Pioneer Energy Services
Annual Report 2019

Plain-text annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-K (Mark one) ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2019 or o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number: 1-8182 PIONEER ENERGY SERVICES CORP. (Exact name of registrant as specified in its charter) _____________________________________________ TEXAS 74-2088619 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number) 1250 N.E. Loop 410, Suite 1000 San Antonio, Texas (Address of principal executive offices) 78209 (Zip Code) Registrant’s telephone number, including area code: (855) 884-0575 Securities registered pursuant to Section 12(b) of the Act Title of each class Trading 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 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑ 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 ☑ 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 ☑ No ☐ Indicate by check mark whether the Registrant has submitted electronically 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 such files). Yes ☑ No ☐ 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. Large accelerated filer o Accelerated filer o Non-accelerated filer ☑ Smaller reporting company ☑ 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 ☑ The aggregate market value of the registrant’s common stock held by non-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, 2019) was approximately $19.0 million. As of February 28, 2020, there were 79,579,571 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding. Items 10, 11, 12, 13 and 14 of Part III will be incorporated by reference from the Form 10-K/A to be filed with the Securities and Exchange Commission. DOCUMENTS INCORPORATED BY REFERENCE TABLE OF CONTENTS PART I Introductory Note Business Risk Factors Unresolved Staff Comments Properties Legal Proceedings Mine Safety Disclosures Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities Selected Financial Data Management’s Discussion and Analysis of Financial Condition and Results of Operations PART II Item 1. Item 1A. Item 1B. Item 2. Item 3. Item 4. Item 5. Item 6. Item 7. Item 7A. Quantitative and Qualitative Disclosures About Market Risk Item 8. Item 9. Item 9A. Item 9B. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. Item 16. Financial Statements and Supplementary Data Changes in and Disagreements With Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information Directors, Executive Officers and Corporate Governance Executive Compensation PART III Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters Certain Relationships and Related Transactions, and Director Independence Principal Accounting Fees and Services Exhibits, Financial Statement Schedules Form 10-K Summary PART IV Page 1 3 15 34 34 34 34 35 35 36 50 51 84 84 84 85 85 85 85 85 86 88 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,” 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; 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; operating hazards inherent in our operations; the supply of marketable equipment within the industry; the continued availability of new components for our fleets; the continued availability of qualified personnel; the political, economic, regulatory and other uncertainties encountered by our operations, changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment the occurrence of cybersecurity incidents; the success or failure of future acquisitions or dispositions; future compliance with covenants under our debt arrangements; and 1 • 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.” 2 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. 3 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. 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. 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. Financial information about our operating segments is included in Note 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 We 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 current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling. The following table summarizes our current rig fleet composition by segment and region: 4 Domestic drilling Marcellus/Utica Permian Basin and Eagle Ford Bakken International drilling Multi-well, Pad-capable SCR rigs AC rigs Total — — — 8 5 10 2 — 5 10 2 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 hook load capacity, mud pump pressure rating, and the ability to drill multiple well bores from a single surface location or pad. Every drilling rig in our fleet is electric, either AC or SCR powered. Electric rigs are considered safer, more reliable and more efficient than mechanically powered rigs, while AC rigs are considered to be more energy efficient and provide more precise control of equipment than their SCR counterparts, further enhancing rig safety and reducing drilling time. All but one of our rigs has 750,000 pounds or greater of hook load capacity, and every drilling rig is equipped with a top drive, an iron roughneck, an automatic catwalk, and a walking or skidding system. This equipment provides our clients with drilling rigs that have more varied capabilities for drilling in unconventional plays and improves our efficiency and safety, as described in more detail below. Top drives can be used in horizontal well drilling to reach formations that may not be accessible with conventional rotary drilling 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-handling feature on the rig floor, which is used to help reduce the occurrence of repetitive motion injuries and decrease drill pipe tripping time. An automated catwalk is a drill pipe-handling feature used to raise drill pipe, drill collars, casing, and other necessary items to the drilling rig floor. Its function has significant safety advantages and can reduce the overall time required to complete the well. Oil and gas exploration and production companies typically prefer to use “pad drilling” which allows a series of horizontal wells to 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. 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. 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. Generally, our land drilling 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. 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, but we typically enter into longer-term drilling contracts for our newly constructed rigs and/or during periods of higher rig demand. 5 Production Services Our production services business segments provide well, wireline and coiled tubing services to producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and 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 drilling 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. 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, 2019, the fleet counts for each of our production services business segments are as follows: Well servicing rigs, by horsepower (HP) rating Wireline services units Coiled tubing services units 550 HP 600 HP Total 112 12 124 Total 93 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 6 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. Our fleet consists of 112 rigs with 550 horsepower and 12 rigs with 600 horsepower which are deployed through 9 operating locations concentrated in Texas, as well as in North Dakota, Colorado and 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 open- and cased-hole logging services. Other applications for wireline tools include placing equipment in or retrieving equipment (or debris) from the wellbore, installing bridge plugs, perforating the casing in order to prepare the well for production, or cutting off pipe that is stuck in the well so that the free section can be recovered. Our fleet of 93 wireline units, 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 10 operating locations concentrated in Texas and the Rocky Mountain and Mid-Continent regions, as well as in Louisiana and North 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 and 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 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 fleet consists of 4 small-diameter and 5 large-diameter (larger than two inches) units, which are deployed through 2 operating locations that provide services in Texas, 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. 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 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 7 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 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 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. 8 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 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 9 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. 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 in determining which service provider is awarded the work, and that many clients are willing to pay a 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 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 well servicing providers that we primarily compete with are Key Energy Services, Basic Energy Services, NexTier Oilfield Services, Superior Energy Services, Forbes Energy 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, NexTier 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 that increased the variety 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 NexTier Oilfield Services, Superior Energy Services, Key Energy Services, Schlumberger Ltd., Halliburton Company, Quintana Energy Services and RPC, Inc. 10 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. Year ended December 31, 2019 Apache Corporation Continental Resources, Inc. Gran Tierra Energy, Inc. Year ended December 31, 2018 Gran Tierra Energy, Inc. Apache Corporation QEP Energy Company Seasonality Total Revenue Percentage 7.1% 5.7% 5.6% 8.1% 5.9% 5.8% 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. 11 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 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 and could substantially lengthen the delivery times for equipment and supplies. Any significant delays in our obtaining equipment or supplies could limit our operations and jeopardize our relations with clients and could delay and adversely affect our ability to obtain new contracts for our rigs. 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 per drilling rig and a deductible on production services equipment of $250,000 per occurrence, with an additional $350,000 annual aggregate deductible. Our third-party liability insurance coverage is $101 million per occurrence and in the aggregate, with a deductible of $250,000 per occurrence and an additional $250,000 annual aggregate deductible. We also carry insurance coverage for pollution liability up to $20 million with a deductible of $500,000. We believe that we are adequately insured for public liability and property damage to others with 12 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. 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 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 13 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 website address is www.pioneeres.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, are available free of charge through our website as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission. The public may read and copy these materials at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. For additional information on the operations of the Securities and Exchange Commission’s Public Reference Room, please call 1-800-SEC-0330. In addition, the Securities and Exchange Commission maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. We have also posted on our website our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Business Conduct and Ethics; 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. 14 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; 15 • • • 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. 16 • 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 17 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 18 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. 19 • 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; 20 • • 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. 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. • 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. In late 2014, oil prices worldwide began 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 our business trended upward as a result. However, in late 2018, oil 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 have continued to limit their drilling programs and 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 and production services fleets; our ability to maintain or 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 our equipment and services or an increase in the supply of comparable equipment in our industry or any particular regional market would likely decrease the pricing and utilization rates for our affected service offerings, which would adversely affect our revenues and profitability. The continuing trend toward longer lateral wellbores and the enhanced efficiency of the equipment in our industry, in combination with current commodity prices and more disciplined spending by exploration and production companies, has contributed to an oversupply of equipment in our industry, declining rig counts and dayrates, and 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 21 and can be moved from one market to another in response to market conditions heightens the competition in the industry and may result in an oversupply of equipment in an area. Contract drilling companies and other oilfield service companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling or production services improves in a region where we operate, our competitors might respond by moving in suitable rigs and production services equipment from other regions. An influx of equipment from other regions could rapidly intensify competition, reduce profitability and make any improvement in demand for our services short- lived. Most drilling services contracts and production services contracts are awarded on the basis of competitive bids, which also results in price competition. In addition to pricing and equipment availability, we believe the following factors are also important to our clients in determining which drilling services or production services provider to select: • • • • • • the type, capability and condition of each of the competing drilling rigs, well servicing rigs, wireline units and coiled tubing units; the mobility and efficiency of the equipment; the quality of service and experience of the crews; the reputation and safety record of the company providing the services; the offering of integrated and/or ancillary services; and the ability to provide drilling and production services equipment adaptable to, and personnel familiar with, new technologies and drilling and production techniques. 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 the services our 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 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. 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. 22 • 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. Historically, we have derived a significant portion of our revenue from a limited number of major clients. For the years ended December 31, 2019 and 2018, our drilling and production services to our top three clients accounted for approximately 18% and 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. For a detail of our three largest clients as a percentage of our total revenues during the last two 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. Some 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. In periods of extended market weakness, our clients 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 terms in light of depressed market conditions. 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 terms of our existing drilling contracts, terminate our contracts without justification, leverage their termination rights in an effort to renegotiate contract terms, or otherwise fail to perform their obligations under our contracts. Our clients may also seek to terminate contracts for cause, such as the loss 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 drilling operations and may 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 certain circumstances have the right to terminate the contract. In the event of a cancellation, the payment 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 other equipment being idle for an extended period of time. The cancellation or renegotiation of a number of our contracts could materially reduce our revenues and 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; 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. 23 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 and could substantially lengthen the delivery times for equipment and supplies. Any significant delays in our obtaining equipment or supplies could limit our operations and jeopardize our relations with clients and could delay and adversely affect our ability to obtain new contracts for our rigs. 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 provide 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. 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. 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 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; 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; 24 • • • • 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. 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 “Navigable Waters Protection Rule” issued 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 25 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 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 (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 November 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 limited to only California and Quebec, with a separate trading program administered for the province of 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. Subsequently, the EPA has a number of climate change regulations, including greenhouse gas control and permitting requirements for certain large stationary sources, fuel economy standards for vehicles and emissions standards for power plants. Specific to the oil and gas industry, in 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 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. 26 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. 27 • 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. The BLM has since rescinded much of the 2016 rule, but litigation challenging the 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. The BLM has since proposed rescinding portions of the rule and portions of the rule have been suspended pending the outcome of litigation concerning the rule. 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. 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 was also required, pursuant to a Consent Decree with environmental groups, to reevaluate whether oil and gas wastes should continue to be exempt from being considered hazardous wastes. Although the EPA concluded in April 2019 that no changes to the existing exemption are needed, similar lawsuits could be brought in 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, but it is possible that they will be reinstated through litigation. 28 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 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 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. 29 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; 30 • 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. 31 • 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 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” to utilize its net operating losses and certain other tax attributes existing as of the date of such ownership change. 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 stock 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 net operating losses and certain other tax attributes that may be utilized to offset future taxable income will generally be subject to an annual limitation; however, the annual limitation does not limit the ability to use net operating losses in offsetting cancellation of indebtedness income pursuant to Section 108 of the U.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 negative impact on our financial position and results of operations. If we were to undergo one or more additional ownership changes subsequent to our emergence from the Chapter 11 Cases, our ability to use our net operating loss 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 shares 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 OTC Pink marketplace, or whether the trading volume of our 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 difficult for our shareholders to sell their shares, without depressing the market price for our shares, or at all, which could further depress the trading price of our common stock. An inactive market or 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 otherwise 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 us by suppliers, clients and employees. • There 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 obtain 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. 32 • 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 do not intend to pay or declare 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 DIP Facility and any other debt arrangements. Our DIP Facility includes provisions that generally prohibit us from paying dividends on our capital stock, including our new common stock. • 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 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 our 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. 33 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—Company Overview” and “Business—Facilities” in Item 1 of this report. We believe that we have sufficient properties to conduct our operations and that our significant properties are suitable and adequate for their intended use. ITEM 3. LEGAL PROCEEDINGS From time to time, we are involved in routine litigation or subject to disputes or claims arising 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, results of 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. 34 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 February 28, 2020, 79,579,571 shares of our common stock were outstanding, held by 285 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock. 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. Additionally, 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, 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, 2019. As discussed in “Business—Recent Developments” in Item 1 of this Annual Report on Form 10-K, in connection with the Chapter 11 Cases, our common stock will be extinguished without recovery on the effective date of the Plan. ITEM 6. SELECTED FINANCIAL DATA Not applicable. 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, 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, operating hazards inherent in our operations, the supply of marketable equipment within the industry, the continued availability of new components for our fleets, the continued availability of qualified personnel, 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, 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. 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. 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. 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. Financial information about our operating segments is included in Note 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 — Our current drilling rig fleet is 100% pad-capable and offers the latest advancements in pad drilling, with 17 AC rigs in the US and 8 SCR rigs in Colombia. We provide a comprehensive service offering which includes the drilling rig, crews, supplies, and most of the ancillary equipment needed to operate our drilling rigs, which are deployed through our division offices in the following regions: Domestic drilling: Marcellus/Utica Permian Basin and Eagle Ford Bakken International drilling Rig Count 5 10 2 8 25 Production Services — Our production services business segments provide well, wireline and coiled tubing services to producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and Mississippi. As of December 31, 2019, the fleet counts for each of our production services business segments are as follows: Well servicing rigs, by horsepower (HP) rating 550 HP 600 HP Total 112 12 124 Wireline services units Coiled tubing services units Market Conditions and Outlook Total 93 9 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 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 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 volatility in oil and gas prices and other industry trends, see Item 1A – “Risk Factors” in Part I of this Annual Report on Form 10-K. Market Conditions and Outlook — 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. 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. 39 The trends in commodity pricing and domestic rig counts over the last 12 months are illustrated below: The continuing trend toward longer lateral wellbores and the enhanced efficiency of the equipment in our industry, in combination with current commodity prices and more disciplined spending by exploration and production companies, has contributed to an oversupply of equipment in our industry, declining rig counts and dayrates, and reduced completion activity. As a result, our drilling services experienced a slight decline in both our average domestic revenues per day and our international utilization during the fourth quarter of 2019, as compared to the third quarter. As of December 31, 2019, 18 of our 25 drilling rigs are earning revenues, 15 of which are under term contracts, which if not canceled or renewed prior to the end of their terms, will expire as follows: Domestic rigs International rigs: Earning under contract On standby (not earning) Spot Market Contracts Total Term Contracts Within 6 Months 6 Months to 1 Year 1 Year to 18 Months 18 Months to 2 Years Term Contract Expiration by Period 3 — — 3 12 3 2 17 5 — 2 7 6 3 — 9 — — — — — — — — 2 to 4 Years 1 — — 1 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. 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 activity in the fourth quarter was driven by typical seasonal impacts combined with increased competition in the markets we serve, 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 the South Texas and Rocky Mountain regions. Although we expect a competitive market environment and some additional clients to decrease their activity during 2020 as their new annual budgets will 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 position us well to compete. 40 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 consist of: • • • cash and cash 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 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. Uses of Capital Resources Our principal liquidity requirements are currently for: • • • capital expenditures; working capital needs; and debt service. Our operations have historically generated cash flows sufficient to meet our requirements for debt service and normal capital expenditures. However, our 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. During periods of sustained low activity and pricing, we may also access additional capital through the use of available funds under the 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. Currently, 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 timing 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 requirements, 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, except current ratio): Current assets Current liabilities Working capital Current ratio December 31, 2019 December 31, 2018 Change $ $ 182,912 $ 91,581 91,331 $ 2.0 215,034 $ 104,768 110,266 $ 2.1 (32,122) (13,187) (18,935) (0.1) Our current assets decreased by $32.1 million during 2019, primarily related to a decrease of $28.9 million in cash and cash equivalents 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 purchase of property and equipment, partially offset by $12.0 million of cash from operating activities, $7.7 million of proceeds from the sale of property and equipment, and $1.5 million of proceeds from insurance recoveries. The net decrease in our total trade and unbilled receivables is primarily due to the timing of billing and collection cycles for long-term drilling contracts in 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 60 days, and our Colombian trade receivables generally turn over within 120 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. 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 accrued employee compensation and related costs during 2019 resulted from a decrease in accrued incentive cash compensation associated with the payment of 2018 annual bonuses in the first quarter of 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 overall decrease in accrued employee 42 compensation and related costs was net of $3.5 million of accrued quarterly incentive compensation that was paid in January 2020. • • The $4.2 million decrease in accounts payable during 2019 is primarily due to a 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 slightly 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 of January 1, 2019, as well as an increase in accrued professional fees. For additional information about 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): Contractual Obligations Debt Interest on debt Purchase commitments Operating leases Incentive compensation Total Within 1 Year 2 to 3 Years 4 to 5 Years Beyond 5 Years Payments Due by Period $ 475,000 $ — $ 475,000 $ 79,188 3,612 8,716 4,612 35,000 3,612 2,496 4,065 44,188 — 3,380 547 — $ — — 2,029 — $ 571,128 $ 45,173 $ 523,115 $ 2,029 $ — — — 811 — 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. 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 9.5% interest rate that was in effect at December 31, 2019, and (2) the principal balance of $175 million at December 31, 2019, and assuming repayment of the outstanding balance occurs on 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 $1.6 million of inventory and job supplies for our coiled tubing operations, as well as support equipment for our wireline operations and routine refurbishments to our domestic drilling fleet. Operating leases — Our operating lease 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 — 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- 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 domestic assets, in each case, subject to certain exceptions and 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 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, 2019, the asset coverage ratio, as calculated under the Term Loan, was 1.94 to 1.00. 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-month basis. Our debt 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 Notes to Consolidated Financial Statements, included in Part II, Item 8, Financial Statements and Supplementary Data, of this Annual Report on Form 10-K. 44 Results of Operations The following table provides certain information about our operations, including details 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, 2019 and 2018 (amounts in thousands, except percentages): Revenues: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Consolidated revenues Operating costs: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Consolidated operating costs Gross margin: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Consolidated gross margin Consolidated: Net loss Adjusted EBITDA (1) Year ended December 31, 2019 2018 $ 151,769 26% $ 88,932 240,701 115,715 172,931 46,445 335,091 15% 41% 20% 31% 8% 59% 145,676 84,161 229,837 93,800 215,858 50,602 360,260 25% 14% 39% 16% 36% 9% 61% $ $ $ $ $ $ $ 575,792 100% $ 590,097 100% 92,183 65,007 157,190 83,461 151,145 39,557 274,163 21% $ 15% 36% 19% 36% 9% 64% 86,910 64,074 150,984 67,554 167,337 44,038 278,929 20% 15% 35% 16% 39% 10% 65% 431,353 100% $ 429,913 100% 59,586 23,925 83,511 32,254 21,786 6,888 60,928 41% $ 17% 58% 22% 15% 5% 42% 58,766 20,087 78,853 26,246 48,521 6,564 81,331 37% 13% 50% 16% 30% 4% 50% 144,439 100% $ 160,184 100% (63,904) 60,153 $ $ (49,011) 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. 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. 45 A reconciliation of net loss, as reported, to Adjusted EBITDA, and to consolidated gross margin, are set forth in the following table: Net loss Depreciation Impairment Interest expense Income tax expense (benefit) Adjusted EBITDA General and administrative Bad debt expense (recovery), net Gain on dispositions of property and equipment, net Other income Consolidated gross margin Year ended December 31, 2019 2018 $ (amounts in thousands) (63,904) $ (49,011) 90,884 2,667 39,835 (9,329) 60,153 91,185 (79) (4,513) (2,307) $ 144,439 $ 93,554 4,422 38,782 1,908 89,655 74,117 271 (3,121) (738) 160,184 Consolidated gross margin — Our consolidated gross margin decreased by $15.7 million, or 10%, during 2019 as compared to 2018, due to a decline in demand for our wireline services, despite an increase in gross margin for all our other business segments in 2019. The $15.7 million overall decrease in consolidated gross margin was net of a $11.0 million increase in gross margin for our other business segments. • Drilling Services — Our drilling services revenues and operating costs increased by $10.9 million, or 5%, and $6.2 million, or 4%, respective, during 2019 as compared to 2018. The resulting increase in margin during 2019 is primarily due to the deployment of our newest AC drilling rig in March 2019, increased revenues associated with the demobilization of rigs in 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: Domestic drilling: Average number of drilling rigs Utilization rate Revenue days Average revenues per day Average operating costs per day Average margin per day International drilling: Average number of drilling rigs Utilization rate Revenue days Average revenues per day Average operating costs per day Average margin per day Year ended December 31, 2019 2018 17 92% 5,660 26,814 $ 16,287 10,527 $ 8 75% 2,195 40,516 $ 29,616 10,900 $ 16 99% 5,808 25,082 14,964 10,118 8 77% 2,258 37,272 28,376 8,896 $ $ $ $ Our domestic drilling average revenues and margin per day increased during 2019 as compared to 2018, 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 dayrates 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 during 2019 as compared to 2018 primarily due to $2.5 million of revenues associated with the demobilization of five rigs in Colombia during the second half of 2019, as well as increasing dayrates during late 2018 and early 2019. Average margin per day during 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 decreased by $25.2 million, or 7%, and $4.8 million, or 2%, during 2019 as compared to 2018. The decrease in revenue is a result of the decreased demand for wireline completion services, partially offset by increased demand for our 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: Well servicing: Average number of rigs Utilization rate Rig hours Average revenue per hour Wireline services: Average number of units Number of jobs Average revenue per job Coiled tubing services: Average number of units Revenue days Average revenue per day Year ended December 31, 2019 2018 125 58% 201,768 574 $ 97 8,366 20,671 $ 9 1,274 36,456 $ 125 49% 171,851 546 107 10,943 19,726 12 1,472 34,376 $ $ $ Our well servicing business experienced an increase in demand 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 per hour increased by 5% during 2019 as compared to 2018. Our wireline services business segment experienced a decrease of 24% in the number of jobs completed during 2019, 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 services to complete both newly drilled wells and the remaining inventory of wells which had been drilled in prior periods but were not yet completed. Our coiled tubing services business experienced a decrease of 13% in revenue days during 2019 as compared to 2018, while average revenue per day increased 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 expense — Our depreciation expense decreased by $2.7 million during 2019, primarily in our wireline and coiled tubing segments, which currently operate with an overall smaller fleet as compared to 2018. Impairment — 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 certain assets which were classified as held for sale, to their estimated fair values based on expected sale prices. For more detail, 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. 47 Interest expense — Our interest expense increased by $1.1 million during 2019, as compared to 2018, primarily due to an increase in the LIBOR interest rate applicable to our Term Loan. For more detail 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. 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 $17.1 million, or 23%, during 2019 as compared to 2018, largely due to a net increase in incentive compensation of $9.4 million associated with retention and incentive 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 evaluation of strategic alternatives and the ultimate preparation for the filing of the Chapter 11 Cases in 2020 as well as 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 — During the years ended December 31, 2019 and 2018, we recognized net gains of $4.5 million and $3.1 million, respectively, on the disposition or sale of various property and equipment, primarily including drill pipe and collars, a domestic drilling yard, and certain older and/or underutilized equipment, most of which were previously held for sale. Other income — The increase in our other income during 2019 is primarily related to net foreign currency gains recognized for our Colombian operations, as compared to net foreign currency losses during 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 increases in activity in our industry, we estimate that inflation had a modest impact on our operations during 2018 and 2019. Although it varies by business, we do not expect significant inflationary pressure to impact our business in 2020. Critical Accounting Policies and Estimates The preparation of financial statements in conformity with U.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. Going concern — The accompanying financial statements have been prepared assuming that we will 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 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. For more information, 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, of this Annual Report on Form 10-K. 48 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 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 adoption date of January 1, 2019. For leases that commenced 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 disclosures under the new standard, see 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. Accounting estimates — Material estimates that are particularly susceptible to significant changes in the near term relate to our estimates of certain variable revenues and amortization 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, and our estimate of compensation-related accruals. • • In accordance with ASC Topic 606, Revenue from Contracts with Customers, we estimate certain variable revenues associated with the demobilization of our drilling rigs under daywork drilling contracts. We also make estimates of the applicable 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 current 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 Supplementary Data, of this Annual Report on Form 10-K. In accordance with ASC Topic 360, Property, Plant and Equipment, we monitor all indicators of potential impairments. Due to lower-than-anticipated operating results and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2019 and again at December 31, 2019. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the estimated fair value of the reporting unit’s assets was in excess of the carrying value. 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 analysis are reasonable, different assumptions and estimates could materially impact the analysis 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 services decreases below what we are currently projecting, our estimated cash flows may decrease and our estimates of the fair value of certain assets may decrease as well. If any of the foregoing were to occur, we could incur impairment 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, 2019, we had $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. During 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 reduced 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 offsets a portion of our domestic net deferred tax assets. For more information, 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. • We use a combination of self-insurance and third-party insurance for various types of coverage. We have stop-loss coverage of $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 cost 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-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 consolidated 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 10, 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. 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. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Not applicable. 50 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA PIONEER ENERGY SERVICES CORP. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Reports of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2019 and 2018 Consolidated Statements of Operations for the years ended December 31, 2019 and 2018 Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2019 and 2018 Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018 Notes to Consolidated Financial Statements 51 Page 52 54 55 56 57 58 Report of Independent Registered Public Accounting Firm To the Shareholders and Board of Directors 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, 2019 and 2018, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 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, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 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 misstatement 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 March 6, 2020 52 Report of Independent Registered Public Accounting Firm To the Shareholders and Board of Directors 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, 2019, based on criteria established in Internal 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, 2019, based on criteria established in Internal 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, 2019 and 2018, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated March 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 March 6, 2020 53 PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS Current assets: Cash and cash equivalents Restricted cash Receivables: Trade, net of allowance for doubtful accounts Unbilled receivables Insurance recoveries Other receivables Inventory Assets held for sale Prepaid expenses and other current assets Total current assets Property and equipment, at cost Less accumulated depreciation Net property and equipment Deferred income taxes Operating lease assets Other noncurrent assets Total assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable Deferred revenues Accrued expenses: Employee compensation and related costs Insurance claims and settlements Insurance premiums and deductibles Interest Other Total current liabilities Long-term debt, less unamortized discount and debt issuance costs Noncurrent operating lease liabilities Deferred income taxes Other noncurrent liabilities Total liabilities Commitments and contingencies (Note 13) Shareholders’ equity: December 31, 2019 December 31, 2018 (in thousands, except share data) $ 24,619 $ 998 79,135 12,590 22,873 8,928 22,453 3,447 7,869 182,912 1,119,546 648,376 471,170 11,540 7,264 1,068 673,954 $ 32,551 $ 1,339 13,781 22,873 5,940 5,452 9,645 91,581 467,699 5,700 4,417 481 $ $ 53,566 998 76,924 24,822 23,656 5,479 18,898 3,582 7,109 215,034 1,118,215 593,357 524,858 — — 1,658 741,550 36,766 1,722 24,747 23,593 5,482 6,148 6,310 104,768 464,552 — 3,688 3,484 569,878 576,492 Preferred stock, 10,000,000 shares authorized; none issued and outstanding — — 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, respectively Additional paid-in capital Treasury stock, at cost; 877,047 and 789,532 shares at December 31, 2019 and December 31, 2018, respectively Accumulated deficit Total shareholders’ equity Total liabilities and shareholders’ equity 8,008 553,210 (5,090) (452,052) 104,076 $ 673,954 $ 7,900 550,548 (4,965) (388,425) 165,058 741,550 See accompanying notes to consolidated financial statements. 54 PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Revenues Costs and expenses: Operating costs Depreciation General and administrative Bad debt expense (recovery), net Impairment Gain on dispositions of property and equipment, net Total costs and expenses Loss from operations Other income (expense): Interest expense, net of interest capitalized Other income, net Total other expense, net Loss before income taxes Income tax (expense) benefit Net loss Loss per common share - Basic Loss per common share - Diluted Weighted average number of shares outstanding—Basic Weighted average number of shares outstanding—Diluted Year ended December 31, 2019 2018 (in thousands, except per share data) $ 575,792 $ 590,097 431,353 90,884 91,185 (79) 2,667 (4,513) 611,497 (35,705) (39,835) 2,307 (37,528) (73,233) 9,329 (63,904) $ (0.81) $ (0.81) $ 78,423 78,423 429,913 93,554 74,117 271 4,422 (3,121) 599,156 (9,059) (38,782) 738 (38,044) (47,103) (1,908) (49,011) (0.63) (0.63) 77,957 77,957 $ $ $ See accompanying notes to consolidated financial statements. 55 PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY Shares Amount Common Treasury Common Treasury Additional Paid In Capital Accumulated Deficit Total Shareholders’ Equity Balance as of December 31, 2017 78,350 (631) $ 7,835 $ (in thousands) (4,416) $ 546,158 $ (339,481) $ Net loss Exercise of options Purchase of treasury stock Cumulative-effect adjustment due to adoption of ASC Topic 606 Issuance of restricted stock Stock-based compensation expense — 3 — — 651 — — — (159) — — — — — — — 65 — — — (549) — — — — 12 — — (65) 4,443 (49,011) — — 67 — — Balance as of December 31, 2018 79,004 (790) $ 7,900 $ (4,965) $ 550,548 $ (388,425) $ Net loss Purchase of treasury stock Cumulative-effect adjustment due to adoption of ASC Topic 842 Issuance of restricted stock Stock-based compensation expense — — — 1,075 — — (87) — — — — — — 108 — — (125) — — — — — — (108) 2,770 (63,904) — 277 — — Balance as of December 31, 2019 80,079 (877) $ 8,008 $ (5,090) $ 553,210 $ (452,052) $ 210,096 (49,011) 12 (549) 67 — 4,443 165,058 (63,904) (125) 277 — 2,770 104,076 See accompanying notes to consolidated financial statements. 56 PIONEER ENERGY SERVICES CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Cash flows from operating activities: Net loss Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Year ended December 31, 2019 2018 (in thousands) $ (63,904) $ (49,011) Depreciation Allowance for doubtful accounts, net of recoveries Write-off of obsolete inventory Gain on dispositions of property and equipment, net Stock-based compensation expense Phantom stock compensation expense Amortization of debt issuance costs and discount Impairment Deferred income taxes Change in other noncurrent assets Change in other noncurrent liabilities Changes in current assets and liabilities: Receivables Inventory Prepaid expenses and other current assets Accounts payable Deferred revenues Accrued expenses Net cash provided by operating activities Cash flows from investing activities: Purchases of property and equipment Proceeds from sale of property and equipment Proceeds from insurance recoveries Net cash used in investing activities Cash flows from financing activities: Proceeds from exercise of options Purchase of treasury stock Net cash used in financing activities Net decrease in cash, cash equivalents and restricted cash Beginning cash, cash equivalents and restricted cash Ending cash, cash equivalents and restricted cash Supplementary disclosure: Interest paid Income tax paid Noncash investing and financing activity: Change in capital expenditure accruals 90,884 (79) 570 (4,513) 2,770 (112) 3,147 2,667 (10,811) 3,122 (4,328) 7,062 (4,088) (809) 3,638 (383) (12,811) 12,022 (50,046) 7,733 1,469 (40,844) — (125) (125) (28,947) 54,564 25,617 $ 37,342 $ 3,964 $ (5,217) $ 93,554 271 — (3,121) 4,443 47 2,900 4,422 538 565 (426) (8,644) (4,841) (1,140) (1,272) 420 950 39,655 (67,148) 5,864 1,082 (60,202) 12 (549) (537) (21,084) 75,648 54,564 36,624 3,556 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. Our drilling services business segments provide contract land drilling services through three domestic divisions which are located in the Marcellus/Utica, Permian Basin and Eagle Ford, and Bakken regions, and internationally in Colombia. We 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 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: Domestic drilling International drilling Multi-well, Pad-capable AC rigs SCR rigs Total 17 — — 8 17 8 25 Our production services business segments provide well, wireline and coiled tubing services to producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and Mississippi. As of December 31, 2019, the fleet counts for each of our production services business segments are as follows: Well servicing rigs, by horsepower (HP) rating Wireline services units Coiled tubing services units Basis of Presentation 550 HP 600 HP Total 112 12 124 Total 93 9 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, 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 estimates of certain variable revenues and amortization 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, and our estimate of compensation-related accruals. Subsequent Events — In preparing the accompanying consolidated financial statements, we have reviewed events that have occurred after December 31, 2019, through the filing of this Annual Report on Form 10-K, for inclusion as necessary. See Note 2, Going Concern and Subsequent Events, for more information. 58 Change in Accounting Principle and Recently Issued Accounting Standards Changes to accounting principles generally accepted in the United States of America (“U.S. GAAP”) are established 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 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 adoption date of January 1, 2019. For leases that commenced 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 disclosures under the new standard, see Note 4, Leases. Significant Accounting Policies and Detail of Account Balances Cash and Cash Equivalents — Cash equivalents at December 31, 2019 and 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 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. 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 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 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, dayrate revenues are recognized in the 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. Substantially all of our unbilled receivables represent revenues we have recognized in excess of amounts billed on drilling contracts. For more information, see Note 3, Revenue from Contracts with Customers. 59 Other Receivables — Our other receivables primarily consist of recoverable taxes related to our international operations, as well as vendor rebates and 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. Prepaid expenses and other current assets also include deferred mobilization costs for short-term drilling 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 Noncurrent Assets — Other noncurrent 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. Other Accrued Expenses — Our other accrued expenses include accruals for items such as sales taxes, property taxes, withholding 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. 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. 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 premiums and estimated liability for the self-insured portion of 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, in substance, multiple awards. 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. For more information, see Note 7, Income Taxes. 60 Foreign Currencies — Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense. Comprehensive Income — We have not reported comprehensive income due to the absence of items of other comprehensive income in the periods presented. Reclassifications — Certain amounts in the consolidated financial statements for the prior year has been reclassified to conform to the current year’s presentation. 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. (“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”). 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. 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. Upon emergence from Chapter 11, 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. 61 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 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 from Contracts with Customers 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 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 service offering, including the drilling rig, crew, supplies, and most of the ancillary equipment necessary to operate the rig. Contract modifications that extend the term of a dayrate contract are generally accounted for prospectively as a separate dayrate contract. 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, 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 of our drilling rigs to and from the client’s drill site do not relate to a distinct good or service and 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. 62 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 related contract, including any contracted renewal or extension periods, which is our estimate of the period during which we expect to benefit from the cost of mobilizing the rig. Costs associated with the final demobilization at the end of the contract term are expensed when incurred, when the demobilization 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 distinct within the terms of the contract and are 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. We also act as a principal for certain reimbursable services and auxiliary equipment provided by us to our clients, for which we incur costs and earn revenues, many of which are variable, or dependent upon the 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 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. 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): Balance at beginning of year Increase (decrease) in allowance charged to expense Accounts charged against the allowance Balance at end of year Year ended December 31, 2019 2018 $ $ 1,423 $ (167) (432) 824 $ 1,224 271 (72) 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 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 net current and noncurrent portions separately classified in our consolidated balance sheets, and referred to herein as “deferred revenues.” Contract cost assets represent the costs associated with the initial mobilization required in order to fulfill the contract, which are deferred and recognized ratably over the period during which we expect to benefit from the mobilization, or the period during which we expect to satisfy the performance obligations of the related contract. Contract cost assets are presented as 63 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): Current deferred revenues Current deferred costs Noncurrent deferred revenues Noncurrent deferred costs $ $ As of December 31, 2019 2018 1,339 $ 1,071 57 $ 267 1,722 1,543 437 679 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): Amortization of deferred revenues Amortization of deferred costs Year ended December 31, 2019 2018 $ 6,203 $ 4,786 2,961 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 expect our 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 affected by economic factors. We believe the disclosure of revenues by operating segment achieves the objective of this disclosure 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 by geography (international versus domestic). 64 Concentration of Clients We derive a significant portion of our revenue from a limited number of major clients. For the years ended December 31, 2019 and 2018, our drilling and production services provided to our top three clients accounted for approximately 18% and 20%, respectively, of our revenue. 4. Leases As a drilling and production services provider, we provide the drilling 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, allows 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 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, we lease our corporate office headquarters in San 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 elected 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 associated lease liability. The operating lease asset and operating lease liability are discounted at the rate which represents our secured incremental borrowing rate, as our leases do not provide an implicit rate, and which we estimate based on the rate 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 office equipment (for example, copiers), which totaled approximately $1.2 million during the year ended December 31, 2019. The following table summarizes our lease expense recognized, excluding variable lease costs (amounts in thousands): Long-term operating lease expense Short-term operating lease expense 65 Year ended December 31, $ $ 2019 3,699 15,187 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 In the second year In the third year In the fourth year In the fifth year Thereafter Total undiscounted lease obligations Impact of discounting Discounted value of operating lease obligations Current operating lease liabilities Noncurrent operating lease liabilities 3,318 2,032 1,721 1,407 1,110 1,738 11,326 $ $ $ $ $ 2,496 $ 1,933 1,447 1,117 912 811 8,716 $ (818) 7,898 2,198 5,700 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: Weighted-average remaining lease term (in years) Weighted-average discount rate 5. Property and Equipment The following table presents the estimated useful lives and costs of our assets by class: Drilling rigs and equipment Well servicing rigs and equipment Wireline units and equipment Coiled tubing units and equipment Vehicles Office equipment Buildings and improvements Property and equipment not yet placed in service Land December 31, 2019 4.5 4.5% $ Lives 3 - 25 3 - 20 1 - 10 1 - 7 3 - 10 3 - 10 3 - 40 — — As of December 31, 2019 2018 Cost (amounts in thousands) 613,061 $ 259,102 131,628 30,816 50,308 12,353 16,988 3,330 1,960 590,148 252,589 144,171 25,689 50,317 11,606 23,610 17,718 2,367 $ 1,119,546 $ 1,118,215 Capital Expenditures — Our capital expenditure additions were $44.8 million and $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, 2019 and 2018, respectively, on the disposition or sale of various property and equipment, primarily including 66 drill pipe and collars, a domestic drilling yard, and certain older and/or underutilized equipment, most of which were previously held for sale. Assets 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 asset 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, and the amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of the assets. Due to adverse factors affecting our well servicing operations, including increased competition and labor shortages in certain well servicing markets, and lower than anticipated utilization, all of which contributed to a decline in our projected cash flows for the well 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 excess of the carrying amount. Due to lower-than-anticipated operating results and a decline in our projected cash flows for the coiled tubing reporting unit, we performed an impairment analysis of this reporting unit at September 30, 2019 and again at December 31, 2019. As a result of this analysis, we concluded that this reporting unit was not at risk of impairment because the estimated fair value of the reporting unit’s assets was in excess of the carrying value. 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. 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 analysis are reasonable, different assumptions and estimates could materially impact the analysis and resulting conclusions. If commodity prices decrease or remain at current levels for an extended period of time, or if the demand for any of our services decreases below what we are currently projecting, our estimated cash flows may decrease and our estimates of the fair value of certain assets may decrease as well. If any of the foregoing were to occur, we could incur impairment charges on the related assets. 67 6. Debt Our debt consists of the following (amounts in thousands): Senior secured term loan Senior notes Less unamortized discount (based on imputed interest rate of 10.46%) Less unamortized debt issuance costs December 31, 2019 December 31, 2018 $ $ 175,000 $ 300,000 475,000 (1,869) (5,432) 467,699 $ 175,000 300,000 475,000 (2,668) (7,780) 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 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. 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; 68 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 “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 is 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, 2019, we had $9.4 million in committed letters of credit, which, after borrowing base limitations, resulted in borrowing availability of $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-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; issue or sell certain equity interests; optionally prepay, redeem or repurchase certain of our subordinated indebtedness; • • • • make loans or investments (including acquisitions); • • • • merge, consolidate, reorganize, recapitalize, or reclassify our equity interests; • • incur additional indebtedness or modify the terms of permitted indebtedness; grant liens; change our business or the business of our subsidiaries; 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, 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. 69 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 14, Guarantor/Non- Guarantor Condensed Consolidating Financial Statements.) 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. 7. Income Taxes The jurisdictional components of income (loss) before income taxes consist of the following (amounts in thousands): Domestic Foreign Income (loss) before income taxes 70 Year ended December 31, 2019 2018 $ $ (85,133) $ 11,900 (73,233) $ (53,230) 6,127 (47,103) The components of our income tax expense (benefit) consist of the following (amounts in thousands): Current: Federal State Foreign Deferred: State Foreign Income tax expense (benefit) Year ended December 31, 2019 2018 $ $ (206) $ 663 654 1,111 729 (11,169) (10,440) (9,329) $ (183) 586 967 1,370 537 1 538 1,908 The difference between the income tax benefit and the amount computed by applying the federal statutory income tax rate to loss before income taxes consists of the following (amounts in thousands): Expected tax expense (benefit) Valuation allowance: Valuation allowance Reversal of valuation allowance on foreign operations Impact of tax law changes on valuation allowance State income taxes Foreign currency translation loss Net tax benefits and nondeductible expenses in foreign jurisdictions GILTI tax Incentive stock options Compensation expense nondeductible for tax purposes Restructuring costs Other nondeductible expenses for tax purposes Other, net Income tax expense (benefit) Year ended December 31, 2019 2018 $ (15,379) $ 12,638 (14,756) — 614 742 940 1,579 595 1,684 1,388 575 51 (9,892) 5,885 — (1,692) 972 1,038 3,104 634 757 114 — 715 273 $ (9,329) $ 1,908 71 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): Deferred tax assets: Domestic net operating loss carryforward Intangibles Foreign net operating loss carryforward Interest expense deduction limitation carryforward Property and equipment Employee stock-based compensation Employee benefits and insurance claims accruals Operating lease liabilities Accounts receivable reserve Inventory Accrued expenses Deferred revenue Valuation allowance Deferred tax liabilities: Property and equipment Operating lease assets Accrued expenses Unbilled revenue Year ended December 31, 2019 2018 $ 102,827 $ 12,145 8,007 6,649 3,656 3,124 2,422 1,832 187 202 233 124 141,408 (59,842) (72,350) (1,686) — (407) Net deferred tax assets (liabilities) $ 7,123 $ 96,777 14,875 9,582 2,495 5,291 3,271 5,374 — 325 236 190 560 138,976 (62,639) (79,606) — (419) — (3,688) As of December 31, 2019, we had $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, 2019 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. During 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 reduced 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 against a portion of our domestic net deferred tax assets. Our domestic federal net operating losses generated through 2017 have a 20-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. 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 generated through 2016 have an indefinite carryforward period, while losses generated after 2016 have a carryforward period of 12 years. As of December 31, 2019, we have a valuation allowance that offsets a portion of our domestic deferred tax 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. 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 our net operating losses being subject to annual limitations. For additional information concerning our bankruptcy proceedings 72 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. We have no unrecognized tax benefits relating to ASC Topic 740 and no unrecognized tax benefit activity during the year ended December 31, 2019. We record interest and penalty expense related to income taxes as interest and other expense, respectively. At December 31, 2019, no interest or penalties have been or are required to be accrued. Our open tax years are 2016 and forward for our federal and most state income tax returns in the United States and 2014 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. 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. The phantom stock unit awards, and the measurement of fair value for these awards, are described in more detail in Note 10, 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 Senior Notes is estimated based on recent observable market prices for our debt instruments, 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 unobservable and therefore more likely to be affected by changes in assumptions. The following table presents supplemental fair value information and carrying value for our debt, net of discount and debt issuance costs (amounts in thousands): Senior notes Senior secured term loan December 31, 2019 December 31, 2018 Hierarchy Level 2 3 Carrying Amount Fair Value Carrying Amount $ 297,848 $ 71,250 $ 296,988 $ 169,851 $ 166,250 167,564 $ 467,699 $ 237,500 $ 464,552 $ Fair Value 186,750 175,875 362,625 73 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): Numerator (both basic and diluted): Net loss Denominator: Weighted-average shares (denominator for basic earnings (loss) per share) Dilutive effect of outstanding stock options, restricted stock and restricted stock unit awards Denominator for diluted earnings (loss) per share Loss per common share - Basic Loss per common share - Diluted Potentially dilutive securities excluded as anti-dilutive 10. Stock-Based Compensation Plans Year ended December 31, 2019 2018 (63,904) $ (49,011) 78,423 — 78,423 (0.81) $ (0.81) $ 4,842 77,957 — 77,957 (0.63) (0.63) 4,722 $ $ $ Our stock-based award plans 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, 2019, the total shares available for future grants to employees and directors under existing plans were 4,045,492, which excludes awards we grant in the form of phantom stock unit awards which are expected to be paid in cash. At this time, however, we have temporarily discontinued the grants of any new equity-based awards. We currently have outstanding stock option and restricted stock awards with vesting based on time of service conditions; restricted stock unit awards with vesting based on time of service conditions, and in certain cases, subject to performance and market conditions; 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, 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. 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, 2019 and 2018 (amounts in thousands): Stock option awards Restricted stock awards Restricted stock unit awards Phantom stock unit awards Year ended December 31, 2019 2018 $ $ $ 137 $ 504 2,129 2,770 $ (112) $ 443 460 3,540 4,443 47 74 As of December 31, 2019, the unrecognized compensation cost to be recognized for our outstanding awards totaled $1.5 million. As a result of the filing of our Chapter 11 Cases, we expect that all of these awards will be canceled. Stock Options We have outstanding stock option awards which vest, or become exercisable, over a three-year period with exercise prices that approximate the fair market value of our common stock on the date of grant, and that expire ten years after the date of grant. The fair value of each option award is measured on the date of grant using a Black-Scholes option pricing model. The following table summarizes our stock option activity from December 31, 2018 through December 31, 2019: Outstanding stock options as of December 31, 2018 Forfeited Outstanding stock options as of December 31, 2019 Stock options exercisable as of December 31, 2019 Number of Shares Weighted-Average Exercise Price Per Share Weighted-Average Remaining Contract Term in Years Aggregate Intrinsic Value (in thousands)(1) 3,739,910 (732,801) 3,007,109 2,920,219 $5.56 4.33 $5.86 $5.85 3.8 $ 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, 2018 through December 31, 2019: Nonvested stock options as of December 31, 2018 Vested Forfeited Nonvested stock options as of December 31, 2019 Restricted Stock Number of Shares Weighted-Average Grant- Date Fair Value Per Share 480,785 (391,388) (2,507) 86,890 $2.09 1.59 4.30 $4.28 Our restricted stock awards 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, 2019 and 2018: Grant-date fair value of awards granted (per share) Aggregate fair value of awards vested (in thousands) Year ended December 31, 2019 2018 $ $ 0.73 $ 62 $ 5.85 979 The following table summarizes our restricted stock activity from December 31, 2018 through December 31, 2019: Nonvested restricted stock as of December 31, 2018 Granted Vested Nonvested restricted stock as of December 31, 2019 Restricted Stock Units Number of Shares Weighted-Average Grant-Date Fair Value per Share 78,632 729,112 (78,632) 729,112 $5.85 0.73 5.85 $0.73 We have outstanding restricted stock unit awards with vesting based on time of service conditions only (“time-based RSUs”), and we have 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 cliff vest at 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. The fair value of our performance-based RSUs that are subject to a market condition is measured using a Monte Carlo simulation model, and compensation expense for these awards is reduced only for actual forfeitures; no adjustment to expense is otherwise made regardless of the number of shares issued. The fair value of our performance-based RSUs that are subject to performance conditions 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, and compensation expense ultimately recognized for these awards will be equal to the fair value of the restricted stock unit award based on the actual outcome of the service and performance conditions. As of December 31, 2019, we estimated that the achievement level for our outstanding performance-based RSUs granted in 2017 will be approximately 75% of the predetermined performance conditions. The following table summarizes our restricted stock unit activity from December 31, 2018 through December 31, 2019: Nonvested restricted stock units as of December 31, 2018 Granted Vested Forfeited Nonvested restricted stock units as of December 31, 2019 Time-Based Award Performance-Based Award Number of Time-Based Award Units Weighted-Average Grant-Date Fair Value per Unit Number of Performance-Based Award Units Weighted-Average Grant-Date Fair Value per Unit 887,469 870,648 (346,069) (53,891) $3.80 1.38 3.58 2.48 563,469 — — (55,749) 1,358,157 $2.36 507,720 $7.73 — — 7.75 $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, 2019 and 2018: Time-based RSUs: Grant-date fair value of awards granted (per share) Aggregate intrinsic value of awards vested (in thousands) Performance-based RSUs: Aggregate intrinsic value of awards vested (in thousands) Phantom Stock Unit Awards Year ended December 31, 2019 2018 $ $ $ 1.38 $ 498 $ — $ 3.85 424 1,547 We 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 three-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 periods. 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 multiple of the grant date stock price. The fair value of time-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. 76 The following table summarizes the number, weighted-average grant-date fair value, and applicable maximum cash value of the phantom stock unit awards granted during the year ended December 31, 2019 and 2018: Performance-based: Phantom stock unit awards granted Weighted-average grant-date fair value (per unit) Maximum cash value per unit (three times the grant date stock price) Time-based: Phantom stock unit awards granted Weighted-average grant-date fair value (per unit) Maximum cash value per unit (three times the grant date stock price) Year ended December 31, 2019 2018 2,467,776 1,188,216 $ $ $ $ 1.10 $ 4.62 $ 810,648 1.17 $ 4.62 $ 3.06 9.66 — — — The 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 consolidated 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. We estimate that a hypothetical increase of $1 in the market price of our common stock, which was $0.03 as of December 31, 2019, if all other inputs were unchanged, would result in an increase in cumulative compensation expense of $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 resulted in an aggregate cash payment of $3.5 million to settle these awards. 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, 2019 and 2018 were $5.3 million and $4.6 million, respectively. 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 actuarial calculation that is based on industry and our company’s historical claim development data, and we accrue the 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 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. Accrued insurance premiums and deductibles related to our estimate of the self-insured portion of costs associated with our health, workers’ compensation, general liability and auto liability insurance are as follows: 77 Workers’ compensation Health insurance General liability and auto liability As of December 31, 2019 2018 $ $ 3,269 $ 1,282 1,389 5,940 $ 2,992 1,834 656 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. 12. Segment Information We have 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), which reflects the basis used by management in making decisions regarding our business for resource allocation and performance assessment, as required by ASC Topic 280, Segment Reporting. Our domestic and international drilling services segments provide contract land drilling services to a diverse group of exploration and production companies through our three drilling divisions in the US and internationally in Colombia. We 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 producers primarily in Texas and the Mid-Continent and Rocky Mountain regions, as well as in North Dakota, Louisiana and Mississippi. The following tables set forth certain financial information for each of our segments and corporate (amounts in thousands): Revenues: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Consolidated revenues Operating costs: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Consolidated operating costs As of and for the year ended December 31, 2019 2018 $ $ $ $ 151,769 $ 88,932 240,701 115,715 172,931 46,445 335,091 575,792 $ 92,183 $ 65,007 157,190 83,461 151,145 39,557 274,163 431,353 $ 145,676 84,161 229,837 93,800 215,858 50,602 360,260 590,097 86,910 64,074 150,984 67,554 167,337 44,038 278,929 429,913 78 Gross margin: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Consolidated gross margin Identifiable Assets: Domestic drilling (1) International drilling (1) (2) Drilling services Well servicing Wireline services Coiled tubing services Production services Corporate Consolidated identifiable assets Depreciation: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Corporate Consolidated depreciation Capital Expenditures: Domestic drilling International drilling Drilling services Well servicing Wireline services Coiled tubing services Production services Corporate Consolidated capital expenditures As of and for the year ended December 31, 2019 2018 59,586 $ 23,925 83,511 32,254 21,786 6,888 60,928 58,766 20,087 78,853 26,246 48,521 6,564 81,331 144,439 $ 160,184 347,036 $ 60,026 407,062 116,473 71,887 30,834 219,194 47,698 673,954 $ 43,162 $ 5,665 48,827 19,894 14,772 6,447 41,113 944 90,884 $ 17,889 $ 4,812 22,701 10,185 5,907 4,736 20,828 1,300 44,829 $ 373,370 43,213 416,583 118,923 87,912 37,326 244,161 80,806 741,550 41,289 5,628 46,917 19,578 17,945 7,987 45,510 1,127 93,554 23,598 6,309 29,907 10,002 15,247 16,558 41,807 1,140 72,854 $ $ $ $ $ $ $ $ (1) (2) 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). 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. 79 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): Consolidated gross margin Depreciation General and administrative Bad debt (expense) recovery, net Impairment Gain on dispositions of property and equipment, net Loss from operations 13. Commitments and Contingencies Year ended December 31, 2019 2018 $ $ 144,439 $ (90,884) (91,185) 79 (2,667) 4,513 (35,705) $ 160,184 (93,554) (74,117) (271) (4,422) 3,121 (9,059) In connection with our operations in Colombia, our foreign subsidiaries routinely obtain bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $68.0 million relating to our performance under these bonds as of December 31, 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. As of December 31, 2019 and 2018, our accrued liability was $2.0 million and $1.7 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. 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, 2019, 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. 80 CONDENSED CONSOLIDATING BALANCE SHEETS (in thousands) Parent Guarantor Subsidiaries December 31, 2019 Non-Guarantor Subsidiaries Eliminations Consolidated ASSETS Current assets: Cash and cash equivalents Restricted cash Receivables, net of allowance Intercompany receivable (payable) Inventory Assets held for sale Prepaid expenses and other current assets Total current assets Net property and equipment Investment in subsidiaries Deferred income taxes Operating lease assets Other noncurrent assets Total assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable Deferred revenues Accrued expenses Total current liabilities Long-term debt, less unamortized discount and debt issuance costs Noncurrent operating lease liabilities Deferred income taxes Other noncurrent liabilities Total liabilities Total shareholders’ equity $ 14,461 $ 998 107 (28,664) — — 2,849 (10,249) 2,374 547,123 44,224 3,114 506 — $ — 10,158 $ — 92,394 64,485 10,325 3,447 4,122 174,773 441,567 47,953 — 3,581 562 30,908 (35,821) 12,128 — 898 18,271 27,229 — 11,540 569 — — $ — 117 — — — — 117 — (595,076) (44,224) — — 24,619 998 123,526 — 22,453 3,447 7,869 182,912 471,170 — 11,540 7,264 1,068 587,092 $ 668,436 $ 57,609 $ (639,183) $ 673,954 $ $ 1,811 $ — 10,570 12,381 467,699 2,749 — 187 483,016 104,076 24,436 $ 6,304 $ 513 44,893 69,842 — 2,536 48,641 294 121,313 547,123 826 2,111 9,241 — 415 — — 9,656 47,953 — $ — 117 117 — — (44,224) — (44,107) (595,076) 32,551 1,339 57,691 91,581 467,699 5,700 4,417 481 569,878 104,076 673,954 Total liabilities and shareholders’ equity $ 587,092 $ 668,436 $ 57,609 $ (639,183) $ ASSETS Current assets: Cash and cash equivalents Restricted cash Receivables, net of allowance Intercompany receivable (payable) Inventory Assets held for sale Prepaid expenses and other current assets Total current assets Net property and equipment Investment in subsidiaries Deferred income taxes Other noncurrent assets Total assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Accounts payable Deferred revenues Accrued expenses Total current liabilities Long-term debt, less unamortized discount and debt issuance costs Deferred income taxes Parent Guarantor Subsidiaries December 31, 2018 Non-Guarantor Subsidiaries Eliminations Consolidated $ 50,350 $ 998 436 (27,245) — — 1,743 26,282 2,022 574,695 42,585 596 — $ — 3,216 $ — 95,030 67,098 9,945 3,582 3,197 178,852 494,376 25,370 — 511 35,219 (39,853) 8,953 — 2,169 9,704 28,460 — — 551 — $ — 196 — — — — 196 — (600,065) (42,585) — $ $ 646,180 $ 699,109 $ 38,715 $ (642,454) $ 1,093 $ — 14,020 15,113 464,552 — 26,795 $ 95 49,640 76,530 — 46,273 $ 8,878 1,627 2,424 12,929 — — — $ — 196 196 — (42,585) 53,566 998 130,881 — 18,898 3,582 7,109 215,034 524,858 — — 1,658 741,550 36,766 1,722 66,280 104,768 464,552 3,688 Other noncurrent liabilities Total liabilities Total shareholders’ equity 1,457 481,122 165,058 1,611 124,414 574,695 416 13,345 25,370 — (42,389) (600,065) Total liabilities and shareholders’ equity $ 646,180 $ 699,109 $ 38,715 $ (642,454) $ 3,484 576,492 165,058 741,550 81 CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS (in thousands) Revenues Costs and expenses: Operating costs Depreciation General and administrative Bad debt expense Impairment Gain (loss) on dispositions of property and equipment, net Intercompany leasing Total costs and expenses Income (loss) from operations Other income (expense): Equity in earnings of subsidiaries Interest expense, net of interest capitalized Other income Total other income (expense) Income (loss) before income taxes Income tax (expense) benefit 1 Net income (loss) Revenues Costs and expenses: Operating costs Depreciation General and administrative Bad debt expense Impairment Gain (loss) on dispositions of property and equipment, net Intercompany leasing Total costs and expenses Income (loss) from operations Other income (expense): Equity in earnings of subsidiaries Interest expense, net of interest capitalized Other income (expense) Total other income (expense), net Income (loss) before income taxes Income tax (expense) benefit 1 Net income (loss) Year ended December 31, 2019 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated $ — $ 486,860 $ 88,932 $ — $ 575,792 — 944 43,376 — — 3 — 44,323 (44,323) 18,184 (39,816) 451 (21,181) (65,504) 1,600 366,352 84,275 45,451 (79) 2,667 (3,752) (4,860) 490,054 (3,194) 23,008 13 1,311 24,332 21,138 (2,954) 65,001 5,665 2,898 — — (764) 4,860 77,660 11,272 — (32) 1,085 1,053 12,325 10,683 — — (540) — — — — (540) 540 (41,192) — (540) (41,732) (41,192) — (63,904) $ 18,184 $ 23,008 $ (41,192) $ 431,353 90,884 91,185 (79) 2,667 (4,513) — 611,497 (35,705) — (39,835) 2,307 (37,528) (73,233) 9,329 (63,904) Year ended December 31, 2018 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated — $ 505,936 $ 84,161 $ — $ 590,097 $ $ — 365,848 1,127 22,506 — — 1 — 23,634 (23,634) 8,966 (38,765) 578 (29,221) (52,855) 3,844 86,799 49,231 271 4,422 (3,068) (4,860) 498,643 7,293 5,669 (16) 867 6,520 13,813 (4,847) 64,065 5,628 2,800 — — (54) 4,860 77,299 6,862 — (1) (287) (288) 6,574 (905) — — (420) — — — — (420) 420 (14,635) — (420) (15,055) (14,635) — $ (49,011) $ 8,966 $ 5,669 $ (14,635) $ 429,913 93,554 74,117 271 4,422 (3,121) — 599,156 (9,059) — (38,782) 738 (38,044) (47,103) (1,908) (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. 82 CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (in thousands) Cash flows from operating activities Cash flows from investing activities: Purchases of property and equipment Proceeds from sale of property and equipment Proceeds from insurance recoveries Cash flows from financing activities: Purchase of treasury stock Intercompany contributions/distributions Net increase (decrease) in cash, cash equivalents and restricted cash Beginning cash, cash equivalents and restricted cash Ending cash, cash equivalents and restricted cash Cash flows from operating activities Cash flows from investing activities: Purchases of property and equipment Proceeds from sale of property and equipment Proceeds from insurance recoveries Cash flows from financing activities: Proceeds from exercise of options Purchase of treasury stock Intercompany contributions/distributions Net decrease in cash, cash equivalents and restricted cash Beginning cash, cash equivalents and restricted cash Ending cash, cash equivalents and restricted cash Year ended December 31, 2019 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated $ (81,025) $ 81,945 $ 11,102 $ — $ 12,022 (814) — — (814) (125) 46,075 45,950 (35,889) 51,348 15,459 $ (44,555) 7,619 641 (36,295) — (45,650) (45,650) — — — $ (4,677) 114 828 (3,735) — (425) (425) 6,942 3,216 10,158 $ — — — — — — — — — — $ (50,046) 7,733 1,469 (40,844) (125) — (125) (28,947) 54,564 25,617 Year ended December 31, 2018 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (51,948) $ 84,663 $ 6,940 $ — $ 39,655 (1,077) (59,478) (6,593) — — 5,826 1,066 38 16 (1,077) (52,586) (6,539) 12 (549) 32,525 31,988 (21,037) 72,385 51,348 $ — — (32,077) (32,077) — — — $ — — (448) (448) (47) 3,263 3,216 $ — — — — — — — — — — — $ (67,148) 5,864 1,082 (60,202) 12 (549) — (537) (21,084) 75,648 54,564 $ $ $ 83 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. 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, 2019, 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, 2019 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, 2019. 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, 2019, 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, 2019. This report is included in Item 8, Financial Statements and Supplementary Data. ITEM 9B. OTHER INFORMATION Not applicable. 84 Items 10, 11, 12, 13 and 14 of Part III will be incorporated by reference from the Form 10-K/A to be filed with the Securities and Exchange Commission. PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A. ITEM 11. EXECUTIVE COMPENSATION The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this item will be provided in an amendment to this Annual Report on Form 10-K/A. 85 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (1) Financial Statements. See Index to Consolidated Financial Statements included in Item 8, Financial Statements and Supplementary Data. PART IV (2) Financial Statement Schedules. No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the consolidated financial statements or notes thereto. (3) Exhibits. The following exhibits are filed as part of this report: Exhibit Number 2.1* 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+* - - - - - - - - - - - - - - - Description Disclosure Statement (Form 8-K dated February 28, 2020 (File No. 1-8182, Exhibit 2.1)). Restated Articles of Incorporation of Pioneer Energy Services Corp. (Form 8-K dated May 22, 2017 (File No. 1-8182, Exhibit 3.1)). Amended and Restated Bylaws of Pioneer Energy Services Corp. (Form 8-K dated July 2, 2019 (File No. 1-8182, Exhibit 3.1)). Form of Certificate representing Common Stock of Pioneer Energy Services Corp. (Form 10-Q dated August 7, 2012 (File No. 1-8182, Exhibit 4.1)). Indenture, dated March 18, 2014, by and among Pioneer Energy Services Corp., the subsidiaries named as guarantors therein and Wells Fargo Bank, National Association, as trustee (Form 8-K dated March 18, 2014 (File No. 1-8182, Exhibit 4.1)). Registration Rights Agreement, dated March 18, 2014, by and among Pioneer Energy Services Corp., the subsidiaries named as guarantors therein and the initial purchasers party thereto (Form 8-K dated March 18, 2014 (File No. 1-8182, Exhibit 10.1)). Pioneer Drilling Company 2003 Stock Plan (Form S-8 dated November 18, 2003 (File No. 333-110569, Exhibit 4.4)). Pioneer Drilling Company Amended and Restated 2007 Incentive Plan (Form 10-Q dated November 3, 2011 (File No. 1-8182, Exhibit 10.1)). Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement (Form 10-Q dated July 30, 2015 (File No. 1- 8182, Exhibit 10.1)). Pioneer Energy Services Corp. 2007 Incentive Plan Form of Stock Option Agreement (Form 10-Q dated July 30, 2015 (File No. 1- 8182, Exhibit 10.2)). Pioneer Energy Services Corp. 2007 Incentive Plan Form of Restricted Stock Unit Award Agreement (Form 10-Q dated July 30, 2015 (File No. 1-8182, Exhibit 10.3)). Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Restricted Stock Unit Award Agreement (Form 10-Q dated July 30, 2015 (File No. 1-8182, Exhibit 10.4)). Pioneer Energy Services Corp. 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 10-Q dated July 30, 2015 (File No. 1-8182, Exhibit 10.5)). Pioneer Energy Services Corp. 2007 Incentive Plan Form of Long-Term Incentive Cash Award Agreement (Form 10-Q dated July 30, 2015 (File No. 1-8182, Exhibit 10.6)). Pioneer Energy Services Corp. 2007 Incentive Plan Form of Performance Phantom Stock Unit Award Agreement (Form 10-Q dated July 28, 2016 (File No. 1-8182, Exhibit 10.3)). 86 10.10+* - Pioneer Energy Services Corp. 2007 Incentive Plan Form of Performance Phantom Stock Unit Award Agreement (Form 10-Q dated May 2, 2018 (File No. 1-8182, Exhibit 10.1)). 10.11+* 10.12+* 10.13+* 10.14+* 10.15+* 10.16+* 10.17+* 10.18* 10.19* 10.20* 10.21* 10.22* 10.23* 10.24+* 10.25+* 10.26+* 10.27+* 10.28+* - - - - - - - - - - - - - - - - Pioneer Energy Services Corp. 2007 Incentive Plan Form of Time-Based Phantom Stock Unit Award Agreement (Form 10-Q dated May 2, 2019 (File No. 1-8182, Exhibit 10.1)). Pioneer Drilling Services, Ltd. Amended and Restated Key Executive Severance Plan (Form 10-Q dated August 5, 2008 (File No. 1- 8182, Exhibit 10.4)). Pioneer Energy Services Corp. Form of Indemnification Agreement (Form 10-Q dated July 31, 2018 (File No. 1-8182, Exhibit 10.1)). Pioneer Drilling Company Employee Relocation Policy Executive Officers – Package A (Form 8-K dated August 8, 2007 (File No. 1- 8182, Exhibit 10.3)). Pioneer Energy Services Corp. Nonqualified Retirement Savings and Investment Plan (Form 8-K dated January 30, 2013 (File No. 1- 8182, Exhibit 10.1)). Employment Letter, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)). Employment Letter, effective May 13, 2012, from Pioneer Drilling Company to Brian L. Tucker (Form 10-Q dated April 29, 2016 (File No. 1-8182, Exhibit 10.1)). Credit Agreement, dated as of November 8, 2017, by and among Pioneer Energy Services Corp., Wells Fargo Bank, National Association, as administrative agent, sole lead arranger, sole bookrunner, and the other financial institutions party thereto (Form 8-K dated November 8, 2017 (File No. 1-8182, Exhibit 10.1)). Term Loan Credit Agreement, dated as of November 8, 2017, by and among Pioneer Energy Services, Corp., Goldman Sachs Lending Partners LLC, as syndication agent and the arranger, Wilmington Trust, National Association, as administrative agent, and the lenders party thereto (Form 8-K dated November 8, 2017 (File No. 1-8182, Exhibit 10.2)). Guaranty and Security Agreement, dated as of November 8, 2017 by and among Pioneer, the other grantors party thereto and Wells Fargo Bank, National Association, as administrative agent (Form 8-K dated November 8, 2017 (File No. 1-8182, Exhibit 10.3)). Intercreditor Agreement, dated November 8, 2017, by and among Wells Fargo, National Association, as initial ABL agent and Wilmington Trust, National Association, as initial term agent, and acknowledged and agreed to by Pioneer and the other grantors party thereto (Form 8-K dated November 8, 2017 (File No. 1-8182, Exhibit 10.4)). Guaranty Agreement, dated as of November 8, 2017, made by each of Pioneer and the guarantors party thereto, in favor of Wilmington Trust, National Association (Form 8-K dated November 8, 2017 (File No. 1-8182, Exhibit 10.5)). Security Agreement, dated as of November 8, 2017, by and among Pioneer, the other grantors party thereto and Wilmington Trust, National Association (Form 8-K dated November 8, 2017 (File No. 1-8182, Exhibit 10.6)). Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 12, 2013 (File No. 1-8182)). Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 9, 2014 (File No. 1-8182)). Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 20, 2015 (File No. 1-8182)). Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 18, 2016 (File No. 1-8182)). Pioneer Energy Services Corp. Amended and Restated 2007 Incentive Plan (Appendix A of definitive proxy statement on Schedule 14A dated April 16, 2019 (File No. 1-8182)). 10.29+* - Form of Retention Bonus Agreement (Form 8-K dated September 13, 2019 (File No. 1-8182, Exhibit 10.1)). 87 10.30+* 10.31+* 10.32* 10.33* 21.1** 23.1** 31.1** 31.2** 32.1# 32.2# 101.INS - - - - - - - - - - - Pioneer Energy Services Corp. 2019 Employee Incentive Plan (Form 8-K dated September 13, 2019 (File No. 1-8182, Exhibit 10.2)). Form of Bonus Award Letter (2019 Employee Incentive Plan) (Form 8-K dated September 13, 2019, (File No. 1-8182, Exhibit 10.3)). Restructuring Support Agreement, by and among the Pioneer RSA Parties and the Consenting Creditors (Form 8-K dated February 28, 2020 (File No. 1-8182, Exhibit 10.1)). Backstop Commitment Agreement, by and among Pioneer Energy Services Corp. and the Commitment Parties (Form 8-K dated February 28, 2020 (File No. 1-8182, Exhibit 10.2)). Subsidiaries of Pioneer Energy Services Corp. Consent of Independent Registered Public Accounting Firm. Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. XBRL 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 None. 88 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. SIGNATURES March 6, 2020 PIONEER ENERGY SERVICES CORP. /S/ WM. STACY LOCKE Wm. Stacy Locke Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature /S/ DEAN A. BURKHARDT Dean A. Burkhardt /S/ WM. STACY LOCKE Wm. Stacy Locke /S/ LORNE E. PHILLIPS Lorne E. Phillips /S/ C. JOHN THOMPSON C. John Thompson /S/ JOHN MICHAEL RAUH John Michael Rauh /S/ SCOTT D. URBAN Scott D. Urban /S/ TAMARA MORYTKO Tamara Morytko Chairman Title President, Chief Executive Officer and Director (Principal Executive Officer) Executive Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) Director Director Director Director 89 Date March 6, 2020 March 6, 2020 March 6, 2020 March 6, 2020 March 6, 2020 March 6, 2020 March 6, 2020 EXHIBIT 21.1 The following is a list of all of Pioneer Energy Services Corp.'s direct and indirect subsidiaries: 1. Pioneer Drilling Services, Ltd., a Texas corporation - 100% direct subsidiary. 2. Pioneer Global Holdings, Inc., a Delaware corporation - 100% indirect subsidiary-100% owned by Pioneer Drilling Services, Ltd. 3. Pioneer Services Holdings, LLC, a Delaware limited liability company - 100% indirect subsidiary-100% owned by Pioneer Global Holdings, Inc. 4. Pioneer Latina Group SDAD, Ltda., a Panama corporation - 100% indirect subsidiary-owned by Pioneer Global Holdings, Inc. (99%) and Pioneer Services Holdings, LLC (1%). 5. Pioneer de Colombia SDAD, Ltda., a Panama corporation - 100% indirect subsidiary-owned by Pioneer Latina Group SDAD, Ltda. (99%) and Pioneer Services Holdings, LLC (1%). 6. Pioneer de Colombia SDAD, Ltda., Surcusal Colombia, a Colombian branch - 100% indirect subsidiary-100% owned by Pioneer de Colombia SDAD, Ltda. 7. Proveedora Internacional de Taladros S.A.S - 100% indirect subsidiary-100% owned by Pioneer Global Holdings, Inc. 8. Pioneer Production Services, Inc., a Delaware corporation - 100% direct subsidiary. 9. Pioneer Wireline Services Holdings, Inc., a Delaware corporation - 100% indirect subsidiary-100% owned by Pioneer Production Services, Inc. 10. Pioneer Wireline Services, LLC, a Delaware limited liability company - 100% indirect subsidiary-100% owned by Pioneer Wireline Services Holdings, Inc. 11. Pioneer Well Services, LLC, a Delaware limited liability company - 100% indirect subsidiary-100% owned by Pioneer Production Services, Inc. 12. Pioneer Fishing & Rental Services, LLC, a Delaware limited liability company - 100% indirect subsidiary-100% owned by Pioneer Production Services, Inc. 13. Pioneer Coiled Tubing Services, LLC, a Delaware limited liability company - 100% indirect subsidiary-100% owned by Pioneer Production Services, Inc. Consent of Independent Registered Public Accounting Firm EXHIBIT 23.1 The Board of Directors Pioneer Energy Services Corp.: We consent to the incorporation by reference in the registration statements (No. 333-225094) on Form S-3 and (Nos. 333-48286, 333-110569, 333-153180, 333-160415, 333-177077, 333-188722, 333-195966, 333-211550, and 333-231684) on Form S-8 of Pioneer Energy Services Corp. of our reports dated March 6, 2020, with respect to the consolidated balance sheets of Pioneer Energy Services Corp. and subsidiaries as of December 31, 2019 and 2018, the related consolidated statements of operations, shareholders' equity, and cash flows for each of the years in the two-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and the effectiveness of internal control over financial reporting as of December 31, 2019, which reports appear in the December 31, 2019 annual report on Form 10-K of Pioneer Energy Services Corp. Our report dated March 6, 2020 contains an explanatory paragraph that states that 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. The consolidated financial statements do not include any adjustments that might result from the outcome of that uncertainty. Our report also refers to the adoption of Accounting Standards Update No. 2016-02, Leases. /s/ KPMG LLP San Antonio, Texas March 6, 2020 I, Wm. Stacy Locke, certify that: 1. I have reviewed this annual report on Form 10-K of Pioneer Energy Services Corp.; Exhibit 31.1 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. March 6, 2020 /s/ Wm. Stacy Locke Wm. Stacy Locke President and Chief Executive Officer I, Lorne E. Phillips, certify that: 1. I have reviewed this annual report on Form 10-K of Pioneer Energy Services Corp.; Exhibit 31.2 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. March 6, 2020 /s/ Lorne E. Phillips Lorne E. Phillips Executive Vice President and Chief Financial Officer Officer’s Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C 1350) Exhibit 32.1 In connection with the Annual Report on Form 10-K of Pioneer Energy Services Corp., a Texas corporation, (the “Company”) for the year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Wm. Stacy Locke, President and Chief Executive Officer, hereby certifies, pursuant to 18 U.S.C. Section 1350, that, to the best of his knowledge: (1) The Report is in full compliance with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: March 6, 2020 /s/ Wm. Stacy Locke Wm. Stacy Locke President and Chief Executive Officer Officer’s Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C 1350) Exhibit 32.2 In connection with the Annual Report on Form 10-K of Pioneer Energy Services Corp., a Texas corporation, (the “Company”) for the year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Lorne E. Phillips, Executive Vice President and Chief Financial Officer, hereby certifies, pursuant to 18 U.S.C. Section 1350, that, to the best of his knowledge: (1) The Report is in full compliance with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: March 6, 2020 /s/ Lorne E. Phillips Lorne E. Phillips Executive Vice President and Chief Financial Officer 

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