expect to spend approximately $40 million on capital expenditures during 2020 primarily to maintain our existing fleets and also re-activate idle equipment as the industry improves. Actual capital expenditures may vary depending on the climate of our industry and any resulting increase or decrease in activity levels, the componentstiming of commitments and payments, availability of capital resources, and the level of investment opportunities that meet our strategic and return on capital employed criteria. We expect to fund the capital expenditures in 2020 from operating cash flow in excess of our working capital wererequirements, although available borrowings under our DIP Facility are also available, if necessary.
Working Capital — Our working capital and current ratio, which we calculate by dividing current assets by current liabilities, was as follows as of December 31, 2019 and 2018 (amounts in thousands), and as described below:thousands, except current ratio):
 December 31,
2017
 December 31,
2016
 Change
Cash and cash equivalents$73,640
 $10,194
 $63,446
Restricted cash2,008
 
 2,008
Receivables:     
Trade, net of allowance for doubtful accounts79,592
 38,764
 40,828
Unbilled receivables16,029
 7,417
 8,612
Insurance recoveries13,874
 17,003
 (3,129)
Other receivables3,510
 8,939
 (5,429)
Inventory14,057
 9,660
 4,397
Assets held for sale6,620
 15,093
 (8,473)
Prepaid expenses and other current assets6,229
 6,926
 (697)
Current assets215,559
 113,996
 101,563
Accounts payable29,538
 19,208
 10,330
Deferred revenues905
 1,449
 (544)
Accrued expenses:     
Payroll and related employee costs21,023
 14,813
 6,210
Insurance premiums and deductibles6,742
 6,446
 296
Insurance claims and settlements13,289
 13,667
 (378)
Interest6,624
 5,395
 1,229
Other6,793
 5,024
 1,769
Current liabilities84,914
 66,002
 18,912
Working capital$130,645
 $47,994
 $82,651
 December 31,
2019
 December 31,
2018
 Change
Current assets$182,912
 $215,034
 $(32,122)
Current liabilities91,581
 104,768
 (13,187)
Working capital$91,331
 $110,266
 $(18,935)
Current ratio2.0
 2.1
 (0.1)
CashOur current assets decreased by $32.1 million during 2019, primarily related to a decrease of $28.9 million in cash and cash equivalents During 2017, we used $63.3 and a net decrease of $10.0 million in our total trade and unbilled receivables.
The decrease in cash and cash equivalents is primarily due to $50.0 million of cash used for the purchasespurchase of property and equipment, and used $5.8partially offset by $12.0 million inof cash from operating activities, primarily funded by $119.2 million of net borrowings (net of debt issuance costs), $12.6$7.7 million of proceeds from the sale of assets, as well as $3.3property and equipment, and $1.5 million of proceeds from 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.
recoveries.
Restricted cashOur 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 receivablesThe net increasedecrease 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.Colombia, as well as the 8% decrease in our revenues during the quarter ended December 31, 2019, as compared to the quarter ended December 31, 2018. Our domestic trade receivables generally turn over within 9060 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.days.
These decreases were partially offset by a combined increase of $7.0 million in inventory and other receivables, primarily attributable to an increase in inventory levels for our international operations’ spare parts and supplies supporting rigs working in remote locations, as well as an increase in recoverable income tax receivables associated with increased activity for our international operations.
Insurance recoveries — Our current liabilities decreased by $13.2 million during 2019, primarily related to a $11.0 million decrease in accrued employee compensation, as well as a decrease in accounts payable.
The decrease in our insurance recoveries receivablesaccrued employee compensation and related costs during 2017 is primarily due to an insurance claim receivable of $3.1 million for2019 resulted from a drilling rig that was damaged during 2016, for which the proceeds were received in early 2017.
Other receivables — The decrease in other receivables during 2017 is primarily due toaccrued incentive cash compensation associated with the salepayment of two drilling rigs2018 annual bonuses 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 thirdfirst quarter of 2017.
Inventory — 2019 of $6.6 million, the $3.5 million settlement of our phantom stock unit awards that vested in April 2019, and the termination of both our annual and long-term cash incentive awards in September 2019. The increaseoverall decrease 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.
accrued employee

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Assets held for sale — Ascompensation and related costs was net of December 31, 2017, our consolidated balance sheet reflects assets held for sale$3.5 million of $6.6accrued quarterly incentive compensation that was paid in January 2020.
The $4.2 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,accounts payable during 2019 is primarily due to 20 older well servicing rigs thata decrease of $5.2 million in our accruals for capital expenditures, offset by an increase in our accruals for operating costs, primarily due to lengthened vendor payment cycles.
These decreases were designatedslightly offset by a $3.3 million increase in other accrued expenses during 2019 primarily related to the recognition of $2.2 million of current operating lease liabilities due to our adoption of ASU No. 2016-02, Leases, and its related amendments as held for sale that were traded in for 20 new-model rigs in the first quarter of 2017,January 1, 2019, as well as the sale of two mechanical drilling rigs and 13 wireline units.
Prepaid expenses and other current assetsThe decreasean increase 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.accrued professional fees. For moreadditional information about rig mobilization service revenues and costs,adoption of this standard, see Note 1, Organization and Summary of Significant Accounting Policies and Note 4, Leases, 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.
Debt and Other Contractual Obligations — The following table includes information about the amount and timing of our contractual obligations at December 31, 2019 (amounts are undiscounted and in thousands):
 Payments Due by Period
Contractual ObligationsTotal Within 1 Year 2 to 3 Years 4 to 5 Years Beyond 5 Years
Debt$475,000
 $
 $475,000
 $
 $
Interest on debt79,188
 35,000
 44,188
 
 
Purchase commitments3,612
 3,612
 
 
 
Operating leases8,716
 2,496
 3,380
 2,029
 811
Incentive compensation4,612
 4,065
 547
 
 
 $571,128
 $45,173
 $523,115
 $2,029
 $811
Debt — Debt obligations at December 31, 2019 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, assuming a maturity date of December 14, 2021. As of December 31, 2019, we had no debt outstanding under our Prepetition ABL Facility.
For more information about our debt obligations, see Note 6, Debt, 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 payable — Our 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 expensesThe increase in other accrued expensesduring 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 Obligations — The 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 ObligationsTotal Within 1 Year 2 to 3 Years 4 to 5 Years Beyond 5 Years
Debt$475,000
 $
 $
 $475,000
 $
Interest on debt144,899
 34,108
 68,215
 42,576
 
Purchase commitments8,170
 8,170
 
 
 
Operating leases9,902
 3,081
 3,534
 1,441
 1,846
Incentive compensation15,722
 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 their maturity on March 15, 2022. Interest payment obligations on our Term Loan were estimated based on (1) the 9.0%9.5% interest rate that was in effect at December 31, 2017,2019, and (2) the principal balance of $175 million at December 31, 2017,2019, and assuming repayment of the outstanding balance occurs aton December 14, 2021.
Purchase commitments — Purchase commitments generally relate to capital projects for the repair, upgrade and maintenance of our equipment, the construction or purchase of new equipment, and purchase orders for various job and inventory supplies. At December 31, 2019, our purchase commitments primarily pertain to deposits on one new$1.6 million of inventory and job supplies for our 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,operations, as well as support equipment for our wireline operations and routine capital expenditures and inventory.refurbishments to our domestic drilling fleet.

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Operating leases — Our operating leases consist oflease obligations relate to long-term lease agreements for office space, operating facilities, field personnel housing, and office equipment.
Incentive compensation — Incentive 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. At December 31, 2019, our incentive compensation payable primarily relates to $3.5 million of quarterly incentive compensation, which was paid in January 2020.
Debt Compliance Requirements — The following isAs of March 1, 2020, we were in default under our Term Loan, Prepetition ABL Facility, and Senior Notes. Filing the Chapter 11 Cases accelerated our Term Loan, Prepetition ABL Facility, and Senior Notes obligations. Additionally, events of default under the credit agreements governing our Term Loan and Prepetition ABL Facility and the indenture governing our Senior notes have occurred and are continuing, including as a summaryresult of cross-



43



defaults between such credit agreements and indenture. However, any efforts to enforce such payment obligations are automatically stayed under the provisions of the Bankruptcy Code.
Our debt instruments contain various restrictions that limit our ability to enter into certain transactions and our debt obligations are, in general, guaranteed by our domestic subsidiaries. Our obligations under the Term Loan are guaranteed by our wholly-owned domestic subsidiaries, and are secured by substantially all of our debt compliance requirements including covenants, restrictionsdomestic assets, in each case, subject to certain exceptions and guarantees,permitted liens. Our obligations under the Prepetition 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. Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our domestic subsidiaries, generally excluding those subsidiaries 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.operate our international drilling business.
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, 2017,2019, the asset coverage ratio, as calculated under the Term Loan, was 2.051.94 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 Prepetition ABL Facility is less than 15% of the maximum amount (or $11.25 million), we are required to maintain a minimum fixed charge coverage ratio, as defined in the Prepetition ABL Facility, of at least 1.00 to 1.00, measured on a trailing 12 month12-month basis.
Our obligations underdebt compliance requirements including covenants, restrictions and guarantees are further described in Note 6, Debt, and Note 14, Guarantor/Non-Guarantor Condensed Consolidating Financial Statements, of the ABL Facility are guaranteed by usNotes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements 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 allSupplementary Data, 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,this Annual Report 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.Form 10-K.

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44



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 detaildetails 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, 20172019 and 20162018 (amounts in thousands, except percentages):
Year ended December 31,Year ended December 31,
2017 20162019 2018
Revenues:              
Domestic drilling$129,276
 29% $112,399
 41 %$151,769
 26% $145,676
 25%
International drilling41,349
 9% 6,808
 2 %88,932
 15% 84,161
 14%
Drilling services170,625
 38% 119,207
 43 %240,701
 41% 229,837
 39%
Well servicing77,257
 17% 71,491
 26 %115,715
 20% 93,800
 16%
Wireline services163,716
 37% 67,419
 24 %172,931
 31% 215,858
 36%
Coiled tubing services34,857
 8% 18,959
 7 %46,445
 8% 50,602
 9%
Production services275,830
 62% 157,869
 57 %335,091
 59% 360,260
 61%
Consolidated revenues$446,455
 100% $277,076
 100 %$575,792
 100% $590,097
 100%
              
Operating costs:              
Domestic drilling$83,122
 25% $63,686
 31 %$92,183
 21% $86,910
 20%
International drilling31,994
 10% 9,465
 5 %65,007
 15% 64,074
 15%
Drilling services115,116
 35% 73,151
 36 %157,190
 36% 150,984
 35%
Well servicing56,379
 17% 53,208
 26 %83,461
 19% 67,554
 16%
Wireline services128,137
 39% 57,634
 28 %151,145
 36% 167,337
 39%
Coiled tubing services31,248
 9% 19,956
 10 %39,557
 9% 44,038
 10%
Production services215,764
 65% 130,798
 64 %274,163
 64% 278,929
 65%
Consolidated operating costs$330,880
 100% $203,949
 100 %$431,353
 100% $429,913
 100%
              
Gross margin:              
Domestic drilling$46,154
 40% $48,713
 67 %$59,586
 41% $58,766
 37%
International drilling9,355
 8% (2,657) (4)%23,925
 17% 20,087
 13%
Drilling services55,509
 48% 46,056
 63 %83,511
 58% 78,853
 50%
Well servicing20,878
 18% 18,283
 25 %32,254
 22% 26,246
 16%
Wireline services35,579
 31% 9,785
 13 %21,786
 15% 48,521
 30%
Coiled tubing services3,609
 3% (997) (1)%6,888
 5% 6,564
 4%
Production services60,066
 52% 27,071
 37 %60,928
 42% 81,331
 50%
Consolidated gross margin$115,575
 100% $73,127
 100 %$144,439
 100% $160,184
 100%
              
Consolidated:              
Net loss$(75,118)   $(128,391)  $(63,904)   $(49,011)  
Adjusted EBITDA (1)
$49,873
   $14,237
  $60,153
   $89,655
  
(1)    Adjusted EBITDA represents income (loss) before interest expense, income tax (expense) benefit, depreciation and amortization, impairment, and any loss on extinguishment of debt and impairments.debt. 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

45



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.table:
Year ended December 31,Year ended December 31,
2017 20162019 2018
(amounts in thousands)(amounts in thousands)
Reconciliation of net loss and Adjusted EBITDA to consolidated gross margin:   
Net loss$(75,118) $(128,391)$(63,904) $(49,011)
Depreciation and amortization98,777
 114,312
Depreciation90,884
 93,554
Impairment1,902
 12,815
2,667
 4,422
Interest expense27,039
 25,934
39,835
 38,782
Loss on extinguishment of debt1,476
 299
Income tax benefit(4,203) (10,732)
Income tax expense (benefit)(9,329) 1,908
Adjusted EBITDA49,873
 14,237
60,153
 89,655
General and administrative69,681
 61,184
91,185
 74,117
Bad debt expense53
 156
Bad debt expense (recovery), net(79) 271
Gain on dispositions of property and equipment, net(3,608) (1,892)(4,513) (3,121)
Other income(424) (558)(2,307) (738)
Consolidated gross margin$115,575
 $73,127
$144,439
 $160,184
Consolidated gross margin Our consolidated gross margin increaseddecreased by 58%$15.7 million, or 10%, during 2017,2019 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, primarily2018, due to improveda decline in demand for our wireline services, while the remainingdespite an increase attributable toin gross margin for all our drilling servicesother business segments is primarily due to higher activityin 2019. The $15.7 million overall decrease in consolidated gross margin was net of a $11.0 million increase in gross margin for our international drilling operations.other business segments.
Drilling Services Our drilling services revenues increased by $51.4 million, or 43%, during 2017, as compared to 2016, whileand operating costs increased by $42.0$10.9 million, or 57%.5%, and $6.2 million, or 4%, respective, during 2019 as compared to 2018. The increases in our drilling services revenues and operating costs primarily resulted from a 42%resulting increase in revenue daysmargin during 2019 is primarily due to the increasing demanddeployment of our newest AC drilling rig in our industry, especiallyMarch 2019, increased revenues associated with the demobilization of rigs in Colombia.

39




Colombia, and the benefit of early termination revenues during 2019 on three domestic drilling contracts. The following table provides operating statistics for each of our drilling services segments for the years ended December 31, 2017 and 2016:segments:
Year ended December 31,Year ended December 31,
2017 20162019 2018
Domestic drilling:      
Average number of drilling rigs16
 23
17
 16
Utilization rate95% 55%92% 99%
Revenue days5,524
 4,628
5,660
 5,808
      
Average revenues per day$23,403
 $24,287
$26,814
 $25,082
Average operating costs per day15,047
 13,761
16,287
 14,964
Average margin per day$8,356
 $10,526
$10,527
 $10,118
      
International drilling:      
Average number of drilling rigs8
 8
8
 8
Utilization rate46% 7%75% 77%
Revenue days1,345
 218
2,195
 2,258
      
Average revenues per day$30,743
 $31,229
$40,516
 $37,272
Average operating costs per day23,787
 43,417
29,616
 28,376
Average margin per day$6,956
 $(12,188)$10,900
 $8,896
Our domestic drilling fleet utilization reached 100% by mid-2017, and remained fully utilized through December 31, 2017. Our domestic drilling average revenues and margin per day increased during 2017,2019 as compared to 2016, decreased, while2018, primarily due to the deployment of our newest AC drilling rig in March 2019 and $3.1 million of revenues for the early termination of three of our drilling contracts, as well as the impact of higher average operating costsdayrates during 2019. Average dayrates during 2019 were higher than in 2018 primarily due to contract dayrate increases that occurred in late 2018 and early 2019, despite the downward re-pricing of contracts that were either renewed or renegotiated in late 2019. The overall increases in average revenues and margin per day were also partially offset by the impact of reduced utilization in 2019, as compared to 2018.



46



Our international average revenues and margin 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,2019 as compared to daywork rates, and incur minimal operating costs. The following table provides2018 primarily due to $2.5 million of revenues associated with the percentagesdemobilization of our consolidated drilling services revenues by contract type forfive rigs in Colombia during 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 endsecond half 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,2019, as well as additional costsincreasing dayrates during the fourth quarter of 2016 to mobilize previously stacked rigs under new contracts, which resulted in a negative averagelate 2018 and early 2019. Average margin per day during 2016.2019 also benefited from reduced costs associated with mobilization and demobilization activity during 2019 as compared to 2018.
Production Services Our revenues and operating costs from production services increaseddecreased by $118.0$25.2 million, or 75%7%, and $4.8 million, or 2%, during 2017,2019 as compared to 2016, while operating costs increased by $85.0 million, or 65%, respectively.2018. The increasesdecrease in revenues and operating costs in our production services segments arerevenue is a result of the decreased demand for wireline completion services, partially offset by increased demand for our services, particularly those that perform completion-related activities.

40




well servicing business which experienced increases of 23% in both revenue and gross margin during 2019. The following table provides operating statistics for each of our production services segments for the years ended December 31, 2017 and 2016:segments:
Year ended December 31,
2017 2016Year ended December 31,
   2019 2018
Well servicing:      
Average number of rigs125
 125
125
 125
Utilization rate43% 41%58% 49%
Rig hours150,240
 144,151
201,768
 171,851
Average revenue per hour$514
 $496
$574
 $546
      
Wireline services:      
Average number of units115
 122
97
 107
Number of jobs11,139
 8,169
8,366
 10,943
Average revenue per job$14,698
 $8,253
$20,671
 $19,726
      
Coiled tubing services:      
Average number of units16
 17
9
 12
Revenue days1,529
 1,352
1,274
 1,472
Average revenue per day$22,797
 $14,023
$36,456
 $34,376
IncreasesOur well servicing business experienced an increase in production servicesdemand during 2019 as compared to 2018, as the number of completed wells increased during the improvement our industry experienced in 2017 and 2018, resulting in a larger inventory of producing wells that now require ongoing maintenance. Our well servicing rig hours increased by 17%, while revenues and operating costs were ledper hour increased by our5% during 2019 as compared to 2018.
Our wireline services business segment which experienced a significant increasedecrease of 24% in completion-related activity as wells that were drilled but notthe number of jobs completed during the downturn created2019, as compared to 2018 while average revenues per job increased 5%. The decrease in activity was primarily a result of decreased demand for completion-related services during 2019, as compared to 2018, when we experienced higher demand for completion services as our industry continues to recover. The numbercomplete both newly drilled wells and the remaining inventory of wireline jobs we completed increased by 36% during 2017, as compared to 2016 while average revenue per job increased by 78%,wells which is largely due to completion-related jobs that earn higher revenue rateshad been drilled in prior periods but also incur higher costs for the job materials consumed on these types of jobs.were not yet completed.
Our well servicing and coiled tubing services business segments experienced a more moderate increasedecrease of 13% 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%,during 2019 as compared to 2018, while the average revenue per day increased by 63%,6%. An influx of coiled tubing equipment has led to excess capacity and increased competition in the South Texas and Rocky Mountain regions, while certain seasonal factors surrounding wildlife migration caused an interruption to the operations in affected areas of the Rocky Mountains, all of which led to a decline in revenue days during 2019, as compared to 2018. The increase in average revenue per day during 2019 was primarily due to a larger proportion of the work performed with larger diameter coiled tubing units, including the addition of two new large-diameter coiled tubing units which were placed in service in July and December 2018. Large-diameter coiled tubing units 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$2.7 million during 2017,2019, primarily in our wireline and coiled tubing segments, which currently operate with an overall smaller fleet 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 2016.2018.
Impairment During the years ended December 31, 20172019 and 2016,2018, we recognized impairment charges of $1.9$2.7 million and $12.8$4.4 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 2,5, 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.



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Interest expense — Our interest expense increased by $1.1 million during the year ended December 31, 2017,2019, as compared to 2016,2018, 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 increasedthe LIBOR interest 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.

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Loss on extinguishment of debt — Our 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.Loan. For more detail see, Note 5,6, Debt, 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.
Income tax expense (benefit) Our effective tax rates differ from the applicable U.S. statutory rates due to a number of factors, primarily due to our domestic valuation allowance and reversals of our foreign valuation allowance in 2019, as well as the impact of permanent items and the mix of profit and loss between federal, state and international taxing jurisdictions. The change in our income tax expense (benefit) during 2019 as compared to 2018 is largely due to the reversal of our valuation allowance for foreign deferred tax assets, which resulted in recognizing a benefit of $14.8 million during 2019. For more detail, see Note 7, 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$17.1 million, or 14%23%, during 2017,2019 as compared to 2016, primarily related to increased compensation costs. The increase in compensation cost was primarily2018, largely due to a $7.1 millionnet increase in salary, employee benefitsincentive compensation of $9.4 million associated with retention and bonus expenseincentive compensation awards granted in the second half of 2019, partially offset by the concurrent termination of the previous annual and long-term cash incentive awards. The increase is also attributable to an increase in professional fees of $6.5 million during 2019 as compared to 2018 related in part to the year ended December 31, 2017, partially as a resultevaluation of increased headcount to accommodate higher activity levels,strategic alternatives and the ultimate preparation for the filing of the Chapter 11 Cases in 2020 as well as increased incentive compensation based on improved company performance.costs incurred in connection with the evaluation and selection of a company-wide enterprise resource planning system.
Gain on dispositions of property and equipment, net OurDuring the years ended December 31, 2019 and 2018, we recognized net gaingains of $3.6$4.5 million and $3.1 million, respectively, on the disposition or sale 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 ofprimarily including drill pipe in operation,and collars, a domestic drilling yard, and certain older and/or underutilized equipment, most of which were previously held 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.sale.
Other income (expense), net Our other income is primarily related to net foreign currency gains recognized for our Colombian operations.

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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 drilling6,808
 2 % 43,878
 8%
Drilling services119,207
 43 % 249,318
 46%
Well servicing71,491
 26 % 133,440
 25%
Wireline services67,419
 24 % 120,387
 22%
Coiled tubing services18,959
 7 % 37,633
 7%
Production services157,869
 57 % 291,460
 54%
Consolidated revenues$277,076
 100 % $540,778
 100%
        
Operating costs:       
Domestic drilling$63,686
 31 % $108,602
 30%
International drilling9,465
 5 % 35,594
 10%
Drilling services73,151
 36 % 144,196
 40%
Well servicing53,208
 26 % 91,125
 25%
Wireline services57,634
 28 % 88,848
 26%
Coiled tubing services19,956
 10 % 33,847
 9%
Production services130,798
 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 services46,056
 63 % 105,122
 58%
Well servicing18,283
 25 % 42,315
 23%
Wireline services9,785
 13 % 31,539
 17%
Coiled tubing services(997) (1)% 3,786
 2%
Production services27,071
 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.

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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,
 2016 2015
 (amounts in thousands)
Reconciliation of net loss and Adjusted EBITDA to consolidated gross margin:   
Net loss$(128,391) $(155,140)
Depreciation and amortization114,312
 150,939
Impairment12,815
 129,152
Interest expense25,934
 21,222
Loss on extinguishment of debt299
 2,186
Income tax benefit(10,732) (37,579)
Adjusted EBITDA14,237
 110,780
General and administrative61,184
 73,903
Bad debt expense (recovery)156
 (188)
Gain on dispositions of property and equipment, net(1,892) (4,344)
Other (income) expense(558) 2,611
Consolidated gross margin$73,127
 $182,762
Consolidated gross marginOur consolidated gross margin decreased by 60% during 2016, as compared to 2015, primarily as a result of decreased activity and pricing pressure for all our service offerings. Of the $109.6 million decrease in consolidated gross margin, 54% was attributable to our drilling services business segments, primarily due to a reduction in domestic drilling activity. The remaining decrease attributable to our production services business segments is primarily due to a reduction in well servicing and wireline services activity.
In response to the downturn in our industry, we took several actions during 2015 and 2016 to reduce costs and better scale our business to the reduced revenues. We reduced our total headcount by over 50%, reduced wage rates for our operations personnel, reduced incentive compensation and eliminated certain employment benefits. We closed ten field offices to reduce overhead and reduce associated lease payments, amended our Revolving Credit Facility, and sold 35 drilling rigs and other drilling equipment for aggregate net proceeds of $65.5 million.

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Drilling ServicesOur drilling services revenues decreased by $130.1 million, or 52%, during 2016, as compared to 2015, while operating costs decreased by $71.0 million, or 49%. The decreases in our drilling services revenues and costs primarily resulted from a 46% decrease in revenue days due to the significant reduction in demand from an industry downturn that bottomed during the second quarter of 2016.
The following table provides operating statistics for each of our drilling services business segments for the years ended December 31, 2016 and 2015:
 Year ended December 31,
 2016 2015
    
Domestic drilling:   
Average number of drilling rigs23
 31
Utilization rate55% 70%
Revenue days4,628
 7,911
    
Average revenues per day$24,287
 $25,969
Average operating costs per day13,761
 13,728
Average margin per day$10,526
 $12,241
    
International drilling:   
Average number of drilling rigs8
 8
Utilization rate7% 39%
Revenue days218
 1,129
    
Average revenues per day$31,229
 $38,864
Average operating costs per day43,417
 31,527
Average margin per day$(12,188) $7,337
Our domestic drilling average revenues per day during 2016 decreased relative to 2015, while our average operating costs per day increased, primarily due to the expiration of term contracts that were entered into in 2014 prior to the downturn at higher revenue rates, many of which were terminated early. Our domestic drilling average operating costs per day increased as a result of more revenue days attributable to daywork activity during 2016, versus more revenue days in 2015 from rigs that were earning but not working and incurring minimal costs under contracts that were terminated early. These increases in 2016 were partially offset by our reduced cost structure.
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. Alternatively, turnkey drilling contracts result in higher average revenues per day and higher average operating costs per day as compared to daywork drilling contracts.
The following table provides the percentages of our consolidated drilling services revenues by contract type for the years ended December 31, 2016 and 2015:
 Year ended December 31,
 2016 2015
Daywork contracts (not terminated early)89% 77%
Daywork contracts terminated early11% 20%
Turnkey contracts% 3%
Our international drilling fleet utilization declined throughout 2016 and 2015 as several contracted rigs were placed on standby by our clients in response to weakening oil prices. In the fourth quarter of 2015, all three of the contracted rigs were placed on standby and remained idle until being redeployed in late 2016. As a result of the low utilization in 2016 and the contracts placed on standby, for which we continued to incur overhead costs until the rig was reactivated, our average international drilling revenues per day decreased while average operating costs per day increased. The increases were partially offset by our reduced cost structure in Colombia.

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Production ServicesOur production services revenues decreased by $133.6 million, or 46%, during 2016, as compared to 2015, while operating costs decreased by $83.0 million, or 39%, respectively. The decreases in revenues and operating costs are a result of reduced demand for our services, which similarly affected each of our production services business segments.
The following table provides operating statistics for each of our production services business segments for the years ended December 31, 2016 and 2015:
 Year ended December 31,
 2016 2015
    
Well servicing:   
Average number of rigs125
 122
Utilization rate41% 65%
Rig hours144,151
 225,938
Average revenue per hour$496
 $591
    
Wireline services:   
Average number of units122
 125
Number of jobs8,169
 9,661
Average revenue per job$8,253
 $12,461
    
Coiled tubing services:   
Average number of units17
 17
Revenue days1,352
 1,672
Average revenue per day$14,023
 $22,507
The decreases in revenues and operating costs for each of our production services segments are a result of the significantly reduced demand for our services in response to the downturn in our industry, which led to decreased activity and increased pricing pressure for all our service offerings. Our well servicing utilization decreased to 41% during 2016, from 65% during 2015, representing a 36% decrease in rig hours, while average revenues per hour decreased by 16%. The the number of wireline jobs we completed during 2016 decreased by 15%, as compared to 2015, while average revenue per job decreased by 34%. Similarly, our coiled tubing services revenue days decreased by 19%, while the average revenue per day also decreased by 38%.
Depreciation and amortization expense — Our depreciation and amortization expense decreased by $36.6 million during 2016, as compared to 2015, primarily as a result of the impairment charges during 2015 to reduce the carrying values of domestic and Colombia drilling rigs, coiled tubing equipment, and intangible assets to their estimated fair values. The sales and disposals of drilling rigs and equipment during 2015 also contributed to the decrease in depreciation expense in 2016. During 2015, we recognized $10.3 million of depreciation on drilling rigs which were subsequently sold or placed as held for sale, and $3.8 million for the amortization of coiled tubing intangible assets which were impaired to zero at the end of 2015. The overall decrease in our depreciation expense was partially offset by $6.1 million of additional depreciation recognized during the year ended December 31, 2016 for the five new drilling rigs which we deployed in 2015.
ImpairmentDuring the year ended December 31, 2016, we recognized impairment charges of $12.8 million, primarily to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices. During the year ended December 31, 2015, we recognized impairment charges of $129.2 million, primarily related to certain domestic and international drilling rigs, coiled tubing equipment, and intangibles and other equipment designated as held for sale. 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 $4.7 million during 2016, as compared to 2015, primarily due to the increased interest rate under our Revolving Credit Facility, which was amended in late 2015 and again in June 2016.
Loss on extinguishment of debt — Our loss on debt extinguishment represents the write off of debt costs associated with the reduced borrowing capacity of our Revolving Credit Facility as a result of the amendments in 2015 and 2016.

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Income tax expense (benefit) — Our effective income tax rate for the year ended December 31, 2016 was 8%, which is lower than the federal statutory rate in the United States primarily due to valuation allowances, the effect of 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 decreased by approximately $12.7 million, or 17% during 2016, as compared to 2015. This decrease is primarily due to a decrease in compensation and benefit costs during 2016 of $5.2 million, resulting primarily from the reduction in our workforce and reduced employee benefits and other actions taken to minimize various administrative costs such as rent, office and travel expenses.
Gain on dispositions of property and equipment, net — Our net gain of $1.9 million on the disposition of property and equipment during the year ended December 31, 2016 was primarily related to a net gain on the sale of three domestic drilling rigs and the disposal of excess drill pipe. These gains were partially offset by a loss on the disposition of damaged drilling equipment. Our net gain of $4.3 million on the disposition of property and equipment during the year ended December 31, 2015 was primarily for the sale of 32 domestic drilling rigs and other drilling equipment.
Other (income) expense —The increase in our other income during 2019 is primarily related to net foreign currency gains recognized for our Colombian operations, during the year ended December 31, 2016, as compared to net foreign currency losses during 2015.2018.
Inflation
When the demand for drilling and production services increases, we may be affected by inflation, which primarily impacts:
wage rates for our operations personnel which increase when the availability of personnel is scarce;
materials and supplies used in our operations;
equipment repair and maintenance costs;
costs to upgrade existing equipment; and
costs to construct new equipment.
With the recent increases in activity in our industry, we estimate that inflation has had a modest impact on our operations during 20162018 and 2017. However,2019. Although it varies by business, we do not expect that we will experience a moderate increasesignificant inflationary pressure to impact our business in inflation in 2018 if activity continues to improve.2020.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with USU.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our financial statements and accompanying notes. Actual results could differ from those estimates.
Revenues and Cost RecognitionGoing concern — Our drilling services business segments earn revenues by drilling oil and gas wells for our clients under daywork contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate specified in each contract.
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has notThe accompanying financial statements have been secured are expensed as incurred. Reimbursementsprepared assuming that we receivewill continue as a going concern. In an effort to achieve liquidity that would be sufficient to meet all of our commitments, we have undertaken a number of actions, including minimizing capital expenditures and reducing recurring expenses. However, we believe that even after taking these actions, we will not have sufficient liquidity to satisfy all of our future financial obligations, comply with our debt covenants, and execute our business plan. As a result, the Pioneer RSA Parties filed a petition for out-of-pocket expenses are recorded as revenuesreorganization under Chapter 11 of the Bankruptcy Code on March 1, 2020. The risks and uncertainties surrounding the Chapter 11 Cases, the defaults under our Debt Instruments, and the out-of-pocket expenses for which they relate are recordedweak industry conditions impacting our business raise substantial doubt as operating costs.
With most term drilling contracts, we are entitled to receiveour ability to continue as a full or reduced rate of revenues from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Revenues derived from rigs placed on standby or from the early termination of term drilling contracts are deferredgoing concern. For more information, see Note 2, Going Concern and recognized as the amounts become fixed or determinable, over the remainder Subsequent Events,of the original term or when the rig is sold.Notes to Consolidated Financial Statements, included in Part II, Item 8 Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.

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Our production services business segments earn revenues for well servicing, wireline services and coiled tubing services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.
All of our revenues are recognized net of sales taxes when applicable.
Long-lived assets LeasesWe evaluate for potential impairment of long-lived assets when indicators of impairment are present,In February 2016, the FASB issued ASU No. 2016-02, Leases, which may include, among other things, significant adverse changes in industry trends (including revenue rates, utilization rates, oilrequires lessees to recognize substantially all leases on the balance sheet, with expense recognition that is similar to the former lease standard, and natural gas market prices, and industry rig counts). In performing an impairment evaluation, we estimatealigns the future undiscounted net cash flows fromprinciples of lessor accounting with the use and eventual dispositionprinciples of the assets groupedFASB’s new revenue guidance in ASC Topic 606. In July 2018, the FASB issued ASU No. 2018-11, Leases: Targeted Improvements, which provides an option to apply the guidance prospectively, and provides a practical expedient allowing lessors to combine the lease and non-lease components of revenues where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The practical expedient also allows a lessor to account for the combined lease and non-lease components under ASC Topic 606, Revenue from Contracts with Customers, when the non-lease component is the predominant element of the combined component.
As a lessor, we elected to apply the practical expedient which allows us to continue to recognize our revenues (both lease and service components) under ASC Topic 606, and continue to present them as one revenue stream in our consolidated statements of operations. As a lessee, this standard primarily impacts our accounting for long-term real estate and office equipment leases, for which we recognized an operating lease asset and a corresponding operating lease liability on our consolidated balance sheet of $9.8 million at the lowest leveladoption date of January 1, 2019. For leases that independent cash flows can be identified. We perform an impairment evaluationcommenced prior to adoption of ASC Topic 842, we elected to apply the package of practical expedients which allows us to carry forward the historical lease classification. The adoption of ASC Topic 842 also resulted in a cumulative effect adjustment of $0.3 million after applicable income taxes, related to the write off of previously unamortized deferred lease liabilities at the date of adoption. For more information about the accounting under ASC Topic 842, and estimate future undiscounted cash flows for each of our reporting units separately, which are our domestic drilling services, international drilling services, well servicing, wireline services and coiled tubing services segments.disclosures under the new standard, see Note 4, If the sum Leases, of the estimated future undiscounted net cash flows is less than the carrying amountNotes to Consolidated Financial Statements, included in Part II, Item 8 Financial Statements and Supplementary Data, of the asset group, then we determine the fair value of the asset group. The amount of an impairment charge is measured as the difference between the carrying amount and the fair value of the assets.The assumptions used in the impairment evaluation are inherently uncertain and require management judgment.
Deferred taxes — We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, well servicing rigs, wireline units and coiled tubing units over 1 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules generally require that we depreciate drilling rigs, well servicing rigs, wireline units and coiled tubing units over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, well servicing rig, wireline unit or coiled tubing unit, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxesthis Annual Report on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.Form 10-K.
Accounting estimates — Material estimates that are particularly susceptible to significant changes in the near term relate to our estimateestimates of the allowance for doubtful accounts, our determination of depreciationcertain variable revenues and amortization expenses,periods of certain deferred revenues and costs associated with drilling daywork contacts, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, our estimate of compensation related accruals and our estimate of sales tax audit liability.compensation-related accruals.
WeIn accordance with ASC Topic 606, Revenue from Contracts with Customers, we estimate an allowance for doubtful accounts based on the creditworthiness of our clients as well as general economic conditions. We evaluate the creditworthiness of our clients based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we havecertain variable revenues associated with the client. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new clients to establish escrow accounts or make prepayments. We had an allowance for doubtful accounts of $1.2 million and $1.7 million at December 31, 2017 and December 31, 2016, respectively.
Our determination of the useful lives of our depreciable assets directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciationdemobilization of our drilling production, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 1 to 25 years.rigs under daywork drilling contracts. We record the same depreciation expense whether a drilling rig, well servicing rig, wireline unit or coiled tubing unit is idle or working. Ouralso make estimates of the useful livesapplicable amortization periods for deferred mobilization costs, and for mobilization revenues related to cancelable term contracts which represent a material right to our clients. These estimates and assumptions are described in more detail in Note 3, Revenue from Contracts with Customers. In order to make these estimates, management considers all the facts and circumstances pertaining to each particular contract, our past experience and knowledge of our drilling, production, transportationcurrent market conditions. For more information, see Note 3, Revenue from Contracts with Customers, of the Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and other equipment are basedSupplementary Data, of this Annual Report on our almost 50 years of experience in the oilfield services industry with similar equipment.Form 10-K.
We evaluate for potential impairment of long-lived assets when indicators of impairment are present, which may include, among other things, significant adverse changes in industry trends (including revenue rates, utilization rates, oil and natural gas market prices, and industry rig counts). Despite the modest recovery in commodity prices that began in late 2016 and continued through 2017, we continue to monitor all indicators of potential impairments inIn accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments. Due to continued performance at levels lower than anticipatedlower-than-anticipated operating results and a

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decline in our projected cash flows for the coiled tubing reporting unit, we again performed an impairment evaluationanalysis of our coiled tubing business asthis reporting unit at September 30, 2019 and again at December 31, 2019. As a result of June 30, 2017 andthis analysis, we concluded that nothis reporting unit was not at risk of impairment because the estimated fair value of the reporting unit’s assets was present.
in excess of the carrying value. The assumptions usedwe use in the evaluation for impairment evaluation are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment analysesanalysis are reasonable, and appropriate, different assumptions and estimates could materially impact the analysesanalysis and resulting conclusions. The most significant inputs used in our impairment analysis include the projected utilization and pricing of our services, as well as the estimated proceeds upon any future sale or disposal of the assets, all of which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. If commodity prices decrease or remain at current levels for an extended period of time, or if the demand for any of our assets become or remain idle for an extended amount of time, thenservices decreases below what we are currently projecting, our estimated cash flows may further decrease and thereforeour estimates of the probabilityfair value of a near term salecertain assets may increase.decrease as well. If any of the foregoing were to occur, we maycould incur additional impairment charges.charges on the related assets. For more information, see Note 5, 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.
As of December 31, 2017,2019, we had $106.2$102.8 million and $8.0 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of



49



our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. AsDuring the fourth quarter of 2019, as a result of sustained profitability in our foreign operations, forecasted earnings, and other positive evidence, we determined that our foreign deferred tax assets, which include net operating loss carryforwards, were likely to be fully realized, and as a result, we havereduced our valuation allowance and recorded a related income tax benefit of $14.8 million. As of December 31, 2019, we continue to maintain a valuation allowance of $59.8 million that fully offsets a portion of our foreign and U.S. federaldomestic net deferred tax assets as of December 31, 2017. The valuation allowance and the recent change in tax laws are the primary factors causing our effective tax rate to be significantly lower than the statutory rate of 35%.assets. For more information, see Note 5,7, 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.
Our accruedWe use a combination of self-insurance and third-party insurance premiums and deductibles asfor various types of December 31, 2017 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $2.0 million and our workers’ compensation, general liability and auto liability insurance of approximately $4.6 million.coverage. We have stop-loss coverage of $200,000$225,000 per covered individual per year under our health insurance and a deductible of $500,000 per occurrence under our workers’ compensation insurance. We have a deductible of $250,000 per occurrence under both our general liability insurance and auto liability insurance, as well as an additional annual aggregate deductible of $250,000 under our general liability insurance. At December 31, 2019, our accrued insurance premiums and deductibles include approximately $1.3 million of accruals for costs incurred under the self-insurance portion of our health insurance and approximately $3.3 million of accruals for costs associated with our workers’ compensation insurance. We accrue for these costs as claims are incurred using an actuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the costscost of administrative services associated with claims processing.
Our compensation expense includes estimates for certain of our long-term incentive compensation plans which have performance-based award components dependent upon our performance over a set performance period, as compared to the performance of a pre-defined peer group. The accruals for these awards include estimates which affect our compensation expense, employee relatedemployee-related accruals and equity. The accruals are adjusted based on actual achievement levels at the end of the pre-determined performance periods. Additionally, our phantom stock unit awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our statementconsolidated statements of operations. Therefore, changes in the inputs used to measure fair value can result in volatility in our compensation expense. This volatility increases as the phantom stock awards approach the vesting date. For more information, see Note 8,10, Equity Transactions and Stock-Based Compensation Plans, 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.
We are currently undergoing sales and use tax audits for multi-year periods and we are working to resolve all relevant issues. As of December 31, 2017 and December 31, 2016, our accrued liability was $1.2 million and $0.6 million, respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits. For more information, see Note 11, Commitments and Contingencies, 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.
Recently Issued Accounting Standards
For a detail of recently issued accounting standards, 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.

Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.

49




Recent Developments
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “Tax Reform Act”) was enacted, with an effective date of January 1, 2018. The legislation significantly changes U.S. tax law by, among other things, lowering corporate income tax rates from 35% to 21%, repealing the alternative minimum tax (AMT), limiting the deductibility of interest expense, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The net impact of the Tax Reform Act for the period ended December 31, 2017 is a $5.4 million benefit, net of valuation allowances.
For more information, 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.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk — We are subject to interest rate market risk on our variable rate debt. As of December 31, 2017, the principal amount under our Term Loan was $175 million, which is our only variable rate debt with an outstanding balance. The impact of a hypothetical 1% increase or decrease in interest rates on this amount of debt would have resulted in a corresponding increase or decrease, respectively, in interest expense of approximately $1.8 million during the year ended December 31, 2017. This potential increase or decrease is based on the simplified assumption that the level of variable rate debt remains constant with an immediate across-the-board interest rate increase or decrease as of January 1, 2017.Not applicable.
Foreign Currency Risk — While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian Pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar have and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in our consolidated financial statements. The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in net foreign currency gains of $0.3 million for the year ended December 31, 2017.

50

50



ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PIONEER ENERGY SERVICES CORP.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
 Page
  
  
  
  
  



51

51



Report of Independent Registered Public Accounting Firm
The shareholdersTo the Shareholders and boardBoard of directorsDirectors
Pioneer Energy Services Corp.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Pioneer Energy Services Corp. and subsidiaries (the Company) as of December 31, 20172019 and 2016,2018, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-yeartwo-year period ended December 31, 2017,2019, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172019 and 2016,2018, and the results of its operations and its cash flows for each of the years in the three-yeartwo-year period ended December 31, 2017,2019, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control—Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, (COSO), and our report dated February 16, 2018March 6, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Going Concern
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations and is facing risks and uncertainties surrounding its Chapter 11 proceedings that raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for leases as of January 1, 2019 due to the adoption of Accounting Standards Update No. 2016-02, Leases.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatementsmisstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ KPMG LLP
We have served as the Company’s auditor since 1979.
San Antonio, Texas
February 16, 2018March 6, 2020



52

52



Report of Independent Registered Public Accounting Firm
The shareholdersTo the Shareholders and boardBoard of directorsDirectors
Pioneer Energy Services Corp.:
Opinion on Internal Control Over Financial Reporting
We have audited Pioneer Energy Services Corp.’s and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 20172019, based on criteria established in Internal Control—Control — Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2019, based on criteria established in Internal Control—Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 20172019 and 2016,2018, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-yeartwo-year period ended December 31, 2017,2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 16, 2018March 6, 2020 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ KPMG LLP
San Antonio, Texas
February 16, 2018March 6, 2020

53

53



PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

December 31,
2017
 December 31,
2016
December 31,
2019
 December 31,
2018
(in thousands, except share data)(in thousands, except share data)
ASSETS  
Current assets:      
Cash and cash equivalents$73,640
 $10,194
$24,619
 $53,566
Restricted cash2,008
 
998
 998
Receivables:      
Trade, net of allowance for doubtful accounts79,592
 38,764
79,135
 76,924
Unbilled receivables16,029
 7,417
12,590
 24,822
Insurance recoveries13,874
 17,003
22,873
 23,656
Other receivables3,510
 8,939
8,928
 5,479
Inventory14,057
 9,660
22,453
 18,898
Assets held for sale6,620
 15,093
3,447
 3,582
Prepaid expenses and other current assets6,229
 6,926
7,869
 7,109
Total current assets215,559
 113,996
182,912
 215,034
Property and equipment, at cost1,093,635
 1,058,261
1,119,546
 1,118,215
Less accumulated depreciation544,012
 474,181
648,376
 593,357
Net property and equipment549,623
 584,080
471,170
 524,858
Other long-term assets1,687
 2,026
Deferred income taxes11,540
 
Operating lease assets7,264
 
Other noncurrent assets1,068
 1,658
Total assets$766,869
 $700,102
$673,954
 $741,550
      
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities:      
Accounts payable$29,538
 $19,208
$32,551
 $36,766
Deferred revenues905
 1,449
1,339
 1,722
Accrued expenses:      
Payroll and related employee costs21,023
 14,813
Employee compensation and related costs13,781
 24,747
Insurance claims and settlements22,873
 23,593
Insurance premiums and deductibles6,742
 6,446
5,940
 5,482
Insurance claims and settlements13,289
 13,667
Interest6,624
 5,395
5,452
 6,148
Other6,793
 5,024
9,645
 6,310
Total current liabilities84,914
 66,002
91,581
 104,768
Long-term debt, less unamortized discount and debt issuance costs461,665
 339,473
467,699
 464,552
Noncurrent operating lease liabilities5,700
 
Deferred income taxes3,151
 8,180
4,417
 3,688
Other long-term liabilities7,043
 5,049
Other noncurrent liabilities481
 3,484
Total liabilities556,773
 418,704
569,878
 576,492
Commitments and contingencies (Note 11)
 
Commitments and contingencies (Note 13)
 
Shareholders’ equity:      
Preferred stock, 10,000,000 shares authorized; none issued and outstanding
 

 
Common stock $.10 par value; 200,000,000 shares authorized at December 31, 2017; 77,719,021 and 77,146,906 shares outstanding at December 31, 2017 and December 31, 2016, respectively7,835
 7,766
Common stock $.10 par value; 200,000,000 shares authorized; 79,202,216 and 78,214,550 shares outstanding at December 31, 2019 and December 31, 2018, respectively8,008
 7,900
Additional paid-in capital546,158
 541,823
553,210
 550,548
Treasury stock, at cost; 630,688 and 515,546 shares at December 31, 2017 and December 31, 2016, respectively(4,416) (3,883)
Treasury stock, at cost; 877,047 and 789,532 shares at December 31, 2019 and December 31, 2018, respectively(5,090) (4,965)
Accumulated deficit(339,481) (264,308)(452,052) (388,425)
Total shareholders’ equity210,096
 281,398
104,076
 165,058
Total liabilities and shareholders’ equity$766,869
 $700,102
$673,954
 $741,550





See accompanying notes to consolidated financial statements.

54




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
(in thousands, except per share data)(in thousands, except per share data)
        
Revenues$446,455
 $277,076
 $540,778
$575,792
 $590,097
        
Costs and expenses:        
Operating costs330,880
 203,949
 358,016
431,353
 429,913
Depreciation and amortization98,777
 114,312
 150,939
Depreciation90,884
 93,554
General and administrative69,681
 61,184
 73,903
91,185
 74,117
Bad debt expense (recovery)53
 156
 (188)
Bad debt expense (recovery), net(79) 271
Impairment1,902
 12,815
 129,152
2,667
 4,422
Gain on dispositions of property and equipment, net(3,608) (1,892) (4,344)(4,513) (3,121)
Total costs and expenses497,685
 390,524
 707,478
611,497
 599,156
Loss from operations(51,230) (113,448) (166,700)(35,705) (9,059)
        
Other income (expense):        
Interest expense, net of interest capitalized(27,039) (25,934) (21,222)(39,835) (38,782)
Loss on extinguishment of debt(1,476) (299) (2,186)
Other income (expense), net424
 558
 (2,611)
Other income, net2,307
 738
Total other expense, net(28,091) (25,675) (26,019)(37,528) (38,044)
        
Loss before income taxes(79,321) (139,123) (192,719)(73,233) (47,103)
Income tax benefit4,203
 10,732
 37,579
Income tax (expense) benefit9,329
 (1,908)
Net loss$(75,118) $(128,391) $(155,140)$(63,904) $(49,011)
        
Loss per common share - Basic$(0.97) $(1.96) $(2.41)$(0.81) $(0.63)
        
Loss per common share - Diluted$(0.97) $(1.96) $(2.41)$(0.81) $(0.63)
        
Weighted average number of shares outstanding—Basic77,390
 65,452
 64,310
78,423
 77,957
        
Weighted average number of shares outstanding—Diluted77,390
 65,452
 64,310
78,423
 77,957














See accompanying notes to consolidated financial statements.

55




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Shares Amount Additional Paid In Capital 
Accumulated Earnings
(Deficit)
 Total Shareholders’ EquityShares Amount Additional Paid In Capital 
Accumulated
Deficit
 Total Shareholders’ Equity
Common TreasuryCommon TreasuryCommon TreasuryCommon Treasury
(In thousands)(in thousands)
Balance as of December 31, 201464,137
 (317) $6,414
 $(3,030) $472,457
 $19,223
 $495,064
Balance as of December 31, 201778,350
 (631) $7,835
 $(4,416) $546,158
 $(339,481) $210,096
Net loss
 
 
 
 
 (155,140) (155,140)
 
 
 
 
 (49,011) (49,011)
Exercise of options and related income tax effect203
 
 20
 
 761
 
 781
Exercise of options3
 
 
 
 12
 
 12
Purchase of treasury stock
 (141) 
 (729) 
 
 (729)
 (159) 
 (549) 
 
 (549)
Income tax effect of restricted stock vesting
 
 
 
 (884) 
 (884)
Income tax effect of stock option forfeitures and expirations
 
 
 
 (78) 
 (78)
Cumulative-effect adjustment due to adoption of ASC Topic 606

 
 
 
 
 67
 67
Issuance of restricted stock616
 
 62
 
 (62) 
 
651
 
 65
 
 (65) 
 
Stock-based compensation expense
 
 
 
 3,629
 
 3,629

 
 
 
 4,443
 
 4,443
Balance as of December 31, 201564,956
 (458) $6,496
 $(3,759) $475,823
 $(135,917) $342,643
Balance as of December 31, 201879,004
 (790) $7,900
 $(4,965) $550,548
 $(388,425) $165,058
Net loss
 
 
 
 
 (128,391) (128,391)
 
 
 
 
 (63,904) (63,904)
Sale of common stock, net of offering costs12,075



1,208


 64,222



65,430
Exercise of options and related income tax effect46
 
 5
 
 178
 
 183
Purchase of treasury stock
 (58) 
 (124) 
 
 (124)
 (87) 
 (125) 
 
 (125)
Income tax effect of restricted stock vesting
 
 
 
 (1,023) 
 (1,023)
Income tax effect of stock option forfeitures and expirations
 
 
 
 (1,264) 
 (1,264)
Cumulative-effect adjustment due to adoption of ASC Topic 842
 
 
 
 
 277
 277
Issuance of restricted stock586
 
 57
 
 (57) 
 
1,075
 
 108
 
 (108) 
 
Stock-based compensation expense
 
 
 
 3,944
 
 3,944

 
 
 
 2,770
 
 2,770
Balance as of December 31, 201677,663
 (516) $7,766
 $(3,883) $541,823
 $(264,308) $281,398
Net loss
 
 
 
 
 (75,118) (75,118)
Purchase of treasury stock
 (115) 
 (533) 
 
 (533)
Issuance of restricted stock687
 
 69
 
 (69) 
 
Stock-based compensation expense
 
 
 
 4,404
 (55) 4,349
Balance as of December 31, 201778,350
 (631) $7,835
 $(4,416) $546,158
 $(339,481) $210,096
Balance as of December 31, 201980,079
 (877) $8,008
 $(5,090) $553,210
 $(452,052) $104,076



















See accompanying notes to consolidated financial statements.

56




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
(in thousands)(in thousands)
Cash flows from operating activities:        
Net loss$(75,118) $(128,391) $(155,140)$(63,904) $(49,011)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:        
Depreciation and amortization98,777
 114,312
 150,939
Depreciation90,884
 93,554
Allowance for doubtful accounts, net of recoveries53
 156
 248
(79) 271
Write-off of obsolete inventory
 101
 
570
 
Gain on dispositions of property and equipment, net(3,608) (1,892) (4,344)(4,513) (3,121)
Stock-based compensation expense4,349
 3,944
 3,629
2,770
 4,443
Phantom stock compensation expense(112) 47
Amortization of debt issuance costs and discount1,548
 1,776
 1,691
3,147
 2,900
Loss on extinguishment of debt1,476
 299
 2,186
Impairment1,902
 12,815
 129,152
2,667
 4,422
Deferred income taxes(5,030) (11,608) (39,286)(10,811) 538
Change in other long-term assets(1) 662
 420
Change in other long-term liabilities1,994
 478
 (132)
Change in other noncurrent assets3,122
 565
Change in other noncurrent liabilities(4,328) (426)
Changes in current assets and liabilities:        
Receivables(49,750) 16,341
 114,644
7,062
 (8,644)
Inventory(4,397) (630) 1,267
(4,088) (4,841)
Prepaid expenses and other current assets744
 310
 1,769
(809) (1,140)
Accounts payable12,409
 1,969
 (30,514)3,638
 (1,272)
Deferred revenues(348) (3,985) 1,922
(383) 420
Accrued expenses9,183
 (1,526) (35,732)(12,811) 950
Net cash provided by (used in) operating activities(5,817) 5,131
 142,719
Net cash provided by operating activities12,022
 39,655
        
Cash flows from investing activities:        
Purchases of property and equipment(63,277) (32,381) (159,615)(50,046) (67,148)
Proceeds from sale of property and equipment12,569
 7,577
 57,674
7,733
 5,864
Proceeds from insurance recoveries3,344
 37
 285
1,469
 1,082
Net cash used in investing activities(47,364) (24,767) (101,656)(40,844) (60,202)
        
Cash flows from financing activities:        
Debt repayments(120,000) (71,000) (60,002)
Proceeds from issuance of debt245,500
 22,000
 
Debt issuance costs(6,332) (819) (1,877)
Proceeds from exercise of options
 183
 781

 12
Proceeds from issuance of common stock, net of offering costs of $4,001
 65,430
 
Purchase of treasury stock(533) (124) (729)(125) (549)
Net cash provided by (used in) financing activities118,635
 15,670
 (61,827)
Net cash used in financing activities(125) (537)
        
Net increase (decrease) in cash, cash equivalents and restricted cash65,454
 (3,966) (20,764)
Net decrease in cash, cash equivalents and restricted cash(28,947) (21,084)
Beginning cash, cash equivalents and restricted cash10,194
 14,160
 34,924
54,564
 75,648
Ending cash, cash equivalents and restricted cash$75,648
 $10,194
 $14,160
$25,617
 $54,564
        
Supplementary disclosure:        
Interest paid$25,082
 $24,516
 $22,506
$37,342
 $36,624
Income tax paid$1,431
 $671
 $2,691
$3,964
 $3,556
Noncash investing and financing activity:        
Change in capital expenditure accruals$(1,830) $175
 $(16,708)$(5,217) $5,706


See accompanying notes to consolidated financial statements.

57




PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.    Organization and Summary of Significant Accounting Policies
Business
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.
Our drilling services business segments provide contract land drilling services through fourthree domestic divisions which are located in the Marcellus/Utica, Permian Basin and Eagle Ford, Permian Basin and Bakken regions, and internationally in Colombia. In addition to our drilling rigs, weWe provide a comprehensive service offering which includes the drilling rig, crews, supplies, and most of the ancillary equipment needed to operate our drilling rigs. Our drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. The following table summarizes our current rig fleet count and composition for each drilling services business segment:
Multi-well, Pad-capableMulti-well, Pad-capable
AC rigsSCR rigsTotalAC rigs SCR rigs Total
Domestic drilling16

1617
 
 17
International drilling
8
8
 8
 8
 24    25
Our production services business segments provide a range of well, wireline and coiled tubing services to a diverse group of explorationproducers primarily in Texas and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain statesregions, as well as in North Dakota, Louisiana and in the Gulf Coast, both onshore and offshore.Mississippi. As of December 31, 2017,2019, the fleet count and compositioncounts for each of our production services business segments isare as follows:
550 HP600 HPTotal550 HP 600 HP Total
Well servicing rigs, by horsepower (HP) rating113
12
125
112 12 124
OnshoreOffshoreTotal 
 Total
Wireline services units1084
112
Wireline services units 93
Coiled tubing services units10
4
14
Coiled tubing services units 9
Basis of Presentation
The accompanying consolidated financial statements include the accounts of Pioneer Energy Services Corp. and our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.America, which contemplate our continuation as a going concern. See Note 2, Going Concern and Subsequent Events,for more information.
Periods Presented — We currently meet the SEC’s definition of a smaller reporting company and therefore qualify for certain reduced disclosure requirements as permitted by the SEC including, among other things, the presentation of the two most recent fiscal years’ statements of operations, shareholders’ equity, and cash flows.
Use of Estimates In preparing the accompanying consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our estimateestimates of the allowance for doubtful accounts, our determination of depreciationcertain variable revenues and amortization expenses,periods of certain deferred revenues and costs associated with drilling daywork contacts, our estimates of projected cash flows and fair values for impairment evaluations, our estimate of the valuation allowance for deferred tax assets, our estimate of the liability relating to the self-insurance portion of our health and workers’ compensation insurance, our estimate of compensation related accruals and our estimate of sales tax audit liability.compensation-related accruals.
Subsequent Events In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred after December 31, 2017,2019, through the filing of this Annual Report on Form 10-K, for inclusion as necessary.
See Note 2, Foreign CurrenciesGoing Concern and Subsequent Events
Our functional currency ,for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of themore information.

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period. Income statement accountsChange in Accounting Principle and Recently Issued Accounting Standards
Changes to accounting principles generally accepted in the United States of America (“U.S. GAAP”) are translated at average ratesestablished by the Financial Accounting Standards Board (FASB) in the form of Accounting Standards Updates (ASUs) to the FASB Accounting Standards Codification (ASC). We consider the applicability and impact of all ASUs. Any ASUs not listed below were assessed and determined to be either not applicable or are expected to have an immaterial impact on our consolidated financial position and results of operations.
Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases, which among other things, requires lessees to recognize substantially all leases on the balance sheet, with expense recognition that is similar to the former lease standard, and aligns the principles of lessor accounting with the principles of the FASB’s new revenue guidance in ASC Topic 606. In July 2018, the FASB issued ASU No. 2018-11, Leases: Targeted Improvements, which provides an option to apply the guidance prospectively, and provides a practical expedient allowing lessors to combine the lease and non-lease components of revenues where the revenue recognition pattern is the same and where the lease component, when accounted for separately, would be considered an operating lease. The practical expedient also allows a lessor to account for the period. Gainscombined lease and lossesnon-lease components under ASC Topic 606, Revenue from remeasurementContracts with Customers, when the non-lease component is the predominant element of foreign currency financialthe combined component.
As a lessor, we elected to apply the practical expedient which allows us to continue to recognize our revenues (both lease and service components) under ASC Topic 606, and continue to present them as one revenue stream in our consolidated statements into U.S. dollarsof operations. As a lessee, this standard primarily impacts our accounting for long-term real estate and from foreign currency transactions are included in other income or expense.
Revenues and Cost Recognition
Drilling Services—Our drilling services business segments earn revenues by drilling oil and gas wells for our clients under daywork contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate specified in each contract.
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the related contract term. Costs incurred to relocate rigs and other drillingoffice equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expensesleases, for which they relate are recorded aswe recognized an operating costs.
Amortizationlease asset and a corresponding operating lease liability on our consolidated balance sheet of deferred revenues and costs during the years ended December 31, 2017, 2016 and 2015 were as follows (amounts in thousands):
 Year ended December 31,
 2017 2016 2015
Amortization of deferred revenues$2,400
 $1,566
 $1,099
Amortization of deferred costs4,953
 2,813
 2,337
Our current and long-term deferred revenues and costs as of December 31, 2017 and 2016 were as follows (amounts in thousands):
 December 31, 2017 December 31, 2016
Current:   
Deferred revenues$905
 $1,449
Deferred costs1,377
 2,290
Long-term:   
Deferred revenues$558
 $202
Deferred costs402
 212
With most term drilling contracts, we are entitled to receive a full or reduced rate of revenues from our clients if they choose to place a rig on standby or to early terminate the contract before its original expiration term. Generally, these revenues are billed and collected over the remaining term of the contract, as the rig is often placed on standby rather than fully released from the contract, and thus may go back to work$9.8 million at the client’s decision any time beforeadoption date of January 1, 2019. For leases that commenced prior to adoption of ASC Topic 842, we elected to apply the endpackage of practical expedients which allows us to carry forward the contract. Somehistorical lease classification. The adoption of our drilling contracts contain “make-whole” provisions whereby if we are ableASC Topic 842 also resulted in a cumulative effect adjustment of $0.3 million after applicable income taxes, related to secure additional work for the rig with another client, then each party is entitled to a make-whole payment. Ifwrite off of previously unamortized deferred lease liabilities at the dayratesdate of adoption. For more information about the accounting under ASC Topic 842, and disclosures under the new contract are less than the dayrates in the original contract, we would be entitled to a reduced revenue dayrate from the terminating client,standard, see Note 4, Leases.
Significant Accounting Policies and likewise, the terminating client may be entitled to a payment from us if the new contract dayrates exceed thoseDetail of the original contract. A client may also choose to early terminate the contract and make an upfront early termination payment based on a per day rate for the remaining term of the contract. Revenues derived from rigs placed on standby or from the early termination of term drilling contracts are deferred and recognized as the amounts become fixed or determinable, over the remainder of the original term or when the rig is sold. Currently, there are no drilling rigs in our fleet with contracts placed on standby.
Drilling Contracts—As of December 31, 2017, all 16 of our domestic drilling rigs are earning revenues, 14 of which are under term contracts. 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.

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Production Services—Our production services business segments earn revenues for well servicing, wireline services and coiled tubing services pursuant to master services agreements based on purchase orders, contracts or other arrangements with the client that include fixed or determinable prices. Production services jobs are generally short-term and are charged at current market rates. Production service revenue is recognized when the service has been rendered and collectability is reasonably assured.
All of our revenues are recognized net of sales taxes when applicable.
Concentration of Clients—We derive 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.Account Balances
Cash and Restricted Cash Equivalents
For purposes of the consolidated statements of cash flows, we consider all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents. We had no cash— Cash equivalents at December 31, 20172019 and 2016.2018 were $8.9 million and $40.6 million, respectively, consisting of investments in highly-liquid money-market mutual funds.
Restricted Cash Our restricted cash balance at December 31, 2017 reflects the portion of net proceeds from the issuance of our senior secured 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,property.
Revenue — Production services jobs are varied in nature but typically represent a single performance obligation, either for a particular job, a series of distinct jobs, or a period of time during which we expectstand ready to complete within 12 months.provide services as our client needs them. Revenue is recognized for these services over time, as the services are performed. Our drilling services business segments earn revenues by drilling oil and gas wells for our clients under daywork contracts. Daywork contracts are comprehensive agreements under which we provide a comprehensive service offering, including the drilling rig, crew, supplies, and most of the ancillary equipment necessary to operate the rig. We account for our services provided under daywork contracts as a single performance obligation comprised of a series of distinct time increments which are satisfied over time. Accordingly, the related restricted cash is presented as currentdayrate revenues are recognized in the accompanying consolidated balance sheets. period during which the services are performed. All of our revenues are recognized net of sales taxes, when applicable. For more information, see Note 3, Revenue from Contracts with Customers.
Trade and Unbilled Accounts Receivable
We record trade accounts receivable at the amount we invoice to our clients. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our clients and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.
We review our allowance for doubtful accounts on a monthly basis. Our typical drilling contract provides for payment of invoices in 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any Substantially all of our domestic contracts in the last three fiscal years. Our production services terms generally provide for payment of invoices in 30 days. Balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our clients.
The changes in our allowance for doubtful accounts consist of the following (amounts in thousands):
 Year ended December 31,
 2017 2016 2015
Balance at beginning of year$1,678
 $2,254
 $2,547
Increase (decrease) in allowance charged to expense(197) 404
 472
Accounts charged against the allowance(257) (980) (765)
Balance at end of year$1,224
 $1,678
 $2,254

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Unbilled Accounts Receivable
The asset “unbilled receivables” representsunbilled receivables represent revenues we have recognized in excess of amounts billed on drilling contractscontracts. For more information, see Note 3, Revenue from Contracts with Customers.



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Other Receivables — Our other receivables primarily consist of recoverable taxes related to our international operations, as well as vendor rebates and production services completed. We typically bill our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract. Our unbilled receivables as of December 31, 2017 and 2016 were as follows (amounts in thousands):
 December 31, 2017 December 31, 2016
Daywork drilling contracts in progress$15,254
 $7,042
Production services775
 375
 $16,029
 $7,417
net income tax receivables.
Inventories
Inventories primarily consist of drilling rig replacement parts and supplies held for use by our drilling operations in Colombia and supplies held for use by our wireline and coiled tubing operations. Inventories are valued at the lower of cost (first in, first out or actual) or net realizable value.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets include items such as insurance, rent deposits, software subscriptions, and other fees. We routinely expense these items in the normal course of business over the periods that we benefit from these expenses benefit.expenses. Prepaid expenses and other current assets also include the current portion of deferred mobilization costs for certainshort-term drilling contracts that are recognized on a straight-line basis over the contract term.contracts.
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated useful lives of the assets using the straight-line method. We record the same depreciation expense whether our equipment is idle or working. We charge our expenses for maintenance and repairs to operating costs. We capitalize expenditures for renewals and betterments to the appropriate property and equipment accounts. For more information, see Note 5, Property and Equipment.
Other Long-TermNoncurrent Assets
Other long-termnoncurrent assets consist of deferred mobilization costs on long-term drilling contracts, cash deposits related to the deductibles on our workers’ compensation insurance policies, and deferred compensation plan investments, the long-term portion of deferred mobilization costs, and intangible assets.investments.
Other Current Liabilities
Accrued Expenses Our other accrued expenses include accruals for items such as sales taxes, property taxes, withholding tax sales tax,liabilities related to our international operations, and professional and other fees. We routinely expense these items in the normal course of business over the periods these expenses benefit.
Other Long-Term Liabilities
Our other accrued expenses also includes the current portion of the lease liability associated with our long-term operating leases.
Other Noncurrent Liabilities — Our other noncurrent liabilities consist of the noncurrent portion of deferred mobilization revenues and liabilities associated with our long-term compensation plans, deferred lease liabilities,plans.
Insurance Recoveries, Accrued Insurance Claims and Settlements, and Accrued Premiums and Deductibles — We use a combination of self-insurance and third-party insurance for various types of coverage. Our accrued premiums and deductibles include the long-termpremiums and estimated liability for the self-insured portion of deferred mobilization revenues.costs associated with our health, workers’ compensation, general liability, and auto liability insurance. Our insurance recoveries receivables and our accrued liability for insurance claims and settlements represent our estimate of claims in excess of our deductible, which are covered and managed by our third-party insurance providers, some of which may ultimately be settled by the insurance provider in the long-term. These are presented in our consolidated balance sheets as current due to the uncertainty in the timing of reporting and payment of claims. For more information, see Note 11, Employee Benefit Plans and Insurance.
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the cost of the acquired common stock is recorded as treasury stock. Gains and losses on the subsequent reissuance of treasury stock shares are credited or charged to additional paid in capital using the average cost method.
Stock-based Compensation
We recognize compensation cost for our stock-based compensation awards based on the fair value estimated in accordance with ASC Topic 718, Compensation—Stock Compensation,. and we recognize forfeitures when they occur. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was,

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in substance, multiple awards. We adopted ASU 2016-09 in the first quarter of 2017 and elected to prospectively recognize forfeitures when they occur, rather than estimating future forfeitures.For more information, see Note 10, Stock-Based Compensation Plans.
Income Taxes
We follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. The effect of a change in tax rates on deferred tax assets and liabilities is reflected in income in the period of enactment. The recent change in tax rates resulting from the enactment of the Tax Cuts and Jobs Act enacted on December 22, 2017 is described inFor more detail ininformation, see Note 5,7, Income Taxes.
Related-Party Transactions


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DuringForeign Currencies — Our functional currency for our foreign subsidiary in Colombia is the years ended December 31, 2017, 2016U.S. dollar. Nonmonetary assets and 2015,liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the Company paid approximately $0.2 millionend of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in each period for trucking and equipment rental services, which represented arms-length transactions, to Gulf Coast Lease Service. Joe Freeman, our Senior Vice President of Well Servicing, serves as the President of Gulf Coast Lease Service, which is owned and operated by Mr. Freeman’s two sons. Mr. Freeman does not receive compensation from Gulf Coast Lease Service, and he serves primarily in an advisory role to his sons.other income or expense.
Comprehensive Income
We have not reported comprehensive income due to the absence of items of other comprehensive income in the periods presented.
Recently Issued Accounting StandardsReclassificationsCertain amounts in the consolidated financial statements for the prior year has been reclassified to conform to the current year’s presentation.
Changes
2.    Going Concern and Subsequent Events
Going Concern and Financial Reporting in Reorganization
In an effort to achieve liquidity that would be sufficient to meet all of our commitments, we have undertaken a number of actions, including minimizing capital expenditures and reducing recurring expenses. However, we believe that even after taking these actions, we will not have sufficient liquidity to satisfy all of our future financial obligations, comply with our debt covenants, and execute our business plan. As a result, the Pioneer RSA Parties filed a petition for reorganization under Chapter 11 of the Bankruptcy Code on March 1, 2020.
The risks and uncertainties surrounding the Chapter 11 Cases, the defaults under our Debt Instruments, and the weak industry conditions impacting our business raise substantial doubt as to our ability to continue as a going concern. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, which contemplate our continuation as a going concern.
Reorganization and Chapter 11 Proceedings
On March 1, 2020 (the “Petition Date”), Pioneer Energy Services Corp. (“U.S. GAAP”Pioneer”) and its affiliates Pioneer Coiled Tubing Services, LLC, Pioneer Drilling Services, Ltd., Pioneer Fishing & Rental Services, LLC, Pioneer Global Holdings, Inc., Pioneer Production Services, Inc., Pioneer Services Holdings, LLC, Pioneer Well Services, LLC, Pioneer Wireline Services Holdings, Inc., Pioneer Wireline Services, LLC (collectively with Pioneer, the “Pioneer RSA Parties”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Chapter 11 proceedings are establishedbeing jointly administered under the caption In re Pioneer Energy Services Corp. et al (the “Chapter 11 Cases”).
In connection with the Bankruptcy Petitions, the Pioneer RSA Parties entered into a restructuring support agreement (the “RSA”) with holders of approximately 99% in aggregate principal amount of our outstanding Term Loan (the “Consenting Term Lenders”) and holders of approximately 75% in aggregate principal amount of our Senior Notes (the “Consenting Noteholders” and together with the Consenting Term Lenders, the “Consenting Creditors”). The RSA incorporates economic terms regarding a restructuring of the Pioneer RSA Parties agreed to by the Financial Accounting Standards Board (FASB)parties reflected in a term sheet attached as Exhibit B to the RSA. Pursuant to the RSA, the Consenting Creditors and the Pioneer RSA Parties made certain customary commitments to each other, including the Consenting Noteholders committing to vote for, and the Consenting Creditors committing to support, the restructuring transactions (the “Restructuring”) to be effectuated through a plan of reorganization that incorporates the economic terms included in the formRSA (the “Plan”). The Pioneer RSA Parties filed the Plan with the Bankruptcy Court on March 2, 2020.
The commencement of Accounting Standards Updates (ASUs)the Chapter 11 Cases constituted an event of default under certain of our debt instruments that accelerated our obligations under our Senior Notes, the Prepetition ABL Facility, and Term Loan. Under the Bankruptcy Code, holders of our Senior Notes and the lenders under our Term Loan and the Prepetition ABL Facility are stayed from taking any action against us as a result of this event of default.
Upon emergence from Chapter 11, we expect we will be required to adopt the FASB Accounting Standards Codification (ASC). We considerfresh start accounting rules, in which case our assets and liabilities will be recorded at fair value as of the applicabilityfresh start reporting date, which may differ materially from the recorded values of assets and impact of all ASUs; any ASUs not listed below were assessed and determined to be either not applicable or are expected to have an immaterial impactliabilities on our consolidated financial positionbalance sheets.



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Debtor-in-Possession Financing and resultsNew Revolver
On February 28, 2020, we received commitments pursuant to the Commitment Letter from PNC Bank, N.A. for a $75 million asset-based revolving loan debtor-in-possession financing facility and a $75 million asset-based revolving exit financing facility. On March 3, 2020, with the approval of operations.the Bankruptcy Court, we entered into the DIP Facility and used the proceeds of the initial extensions of credit thereunder to refinance all outstanding letters of credit under the Prepetition ABL Facility in connection with the termination of the Prepetition ABL Facility and to pay fees and expenses in connection with the Chapter 11 Cases and transactional and professional fees related thereto.
The DIP Facility has a 5-month maturity, bears interest at a rate of LIBOR plus 200 basis points per annum, and contains customary covenants and events of default. The borrowers and guarantors under the DIP Facility are the same as the borrowers and guarantors under the Prepetition ABL Facility. Subject to certain exceptions, our obligations under the DIP Facility are superpriority administrative expenses in the Chapter 11 Cases and are secured by a first-priority lien on inventory and cash and a second-priority lien on all other assets of the borrowers and guarantors thereunder.
The Commitment Letter contemplates that upon our emergence from the Chapter 11 Cases, subject to the satisfaction of certain customary conditions, the DIP Facility will “roll” into the New Revolver. Subject to the terms and conditions of the Commitment Letter, the New Revolver will have a 5-year maturity, will bear interest at a rate per annum between LIBOR plus 175 basis points and LIBOR plus 225 basis points (depending on the average excess availability under the New Revolver), and will contain customary covenants and events of default. Subject to certain exceptions and permitted liens, the obligations of the borrowers and guarantors under the New Revolver will be secured by a first-priority lien on inventory and cash and a second-priority lien on substantially all other assets of the borrowers and guarantors thereunder. We anticipate that the proceeds of the New Revolver will be used to repay in full all amounts outstanding under the DIP Facility and for general corporate purposes.
3.    Revenue Recognition.from Contracts with Customers
In May 2014,Our production services business segments earn revenues for well servicing, wireline services and coiled tubing services pursuant to master services agreements based on purchase orders or other contractual arrangements with the FASB issued ASU No. 2014-09,client. Production services jobs are generally short-term (ranging in duration from several hours to less than 30 days) and are charged at current market rates for the labor, equipment and materials necessary to complete the job. Production services jobs are varied in nature but typically represent a single performance obligation, either for a particular job, a series of distinct jobs, or a period of time during which we stand ready to provide services as our client needs them. Revenue is recognized for these services over time, as the services are performed.
Our drilling services business segments earn revenues by drilling oil and gas wells for our clients under daywork contracts. Daywork contracts are comprehensive agreements under which we provide a comprehensive new revenue recognition standard that will supersede nearly all existing revenue recognition guidance. The standard outlines a single comprehensive model for revenue recognition based onservice offering, including the core principle that a company will recognize revenue when promised goods or services are transferred to clients, in an amount that reflects the consideration to which an entity expects to be entitled in exchange for those goods or services. We have substantially completed our assessmentdrilling rig, crew, supplies, and most of the impactancillary equipment necessary to operate the rig. Contract modifications that extend the term of this new standard.
a dayrate contract are generally accounted for prospectively as a separate dayrate contract. We expect that the application of this new standard will result in the recognition ofaccount for our services provided under daywork contracts as a single performance obligation comprised of a series of distinct time increments which are satisfied over time. Accordingly, dayrate revenues are recognized in the period during which the services are performed.
With most drilling contracts, we also receive payments contractually designated for the mobilization and demobilization of drilling rigs and other equipment to and from the client’s drill site. Revenues associated with the mobilization and demobilization whichof our drilling rigs to and from the client’s drill site do not relate to a distinct good or service will beand are recognized ratably over the related contract term.
The amount of demobilization revenue that we ultimately collect is dependent upon the specific contractual terms, most of which include provisions for reduced (or no) payment for demobilization when, among other things, the contract is renewed or extended with the same client, or when the rig is subsequently contracted with another client prior to the termination of the current contract. Since revenues associated with demobilization activity are typically variable, at each period end, they are estimated at the most likely amount, and constrained when the likelihood of a significant reversal is probable. Any change in the expected amount of demobilization revenue is accounted for with the net cumulative impact of the change in estimate recognized in the period during which the revenue estimate is revised.



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The upfront costs that we incur to mobilize the drilling rig to our client’s initial drilling site are capitalized and recognized ratably over the term of the contract. All other revenues associated with the services we provide,related contract, including dayrate revenues and production services revenues, will continue to be recognized inany contracted renewal or extension periods, which is our estimate of the period during which we expect to benefit from the services are performed. We expect our revenue recognition undercost of mobilizing the new standard to differ from our current revenue recognition pattern primarily as it relates to drillingrig. Costs associated with the final demobilization revenue, which, prior to the new standard, is recognized when the demobilization activity occurs at the end of the contract term but underare expensed when incurred, when the new guidance willdemobilization activity is performed.
From time to time, we may receive fees from our clients for capital improvements to our rigs to meet our client’s requirements. Such revenues are not considered to be estimateddistinct within the terms of the contract and recognizedare therefore allocated to the overall performance obligation, satisfied over the term of the contract. We record deferred revenue for such payments and recognize them ratably as revenue over the initial term of the related drilling contract.
This new standard is effectiveWe also act as a principal for certain reimbursable services and auxiliary equipment provided by us beginning January 1, 2018,to our clients, for which we have adopted usingincur costs and earn revenues, many of which are variable, or dependent upon the modified retrospective method,activity that is actually performed each day under the related contract. Accordingly, reimbursements that we receive for out-of-pocket expenses are recorded as revenues and the out-of-pocket expenses for which they relate are recorded as operating costs during the period to which they relate within the series of distinct time increments.
All of our revenues are recognized net of sales taxes, when applicable.
Trade and Unbilled Accounts Receivable
We record trade accounts receivable at the amount we invoice to our clients. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in which the standard is applied to all contracts existingour accounts receivable as of the datebalance sheet date. We determine the allowance based on the credit worthiness of our clients and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.
Our production services terms generally provide for payment of invoices in 30 days. Our typical drilling contract provides for payment of invoices in 30 days, though the process for invoicing work performed in our international operations generally lengthens the billing cycle for those operations. We review our allowance for doubtful accounts on a monthly basis and balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our clients.
The changes in our allowance for doubtful accounts consist of the following (amounts in thousands):
 Year ended December 31,
 2019 2018
Balance at beginning of year$1,423
 $1,224
Increase (decrease) in allowance charged to expense(167) 271
Accounts charged against the allowance(432) (72)
Balance at end of year$824
 $1,423
Substantially all of our unbilled receivables represent revenues we have recognized in excess of amounts billed on drilling contracts. We typically bill our clients at 15-day intervals during the performance of daywork drilling contracts and upon completion of the daywork contract.
Contract Asset and Liability Balances and Contract Cost Assets
Contract asset and contract liability balances relate to demobilization and mobilization revenues, respectively. Demobilization revenue that we expect to receive is recognized ratably over the related contract term, but invoiced upon completion of the demobilization activity. Mobilization revenue, which is typically collected upon the completion of the initial application,mobilization activity, is deferred and recognized ratably over the related contract term. Contract asset and liability balances are netted at the contract level, with the cumulative effect of applyingnet current and noncurrent portions separately classified in our consolidated balance sheets, and referred to herein as “deferred revenues.”
Contract cost assets represent the standardcosts associated with the initial mobilization required in order to fulfill the contract, which are deferred and recognized in retained earnings (the adoption date adjustments). We estimate thatratably over the adoption of this standard results in a cumulative effect adjustment of less than $1.0 million before applicable income taxes,period during which primarily consistswe expect to benefit from the mobilization, or the period during which we expect to satisfy the performance obligations of the impact of the timing difference related to recognition of demobilization revenue for affected contracts.contract. Contract cost assets are presented as

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either current or noncurrent, according to the duration of the original contract to which it relates, and referred to herein as “deferred costs.”
Our current and noncurrent deferred revenues and costs as of December 31, 2019 and 2018 were as follows (amounts in thousands):
 As of December 31,
 2019 2018
Current deferred revenues$1,339
 $1,722
Current deferred costs1,071
 1,543
    
Noncurrent deferred revenues$57
 $437
Noncurrent deferred costs267
 679
The changes in deferred revenue and cost balances during the year ended December 31, 2019 are primarily related to the amortization of deferred revenues and costs during the period, mostly offset by increased deferred revenue and cost balances for the deployment of rigs under new contracts in 2019 as well as an increase in deferred revenues associated with a prepayment made by one of our international clients. Amortization of deferred revenues and costs during the years ended December 31, 2019 and 2018 were as follows (amounts in thousands):
 Year ended December 31,
 2019 2018
Amortization of deferred revenues$6,203
 $2,961
Amortization of deferred costs4,786
 2,855
In 2019, three of our domestic clients elected to early terminate their contract with us and make an upfront early termination payment based on a per day rate for the respective remaining contract term, resulting in $3.1 million of revenues recognized during 2019. As of December 31, 2019, 18 of our 25 rigs are earning under daywork contracts, 12 of which are domestic term contracts, and 2 international rigs are currently on standby under term contracts.
Unlike our domestic term contracts, our international drilling contracts are cancelable by our clients without penalty, although the contracts require 15 to 30 days notice and payment for demobilization services. The spot contracts for our domestic drilling rigs are also terminable by our client with 30 days notice and include a required payment for demobilization services. Revenues associated with the initial mobilization and/or demobilization of drilling rigs under cancelable contracts are deferred and recognized ratably over the anticipated duration of the original contract, which is the period during which we work towards finalizingexpect our assessment,client to benefit from the mobilization of the rig, and represents a separate performance obligation because the payment for mobilization and/or demobilization creates a material right to our client during the cancelable period, for which the transaction price is allocated to the optional goods and services expected to be provided.
Remaining Performance Obligations
We have elected to apply the practical expedients in ASC Topic 606, Revenue from Contracts with Customers, which allow entities to omit disclosure of (i) the transaction price allocated to the remaining performance obligations associated with short-term contracts, and (ii) the estimated variable consideration related to wholly unsatisfied performance obligations, or to distinct future time increments within a series of performance obligations. Therefore, we have not disclosed the remaining amount of fixed mobilization revenue (or estimated future variable demobilization revenue) associated with short-term contracts, and we have not disclosed an estimate of the amount of future variable dayrate drilling revenue. However, the amount of fixed mobilization revenue associated with remaining performance obligations is reflected in the net unamortized balance of deferred mobilization revenues, which is presented in both current and noncurrent portions in our consolidated balance sheet, and discussed in more detail in the section above entitled, Contract Asset and Liability Balances and Contract Cost Assets.
Disaggregation of Revenue
ASC Topic 606 requires disclosure of the disaggregation of revenue into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are continuing to evaluateaffected by economic factors. We believe the requirementsdisclosure of revenues by operating segment achieves the objective of this standarddisclosure requirement. See Note 12, Segment Information, for the disaggregation of revenues by operating segment, which reflects the disaggregation of revenues by the type of services provided and complete other implementation activities such as implementing new procedures, finalizingby geography (international versus domestic).



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Concentration of Clients
We derive a significant portion of our revenue from a limited number of major clients. For the adoption date adjustmentyears ended December 31, 2019 and drafting disclosures.2018, our drilling and production services provided to our top three clients accounted for approximately 18% and 20%, respectively, of our revenue.
Leases.4.     Leases
In February 2016,As a drilling and production services provider, we provide the FASB issueddrilling rigs and production services equipment which are necessary to fulfill our performance obligations and which are considered leases under ASU No. 2016-02, Leases, (together with its amendments, herein referred to as “ASC Topic 842”). However, ASU No. 2018-11, Leases: Targeted Improvements, which among other things, requires lesseesallows lessors to (i) combine the lease and non-lease components of revenues when the revenue recognition pattern is the same and when the lease component, when accounted for separately, would be considered an operating lease, and (ii) account for the combined lease and non-lease components under ASC Topic 606, Revenue from Contracts with Customers, when the non-lease component is the predominant element of the combined component. We elected to apply this expedient and therefore continue to recognize substantially all leases on the balance sheet, with expense recognition that is similarour revenues (both lease and service components) under ASC Topic 606, and continue to the current lease standard, and aligns the principlespresent them as one revenue stream in our consolidated statements of lessor accounting with the principles of the FASB’s new revenue guidance (referenced above). This ASU is effective for us beginning January 1, 2019 and requires a modified retrospective application, although certain practical expedients are permitted.operations.
We have performed a scoping and preliminary assessment of the impact of this new standard. As a lessee, this standard will impact uswe lease our corporate office headquarters in situations whereSan Antonio, Texas, and we conduct our business operations through 25 other regional offices located throughout the United States and internationally in Colombia. These operating locations typically include regional offices, storage and maintenance yards and employee housing sufficient to support our operations in the area. We lease most of these properties under non-cancelable term and month-to-month operating leases, many of which contain renewal options that can extend the lease term from six months to five years and some of which contain escalation clauses. We also lease supplemental equipment, typically under cancelable short-term and very short term (less than 30 days) leases. Due to the nature of our business, any option to renew these short-term leases, and the options to extend certain of our long-term real estate leases, are generally not considered reasonably certain to be exercised. Therefore, the periods covered by such optional periods are not included in the determination of the term of the lease, and the lease payments during these periods are similarly excluded from the calculation of operating lease asset and lease liability balances.
In accordance with ASC Topic 842, we recognize an operating lease asset and a corresponding operating lease liability for all our long-term leases, which include real estate and office equipment leases, for which we will recognize a right-of-useelected to combine, or not separate, the lease and non-lease components, and therefore, all fixed charges associated with non-lease components are included in the lease payments and the calculation of the operating lease asset and a correspondingassociated lease liability. The operating lease asset and operating lease liability onare discounted at the rate which represents our consolidated balance sheet. The future lease obligations disclosed in Note 4, Leases, provides some insight to the estimated impact of adoption for ussecured incremental borrowing rate, as a lessee. As a lessor,our leases do not provide an implicit rate, and which we expect the adoption of this new standard will apply to our drilling contracts and as a result, we expect to have a lease component and a service component of our revenues derived from these contracts. We have not yet determined the impact this standard may have on our production services businesses. We continue to evaluate the impact of this guidance and have not yet determined its impact on our financial position and results of operations.
Stock-Based Compensation. In March 2016, the FASB issued ASU No. 2016-09, Stock Compensation: Improvements to Employee Share-Based Payment Accounting, to reduce complexity in accounting standards involving several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classificationestimate based on the statementrate in effect under our asset-based lending facility.
We recognize rent expense on a straight-line basis, except for certain variable expenses which are recognized when the variability is resolved, typically during the period in which they are paid. Variable lease payments typically include charges for property taxes and insurance, and some leases contain variable payments related to non-lease components, including common area maintenance and usage of cash flows.
We adopted this ASU as of January 1, 2017 and we recognized a $3.1 million deferred tax asset for previously unrecognized tax benefits, which was then fully reserved by a valuation allowance (see Note 5, Income Taxes). Additionally, we elected to prospectively account for forfeitures as they occur, rather than estimating future forfeitures. The total cumulative-effect impact of adoption, net of valuation allowances, was approximately $55,000 relating to our change in accounting for forfeitures, and was recognized as a reduction to retained earnings in our consolidated statement of shareholders’ equity, together with the impact of stock-based compensation expense. The adoption of this ASU also results in the presentation of any excess tax benefits resulting from the exercise of stock options as operating cash flows in the statement of cash flows, which we apply retrospectively for any comparative periods affected.
Restricted Cash in Statement of Cash Flows. In November 2016, the FASB issued ASU No. 2016-18, Restricted Cash (a consensus of the FASB Emerging Issues Task Force)office equipment (for example, copiers), which requires that restricted cash be included with cash and cash equivalents when reconcilingtotaled approximately $1.2 million during the beginning and end-of-period total amounts shown on the statement of cash flows. This guidance must be applied retrospectively to all periods presented. We early adopted this ASU effectiveyear ended December 31, 2017. See Cash and Restricted Cashsection above, included2019. The following table summarizes our lease expense recognized, excluding variable lease costs (amounts in this Note 1, Organization and Summary of Significant Accounting Policies, for detail regarding the nature of our restricted cash.thousands):
Reclassifications
Certain amounts in the consolidated financial statements for the prior years have been reclassified to conform to the current year’s presentation.
We revised our reportable business segments as of the fourth quarter of 2017, which now include five operating segments, comprised of two drilling services business segments (domestic and international drilling) and three production services business segments (well servicing, wireline services and coiled tubing services). We revised our segments to reflect changes in the basis used by management in making decisions regarding our business for resource allocation and performance assessment. These changes reflect our current operating focus as is required by ASC Topic 280, Segment Reporting. See Note 10, Segment Informationfor this revised presentation.
 Year ended December 31,
 2019
Long-term operating lease expense$3,699
Short-term operating lease expense$15,187

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The following table summarizes the amount and timing of our obligations associated with our long-term operating leases (amounts in thousands):
 December 31, 2019 December 31, 2018
Within 1 year$2,496
 $3,318
In the second year1,933
 2,032
In the third year1,447
 1,721
In the fourth year1,117
 1,407
In the fifth year912
 1,110
Thereafter811
 1,738
Total undiscounted lease obligations$8,716
 $11,326
Impact of discounting(818)  
Discounted value of operating lease obligations$7,898
  
    
Current operating lease liabilities$2,198
  
Noncurrent operating lease liabilities5,700
  
 $7,898
  
We have an additional operating lease for a domestic drilling office and yard that will commence in the first quarter of 2020, for which the total undiscounted cash flows approximate $1.5 million.
The following table summarizes the weighted-average remaining lease term and discount rate associated with our long-term operating leases:
December 31, 2019
Weighted-average remaining lease term (in years)4.5
Weighted-average discount rate4.5%
2.5.    Property and Equipment
As of December 31, 2017 and 2016,The following table presents the estimated useful lives and costs of our asset classes are as follows:assets by class:
 As of December 31, As of December 31,
  2017 2016  2019 2018
Lives     Cost (amounts in thousands)Lives     Cost (amounts in thousands)
Drilling rigs and equipment3 - 25 $594,743
 $582,477
3 - 25 $613,061
 $590,148
Well servicing rigs and equipment3 - 20 244,747
 225,125
3 - 20 259,102
 252,589
Wireline units and equipment1 - 10 142,224
 141,959
1 - 10 131,628
 144,171
Coiled tubing units and equipment1 - 7 18,141
 16,347
1 - 7 30,816
 25,689
Vehicles3 - 10 47,932
 45,424
3 - 10 50,308
 50,317
Office equipment3 - 10 12,717
 11,628
3 - 10 12,353
 11,606
Buildings and improvements3 - 40 24,013
 23,884
3 - 40 16,988
 23,610
Property and equipment not yet placed in service 6,751
 9,050
 3,330
 17,718
Land 2,367
 2,367
 1,960
 2,367
 $1,093,635
 $1,058,261
 $1,119,546
 $1,118,215
Capital Expenditures—Our capital expendituresexpenditure additions were $61.4 million, $32.6$44.8 million and $142.9$72.9 million, including the impact of accruals for capital additions, during the years ended December 31, 2019 and 2018, respectively. Capital additions during 2019 primarily related to various upgrades and refurbishments of our drilling and production services fleets, vehicle and ancillary equipment purchases, and the completion of construction on our 17th AC drilling rig, which we deployed in March. Capital additions during 2018 primarily related to various routine expenditures to maintain our fleets and the purchase of new support equipment, expansion of our coiled tubing and wireline fleets, capital projects to upgrade and refurbish certain components of our international and domestic drilling rigs, the partial construction of the AC drilling rig deployed in March 2019, and vehicle fleet upgrades in all domestic business segments.
Gain/Loss on Disposition of Property — We recognized net gains of $4.5 million and $3.1 million during the years ended December 31, 2017, 2016,2019 and 2015,2018, respectively, which includes $0.4 million, $0.2 million and $3.0 million, respectively, of capitalized interest costs incurred in connection with the expansion of our well servicing fleet in 2017 and the construction of new drilling rigs and other drilling equipment in 2016 and 2015.
Capital expenditures during 2017 primarily related to the acquisition of 20 well servicing rigs and expansion of our wireline fleet, upgrades to certain domestic drilling rigs, routine capital expenditures necessary to deploy assets that were previously idle, and other new drilling equipment and trucks. Capital expenditures during 2016 consisted primarily of routine expenditures to maintain our drilling and production services fleets, and expenditures for equipment ordered in 2014 before the market slowdown. During 2015, capital expenditures primarily related to our five drilling rigs which began construction during 2014 and were completed in 2015, as well as unit additions to our production services fleets that were ordered in 2014.
Capital expenditures incurred for property and equipment not yet placed in service as of December 31, 2017 was primarily related to routine refurbishments on one international drilling rig in preparation for its deployment in 2018, installments on the purchase of three wireline units and one coiled tubing unit, and scheduled refurbishments on drilling and production services equipment. At December 31, 2016, property and equipment not yet placed in service was primarily related to new drilling equipment that was ordered in 2014 but required a long lead-time for delivery, as well as deposits for 20 well servicing rigs and four new wireline units that were on order for delivery in 2017.
Gain/Loss on Disposition of Property—We recorded a net gain during the year ended December 31, 2017 of $3.6 million on the disposition or sale of various property and equipment, primarily for 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.
During 2016, we recorded a net gain of $1.9 million on the disposition of property and equipment, primarily for the sale of three SCR drilling rigs and other drilling equipment for aggregate net proceeds of $11.9 million, and the disposal of excess drill pipe for a gain. The net gains on disposition of assets were partially offset by a loss on the disposition of damaged property when one of our AC drilling rigs sustained damages that resulted in a disposal of damaged components with an aggregate net carrying value of $4.0 million, for which we received insurance proceeds of $3.1 million in January 2017.
During 2015, we recorded a net gain of $4.3 million primarily from the sale of 32 drilling rigs and other drilling equipment which we sold for aggregate net proceeds of $53.6 million.
Assets Held for Sale—As 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 two wireline units and one coiled tubing unit and spare equipment. As of December 31, 2016, our consolidated balance sheet reflects assets held for sale of $15.1 million, which primarily represents the fair value of six domestic mechanical and SCR drilling rigs and drilling equipment, 13 wireline units, 20 older well servicing rigs that were traded in for 20 new-model rigs in the first quarter of 2017, and certain coiled tubing equipment.including

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drill pipe and collars, a domestic drilling yard, and certain older and/or underutilized equipment, most of which were previously held for sale.
ImpairmentsAssets Held for Sale We have various equipment designated as held for sale, with values of $3.4 million and $3.6 million in aggregate as of December 31, 2019 and 2018, respectively, primarily consisting of real estate property for two wireline locations closed during 2019, and the remaining equipment from two SCR drilling rigs which were held for sale at the end of 2018 and dismantled for spare parts in 2019.
During the years ended December 31, 2019 and 2018, we recognized impairment charges of $2.7 million and $4.4 million, respectively, to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures.
Impairments — In accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments. We evaluate for potential impairment of long-lived assets when indicators of impairment are present, which may include, among other things, significant adverse changes in industry trends (including revenue rates, utilization rates, oil and natural gas market prices, and industry rig counts). In performing an impairment evaluation, we estimate the future undiscounted net cash flows from the use and eventual disposition of the assets grouped at the lowest level that independent cash flows can be identified. We perform an impairment evaluation and estimate future undiscounted cash flows for each of our reporting unitsasset groups separately, which are our domestic drilling services, international drilling services, well servicing, wireline services and coiled tubing services segments. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the asset group, then we determine the fair value of the asset group. Thegroup, and the amount of an impairment charge iswould be measured as the difference between the carrying amount and the fair value of the assets.
BeginningDue to adverse factors affecting our well servicing operations, including increased competition and labor shortages in late 2014, oil prices declined significantly resulting in a downturn in our industry that persisted through 2016, affecting both drilling and production services. As a result, we performed several impairment evaluations on our long-lived assets, in accordance with ASC Topic 360, Property, Plant and Equipment, summarized below.
As of December 31, 2014, we owned a total of 31 mechanicalcertain well servicing markets, and lower horsepower electric drilling rigs,than anticipated utilization, all of which were subsequently sold or placed as held for sale during 2015. As the downturn worsened through 2015, resultingcontributed to a decline in significantly reduced revenue and utilization rates, and our projections reflected a more delayed recovery than previously anticipated, we performed impairment testing in 2015 on all the SCR drilling rigs in our domestic and international fleets, and our coiled tubing operations.
As a result of the impairment testing performed in 2015, we recognized $9.7 million to reduce the carrying values of the six SCR drilling rigs that were not pad-capable, and $18.6 million to reduce the carrying values of the six domestic pad-capable SCR rigs in our fleet (those equipped with either a walking or skidding system), to their estimated fair values, based on market appraisals which are considered Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. All of these drilling rigs were subsequently either sold, retired, or placed as held for sale during 2015 and 2016.
We also recognized impairment charges during 2015 of $60.2 million related to our international drilling operations in Colombia ($50.2 million to reduce the carrying values of all eight drilling rigs and related drilling equipment, $3.6 million to reduce the carrying value of inventory, and $6.4 million to reduce the carrying value of nonrecoverable prepaid taxes) and $30.9 million related to our coiled tubing operations ($14.3 million related to our coiled tubing intangibles and $16.6 million to reduce the carrying values of our coiled tubing units and equipment to their estimated fair value, based on market appraisals).
As business conditions and our projected cash flows for our Colombian operations improved as compared to the projections used for thewell servicing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2018. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the sum of the estimated future undiscounted net cash flows for our well servicing reporting unit was significantly in 2015, we did not perform any impairment testing on this business in 2016 or 2017. However, dueexcess of the carrying amount.
Due to lower than anticipatedlower-than-anticipated operating results in 2016 and 2017 and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of our coiled tubing long-lived assetsthis reporting unit at September 30, 20162019 and again at June 30, 2017, which indicatedDecember 31, 2019. As a result of this analysis, we concluded that our projected net undiscounted cash flows associated with the coiled tubingthis reporting unit werewas not at risk of impairment because the estimated fair value of the reporting unit’s assets was in excess of the net carrying value of the assets at both dates and thus no impairment was present.value.
During the years ended December 31, 2017, 2016 and 2015, we recognized impairment charges of $1.9 million, $11.9 million, and $9.9 million, respectively, to reduce the carrying values of assets which were classified as held for sale, to their estimated fair values, based on expected sales prices which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures. During the year ended December 31, 2016, we also recognized $0.9 million of impairment charges to reduce the carrying value of a portion of steel that is on hand for the construction of drilling rigs, which we no longer believe is likely to be used.

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The following table summarizes impairment expense recognized during the years ended December 31, 2017, 2016, and 2015 (amounts in thousands):
 Year ended December 31,
 2017 2016 2015
Assets held for sale$1,902
 $11,897
 $9,858
Colombian assets
 
 60,130
Domestic drilling rigs and equipment
 918
 28,228
Coiled tubing assets
 
 30,936
 $1,902
 $12,815
 $129,152
In order to estimate our future undiscounted cash flows from the use and eventual disposition of our drilling assets, we incorporated probabilities of selling these assets in the near term, versus working them at a significantly reduced expected rate of utilization through the end of their remaining useful lives. The most significant assumptionsinputs used in our impairment analysis areinclude the expected margin per dayprojected utilization and utilization,pricing of our services, as well as the estimated proceeds upon any future sale or disposal of the assets. We used an income approach to estimate the fair valueassets, all of our coiled tubing services reporting unit in 2016 and 2017. The most significant inputs used in our impairment analysis of our coiled tubing operations include the projected utilization and pricing of our coiled tubing services, which are classified as Level 3 inputs as defined by ASC Topic 820, Fair Value Measurements and Disclosures.
The assumptions we use in the evaluation for impairment are inherently uncertain and require management judgment. Although we believe the assumptions and estimates used in our impairment analysesanalysis are reasonable, and appropriate, different assumptions and estimates could materially impact the analysesanalysis and resulting conclusions. The assumptions used inIf commodity prices decrease or remain at current levels for an extended period of time, or if the impairment evaluation are inherently uncertain and require management judgment.These impairment charges are not expected to have an impact on our liquidity or debt covenants; however, they are a reflection of the overall downturn in our industry and decline in our projected future cash flows. Ifdemand for any of our assets become or remain idle for an extended amount of time, thenservices decreases below what we are currently projecting, our estimated cash flows may further decrease and thereforeour estimates of the probabilityfair value of a near term salecertain assets may increase.decrease as well. If any of the foregoing were to occur, we maycould incur additional impairment charges.charges on the related assets.



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3.6.     Debt
Our debt consists of the following (amounts in thousands):
December 31, 2017 December 31, 2016December 31, 2019 December 31, 2018
Senior secured term loan$175,000
 $
$175,000
 $175,000
Senior secured revolving credit facility
 46,000
Senior notes300,000
 300,000
300,000
 300,000
475,000
 346,000
475,000
 475,000
Less unamortized discount (based on imputed interest rate of 10.44%)(3,387) 
Less unamortized discount (based on imputed interest rate of 10.46%)(1,869) (2,668)
Less unamortized debt issuance costs(9,948) (6,527)(5,432) (7,780)
$461,665
 $339,473
$467,699
 $464,552
The commencement of the Chapter 11 Cases constituted an event of default under certain of our debt instruments that accelerated our obligations under our Senior Notes, the Prepetition ABL Facility, and Term Loan. Under the Bankruptcy Code, holders of our Senior Notes and the lenders under our Term Loan and the Prepetition ABL Facility are stayed from taking any action against us as a result of this event of default.
For additional information concerning our bankruptcy proceedings under Chapter 11, see Note 2, Going Concern and Subsequent Events, and Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K.
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,previous credit facility, plus fees and accrued and unpaid interest, as well as the fees and expenses associated with entering into the Term Loan and Prepetition 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 not subject to amortization payments of principal. Interest on the principal amount accrues at the LIBOR rate or the base rate as defined in the agreement, at our option, plus an applicable margin of 7.75% and 6.75%, respectively. 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. However, the Term Loan may be prepaid, at our option, at any time, in whole or in part, subject to a minimum of $5 million, and subject to a declining call premium as defined in the agreement.

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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.
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, 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, 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, including without limitation:
payment defaults;
covenant defaults;
material breaches of representations or warranties;



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event of default under, or acceleration of, other material indebtedness;
bankruptcy or insolvency;
material judgments against us;
failure of any security document supporting the Term Loan; and
change of control.
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.
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“Prepetition 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 Prepetition ABL Facility bears interest, at our option, at the LIBOR rate or the base rate as defined in the Prepetition ABL Facility, plus an applicable margin ranging from 1.75% to 3.25%, based on average availability on the Prepetition ABL Facility. The Prepetition ABL Facility requires a commitment fee due monthly based on the average monthly unused amount of the commitments of the lenders, a fronting fee due for each letter of credit issued, and a monthly letter of credit fee due based on the average undrawn amount of letters of credit outstanding during such period. The Prepetition 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. Availability under the Prepetition ABL Facility will beis determined by reference to a borrowing base as defined in the agreement, generally comprised of a percentage of our accounts receivable and inventory.
We have not drawn upon the Prepetition ABL Facility to date. As of December 31, 2017,2019, we had $9.7$9.4 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $53.1$48.0 million. Borrowings available under the Prepetition 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 Prepetition ABL Facility is maintained. Additionally, if our availability under the Prepetition ABL Facility is less than 15% of the maximum amount (or $11.25 million), we are required to maintain a minimum fixed charge coverage ratio, as defined in the Prepetition ABL Facility, of at least 1.00 to 1.00, measured on a trailing 12 month12-month basis.
The Prepetition ABL Facility also contains customary restrictive covenants which, subject to certain exceptions, limit, among other things, our ability to:
declare dividends and make other distributions;

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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.
Our obligations under the Prepetition 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.
Senior Notes
In 2014, we issued $300 million of unregistered senior notes at face value, with a coupon interest rate of 6.125% that are due in 2022 (the “Senior Notes”). The Senior Notes will mature on March 15, 2022 with interest due semi-annually in arrears on March 15 and September 15 of each year. We have the option to redeem the Senior Notes, in whole or in part, at any time on or after March 15, 2017 in each case at the redemption price specified in the Indenture dated March 18, 2014 (the “Indenture”) plus any accrued and unpaid interest and any additional interest (as defined in the Indenture) thereon to the date of redemption.



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In accordance with a registration rights agreement with the holders of our Senior Notes, we filed an exchange offer registration statement on Form S-4 with the Securities and Exchange Commission that became effective on October 2, 2014. The exchange offer registration statement enabled the holders of our Senior Notes to exchange their senior notes for publicly registered notes with substantially identical terms. References to the “Senior Notes” herein include the senior notes issued in the exchange offer.
If we experience a change of control (as defined in the Indenture), we will be required to make an offer to each holder of the Senior Notes to repurchase all or any part of the Senior Notes at a purchase price equal to 101% of the principal amount of each Senior Note, plus accrued and unpaid interest, if any, to the date of repurchase. If we engage in certain asset sales, within 365 days of such sale we will be required to use the net cash proceeds from such sale, to the extent we do not reinvest those proceeds in our business, to make an offer to repurchase the Senior Notes at a price equal to 100% of the principal amount of each Senior Note, plus accrued and unpaid interest to the repurchase date.
The Indenture, 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 Senior Notes are not subject to any sinking fund requirements. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by certain of our existing domestic subsidiaries and by certain of our future domestic subsidiaries. (See Note 1314, Guarantor/Non-Guarantor Condensed ConsolidatedConsolidating Financial Statements.)
Senior Secured Revolving Credit Facility and Loss on Extinguishment of Debt
We had a credit agreement, most recently amended on June 30, 2016, with Wells Fargo Bank, N.A. and a syndicate of lenders which provided for a senior secured revolving credit facility, with sub-limits for letters of credit and swing-line

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loans, of up to an aggregate commitment amount of $150 million, all of which was set to mature in March 2019 (the “Revolving Credit Facility”). However, in connection with our entry into the Term Loan in November 2017, as described above, all indebtedness outstanding under the Revolving Credit Facility was repaid, together with related costs and expenses, and the Revolving Credit Facility was retired. In connection with the retirement of the Revolving Credit Facility in 2017, we recognized $1.5 million of loss on extinguishment of debt for the write off of the unamortized debt issuance costs, which were being amortized using the straight-line method over the term of the agreement. Additionally, during the years ended December 31, 2016 and 2015, we recognized $0.3 million and $2.2 million, respectively, of loss on extinguishment of debt for the reduction of borrowing capacity under our Revolving Credit Facility.
Debt Issuance Costs and Original Issue Discount
Costs incurred in connection with the issuance of our Senior Notes were capitalized and are being amortized using the effective interest method over the term of the Senior Notes which mature in March 2022. The original issue discount and costs incurred in connection with the issuance of the Term Loan were capitalized and are being amortized using the effective interest method over the expected term of the agreement. Costs incurred in connection with the Prepetition ABL Facility were capitalized and are being amortized using the straight-line method over the expected term of the agreement.
4.     Leases
We lease our corporate office facilities in San Antonio, Texas, and we lease real estate at 38 other locations, which are primarily used for field offices, storage and maintenance yards, and field personnel housing. We lease these properties, as well as office and other equipment, under non-cancelable operating leases, most of which contain renewal options and some of which contain escalation clauses. We recognize rent expense on a straight-line basis for our leases with escalating payments.
Rent expense under operating leases, including rental exit costs, was $4.8 million, $5.0 million and $6.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. Future lease obligations required under non-cancelable operating leases as of December 31, 2017 were as follows (amounts in thousands):
Year ended December 31, 
2018$3,081
20192,273
20201,261
2021818
2022623
Thereafter1,846
 $9,902
5.7.     Income Taxes
The jurisdictional components of lossincome (loss) before income taxes consist of the following (amounts in thousands): 
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
Domestic$(76,078) $(122,277) $(123,499)$(85,133) $(53,230)
Foreign(3,243) (16,846) (69,220)11,900
 6,127
Loss before income taxes$(79,321) $(139,123) $(192,719)
Income (loss) before income taxes$(73,233) $(47,103)

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The components of our income tax expense (benefit) consist of the following (amounts in thousands): 
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
Current:        
Federal$(81) $(219) $(535)$(206) $(183)
State146
 (95) 401
663
 586
Foreign978
 1,189
 1,238
654
 967
1,043
 875
 1,104
1,111
 1,370
Deferred:        
Federal(5,417) (12,500) (42,113)
State143
 902
 29
729
 537
Foreign28
 (9) 3,401
(11,169) 1
(5,246) (11,607) (38,683)(10,440) 538
        
Income tax benefit$(4,203) $(10,732) $(37,579)
Income tax expense (benefit)$(9,329) $1,908
The difference between the income tax benefit and the amount computed by applying the federal statutory income tax rate of 35%to loss before income taxes consists of the following (amounts in thousands): 
 Year ended December 31,
 2017 2016 2015
Expected tax expense (benefit)$(27,762) $(48,693) $(67,452)
Valuation allowance:     
Valuation allowance on operations24,265
 38,324
 20,329
Impact of Tax Reform Act on valuation allowance(25,564) 
 
Change in tax rate20,147
 516
 
State income taxes339
 (3,033) (2,066)
Foreign currency translation loss599
 838
 8,660
Net tax benefits and nondeductible expenses in foreign jurisdictions1,493
 407
 2,135
Incentive stock options1,297
 97
 83
Nondeductible expenses for tax purposes796
 386
 577
Expiration of capital loss
 641
 
Other, net187
 (215) 155
Income tax benefit$(4,203) $(10,732) $(37,579)
Income tax expense (benefit) was allocated as follows (amounts in thousands):
 Year ended December 31,
 2017 2016 2015
Continuing operations$(4,203) $(10,732) $(37,579)
Shareholders’ equity
 2,287
 962
 $(4,203) $(8,445) $(36,617)
 Year ended December 31,
 2019 2018
Expected tax expense (benefit)$(15,379) $(9,892)
Valuation allowance:   
Valuation allowance12,638
 5,885
Reversal of valuation allowance on foreign operations(14,756) 
Impact of tax law changes on valuation allowance
 (1,692)
State income taxes614
 972
Foreign currency translation loss742
 1,038
Net tax benefits and nondeductible expenses in foreign jurisdictions940
 3,104
GILTI tax1,579
 634
Incentive stock options595
 757
Compensation expense nondeductible for tax purposes1,684
 114
Restructuring costs1,388
 
Other nondeductible expenses for tax purposes575
 715
Other, net51
 273
Income tax expense (benefit)$(9,329) $1,908

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Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. The components of our deferred income tax assets and liabilities were as follows (amounts in thousands):
Year ended December 31,Year ended December 31,
2017 20162019 2018
Deferred tax assets:      
Domestic net operating loss carryforward$94,598
 $122,769
$102,827
 $96,777
Intangibles12,145
 14,875
Foreign net operating loss carryforward11,619
 8,640
8,007
 9,582
Intangibles18,058
 33,722
Interest expense deduction limitation carryforward6,649
 2,495
Property and equipment9,280
 11,809
3,656
 5,291
Employee stock-based compensation3,124
 3,271
Employee benefits and insurance claims accruals5,652
 6,802
2,422
 5,374
Employee stock-based compensation3,753
 6,732
Operating lease liabilities1,832
 
Accounts receivable reserve284
 626
187
 325
Inventory295
 613
202
 236
Accrued expenses not deductible for tax purposes
 232
Accrued revenue not income for book purposes316
 277
Accrued expenses233
 190
Deferred revenue124
 560
143,855
 192,222
141,408
 138,976
Valuation allowance(59,766) (57,820)(59,842) (62,639)
      
Deferred tax liabilities:      
Accrued expenses not deductible for book purposes(112) 
Property and equipment(87,128) (142,582)(72,350) (79,606)
Operating lease assets(1,686) 
Accrued expenses
 (419)
Unbilled revenue(407) 
   
Net deferred tax assets (liabilities)$(3,151) $(8,180)$7,123
 $(3,688)
As of December 31, 2017,2019, we had $106.2$102.8 million and $8.0 million of deferred tax assets related to domestic and foreign net operating losses, respectively, that are available to reduce future taxable income. In assessing the realizability of our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
In performing this analysis as of December 31, 20172019 in accordance with ASC Topic 740, Income Taxes, we assessed the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant pieceDuring the fourth quarter of negative evidence evaluated is the cumulative loss incurred during previous years. Such negative evidence limits the ability to consider2019, as a result of sustained profitability in our foreign operations, forecasted earnings, and other positive evidence, we determined that is subjective, such as projections for taxable income in future years. Due to the downturn in our industry, we are in a netforeign deferred tax asset position,assets, which include net operating loss carryforwards, were likely to be fully realized, and as a result, we recognizedreduced our valuation allowance and recorded a benefit only to the extent that reversals of deferredrelated income tax liabilities are expectedbenefit of $14.8 million. As of December 31, 2019, we continue to generate taxable income in each relevant jurisdiction in future periods which would offsetmaintain a valuation allowance against a portion of our domestic net deferred tax assets.
Our domestic federal net operating losses generated through 2017 have a 20 year20-year carryforward period and can be used to offset future domestic taxable income until their expiration, beginning in 2030, with the latest expiration in 2037, while the2037. Losses generated after 2017 have an unlimited carryforward period and are limited in usage to 80% of taxable income. The majority of our foreign net operating losses (any generated prior to 2017)through 2016 have an indefinite carryforward period. However,period, while losses generated after 2016 have a carryforward period of 12 years. As of December 31, 2019, we have a valuation allowance that fully offsets a portion of our foreign and U.S. federaldomestic deferred tax assets as of December 31, 2017.assets. We also have net operating loss carryforwards in many of the states that we operate in. Most of these are filed on a unitary or combined basis. These states have carryover periods between 5 and 20 years, with most being 15 or 20. We have determined that a valuation allowance should be recorded against
Our ability to utilize our domestic net operating loss carryforwards to offset future taxable income and to reduce our U.S. federal income tax liability is subject to certain requirements and restrictions. In connection with the Chapter 11 Cases, we may experience an ownership change, as defined in the U.S. Internal Revenue Code, which would result in some of the state benefits through December 31, 2017. The valuation allowance and the recent change in tax laws, as described further below, are the primary factors causing our effective tax ratenet operating losses being subject to be significantly lower than the statutory rate of 35%. The amount of the deferred tax asset considered realizable, however, would increase if cumulative losses are no longer present andannual limitations. For additional weight is given to subjective evidence in the form of projected future taxable income.
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the “Tax Reform Act”) was enacted. The legislation significantly changes U.S. tax law by, among other things, permanently reducing the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21%, repealing the alternative minimum tax (AMT), implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries.information concerning our bankruptcy proceedings

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As a resultunder Chapter 11, see Note 2, Going Concern and Subsequent Events, and Item 1A – “Risk Factors” in Part I of the reduction in the U.S. corporate income tax rate, we revalued our ending net deferred tax assets at December 31, 2017 and recognized a $20.1 million tax expense in 2017, which is fully offset by a $20.1 million reduction of the valuation allowance.
Due to the repeal of the AMT, we have reduced the valuation allowance by $5.2 million to remove the effects of AMTthis Annual Report on the realizability of our deferred tax assets in future years. In addition, we reversed the valuation allowance on the AMT credit carryforward of $0.2 million that will now be refundable through 2021 and has been reclassified from a deferred tax asset to a non-current receivable.
The Tax Reform Act provides for a one-time deemed mandatory repatriation of post-1986 undistributed foreign subsidiary earnings and profits through the year ended December 31, 2017. We have an accumulated deficit from our foreign operations, and therefore we have not included any tax impacts for this provision.
To minimize tax base erosion with a territorial tax system, beginning in 2018, the Tax Reform Act provides for a new global intangible low-taxed income (GILTI) provision. Under the GILTI provision, certain foreign subsidiary earnings in excess of an allowable return on the foreign subsidiary’s tangible assets are included in U.S. taxable income. We expect to be subject to GILTI; however, the inclusion is expected to be offset by net operating loss carry forwards in the U.S. We are still evaluating, pending further interpretive guidance, whether to make a policy election to treat the GILTI tax as a period expense or to provide U.S. deferred taxes on foreign temporary differences that are expected to generate GILTI income when they reverse in future years.
Given the significance of the legislation, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118), which allows registrants to record provisional amounts during a one year “measurement period” similar to that used when accounting for business combinations. However, the measurement period is deemed to have ended earlier when the registrant has obtained, prepared and analyzed the information necessary to finalize its accounting. During the measurement period, impacts of the law are expected to be recorded at the time a reasonable estimate for all or a portion of the effects can be made, and provisional amounts can be recognized and adjusted as information becomes available, prepared or analyzed. SAB 118 summarizes a three-step process to be applied at each reporting period to account for and qualitatively disclose: (1) the effects of the change in tax law for which accounting is complete; (2) provisional amounts (or adjustments to provisional amounts) for the effects of the tax law where accounting is not complete, but that a reasonable estimate has been determined; and (3) a reasonable estimate cannot yet be made and therefore taxes are reflected in accordance with law prior to the enactment of the Tax Reform Act.
Our accounting is complete for the year ended December 31, 2017 as related to the re-measurement of deferred taxes to the new tax rate of 21%, repeal of the AMT, and mandatory repatriation. We are awaiting further interpretive guidance regarding the possible application of deferred taxes to GILTI, and thus taxes are reflected in accordance with law prior to the enactment of the Tax Reform Act.
Other significant provisions that are not yet effective for the year ended December 31, 2017, but may impact income taxes in future years include a limitation on the current deductibility of net interest expense in excess of 30% of adjusted taxable income, and a limitation of net operating losses generated after 2017 to 80% of taxable income.
Because we have an accumulated foreign deficit of $52.4 million at December 31, 2017, we have not recorded a tax liability from the mandatory repatriation provision of the Tax Reform Act. We do not intend to distribute earnings in a taxable manner, and therefore, we intend to limit any potential distributions to earnings previously taxed in the U.S., or earnings that would qualify for the 100% dividends received deduction provided for in the Tax Reform Act. As a result, we have not recognized a deferred tax liability on our investment in foreign subsidiaries.
On December 29, 2016, the Colombian government enacted a tax reform bill that eliminated the tax for equality (“CREE”), increased the general corporate tax rate from 25% to 40% in 2017, 37% in 2018, 33% in 2019 and created a new 5% dividend tax, among other things. Deferred tax assets and liabilities were adjusted to the new rates; however, the valuation allowance fully offset the impact to tax expense. A few other notable provisions include a shorter twelve-year carryforward period for net operating losses generated after 2016, a longer statute of limitations for returns filed after 2016 and annual limits on tax depreciation allowed.Form 10-K.
We have no unrecognized tax benefits relating to ASC Topic 740 and no unrecognized tax benefit activity during the year ended December 31, 2017.

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2019. We record interest and penalty expense related to income taxes as interest and other expense, respectively. At December 31, 2017,2019, no interest or penalties have been or are required to be accrued. Our open tax years are 20102016 and forward for our federal and most state income tax returns in the United States and 20122014 and forward for our income tax returns in Colombia. Net operating losses generated in years prior to our open years and carried forward are available for adjustment and subject to the statute of limitation provisions of such year when the net operating losses are utilized.
International Tax Reform
On December 28, 2018, the Colombian government enacted a new tax reform bill that decreases the general corporate tax rate from 33% to 30% by 2022, phases out the presumptive tax system by 2021, increases withholding tax rates on payments abroad for various services, and taxes indirect transfers of Colombian assets, among other things. Deferred tax assets and liabilities were adjusted to the new tax rates as of December 31, 2018; however, the adjustments to the valuation allowance fully offset the impact to tax expense in the year of enactment.
On October 19, 2019, the Colombian Constitutional Court declared Colombia’s 2018 Tax Reform unconstitutional due to procedural flaws in the approval process. On December 27, 2019, Colombia re-enacted the tax reform effective January 1, 2020, mirroring most of the provisions contained in the 2018 Tax Reform that was ruled unconstitutional.
6.Fair Value of Financial Instruments
8.     Fair Value of Financial Instruments
The FASB’s Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, defines fair value and provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value. Our financial instruments consist primarily of cash and cash equivalents, trade and other receivables, trade payables, phantom stock unit awards and long-term debt.
The carrying value of cash and cash equivalents, trade and other receivables, and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments. At December 31, 2017 and December 31, 2016, the aggregate estimated fair value of our phantom stock unit awards was $6.1 million and $7.0 million, respectively, for which the vested portion recognized as a liability in our consolidated balance sheets was $3.6 million and $2.0 million, respectively. The phantom stock unit awards, and the measurement of fair value for these awards, are described in more detail in Note 8,10, Equity Transactions and Stock-Based Compensation Plans.At December 31, 2019, the estimated aggregate fair value of our phantom stock unit awards was $0.1 million.
The fair value of our long-term debtSenior Notes is estimated using a discounted cash flow analysis, based on rates that we believe we would currently payrecent observable market prices for similar types ofour debt instruments. This discounted cash flow analysis is based on inputsinstruments, which are defined by ASC Topic 820 as Level 2 inputs. The fair value of our Term Loan is based on estimated market pricing for our debt instrument, which is defined by ASC Topic 820 as using Level 3 inputs which are observable inputs for similar types of debt instruments.unobservable and therefore more likely to be affected by changes in assumptions. The following table presents supplemental fair value information aboutand carrying value for our long-term debt, at December 31, 2017net of discount and December 31, 2016debt issuance costs (amounts in thousands):
 December 31, 2017 December 31, 2016
 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Total debt, net of discount and debt issuance costs$461,665
 $415,561
 $339,473
 $326,249
   December 31, 2019 December 31, 2018
 Hierarchy Level 
Carrying
Amount
 
Fair
Value
 
Carrying
Amount
 
Fair
Value
Senior notes2 $297,848
 $71,250
 $296,988
 $186,750
Senior secured term loan3 169,851
 $166,250
 167,564
 175,875
   $467,699
 $237,500
 $464,552
 $362,625



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7.Earnings (Loss) Per Common Share


9.     Earnings (Loss) Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic earnings per share and diluted earnings per share computations (amounts in thousands, except per share data):
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
Numerator (both basic and diluted):        
Net loss$(75,118) $(128,391) $(155,140)$(63,904) $(49,011)
Denominator:        
Weighted-average shares (denominator for basic earnings (loss) per share)77,390
 65,452
 64,310
78,423
 77,957
Dilutive effect of outstanding stock options, restricted stock and restricted stock unit awards
 
 

 
Denominator for diluted earnings (loss) per share77,390
 65,452
 64,310
78,423
 77,957
Loss per common share - Basic$(0.97) $(1.96) $(2.41)$(0.81) $(0.63)
Loss per common share - Diluted$(0.97) $(1.96) $(2.41)$(0.81) $(0.63)
Potentially dilutive securities excluded as anti-dilutive5,116
 4,953
 4,832
4,842
 4,722
8.      Equity Transactions and10.    Stock-Based Compensation Plans
Equity Transactions
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. In December 2016, we sold 12,075,000 shares of common stock in a public offering and received proceeds of $65.4 million, net of underwriting discounts and offering expenses. As of December 31, 2017,

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$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.
Stock-based Compensation Plans
We haveOur stock-based award plans that are administered by the Compensation Committee of our Board of Directors, which selects persons eligible to receive awards and determines the number, terms, conditions and other provisions of the awards.
At December 31, 20172019, the total shares available for future grants to employees and directors under existing plans were 3,204,802,4,045,492, which excludes awards we grant in the form of phantom stock unit awards which are expected to be paid in cash. In January 2018, our BoardAt this time, however, we have temporarily discontinued the grants of Directors approved the grant of the following awards:any new equity-based awards.
Vesting PeriodNumber of Shares or Units
Restricted stock unit awards3 years788,377
Phantom stock unit awards39 months1,188,216
We grantcurrently have outstanding stock option and restricted stock awards with vesting based on time of service conditions. We grantconditions; restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions. We grantconditions; and phantom stock unit awards with vesting based on time of service, performance and market conditions, which are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation since we expect to settle the awards in cash when they become vested.
We recognize compensation cost for our stock-based compensation awards based on the fair value estimated in accordance with ASC Topic 718.718, Compensation—Stock Compensation, and we recognize forfeitures when they occur. For our awards with graded vesting, we recognize compensation expense on a straight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multiple awards. We adopted ASU 2016-09 in the first quarter of 2017 and elected to prospectively recognize forfeitures when they occur, rather than estimating future forfeitures.
The following table summarizes the stock-based compensation expense recognized, by award type, and the compensation expense (benefit) recognized for phantom stock unit awards during the years ended December 31, 2017, 20162019 and 20152018 (amounts in thousands):
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
Stock option awards$974
 $766
 $923
$137
 $443
Restricted stock awards461
 421
 399
504
 460
Restricted stock unit awards2,914
 2,757
 2,307
2,129
 3,540
$4,349
 $3,944
 $3,629
$2,770
 $4,443
        
Phantom stock unit awards$1,609
 $1,971
 $
$(112) $47
The following table summarizes


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As of December 31, 2019, the unrecognized compensation cost (amounts in thousands) to be recognized andfor our outstanding awards totaled $1.5 million. As a result of the weighted-average period remaining (in years) over which the compensation cost is expected tofiling of our Chapter 11 Cases, we expect that all of these awards will be recognized, by award type, as of December 31, 2017:
 Weighted-Average Period Remaining Unrecognized Compensation Cost
Stock options0.66 $599
Restricted stock awards0.38 174
Restricted stock unit awards1.32 3,655
Phantom stock unit awards1.33 2,491
 
 $6,919
canceled.
Stock Options
We granthave outstanding stock option awards which generallyvest, or become exercisable, over a three-yearthree-year period and expire ten years after the date of grant. Our stock-based compensation plans requirewith exercise prices that all stock option awards have an exercise price that is not less thanapproximate the fair market value of our common stock on the date of grant, and that expire ten years after the date of grant. We issue shares of our common stock when vested stock option awards are exercised.

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We estimate theThe fair value of each option grantaward is measured on the date of grant using a Black-Scholes option pricing model.The following table summarizes the assumptions used in the Black-Scholes option pricing model based on a weighted-average calculation for the options granted during the years ended December 31, 2017, 2016 and 2015:
 Year ended December 31,
 2017 2016 2015
Expected volatility76% 70% 64%
Risk-free interest rates2.1% 1.5% 1.4%
Expected life in years5.86
 5.70
 5.52
Grant-date fair value$4.28 $0.80 $2.31
The assumptions used in the Black-Scholes option pricing model are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.
The following table summarizes our stock option activity from December 31, 20162018 through December 31, 20172019:
 
Number of
Shares
 
Weighted-Average
Exercise Price
Per Share
 
Weighted-Average
Remaining 
Contract Term in Years
 
Aggregate Intrinsic Value (in thousands)(1)
Outstanding stock options as of December 31, 20164,384,425 $7.42    
Granted268,185 6.40    
Forfeited(382,700) 13.82    
Outstanding stock options as of December 31, 20174,269,910 $6.78 4.5 $1,576
        
Stock options exercisable as of December 31, 20173,288,463 $7.90 3.4 $525
        
(1) Intrinsic value is the amount by which the market price of our common stock exceeds the exercise price of the stock options.
The following table presents the aggregate intrinsic value of stock options exercised during the years ended December 31, 2017, 2016 and 2015 (amounts in thousands):
 Year ended December 31,
 2017 2016 2015
Aggregate intrinsic value of stock options exercised$
 $12
 $361
 
Number of
Shares
 
Weighted-Average
Exercise Price
Per Share
 
Weighted-Average
Remaining 
Contract Term in Years
 
Aggregate Intrinsic Value (in thousands)(1)
Outstanding stock options as of December 31, 20183,739,910 $5.56    
Forfeited(732,801) 4.33    
Outstanding stock options as of December 31, 20193,007,109 $5.86 3.8 $
        
Stock options exercisable as of December 31, 20192,920,219 $5.85 3.7 $
        
(1) Intrinsic value is the amount by which the market price of our common stock exceeds the exercise price of the stock options.
The following table summarizes our nonvested stock option activity from December 31, 20162018 through December 31, 2017:2019:
 
Number of
Shares
 
Weighted-Average Grant-Date
Fair Value Per Share
Nonvested stock options as of December 31, 20161,186,917 $1.29
Granted268,185 4.28
Vested(473,655) 1.69
Nonvested stock options as of December 31, 2017981,447 $1.91

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Number of
Shares
 
Weighted-Average Grant-Date
Fair Value Per Share
Nonvested stock options as of December 31, 2018480,785 $2.09
Vested(391,388) 1.59
Forfeited(2,507) 4.30
Nonvested stock options as of December 31, 201986,890 $4.28
Restricted Stock
We grantOur restricted stock awards that vest over a one-year period with a fair value based on the closing price of our common stock on the date of the grant. When restricted stock awards are granted, or when restricted stock unit awards are converted to restricted stock, shares of our common stock are considered issued, but subject to certain restrictions.
The following table presents the weighted-average grant-date fair value per share of restricted stock awards granted and the aggregate fair value of restricted stock awards vested during the years ended December 31, 2017, 20162019 and 2015:2018:
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
Grant-date fair value (per share)$2.75
 $2.76
 $7.40
Grant-date fair value of awards granted (per share)$0.73
 $5.85
Aggregate fair value of awards vested (in thousands)$483
 $137
 $368
$62
 $979
The following table summarizes our restricted stock activity from December 31, 20162018 through December 31, 2017:2019:
Number of
Shares
 
Weighted-Average
Grant-Date
Fair Value per Share
Number of
Shares
 
Weighted-Average
Grant-Date
Fair Value per Share
Nonvested restricted stock as of December 31, 2016166,664 $2.76
Nonvested restricted stock as of December 31, 201878,632 $5.85
Granted167,272 2.75729,112 0.73
Vested(166,664) 2.76(78,632) 5.85
Nonvested restricted stock as of December 31, 2017167,272 $2.75
Nonvested restricted stock as of December 31, 2019729,112 $0.73
Restricted Stock Units
We granthave outstanding restricted stock unit awards with vesting based on time of service conditions only (“time-based RSUs”), and we granthave outstanding restricted stock unit awards with vesting based on time of service, which are also subject to



75



performance and market conditions (“performance-based RSUs”). Shares of our common stock are issued to recipients of restricted stock units only when they have satisfied the applicable vesting conditions.
Our time-based RSUs generally vest over a three-year period, with fair values based on the closing price of our common stock on the date of grant.
Our performance-based RSUs generally cliff vest afterat 39 months from the date of grant and are granted at a target number of issuable shares, for which the final number of shares of common stock is adjusted based on our actual achievement levels that are measured against predetermined performance conditions. The number of shares of common stock awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the performance period, generally three years.
Approximately half The fair value of theour performance-based RSUs outstandingthat are subject to a market condition based on relative total shareholder return, as compared to that of our predetermined peer group, and therefore the fair value of these awards is measured using a Monte Carlo simulation model. Compensationmodel, and compensation expense for equitythese awards with a market condition is reduced only for actual forfeitures; no adjustment to expense is otherwise made regardless of the number of shares issued. The remainingfair value of our performance-based RSUs that are subject to performance conditions based on our EBITDA and EBITDA return on capital employed, relative to our predetermined peer group, and therefore the fair value is based on the closing price of our common stock on the date of grant, applied to the estimated number of shares that will be awarded. Compensationawarded, and compensation expense ultimately recognized for these awards with performance conditions will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions.
In April 2017, we determined that 121% of the target number of shares granted during 2014 were actually earned based on the Company’s achievement of the performance measures as described above, resulting in an increase of 54,429 shares being issued. As of December 31, 20172019, we estimateestimated that the weighted average achievement level for our outstanding performance-based RSUs granted in 2015 and 2017 will be approximately 100%75% of the predetermined performance conditions.

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The following table summarizes our restricted stock unit activity from December 31, 20162018 through December 31, 2017:2019:
Time-Based Award Performance-Based AwardTime-Based Award Performance-Based Award
Number of
Time-Based
Award Units
 
Weighted-Average
Grant-Date
Fair Value 
per Unit
 
Number of
Performance-Based
Award Units
 Weighted-Average
Grant-Date
Fair Value 
per Unit
Number of
Time-Based
Award Units
 
Weighted-Average
Grant-Date
Fair Value 
per Unit
 
Number of
Performance-Based
Award Units
 Weighted-Average
Grant-Date
Fair Value 
per Unit
Nonvested restricted stock units as of
December 31, 2016
397,790
 $3.45 685,817
 $7.28
Nonvested restricted stock units as of
December 31, 2018
887,469 $3.80 563,469
 $7.73
Granted96,728
 5.61 563,469
 7.75
870,648 1.38 
 
Achieved performance adjustment
 
 54,429
 9.66
Vested(202,387)
 4.90 (317,598) 9.66
(346,069) 3.58 
 
Forfeited(40,245)
 2.66 
 
(53,891) 2.48 (55,749) 7.75
Nonvested restricted stock units as of
December 31, 2017
251,886
 $3.24 986,117
 $6.91
Nonvested restricted stock units as of
December 31, 2019
1,358,157 $2.36 507,720
 $7.73
The following table presents the weighted-average grant-date fair value per share of restricted stock units granted and the aggregate intrinsic value of restricted stock units vested (converted) during the years ended December 31, 2017, 20162019 and 2015:2018:
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
Time-based RSUs:        
Grant-date fair value of awards granted (per share)$5.61
 $1.47
 $4.08
$1.38
 $3.85
Aggregate intrinsic value of awards vested (in thousands)$1,206
 $314
 $1,575
$498
 $424
Performance-based RSUs:        
Grant-date fair value of awards granted (per share)$7.75
 $
 $6.66
Aggregate intrinsic value of awards vested (in thousands)$969
 $609
 $1,402
$
 $1,547
Phantom Stock Unit Awards
In 2016, we granted 1,268,068We have outstanding phantom stock unit awards with vesting based on time of service, performance and market conditions. Time-based phantom stock unit awards, which were granted in 2019, vest annually in thirds over a weighted-average grant-date fair value of $1.35 per share. Thesethree-year vesting period. Performance-based phantom stock unit awards, which were granted in 2016, 2018 and 2019, cliff-vest after 39 months from the date of grant, with vesting based on time of service, performance and market conditions. The number of performance-based units ultimately awarded will be based upon the Company’s achievement in certain performance conditions, as compared to a predefined peer group, over the respective three-year performance period, and eachperiods. Each unit awarded will entitle the employee to a cash payment equal to the stock price of our common stock on the date of vesting, subject to an applicable maximum payout feature that is based on a maximummultiple of $8.08 (which is four times the grant date stock price on the date of grant).price.
The fair value of thesetime-based phantom stock unit awards is measured using a Black-Scholes pricing model, and the fair value of performance-based phantom stock unit awards is measured using a Monte Carlo simulation model, with inputs that are defined as Level 3 inputs under ASC Topic 820, Fair Value Measurements and Disclosures. Half



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The following table summarizes the number, weighted-average grant-date fair value, and applicable maximum cash value of the phantom stock unit awards granted are subject to a market condition based on relative total shareholder return, as compared to that of our predetermined peer group,during the year ended December 31, 2019 and therefore the fair value of these awards is measured using a Monte Carlo simulation model. 2018:
 Year ended December 31,
 2019 2018
Performance-based:   
Phantom stock unit awards granted2,467,776
 1,188,216
Weighted-average grant-date fair value (per unit)$1.10
 $3.06
Maximum cash value per unit (three times the grant date stock price)$4.62
 $9.66
Time-based:   
Phantom stock unit awards granted810,648
 
Weighted-average grant-date fair value (per unit)$1.17
 $
Maximum cash value per unit (three times the grant date stock price)$4.62
 $
The remaining phantom stock unit awards are subject to performance conditions, based on our EBITDA and EBITDA return on capital employed, relative to our predetermined peer group, and the fair value of these awards is measured using a Black-Scholes pricing model. As of December 31, 2017, our achievement level for the awards granted during 2016 is estimated to be approximately 150%.
These awards are classified as liability awards under ASC Topic 718, Compensation—Stock Compensation, because we expect to settle the awards in cash when they vest, and are remeasured at fair value at the end of each reporting period until they vest. The change in fair value is recognized as a current period compensation expense in our statementconsolidated statements of operations. Therefore,operations.Therefore, changes in the inputs used to measure fair value can result in volatility in our compensation expense. This volatility increases as the phantom stock awards approach the vesting date. We estimate that a hypothetical increase of $1 in the market price of our common stock, which was $0.03 as of December 31, 2017,2019, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $0.9$1.4 million, which represents the hypothetical increase in fair value of the liability for the 2018 and 2019 phantom stock unit awards. As of December 31, 2019, we estimate the weighted-average achievement level for our outstanding phantom stock unit awards granted in 2018 and 2019 to be 50%.
In April 2019, we determined that 175% of the target number of phantom stock unit awards granted during 2016 were earned based on the Company’s achievement of the performance measures, as compared to the predefined peer group, which would be recognized as compensation expenseresulted in our statementan aggregate cash payment of operations.$3.5 million to settle these awards.
9.11.    Employee Benefit Plans and Insurance
We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may make a matching contribution, on a discretionary basis, equal to a percentage of each eligible employee’s annual contribution, which we determine annually. Our matching contributions for the years ended December 31, 2017, 20162019 and 20152018 were $3.1 million, $0.3$5.3 million and $4.2$4.6 million, respectively. In
We use a combination of self-insurance and third-party insurance for various types of coverage. We are self-insured for up to $500,000 per incident for all workers’ compensation claims submitted by employees for on-the-job injuries. We accrue our workers’ compensation claim cost estimates using an effort to reduce costs in response toactuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the downturn in our industry, we suspended matching contributions from February 2016 to January 2017.
cost of administrative services associated with claims processing. We maintain a self-insurance program for major medical and hospitalization coverage for employees and their dependents, which is partially funded by employee payroll deductions. We have a maximum health insurance liability of $225,000 per covered individual per year, while amounts in excess of this maximum are covered under a separate policy provided by an insurance company. We have provided for reported claims costs as well as incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $200,000 per covered individual per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued insurance premiums and deductibles included $2.0 million for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance at both December 31, 2017 and 2016.
We are self-insured for up to $500,000 per incident for all workers’ compensation claims submitted by employees for on-the-job injuries. We accrue our workers’ compensation claim cost estimates based on historical claims development data and we accrue the cost of administrative services associated with claims processing. We also have a deductible of $250,000$250,000 per occurrence under both our general liability insurance and auto liability insurance, as well as an additional annual aggregate deductible of $250,000 under our general liability insurance.
Accrued insurance premiums and deductibles at December 31, 2017 and 2016 include $4.6 million and $4.4 million, respectively, forrelated to our estimate of costs

77




relative to the self-insured portion of costs associated with our health, workers’ compensation, general liability and auto liability insurance. insurance are as follows:



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 As of December 31,
 2019 2018
Workers’ compensation$3,269
 $2,992
Health insurance1,282
 1,834
General liability and auto liability1,389
 656
 $5,940
 $5,482
Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.
Our insurance recoveries receivables and our accrued liability for insurance claims and settlements represent our estimate of claims in excess of our deductible, which are covered and managed by our third-party insurance providers, some of which may ultimately be settled by the insurance provider in the long-term. These are presented in our consolidated balance sheets as current due to the uncertainty in the timing of reporting and payment of claims.
10.
12.    Segment Information
We revised our reportable business segments as of the fourth quarter of 2017, which now includehave five operating segments, comprised of two drilling services business segments (domestic and international drilling) and three production services business segments (well servicing, wireline services and coiled tubing services). We revised our segments to reflect changes in, which reflects the basis used by management in making decisions regarding our business for resource allocation and performance assessment. These changes reflect our current operating focusassessment, as is required by ASC Topic 280, Segment Reporting. The following financial information presented as of and for the years ended December 31, 2017, 2016, and 2015 have been restated to reflect this change.
Our domestic and international drilling services segments provide contract land drilling services to a diverse group of exploration and production companies through our fourthree drilling divisions in the US and internationally in Colombia. In addition to our drilling rigs, weWe provide a comprehensive service offering which includes the drilling rig, crews, supplies, and most of the ancillary equipment needed to operate our drilling rigs.
Our well servicing, wireline services and coiled tubing services segments provide a range of production services to a diverse group of explorationproducers primarily in Texas and production companies, with our operations concentrated in the major domestic onshore oil and gas producing regions in the Mid-Continent and Rocky Mountain statesregions, as well as in North Dakota, Louisiana and in the Gulf Coast, both onshore and offshore.Mississippi.
The following table setstables set forth certain financial information for each of our segments and corporate (amounts in thousands):
As of and for the year ended December 31,
2017 2016 2015As of and for the year ended December 31,
     2019 2018
Revenues:        
Domestic drilling$129,276
 $112,399
 $205,440
$151,769
 $145,676
International drilling41,349
 6,808
 43,878
88,932
 84,161
Drilling services170,625
 119,207
 249,318
240,701
 229,837
Well servicing77,257
 71,491
 133,440
115,715
 93,800
Wireline services163,716
 67,419
 120,387
172,931
 215,858
Coiled tubing services34,857
 18,959
 37,633
46,445
 50,602
Production services275,830
 157,869
 291,460
335,091
 360,260
Consolidated revenues$446,455
 $277,076
 $540,778
$575,792
 $590,097
        
Operating costs:        
Domestic drilling$83,122
 $63,686
 $108,602
$92,183
 $86,910
International drilling31,994
 9,465
 35,594
65,007
 64,074
Drilling services115,116
 73,151
 144,196
157,190
 150,984
Well servicing56,379
 53,208
 91,125
83,461
 67,554
Wireline services128,137
 57,634
 88,848
151,145
 167,337
Coiled tubing services31,248
 19,956
 33,847
39,557
 44,038
Production services215,764
 130,798
 213,820
274,163
 278,929
Consolidated operating costs$330,880
 $203,949
 $358,016
$431,353
 $429,913
        
Gross margin:     
Domestic drilling$46,154
 $48,713
 $96,838
International drilling9,355
 (2,657) 8,284
Drilling services55,509
 46,056
 105,122
Well servicing20,878
 18,283
 42,315
Wireline services35,579
 9,785
 31,539
Coiled tubing services3,609
 (997) 3,786
Production services60,066
 27,071
 77,640
Consolidated gross margin$115,575
 $73,127
 $182,762
     

78

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As of and for the year ended December 31,As of and for the year ended December 31,
2017 2016 20152019 2018
Gross margin:   
Domestic drilling$59,586
 $58,766
International drilling23,925
 20,087
Drilling services83,511
 78,853
Well servicing32,254
 26,246
Wireline services21,786
 48,521
Coiled tubing services6,888
 6,564
Production services60,928
 81,331
Consolidated gross margin$144,439
 $160,184
        
Identifiable Assets:        
Domestic drilling$404,144
 $415,953
 $463,618
International drilling (1)
36,403
 36,337
 54,590
Domestic drilling (1)
$347,036
 $373,370
International drilling (1) (2)
60,026
 43,213
Drilling services440,547
 452,290
 518,208
407,062
 416,583
Well servicing125,951
 126,917
 155,421
116,473
 118,923
Wireline services92,081
 80,502
 94,777
71,887
 87,912
Coiled tubing services30,254
 26,062
 31,332
30,834
 37,326
Production services248,286
 233,481
 281,530
219,194
 244,161
Corporate78,036
 14,331
 22,237
47,698
 80,806
Consolidated identifiable assets$766,869
 $700,102
 $821,975
$673,954
 $741,550
        
Depreciation and Amortization:     
Depreciation:   
Domestic drilling$45,243
 $53,900
 $68,651
$43,162
 $41,289
International drilling5,718
 6,869
 11,614
5,665
 5,628
Drilling services50,961
 60,769
 80,265
48,827
 46,917
Well servicing19,943
 22,925
 25,810
19,894
 19,578
Wireline services18,451
 20,707
 26,837
14,772
 17,945
Coiled tubing services8,181
 8,661
 16,688
6,447
 7,987
Production services46,575
 52,293
 69,335
41,113
 45,510
Corporate1,241
 1,250
 1,339
944
 1,127
Consolidated depreciation and amortization$98,777
 $114,312
 $150,939
Consolidated depreciation$90,884
 $93,554
   
        
Capital Expenditures:        
Domestic drilling$19,219
 $19,118
 $111,839
$17,889
 $23,598
International drilling6,319
 678
 1,221
4,812
 6,309
Drilling services25,538
 19,796
 113,060
22,701
 29,907
Well servicing17,776
 5,274
 15,716
10,185
 10,002
Wireline services11,883
 3,499
 9,101
5,907
 15,247
Coiled tubing services5,496
 3,548
 4,411
4,736
 16,558
Production services35,155
 12,321
 29,228
20,828
 41,807
Corporate754
 439
 619
1,300
 1,140
Consolidated capital expenditures$61,447
 $32,556
 $142,907
$44,829
 $72,854
(1) Identifiable assets for our international operations in Colombia
(1)Identifiable assets for our drilling segments include the impact of a $36.1 million and $40.1 million intercompany balance, as of December 31, 2019 and 2018, respectively, between our domestic drilling segment (intercompany receivable) and our international drilling segment (intercompany payable).
(2)Identifiable assets for our international drilling segment include five drilling rigs that are owned by our Colombia subsidiary and three drilling rigs that are owned by one of our domestic subsidiaries and leased to our Colombia subsidiary.



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The following table reconciles the consolidated gross margin of our segments reported above to loss from operations as reported on the consolidated statements of operations (amounts in thousands):
Year ended December 31,Year ended December 31,
2017 2016 20152019 2018
Consolidated gross margin$115,575
 $73,127
 $182,762
$144,439
 $160,184
Depreciation and amortization(98,777) (114,312) (150,939)
Depreciation(90,884) (93,554)
General and administrative(69,681) (61,184) (73,903)(91,185) (74,117)
Bad debt (expense) recovery(53) (156) 188
Bad debt (expense) recovery, net79
 (271)
Impairment(1,902) (12,815) (129,152)(2,667) (4,422)
Gain on dispositions of property and equipment, net3,608
 1,892
 4,344
4,513
 3,121
Loss from operations$(51,230) $(113,448) $(166,700)$(35,705) $(9,059)
11.
Commitments and Contingencies
13.    Commitments and Contingencies
In connection with our operations in Colombia, our foreign subsidiaries have obtainedroutinely obtain bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $59.2$68.0 million relating to our performance under these bonds as of December 31, 2017.

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2019. Based on historical experience and information currently available, we believe the likelihood of demand for payment under these bonds and guarantees is remote.
We are currently undergoing sales and use tax audits for multi-year periods and we are working to resolve all relevant issues.periods. As of December 31, 20172019 and December 31, 2016,2018, our accrued liability was $1.2$2.0 million and $0.61.7 million, respectively, based on our estimate of the sales and use tax obligations that are expected to result from these audits. Due to the inherent uncertainty of the audit process, we believe that it is reasonably possible that we may incur additional tax assessments with respect to one or more of the audits in excess of the amount accrued. We believe that such an outcome would not have a material adverse effect on our results of operations or financial position. Because certain of these audits are in a preliminary stage, an estimate of the possible loss or range of loss from an adverse result in all or substantially all of these cases cannot reasonably be made.
Due to the nature of our business, we are, from time to time, involved in litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations.
12.     Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for the years ended December 31, 2017 and 2016 (in thousands, except per share data):
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 Total
Year ended December 31, 2017         
Revenues$95,757
 $107,130
 $117,281
 $126,287
 $446,455
Loss from operations(18,873) (12,729) (10,892) (8,736) (51,230)
Income tax benefit (expense)(48) (1,135) (17) 5,403
 4,203
Net loss(25,124) (20,209) (17,227) (12,558) (75,118)
Loss per share:         
Basic$(0.33) $(0.26) $(0.22) $(0.16) $(0.97)
Diluted$(0.33) $(0.26) $(0.22) $(0.16) $(0.97)
          
Year ended December 31, 2016         
Revenues$74,952
 $62,290
 $68,353
 $71,481
 $277,076
Loss from operations(23,014) (26,025) (29,885) (34,524) (113,448)
Income tax benefit1,958
 1,990
 1,698
 5,086
 10,732
Net loss(27,699) (29,991) (34,620) (36,081) (128,391)
Loss per share:         
Basic$(0.43) $(0.46) $(0.53) $(0.53) $(1.96)
Diluted$(0.43) $(0.46) $(0.53) $(0.53) $(1.96)

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13.
14.    Guarantor/Non-Guarantor Condensed Consolidating Financial Statements
Our Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by all existing 100% owned domestic subsidiaries, except for Pioneer Services Holdings, LLC. The subsidiaries that generally operate our non-U.S. business concentrated in Colombia do not guarantee our Senior Notes. The non-guarantor subsidiaries do not have any payment obligations under the Senior Notes, the guarantees or the Indenture.
In the event of a bankruptcy, liquidation or reorganization of any non-guarantor subsidiary, such non-guarantor subsidiary will pay the holders of its debt and other liabilities, including its trade creditors, before it will be able to distribute any of its assets to us. In the future, any non-U.S. subsidiaries, immaterial subsidiaries and subsidiaries that we designate as unrestricted subsidiaries under the Indenture will not guarantee the Senior Notes. As of December 31, 20172019, there were no restrictions on the ability of subsidiary guarantors to transfer funds to the parent company.
As a result of the guarantee arrangements, we are presenting the following condensed consolidating balance sheets, statements of operations and statements of cash flows of the issuer, the guarantor subsidiaries and the non-guarantor subsidiaries.

81

80



CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)
December 31, 2017December 31, 2019
Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations ConsolidatedParent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
ASSETS                  
Current assets:                  
Cash and cash equivalents$72,258
 $(1,881) $3,263
 $
 $73,640
$14,461
 $
 $10,158
 $
 $24,619
Restricted cash2,008
 
 
 
 2,008
998
 
 
 
 998
Receivables, net of allowance7
 93,866
 19,174
 (42) 113,005
107
 92,394
 30,908
 117
 123,526
Intercompany receivable (payable)(24,836) 51,532
 (26,696) 
 
(28,664) 64,485
 (35,821) 
 
Inventory
 7,741
 6,316
 
 14,057

 10,325
 12,128
 
 22,453
Assets held for sale
 6,620
 
 
 6,620

 3,447
 
 
 3,447
Prepaid expenses and other current assets1,238
 3,193
 1,798
 
 6,229
2,849
 4,122
 898
 
 7,869
Total current assets50,675
 161,071
 3,855
 (42) 215,559
(10,249) 174,773
 18,271
 117
 182,912
Net property and equipment2,011
 521,080
 26,532
 
 549,623
2,374
 441,567
 27,229
 
 471,170
Investment in subsidiaries596,927
 20,095
 
 (617,022) 
547,123
 47,953
 
 (595,076) 
Deferred income taxes38,028
 
 
 (38,028) 
44,224
 
 11,540
 (44,224) 11,540
Other long-term assets496
 788
 403
 
 1,687
Operating lease assets3,114
 3,581
 569
 
 7,264
Other noncurrent assets506
 562
 
 
 1,068
Total assets$587,092
 $668,436
 $57,609
 $(639,183) $673,954
LIABILITIES AND SHAREHOLDERS’ EQUITY         
Current liabilities:         
Accounts payable$1,811
 $24,436
 $6,304
 $
 $32,551
Deferred revenues
 513
 826
 
 1,339
Accrued expenses10,570
 44,893
 2,111
 117
 57,691
Total current liabilities12,381
 69,842
 9,241
 117
 91,581
Long-term debt, less unamortized discount and debt issuance costs467,699
 
 
 
 467,699
Noncurrent operating lease liabilities2,749
 2,536
 415
 
 5,700
Deferred income taxes
 48,641
 
 (44,224) 4,417
Other noncurrent liabilities187
 294
 
 
 481
Total liabilities483,016
 121,313
 9,656
 (44,107) 569,878
Total shareholders’ equity104,076
 547,123
 47,953
 (595,076) 104,076
Total liabilities and shareholders’ equity$587,092
 $668,436
 $57,609
 $(639,183) $673,954
         
December 31, 2018
Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
ASSETS         
Current assets:         
Cash and cash equivalents$50,350
 $
 $3,216
 $
 $53,566
Restricted cash998
 
 
 
 998
Receivables, net of allowance436
 95,030
 35,219
 196
 130,881
Intercompany receivable (payable)(27,245) 67,098
 (39,853) 
 
Inventory
 9,945
 8,953
 
 18,898
Assets held for sale
 3,582
 
 
 3,582
Prepaid expenses and other current assets1,743
 3,197
 2,169
 
 7,109
Total current assets26,282
 178,852
 9,704
 196
 215,034
Net property and equipment2,022
 494,376
 28,460
 
 524,858
Investment in subsidiaries574,695
 25,370
 
 (600,065) 
Deferred income taxes42,585
 
 
 (42,585) 
Other noncurrent assets596
 511
 551
 
 1,658
Total assets$688,137
 $703,034
 $30,790
 $(655,092) $766,869
$646,180
 $699,109
 $38,715
 $(642,454) $741,550
LIABILITIES AND SHAREHOLDERS’ EQUITY                  
Current liabilities:                  
Accounts payable$286
 $24,174
 $5,078
 $
 $29,538
$1,093
 $26,795
 $8,878
 $
 $36,766
Deferred revenues
 97
 808
 
 905

 95
 1,627
 
 1,722
Accrued expenses12,504
 37,814
 4,195
 (42) 54,471
14,020
 49,640
 2,424
 196
 66,280
Total current liabilities12,790
 62,085
 10,081
 (42) 84,914
15,113
 76,530
 12,929
 196
 104,768
Long-term debt, less unamortized discount and debt issuance costs461,665
 
 
 
 461,665
464,552
 
 
 
 464,552
Deferred income taxes
 41,179
 
 (38,028) 3,151

 46,273
 
 (42,585) 3,688
Other long-term liabilities3,586
 2,843
 614
 
 7,043
Other noncurrent liabilities1,457
 1,611
 416
 
 3,484
Total liabilities478,041
 106,107
 10,695
 (38,070) 556,773
481,122
 124,414
 13,345
 (42,389) 576,492
Total shareholders’ equity210,096
 596,927
 20,095
 (617,022) 210,096
165,058
 574,695
 25,370
 (600,065) 165,058
Total liabilities and shareholders’ equity$688,137
 $703,034
 $30,790
 $(655,092) $766,869
$646,180
 $699,109
 $38,715
 $(642,454) $741,550
         
December 31, 2016
Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
ASSETS         
Current assets:         
Cash and cash equivalents$9,898
 $(764) $1,060
 $
 $10,194
Receivables, net of allowance480
 64,946
 7,210
 (513) 72,123
Intercompany receivable (payable)(24,836) 35,427
 (10,591) 
 
Inventory
 5,659
 4,001
 
 9,660
Assets held for sale
 15,035
 58
 
 15,093
Prepaid expenses and other current assets1,280
 4,014
 1,632
 
 6,926
Total current assets(13,178) 124,317
 3,370
 (513) 113,996
Net property and equipment2,501
 556,062
 25,517
 
 584,080
Investment in subsidiaries577,965
 24,270
 
 (602,235) 
Deferred income taxes65,041
 
 
 (65,041) 
Other long-term assets583
 1,029
 414
 
 2,026
Total assets$632,912
 $705,678
 $29,301
 $(667,789) $700,102
LIABILITIES AND SHAREHOLDERS’ EQUITY         
Current liabilities:         
Accounts payable$546
 $16,317
 $2,345
 $
 $19,208
Deferred revenues
 680
 769
 
 1,449
Accrued expenses9,316
 34,765
 1,777
 (513) 45,345
Total current liabilities9,862
 51,762
 4,891
 (513) 66,002
Long-term debt, less unamortized discount and debt issuance costs339,473
 
 
 
 339,473
Deferred income taxes
 73,249
 (28) (65,041) 8,180
Other long-term liabilities2,179
 2,702
 168
 
 5,049
Total liabilities351,514
 127,713
 5,031
 (65,554) 418,704
Total shareholders’ equity281,398
 577,965
 24,270
 (602,235) 281,398
Total liabilities and shareholders’ equity$632,912
 $705,678
 $29,301
 $(667,789) $700,102

82

81



CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(in thousands)

Year ended December 31, 2017Year ended December 31, 2019
Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations ConsolidatedParent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Revenues$
 $405,106
 $41,349
 $
 $446,455
$
 $486,860
 $88,932
 $
 $575,792
Costs and expenses:                  
Operating costs
 298,898
 31,982
 
 330,880

 366,352
 65,001
 
 431,353
Depreciation and amortization1,242
 91,817
 5,718
 
 98,777
Depreciation944
 84,275
 5,665
 
 90,884
General and administrative22,869
 45,387
 1,922
 (497) 69,681
43,376
 45,451
 2,898
 (540) 91,185
Bad debt expense
 53
 
 
 53

 (79) 
 
 (79)
Impairment
 1,902
 
 
 1,902

 2,667
 
 
 2,667
Gain (loss) on dispositions of property and equipment, net2
 (3,454) (156) 
 (3,608)3
 (3,752) (764) 
 (4,513)
Intercompany leasing
 (4,860) 4,860
 
 

 (4,860) 4,860
 
 
Total costs and expenses24,113
 429,743
 44,326
 (497) 497,685
44,323
 490,054
 77,660
 (540) 611,497
Income (loss) from operations(24,113) (24,637) (2,977) 497
 (51,230)(44,323) (3,194) 11,272
 540
 (35,705)
Other income (expense):                  
Equity in earnings of subsidiaries4,317
 (3,936) 
 (381) 
18,184
 23,008
 
 (41,192) 
Interest expense, net of interest capitalized(27,061) 20
 2
 
 (27,039)(39,816) 13
 (32) 
 (39,835)
Loss on extinguishment of debt(1,476) 
 
 
 (1,476)
Other income (expense), net54
 896
 (29) (497) 424
Total other (expense) income(24,166) (3,020) (27) (878) (28,091)
Other income451
 1,311
 1,085
 (540) 2,307
Total other income (expense)(21,181) 24,332
 1,053
 (41,732) (37,528)
Income (loss) before income taxes(48,279) (27,657) (3,004) (381) (79,321)(65,504) 21,138
 12,325
 (41,192) (73,233)
Income tax (expense) benefit 1
(26,839) 31,974
 (932) 
 4,203
1,600
 (2,954) 10,683
 
 9,329
Net income (loss)$(75,118) $4,317
 $(3,936) $(381) $(75,118)$(63,904) $18,184
 $23,008
 $(41,192) $(63,904)
                  
Year ended December 31, 2016Year ended December 31, 2018
Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations ConsolidatedParent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Revenues$
 $270,268
 $6,808
 $
 $277,076
$
 $505,936
 $84,161
 $
 $590,097
Costs and expenses:                  
Operating costs
 194,515
 9,434
 
 203,949

 365,848
 64,065
 
 429,913
Depreciation and amortization1,250
 106,193
 6,869
 
 114,312
Depreciation1,127
 86,799
 5,628
 
 93,554
General and administrative21,657
 38,564
 1,515
 (552) 61,184
22,506
 49,231
 2,800
 (420) 74,117
Bad debt expense
 156
 
 
 156

 271
 
 
 271
Impairment
 12,260
 555
 
 12,815

 4,422
 
 
 4,422
Gain on dispositions of property and equipment, net
 (1,838) (54) 
 (1,892)
Gain (loss) on dispositions of property and equipment, net1
 (3,068) (54) 
 (3,121)
Intercompany leasing
 (4,860) 4,860
 
 

 (4,860) 4,860
 
 
Total costs and expenses22,907
 344,990
 23,179
 (552) 390,524
23,634
 498,643
 77,299
 (420) 599,156
Income (loss) from operations(22,907) (74,722) (16,371) 552
 (113,448)(23,634) 7,293
 6,862
 420
 (9,059)
Other income (expense):                  
Equity in earnings of subsidiaries(63,374) (17,835) 
 81,209
 
8,966
 5,669
 
 (14,635) 
Interest expense, net of interest capitalized(25,845) (88) (1) 
 (25,934)(38,765) (16) (1) 
 (38,782)
Loss on extinguishment of debt(299) 
 
 
 (299)
Other income (expense), net18
 1,430
 (338) (552) 558
Total other (expense) income(89,500) (16,493) (339) 80,657
 (25,675)
Other income (expense)578
 867
 (287) (420) 738
Total other income (expense), net(29,221) 6,520
 (288) (15,055) (38,044)
Income (loss) before income taxes(112,407) (91,215) (16,710) 81,209
 (139,123)(52,855) 13,813
 6,574
 (14,635) (47,103)
Income tax (expense) benefit 1
(15,984) 27,841
 (1,125) 
 10,732
3,844
 (4,847) (905) 
 (1,908)
Net income (loss)$(128,391) $(63,374) $(17,835) $81,209
 $(128,391)$(49,011) $8,966
 $5,669
 $(14,635) $(49,011)
                  
1 The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.
1 The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.
1 The income tax (expense) benefit reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.


83




CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Continued)
(in thousands)

 Year ended December 31, 2015
 Parent Guarantor
Subsidiaries
 Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Revenues$
 $496,900
 $43,878
 $
 $540,778
Costs and expenses:         
Operating costs
 322,458
 35,558
 
 358,016
Depreciation and amortization1,338
 137,987
 11,614
 
 150,939
General and administrative21,515
 50,710
 2,230
 (552) 73,903
Bad debt expense (recovery)
 571
 (759) 
 (188)
Impairment
 73,270
 56,632
 (750) 129,152
Gain (loss) on dispositions of property and equipment, net117
 (4,350) (111) 
 (4,344)
Intercompany leasing
 (4,860) 4,860
 
 
Total costs and expenses22,970
 575,786
 110,024
 (1,302) 707,478
Income (loss) from operations(22,970) (78,886) (66,146) 1,302
 (166,700)
Other income (expense):         
Equity in earnings of subsidiaries(126,553) (74,459) 
 201,012
 
Interest expense, net of interest capitalized(21,128) (117) 23
 
 (21,222)
Loss on extinguishment of debt(2,186) 
 
 
 (2,186)
Other income (expense), net6
 1,687
 (3,752) (552) (2,611)
Total other (expense) income(149,861) (72,889) (3,729) 200,460
 (26,019)
Income (loss) before income taxes(172,831) (151,775) (69,875) 201,762
 (192,719)
Income tax (expense) benefit 1
16,941
 25,222
 (4,584) 
 37,579
Net income (loss)$(155,890) $(126,553) $(74,459) $201,762
 $(155,140)
          
1  The income tax expense (benefit) reflected in each column does not include any tax effect of the equity in earnings (losses) of subsidiaries.





84

82



CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(in thousands)
Year ended December 31, 2017Year ended December 31, 2019
Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations ConsolidatedParent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Cash flows from operating activities$(40,068) $25,492
 $8,759
 $
 $(5,817)$(81,025) $81,945
 $11,102
 $
 $12,022
                  
Cash flows from investing activities:                  
Purchases of property and equipment(745) (56,556) (6,407) 431
 (63,277)(814) (44,555) (4,677) 
 (50,046)
Proceeds from sale of property and equipment
 12,768
 232
 (431) 12,569

 7,619
 114
 
 7,733
Proceeds from insurance recoveries
 3,344
 
 
 3,344

 641
 828
 
 1,469
(745) (40,444) (6,175) 
 (47,364)(814) (36,295) (3,735) 
 (40,844)
                  
Cash flows from financing activities:                  
Debt repayments(120,000) 
 
 
 (120,000)
Proceeds from issuance of debt245,500
 
 
 
 245,500
Debt issuance costs(6,332) 
 
 
 (6,332)
Purchase of treasury stock(533) 
 
 
 (533)(125) 
 
 
 (125)
Intercompany contributions/distributions(13,454) 13,835
 (381) 
 
46,075
 (45,650) (425) 
 
105,181
 13,835
 (381) 
 118,635
45,950
 (45,650) (425) 
 (125)
                  
Net increase (decrease) in cash, cash equivalents and restricted cash64,368
 (1,117) 2,203
 
 65,454
(35,889) 
 6,942
 
 (28,947)
Beginning cash, cash equivalents and restricted cash9,898
 (764) 1,060
 
 10,194
51,348
 
 3,216
 
 54,564
Ending cash, cash equivalents and restricted cash$74,266
 $(1,881) $3,263
 $
 $75,648
$15,459
 $
 $10,158
 $
 $25,617
                  
Year ended December 31, 2016Year ended December 31, 2018
Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations ConsolidatedParent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Cash flows from operating activities$(39,344) $45,035
 $(560) $
 $5,131
$(51,948) $84,663
 $6,940
 $
 $39,655
                  
Cash flows from investing activities:                  
Purchases of property and equipment(452) (31,049) (880) 
 (32,381)(1,077) (59,478) (6,593) 
 (67,148)
Proceeds from sale of property and equipment
 7,523
 54
 
 7,577

 5,826
 38
 
 5,864
Proceeds from insurance recoveries
 37
 
 
 37

 1,066
 16
 
 1,082
(452) (23,489) (826) 
 (24,767)(1,077) (52,586) (6,539) 
 (60,202)
                  
Cash flows from financing activities:                  
Debt repayments(71,000) 
 
 
 (71,000)
Proceeds from issuance of debt22,000
 
 
 
 22,000
Debt issuance costs(819) 
 
 
 (819)
Proceeds from exercise of options183
 
 
 
 183
12
 
 
 
 12
Proceeds from common stock, net of offering costs65,430
 
 

 
 65,430
Purchase of treasury stock(124) 
 
 
 (124)(549) 
 
 
 (549)
Intercompany contributions/distributions16,803
 (16,698) (105) 
 
32,525
 (32,077) (448) 
 
32,473
 (16,698) (105) 
 15,670
31,988
 (32,077) (448) 
 (537)
                  
Net increase (decrease) in cash and cash equivalents(7,323) 4,848
 (1,491) 
 (3,966)
Beginning cash and cash equivalents17,221
 (5,612) 2,551
 
 14,160
Ending cash and cash equivalents$9,898
 $(764) $1,060
 $
 $10,194
Net decrease in cash, cash equivalents and restricted cash(21,037) 
 (47) 
 (21,084)
Beginning cash, cash equivalents and restricted cash72,385
 
 3,263
 
 75,648
Ending cash, cash equivalents and restricted cash$51,348
 $
 $3,216
 $
 $54,564
  




85

83



CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Continued)
(in thousands)

 Year ended December 31, 2015
 Parent 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 Eliminations Consolidated
Cash flows from operating activities$4,067
 $147,643
 $(8,991) $
 $142,719
          
Cash flows from investing activities:         
Purchases of property and equipment(663) (157,336) (1,885) 269
 (159,615)
Proceeds from sale of property and equipment32
 57,444
 467
 (269) 57,674
Proceeds from insurance recoveries
 285
 
 
 285
 (631) (99,607) (1,418) 
 (101,656)
          
Cash flows from financing activities:         
Debt repayments(60,000) (2) 
 
 (60,002)
Debt issuance costs(1,877) 
 
 
 (1,877)
Proceeds from exercise of options781
 
 
 
 781
Purchase of treasury stock(729) 
 
 
 (729)
Intercompany contributions/distributions47,922
 (48,130) 208
 
 
 (13,903) (48,132) 208
 
 (61,827)
          
Net increase (decrease) in cash and cash equivalents(10,467) (96) (10,201) 
 (20,764)
Beginning cash and cash equivalents27,688
 (5,516) 12,752
 
 34,924
Ending cash and cash equivalents$17,221
 $(5,612) $2,551
 $
 $14,160


86




ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.

ITEM 9A.CONTROLS AND PROCEDURES
ITEM 9A.    CONTROLS AND PROCEDURES
Management’s Evaluation of Disclosure Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 20172019, to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
In the ordinary course of business, we may make changes to our systems and processes to improve controls and increase efficiency, and make changes to our internal controls over financial reporting in order to ensure that we maintain an effective internal control environment.
There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 20172019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Pioneer Energy Services Corp. is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer Energy Services Corp.’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Pioneer Energy Services Corp. are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Pioneer Energy Services Corp.’s management assessed the effectiveness of Pioneer Energy Services Corp.’s internal control over financial reporting as of December 31, 20172019. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on our assessment we have concluded that, as of December 31, 20172019, Pioneer Energy Services Corp.’s internal control over financial reporting was effective based on those criteria.
KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pioneer Energy Services Corp. included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of Pioneer Energy Services Corp.’s internal control over financial reporting as of December 31, 20172019. This report is included in Item 8, Financial Statements and Supplementary Data.

ITEM 9B.OTHER INFORMATION
Not applicable.

87

84



PART III
In Items 10, 11, 12, 13 and 14 below, we are incorporatingof Part III will be incorporated by reference the information we refer to in those Items from the definitive proxy statement for our 2018 Annual Meeting of Shareholders. We intendForm 10-K/A to file that definitive proxy statementbe filed with the SEC on or about April 17, 2018 (and, in any event, not later than 120 days after the end of the fiscal year covered by this report).Securities and Exchange Commission.
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Please see theThe information appearingrequired by this item will be provided in the proposal for the election of directors and under the headings “Executive Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Business Conduct and Ethics and Corporate Governance Guidelines” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the definitive proxy statement for our 2018an amendment to this Annual Meeting of Shareholders for the information this Item 10 requires.Report on Form 10-K/A.
ITEM 11.EXECUTIVE COMPENSATION
Please see theThe information appearing under the headings “Compensation Discussion and Analysis,” “Director Compensation,” “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee”required by this item will be provided in the definitive proxy statement for our 2018an amendment to this Annual Meeting of Shareholders for the information this Item 11 requires.Report on Form 10-K/A.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS
Please see theThe information appearing under the heading “Security Ownership of Certain Beneficial Owners and Management”required by this item will be provided in the definitive proxy statement for our 2018 Annual Meeting of Shareholders for the information this Item 12 requires.
Equity Compensation Plan Information
The following table summarizes, as of December 31, 2017, the indicated information regarding our Amended and Restated 2007 Incentive Plan (“the 2007 Incentive Plan”) and the Pioneer Drilling Company 2003 Stock Plan. The material features of these plans are described in Note 8, Equity Transactions and Stock-Based Compensation Plans, of the Notesan amendment to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K.10-K/A.
Plan category
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants And Rights(1)
 
Weighted Average Exercise Price of Outstanding Options, Warrants And Rights(2)
 
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans(3)
Equity compensation plans approved by security holders5,508,039
 $6.78
 3,204,802
Equity compensation plans not approved by security holders
 
 
 5,508,039
 $6.78
 3,204,802
(1)Includes (a) 3,743,991 shares subject to issuance pursuant to outstanding awards of stock options and 1,238,129 shares subject to issuance pursuant to outstanding awards of restricted stock units (assuming the target level of performance achievement) under the 2007 Incentive Plan; and (b) 525,919 shares subject to issuance pursuant to outstanding awards of stock options under the Pioneer Drilling Company 2003 Stock Plan. It does not include awards we grant in the form of phantom stock unit awards which are expected to be paid in cash.
(2)The weighted-average exercise price does not take into account the shares issuable upon vesting of outstanding awards of restricted stock units, which have no exercise price.
(3)Represents 2,322,320 shares available for future issuance in the form of restricted stock under the 2007 Incentive Plan as of December 31, 2017.

88




From January 1, 2018 to February 16, 2018, we granted restricted stock unit awards covering 788,377 shares of our common stock to 87 employees and executive officers. Applying the share counting rules under the 2007 Incentive Plan, these grants reduce the total number of shares available for issuance under the 2007 Incentive Plan by 1,087,960, leaving 2,116,842 shares available for issuance as of February 16, 2018. Pursuant to the terms of the 2007 Incentive Plan, if full value awards are issued, the fungible share pool approach under the 2007 Incentive Plan would deplete the shares available for issuance at a rate of 1.38 shares per share actually covered by an award.
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Please see theThe information appearingrequired by this item will be provided in the proposal for the election of directors and under the heading “Certain Relationships and Related Transactions” in the definitive proxy statement for our 2018an amendment to this Annual Meeting of Shareholders for the information this Item 13 requires.Report on Form 10-K/A.
ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
Please see theThe information appearingrequired by this item will be provided in the proposal for the ratification of the appointment of our independent registered public accounting firm in the definitive proxy statement for our 2018an amendment to this Annual Meeting of Shareholders for the information this Item 14 requires.Report on Form 10-K/A.



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PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(1) Financial Statements.
See Index to Consolidated Financial Statements included in Item 8, Financial Statements and Supplementary Data.
(2) Financial Statement Schedules.
No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto.
(3) Exhibits.
See the Index to Exhibits immediately preceding theThe following exhibits are filed withas part of this report.
ITEM 16.EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Not applicable.


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SIGNATURES

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

report:
Exhibit
Number
 PIONEER ENERGY SERVICES CORP.Description
   
February 16, 20182.1*-
/S/    WM. STACY LOCKE
Wm. Stacy Locke
Chief Executive Officer and President


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/S/    DEAN A. BURKHARDT
ChairmanDisclosure Statement (Form 8-K dated February 16, 2018
Dean A. Burkhardt
/S/    WM28, 2020 (File No. 1-8182, Exhibit 2.1)). STACY LOCKE
President, Chief Executive Officer and Director
(Principal Executive Officer)
February 16, 2018
Wm. Stacy Locke
/S/    LORNEE. PHILLIPS
Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)February 16, 2018
Lorne E. Phillips
/S/    C. JOHN THOMPSON
DirectorFebruary 16, 2018
C. John Thompson
/S/    JOHN MICHAEL RAUH
DirectorFebruary 16, 2018
John Michael Rauh
/S/    SCOTT D. URBAN
DirectorFebruary 16, 2018
Scott D. Urban



90




Index to Exhibits

The following documents are exhibits to this Form 10-K:
Exhibit
Number
Description
   
3.1*-
   
3.2*-
   
4.1*-
   
4.2*-
   
4.3*-
   
10.1+*-
   
10.2+*-
   
10.3+*-
   
10.4+*-
   
10.5+*-
   
10.6+*-
   
10.7+*-
   
10.8+*-
   
10.9+*-
   



86



10.10+*-
10.11+*
10.12+*-
   
10.11+10.13+*-
   
10.12+10.14+*-
   
10.13+10.15+*-
   
10.14+10.16+*-
   
10.15+10.17+*-
   

91




10.16*-
10.17*-
10.18*-
10.19*-
10.20*-
10.21*-
10.22*
   
10.23*10.19*-
   
10.24*10.20*-
   
10.25*10.21*-
   
10.26*10.22*-
   
10.27*10.23*-
   
10.28+10.24+*-
   
10.29+10.25+*-
   
10.30+10.26+*-
   
10.31+10.27+*-
   
10.32+10.28+* 
10.29+*-



87



10.30+*-
10.31+*-
10.32*-
   
12.1**10.33*-
   
21.1**-
   

92




23.1**-
   
31.1**-
   
31.2**-
   
32.1#-
   
32.2#-
   
101**101.INS-The following financial statements from Pioneer Energy Services Corp.’s Form 10-K for the year ended December 31, 2017, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated Financial Statements.Instance Document
101.SCH-XBRL Taxonomy Schema Document
101.CAL-XBRL Calculation Linkbase Document
101.LAB-XBRL Label Linkbase Document
101.PRE-XBRL Presentation Linkbase Document
101.DEF-XBRL Definition Linkbase Document
   
*Incorporated by reference to the filing indicated.
**Filed herewith.
#Furnished herewith.
+Management contract or compensatory plan or arrangement.

ITEM 16.FORM 10-K SUMMARY
93None.



88




SIGNATURES

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

PIONEER ENERGY SERVICES CORP.
March 6, 2020
/S/    WM. STACY LOCKE
Wm. Stacy Locke
Chief Executive Officer and President


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SignatureTitleDate
/S/    DEAN A. BURKHARDT
ChairmanMarch 6, 2020
Dean A. Burkhardt
/S/    WM. STACY LOCKE
President, Chief Executive Officer and Director
(Principal Executive Officer)
March 6, 2020
Wm. Stacy Locke
/S/    LORNEE. PHILLIPS
Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)March 6, 2020
Lorne E. Phillips
/S/    C. JOHN THOMPSON
DirectorMarch 6, 2020
C. John Thompson
/S/    JOHN MICHAEL RAUH
DirectorMarch 6, 2020
John Michael Rauh
/S/    SCOTT D. URBAN
DirectorMarch 6, 2020
Scott D. Urban
/S/    TAMARA MORYTKO
DirectorMarch 6, 2020
Tamara Morytko





89