Company Quick10K Filing
Key Energy Services
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$0.00 20 $41
10-K 2020-03-13 Annual: 2019-12-31
10-Q 2019-11-08 Quarter: 2019-09-30
10-Q 2019-08-09 Quarter: 2019-06-30
10-Q 2019-05-09 Quarter: 2019-03-31
10-K 2019-03-15 Annual: 2018-12-31
10-Q 2018-11-07 Quarter: 2018-09-30
10-Q 2018-08-09 Quarter: 2018-06-30
10-Q 2018-05-10 Quarter: 2018-03-31
10-K 2018-02-28 Annual: 2017-12-31
10-Q 2017-11-09 Quarter: 2017-09-30
10-Q 2017-08-10 Quarter: 2017-06-30
10-Q 2017-05-11 Quarter: 2017-03-31
10-K 2017-03-02 Annual: 2016-12-31
10-Q 2016-11-14 Quarter: 2016-09-30
10-Q 2016-08-15 Quarter: 2016-06-30
10-Q 2016-05-13 Quarter: 2016-03-31
10-K 2016-03-04 Annual: 2015-12-31
10-Q 2015-11-09 Quarter: 2015-09-30
10-Q 2015-08-04 Quarter: 2015-06-30
10-Q 2015-05-05 Quarter: 2015-03-31
10-K 2015-02-25 Annual: 2014-12-31
10-Q 2014-11-04 Quarter: 2014-09-30
10-Q 2014-08-07 Quarter: 2014-06-30
10-Q 2014-05-06 Quarter: 2014-03-31
10-K 2014-02-25 Annual: 2013-12-31
10-Q 2013-11-01 Quarter: 2013-09-30
10-Q 2013-08-02 Quarter: 2013-06-30
10-Q 2013-05-03 Quarter: 2013-03-31
10-K 2013-02-25 Annual: 2012-12-31
10-Q 2012-11-08 Quarter: 2012-09-30
10-Q 2012-08-03 Quarter: 2012-06-30
10-Q 2012-05-04 Quarter: 2012-03-31
10-K 2012-02-29 Annual: 2011-12-31
10-Q 2011-11-04 Quarter: 2011-09-30
10-Q 2011-08-05 Quarter: 2011-06-30
10-Q 2011-05-06 Quarter: 2011-03-31
10-K 2011-02-28 Annual: 2010-12-31
10-Q 2010-11-02 Quarter: 2010-09-30
10-Q 2010-08-05 Quarter: 2010-06-30
10-Q 2010-05-10 Quarter: 2010-03-31
10-K 2010-02-26 Annual: 2009-12-31
8-K 2020-03-23 Officers, Exhibits
8-K 2020-03-10 Earnings, Exhibits
8-K 2020-03-06 Enter Agreement, Off-BS Arrangement, Sale of Shares, Shareholder Rights, Officers, Amend Bylaw, Other Events, Exhibits
8-K 2020-02-28 Enter Agreement
8-K 2020-02-18 Shareholder Vote
8-K 2020-01-31 Enter Agreement, Exhibits
8-K 2020-01-24 Enter Agreement, Sale of Shares, Other Events, Exhibits
8-K 2020-01-10 Enter Agreement, Exhibits
8-K 2019-12-30 Officers, Exhibits
8-K 2019-12-20 Enter Agreement, Exhibits
8-K 2019-12-06 Enter Agreement, Other Events, Exhibits
8-K 2019-11-27 Exhibits
8-K 2019-11-15 Amend Bylaw, Exhibits
8-K 2019-11-07 Earnings, Exhibits
8-K 2019-10-29 Enter Agreement, Other Events, Exhibits
8-K 2019-08-08 Earnings, Exhibits
8-K 2019-06-25 Exhibits
8-K 2019-05-08 Earnings, Exhibits
8-K 2019-05-01 Officers, Shareholder Vote, Exhibits
8-K 2019-04-26 Officers
8-K 2019-04-05 Enter Agreement, Exhibits
8-K 2019-03-26 Officers
8-K 2019-02-26 Earnings, Exhibits
8-K 2019-02-22 Shareholder Vote
8-K 2019-02-11 Earnings, Regulation FD, Exhibits
8-K 2019-02-04 Officers, Exhibits
8-K 2019-01-24 Officers
8-K 2018-11-07 Earnings, Exhibits
8-K 2018-10-03 Officers
8-K 2018-10-01 Earnings, Regulation FD, Exhibits
8-K 2018-09-20 Other Events, Exhibits
8-K 2018-09-12 Officers
8-K 2018-08-17 Officers, Regulation FD, Exhibits
8-K 2018-08-09 Earnings, Exhibits
8-K 2018-06-22 Officers, Exhibits
8-K 2018-05-29 Officers
8-K 2018-05-10 Earnings, Exhibits
8-K 2018-05-10 Officers, Exhibits
8-K 2018-03-26 Regulation FD, Exhibits
8-K 2018-02-27 Earnings, Exhibits
8-K 2018-02-12 Regulation FD, Exhibits
8-K 2017-12-31 Officers
KEG 2019-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Note 1. Organization and Summary of Significant Accounting Policies
Note 2. Revenue From Contracts with Customers
Note 3. Other Balance Sheet Information
Note 4. Other Income, Net
Note 5. Allowance for Doubtful Accounts
Note 6. Property and Equipment
Note 7. Intangible Assets
Note 8. Earnings per Share
Note 9. Estimated Fair Value of Financial Instruments
Note 10. Asset Retirement Obligations
Note 11. Income Taxes
Note 12. Long-Term Debt
Note 13. Commitments and Contingencies
Note 14. Employee Benefit Plans
Note 15. Stockholders' Equity
Note 16. Share-Based Compensation
Note 17. Transactions with Related Parties
Note 18. Supplemental Cash Flow Information
Note 19. Segment Information
Note 20. Unaudited Quarterly Results of Operations
Note 21. Leases
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits, Financial Statement Schedules
Item 16. Form 10-K Summary
EX-4.2.1 keg10-k12312019ex421.htm
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EX-10.5.22 keg10-k12312019ex10522.htm
EX-21.1 keg10-k12312019ex21.htm
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EX-32 keg10-k12312019ex32.htm

Key Energy Services Earnings 2019-12-31

KEG 10K Annual Report

Balance SheetIncome StatementCash Flow

Comparables ($MM TTM)
Ticker M Cap Assets Liab Rev G Profit Net Inc EBITDA EV G Margin EV/EBITDA ROA
RNGR 61 308 106 342 0 7 39 107 0% 2.8 2%
NES 66 278 66 180 0 -26 1 98 0% 76.0 -9%
QES 62 267 129 548 0 -69 -15 80 0% -5.3 -26%
BAS 40 668 540 565 184 -141 -12 303 32% -25.9 -21%
KEG 28 374 446 87 -90 -25 249 19% -9.8 -24%
RCON 17 157 50 8 1 2 2 13 14% 5.3 1%
ENSV 14 40 40 38 7 -4 3 17 18% 5.5 -11%
NEX 1,059 587 1,780 412 -17 287 181 23% 0.6 -2%
NOA
USWS 656 432 541 87 -108 42 292 16% 7.0 -16%

10-K 1 keg10-k12312019.htm 10-K Document

 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ______________________________________
Form 10-K
(Mark One)
 
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 001-08038
KEY ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
Delaware
 
04-2648081
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
1301 McKinney Street
Suite 1800
Houston, Texas 77010
(Address of principal executive offices, including Zip Code)
(713) 651-4300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
 
 
 
Title of Each Class
Trading Symbol
Name of Exchange on Which Registered
Common Stock, $0.01 par value
KEGXD
OTC
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
None
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act.    Yes  ¨         No  þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes  ¨         No  þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ         No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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  þ 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
 
¨
  
Accelerated filer
 
¨
 
 
 
 
Non-accelerated filer
 
þ
  
Smaller reporting company
 
þ
 
 
 
 
 
 
 
 
 
 
 
Emerging growth company
 
¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨ 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨       No  þ
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes þ No ¨
The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2019, based on the $112.50 per share closing price for the registrant’s common stock on such date as adjusted for the 1-for-50 reverse stock split effective as of March 6, 2020, was $16.6 million (for purposes of calculating these amounts, only directors, officers and beneficial owners of 10% or more of the outstanding common stock of the registrant have been deemed affiliates).
As of March 6, 2020, the number of outstanding shares of common stock of the registrant was 13,775,267.
 
 






KEY ENERGY SERVICES, INC.
ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2019
INDEX
 
 
Page
Number
 
PART I
 
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
 
PART II
 
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
 
PART III
 
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
 
PART IV
 
ITEM 15.
ITEM 16.


2


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
In addition to statements of historical fact, this report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Statements that are not historical in nature or that relate to future events and conditions are, or may be deemed to be, forward-looking statements. These “forward-looking statements” are based on our current expectations, estimates and projections about Key Energy Services, Inc. and its wholly owned and controlled subsidiaries, our industry and management’s beliefs and assumptions concerning future events and financial trends affecting our financial condition and results of operations. In some cases, you can identify these statements by terminology such as “may,” “will,” “should,” “predicts,” “expects,” “believes,” “anticipates,” “projects,” “potential” or “continue” or the negative of such terms and other comparable terminology. These statements are only predictions and are subject to substantial risks and uncertainties and are not guarantees of performance. Future actions, events and conditions and future results of operations may differ materially from those expressed in these statements. In evaluating those statements, you should carefully consider the risks outlined in “Item 1A. Risk Factors.”
We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date of this report except as required by law. All of our written and oral forward-looking statements are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements.
Important factors that may affect our expectations, estimates or projections include, but are not limited to, the following:
our ability to satisfy our cash and liquidity needs, including our ability to generate sufficient liquidity or cash flow from operations or to obtain adequate financing to fund our operations or otherwise meet our obligations as they come due;
our ability to retain employees, customers or suppliers as a result of our financial condition generally or as a result of our recent Restructuring (as defined below);
our inability to achieve the potential benefits of the Restructuring;
conditions in the services and oil and natural gas industries, especially oil and natural gas prices and capital expenditures by oil and natural gas companies;
our ability to achieve the benefits of cost-cutting initiatives, including our plan to optimize our geographic footprint, including exiting certain locations and reducing our regional and corporate overhead costs;
our ability to implement price increases or maintain pricing on our core services;
risks that we may not be able to reduce, and could even experience increases in, the costs of labor, fuel, equipment and supplies employed in our businesses;
industry capacity;
asset impairments or other charges;
the low demand for our services and resulting operating losses and negative cash flows;
our highly competitive industry as well as operating risks, which are primarily self-insured, and the possibility that our insurance may not be adequate to cover all of our losses or liabilities;
significant costs and potential liabilities resulting from compliance with applicable laws, including those resulting from environmental, health and safety laws and regulations, specifically those relating to hydraulic fracturing, as well as climate change legislation or initiatives;
our historically high employee turnover rate and our ability to replace or add workers, including executive officers and skilled workers;
our ability to implement technological developments and enhancements;
severe weather impacts on our business, including from hurricane activity;
our ability to successfully identify, make and integrate acquisitions and our ability to finance future growth of our operations or future acquisitions;
our ability to achieve the benefits expected from disposition transactions;
the loss of one or more of our larger customers;
the amount of our debt and the limitations imposed by the covenants in the agreements governing our debt, including our ability to comply with covenants under our debt agreements;
an increase in our debt service obligations due to variable rate indebtedness;
our inability to achieve our financial, capital expenditure and operational projections, including quarterly and annual projections of revenue, and/or operating income and the possibility of our inaccurate assessment of future activity levels, customer demand, and pricing stability which may not materialize (whether for Key as a whole or for geographic regions and/or business segments individually);
our ability to respond to changing or declining market conditions, including our ability to reduce the costs of labor, fuel, equipment and supplies employed and used in our businesses;
adverse impact of litigation; and
other factors affecting our business described in “Item 1A. Risk Factors.”

3


PART I
ITEM 1.    BUSINESS
General Description of Business
Key Energy Services, Inc., a Delaware corporation, is the largest onshore, rig-based well servicing contractor based on the number of rigs owned. References to “Key,” the “Company,” “we,” “us” or “our” in this report refer to Key Energy Services, Inc., its wholly owned subsidiaries and its controlled subsidiaries. We were organized in April 1977 in Maryland and commenced operations in July 1978 under the name National Environmental Group, Inc. In December 1992, we became Key Energy Group, Inc. and we changed our name to Key Energy Services, Inc. in December 1998. We reincorporated as a Delaware corporation on December 15, 2016.
We provide a full range of well services to major oil companies and independent oil and natural gas production companies. Our services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services, and other ancillary oilfield services. Additionally, certain rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States. An important component of the Company’s growth strategy is to make acquisitions that will strengthen its core services or presence in selected markets, and the Company also makes strategic divestitures from time to time. To that end, we completed the sale of our Canadian subsidiary and Russian subsidiary in the second and third quarters of 2017, respectively. The Company expects that the industry in which it operates will continue to experience consolidation, and as part of its strategy the Company actively explores opportunities arising out of this consolidation, which could include mergers, consolidations or acquisitions or further dispositions or other transactions, including by engaging in discussions with other industry participants concerning these opportunities. There can be no assurance that any such activities will be consummated.
Restructuring and Reverse Stock Split
On March 6, 2020, we closed the previously announced restructuring of our capital structure and indebtedness (the “Restructuring”) pursuant to the Restructuring Support Agreement, dated as of January 24, 2020 (the “RSA”), with lenders under our Prior Term Loan Facility (as defined below) collectively holding over 99.5% (the “Supporting Term Lenders”) of the principal amount of the Company’s then outstanding term loans. Pursuant to or in connection with the RSA and the Restructuring contemplated thereby, among other things we effected the following transactions and changes to our capital structure and governance:
immediately prior to the closing of the Restructuring, we completed a 1-for-50 reverse stock split of our outstanding common stock as a result of which our issued and outstanding common stock decreased from 20,659,654 to 413,258 shares; accordingly, all share and per share information contained in this report has been restated to retroactively show the effect of this stock split;
pursuant to exchange agreements entered into at the closing of the Restructuring, we then exchanged approximately $241.9 million aggregate outstanding principal of our term loans (together with accrued interest thereon) held by Supporting Term Lenders under our Prior Term Loan Facility into (i) approximately 13.4 million newly issued shares of common stock representing 97% of the Company’s outstanding shares after giving effect to such issuance (and without giving effect to dilution by the New Warrants and MIP (each as defined below)) and (ii) $20 million of term loans under our new $51.2 million term loan facility (the “New Term Loan Facility”), each on a pro rata basis based on their holdings of term loans under the Prior Term Loan Facility;
distributed to our common stockholders of record as of February 18, 2020 two series of warrants (the “New Warrants”);
entered into the $51.2 million New Term Loan Facility, of which (i) $30 million was funded at closing of the Restructuring with new cash proceeds from the Supporting Term Lenders and $20 million was issued in exchange for term loans held by the Supporting Term Lenders under the Prior Term Loan Facility as described above and (ii) an approximate $1.2 million was a senior secured term loan tranche in respect of term loans held by lenders under the Prior Term Loan Facility who were not Supporting Term Lenders;
entered into the New ABL Facility (as defined below);
adopted a new management incentive plan (the “MIP”) representing up to 9% of the Company’s outstanding shares after giving effect to the issuance of shares described above; and
made certain changes to the Company’s governance, including changes to our Board of Directors (the “Board”), amendments to our governing documents and entry into the Stockholders Agreement (as defined below) with the Supporting Term Lenders.
In accordance with the RSA at the closing of the Restructuring, the Company amended and restated its certificate of incorporation and entered into a stockholders agreement (the “Stockholders Agreement”) with the Supporting Term Lenders in order to, among other things, provide for a Board of seven members. Pursuant to the Stockholders Agreement, our Board consists of our chief executive officer and six other members appointed by various Supporting Term Lenders. Specifically, pursuant to the Stockholders Agreement, Supporting Term Lenders who hold more than 25% of the Company’s outstanding shares as of the closing

4


of the Restructuring are entitled to nominate two directors and Supporting Term Lenders who hold between 10% and 25% of the Company’s outstanding shares as of the closing of the Restructuring are entitled to nominate one director. All appointees or nominees of Supporting Term Lenders, other than any directed appointed or nominated by Soter Capital LLC (“Soter”), must meet the “independent director” requirements set forth in Section 303A of the NYSE Listed Company Manual. In addition, pursuant to the Stockholders Agreement, Supporting Term Lenders are entitled to appoint a non-voting board observer subject to specified ownership thresholds.
In accordance with the RSA and following the closing of the Restructuring, the Company distributed to stockholders of record as of February 18, 2020 the New Warrants. The New Warrants were issued in two series each with a four-year exercise period. The first series entitles the holders to purchase in the aggregate 1,669,730 newly issued shares of common stock, representing 10% of the Company’s common shares at the closing of the Restructuring on an as-exercised basis (after giving effect to the exercise of all New Warrants, but subject to dilution by issuances under the MIP). The aggregate exercise price of the first series of New Warrants is $19.23 and was determined based on the aggregate outstanding principal amount of term loans under the Prior Term Loan Facility plus accrued interest thereon at the default rate as of the closing of the Restructuring. The second series of New Warrants entitles the holders to purchase in the aggregate 1,252,297 newly issued shares of common stock, representing 7.5% of the Company’s common shares at the closing of the Restructuring on an as-exercised basis (after giving effect to the exercise of all New Warrants, but subject to dilution by issuances under the MIP). The aggregate strike price of the second series of New Warrants is $28.85 and was determined based on the product of (i) the aggregate outstanding principal amount of term loans under the Prior Term Loan Facility plus accrued interest thereon at the default rate as of the closing of the Restructuring, multiplied by (ii) 1.50.
For more information on our New Term Loan Facility and New ABL Facility entered into in connection with the Restructuring, see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Service Offerings
Our reportable business segments are Rig Services, Fishing and Rental Services, Coiled Tubing Services and Fluid Management Services. Our reportable business segments previously included an International segment. We also have a “Functional Support” segment associated with overhead and other costs in support of our reportable segments. Our Rig Services, Fluid Management Services, Coiled Tubing Services and Fishing and Rental Services operate geographically within the United States. The International reportable segment includes our former operations in Canada and Russia, which were sold in the second and third quarters of 2017, respectively. We evaluate the performance of our segments based on gross margin measures. All inter-segment sales pricing is based on current market conditions. See “Note 19. Segment Information” in “Item 8. Financial Statements and Supplementary Data” for additional financial information about our reportable business segments and the various geographical areas where we operate.
Rig Services
Our Rig Services include the completion of newly drilled wells, workover and recompletion of existing oil and natural gas wells, well maintenance, and the plugging and abandonment of wells at the end of their useful lives. We also provide specialty drilling services to oil and natural gas producers with certain of our larger rigs that are capable of providing conventional and horizontal drilling services. Our rigs encompass various sizes and capabilities, allowing us to service all types of oil and gas wells. Many of our rigs are outfitted with our proprietary KeyView® technology, which captures and reports well site operating data and provides safety control systems. We believe that this technology allows our customers and our crews to better monitor well site operations, improves efficiency and safety, and adds value to the services that we offer.
The completion and recompletion services provided by our rigs prepare wells for production, whether newly drilled or recently extended through a workover operation. The completion process may involve selectively perforating the well casing to access production zones, stimulating and testing these zones, and installing tubular and downhole equipment. We typically provide a well service rig and may also provide other equipment to assist in the completion process. Completion services vary by well and our work may take a few days to several weeks to perform, depending on the nature of the completion.
The workover services that we provide are designed to enhance the production of existing wells and generally are more complex and time consuming than normal maintenance services. Workover services can include deepening or extending wellbores into new formations by drilling horizontal or lateral wellbores, sealing off depleted production zones and accessing previously bypassed production zones, converting former production wells into injection wells for enhanced recovery operations and conducting major subsurface repairs due to equipment failures. Workover services may last from a few days to several weeks, depending on the complexity of the workover.
Maintenance services provided with our rig fleet are generally required throughout the life cycle of an oil or natural gas well. Examples of these maintenance services include routine mechanical repairs to the pumps, tubing and other equipment, removing debris and formation material from wellbores, and pulling rods and other downhole equipment from wellbores to identify

5


and resolve production problems. Maintenance services are generally less complicated than completion and workover related services and require less time to perform.
Our rig fleet is also used in the process of permanently shutting-in oil or natural gas wells that are at the end of their productive lives. These plugging and abandonment services generally require auxiliary equipment in addition to a well servicing rig. The demand for plugging and abandonment services is not significantly impacted by the demand for oil and natural gas because well operators are required by state regulations to plug wells that are no longer productive.
We believe that the largest competitors for our Rig Services include NexTier Oilfield Solutions Inc., Basic Energy Services, Inc., Superior Energy Services, Inc., Forbes Energy Services Ltd., Pioneer Energy Services Corp and Ranger Energy Services, Inc. Numerous smaller companies also compete in our rig-based markets in the United States.
Fishing and Rental Services
We offer a full line of fishing services and rental equipment designed for use in providing onshore drilling and workover services. Fishing services involve recovering lost or stuck equipment in the wellbore utilizing a broad array of “fishing tools.” Our rental tool inventory consists of drill pipe, tubulars, handling tools (including our patented Hydra-Walk® pipe-handling units and services), pressure-control equipment, pumps, power swivels, reversing units and foam air units. Our rental inventory also included frac stack equipment used to support hydraulic fracturing operations and the associated flowback of frac fluids, proppants, oil and natural gas. We also had provided well-testing services. Our frac stack equipment and well-testing services were sold in the second quarter of 2017.
Demand for our Fishing and Rental Services is also closely related to capital spending by oil and natural gas producers.
Our primary competitors for our Fishing and Rental Services include Baker Oil Tools (owned by Baker Hughes, a GE company, LLC), Weatherford International Ltd., Basic Energy Services, Inc., Smith Services (owned by Schlumberger), Superior Energy Services, Inc., Quail Tools (owned by Parker Drilling Company) and Knight Oil Tools. Numerous smaller companies also compete in our fishing and rental services markets in the United States.
Coiled Tubing Services
Coiled Tubing Services involve the use of a continuous metal pipe spooled onto a large reel which is then deployed into oil and natural gas wells to perform various applications, such as wellbore clean-outs, nitrogen jet lifts, through-tubing fishing, and formation stimulations utilizing acid and chemical treatments. Coiled tubing, particularly larger diameter coil units, is also used for a number of horizontal well applications such as milling temporary isolation plugs that separate frac zones and various other pre- and post-hydraulic fracturing well preparation services.
Our primary competitors in the Coiled Tubing Services market include Schlumberger Ltd., Baker Hughes, a GE company, LLC, Halliburton Company, Superior Energy Services, Inc., Nine Energy Services and NexTier Oilfield Solutions Inc. Numerous smaller companies also compete in our coiled tubing services markets in the United States. Demand for these services generally corresponds to demand for well completion services.
Fluid Management Services
We provide transportation and well-site storage services for various fluids utilized in connection with drilling, completions, workover and maintenance activities. We also provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in saltwater disposal (“SWD”) wells owned by us or a third party. Demand and pricing for these services generally correspond to demand for our well service rigs.
We believe that the largest competitors for our domestic fluid management services include Select Energy Services, Basic Energy Services, Inc., Superior Energy Services, Inc., Nuverra Environmental Solutions, Forbes Energy Services Ltd., and Stallion Oilfield Services Ltd. Numerous smaller companies also compete in the fluid management services market in the United States.
International Segment
Our International segment included our former operations in Canada and Russia. We completed the sale of our Canadian subsidiary and Russian subsidiary in the second and third quarters of 2017, respectively. Our services in Russia consisted of rig-based services such as the maintenance, workover, and recompletion of existing oil wells, completion of newly-drilled wells, and plugging and abandonment of wells at the end of their useful lives. Our Canadian subsidiary was a technology development and control systems business focused on the development of hardware and software related to oilfield service equipment controls, data acquisition and digital information flow.
Functional Support Segment
Our Functional Support segment includes unallocated overhead costs associated with sales, safety and administrative support for each of our reporting segments.

6


Equipment Overview
We categorize our rigs and equipment as active, warm stacked or cold stacked. We consider an active rig or piece of equipment to be a unit that is working, deployed, available for work or idle. A warm stacked rig or piece of equipment is a unit that is down for repair or needs repair. A cold stacked rig or piece of equipment is a unit that would require such significant investment to redeploy that we may salvage for parts, sell the unit or scrap the unit. The definitions of active, warm stacked or cold stacked are used for the majority of our equipment.
Rigs
As mentioned above, our fleet is diverse and allows us to work on all types of wells, ranging from very shallow wells to long horizontal laterals. Higher derrick lifting capacity rigs will be utilized to service the deeper wells and longer laterals as they require a higher pull weight and taller derrick. The lower derrick lifting capacity rigs are typically used on shallower, less complex wells. In most cases, these rigs can be reassigned to other regions should market conditions warrant the transfer of equipment. The following table summarizes our rigs based on derrick height measured in feet as of December 31, 2019:
 
Derrick Height (Feet)
 
< 102’
 
≥ 102’
 
Total
Active
89

 
161

 
250

Warm stacked
173

 
89

 
262

Cold stacked
250

 
101

 
351

Total
512

 
351

 
863

Coiled Tubing
Coiled tubing uses a spooled continuous metal pipe that is injected downhole in oil and gas wells in order to convey tools, log, stimulate, clean-out and perform other intervention functions. Typically, larger diameter coiled tubing is able to service longer lateral horizontal wells. The table below summarizes our Coiled Tubing Services fleet by pipe diameter as of December 31, 2019:
 
Pipe Diameter (Inches)
 
< 2
 
≥ 2” < 2.375”
 
≥ 2.375
 
Total
Active
9

 
1

 
9

 
19

Warm stacked
4

 
3

 
3

 
10

Cold stacked
3

 
3

 
1

 
7

Total
16

 
7

 
13

 
36

Fluid Management Services
We have an extensive and diverse fleet of oilfield transportation service vehicles. We broadly define an oilfield transportation service vehicle as any heavy-duty, revenue-generating vehicle weighing over one ton. Our transportation fleet includes vacuum trucks, winch trucks, hot oilers and other vehicles, including kill trucks and various hauling and transport trucks. The table below summarizes our Fluid Management Services fleet as of December 31, 2019:
 
Active
 
Warm Stacked
 
Cold Stacked
 
Total
Truck Type
 
 
 
 
 
 
 
Vacuum Trucks
212

 
100

 
28

 
340

Winch Trucks
85

 
14

 
4

 
103

Hot Oil Trucks
10

 
16

 
10

 
36

Kill Trucks
34

 
11

 
9

 
54

Other
44

 
6

 
11

 
61

Total
385

 
147

 
62

 
594


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Disposal Wells
As part of our Fluid Management Services, we provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in SWD wells. The table below summarizes our SWD facilities, and brine and freshwater stations by state as of December 31, 2019:
 
Owned
 
Leased(1)
 
Total
Location
 
 
 
 
 
Arkansas
1

 

 
1

Louisiana
2

 

 
2

New Mexico
1

 
9

 
10

Texas
23

 
24

 
47

Total
27

 
33

 
60

(1)
Includes SWD facilities as “leased” if we own the wellbore for the SWD but lease the land. In other cases, we lease both the wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain the wellbore at the termination of the lease.
Other Business Data
Raw Materials
We purchase a wide variety of raw materials, parts and components that are made by other manufacturers and suppliers for our use. We are not dependent on any single source of supply for those parts, supplies or materials.
Customers
Our customers include major oil companies, independent oil and natural gas production companies. During the year ended December 31, 2017, Chevron Texaco Exploration and Production accounted for approximately 12% of our consolidated revenue. No other customer accounted for more than 10% of our consolidated revenue during the years ended December 31, 2019, 2018 and 2017. No customers accounted for more than 10% of our total accounts receivable as of December 31, 2019 and 2018.
Competition and Other External Factors
The markets in which we operate are highly competitive. Competition is influenced by such factors as product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. We believe that an important competitive factor in establishing and maintaining long-term customer relationships is having an experienced, skilled and well-trained work force. We devote substantial resources toward employee safety and training programs. We believe many of our larger customers place increased emphasis on the safety, performance and quality of the crews, equipment and services provided by their contractors. Although we believe customers consider all of these factors, price is often the primary factor in determining which service provider is awarded the work. However, in numerous instances, we secure and maintain work for large customers for which efficiency, safety, technology, size of fleet and availability of other services are of equal importance to price.
The demand for our services and price we receive fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven for the most part by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in a lower oil and natural gas price environment, demand for service and maintenance generally decreases as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Furthermore, in a low commodity price environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.
The level of our revenues, earnings and cash flows are substantially dependent upon, and affected by, the level of U.S. and international oil and natural gas exploration, development and production activity, as well as the equipment capacity in any particular region.

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Seasonality
Our operations are impacted by seasonal factors. Historically, our business has been negatively impacted during the winter months due to inclement weather, fewer daylight hours and holidays. During the summer months, our operations may be impacted by tropical or other inclement weather systems. During periods of heavy snow, ice or rain, we may not be able to operate or move our equipment between locations, thereby reducing our ability to provide services and generate revenues. In addition, the majority of our equipment works only during daylight hours. In the winter months when days become shorter, this reduces the amount of time that our assets can work and therefore has a negative impact on total hours worked. Lastly, during the fourth quarter, we historically experience a significant slowdown during the Thanksgiving and Christmas holiday seasons and demand sometimes slows during this period as our customers exhaust their annual spending budgets.
Patents, Trade Secrets, Trademarks and Copyrights
We own numerous patents, trademarks and proprietary technology that we believe provide us with a competitive advantage in the various markets in which we operate or intend to operate. We have devoted significant resources to developing technological improvements in our well service business and have sought patent protection for products and methods that appear to have commercial significance. All the issued patents have varying remaining durations through 2035, and began expiring in 2019.
We own several trademarks that are important to our business. In general, depending upon the jurisdiction, trademarks are valid as long as they are in use, or their registrations are properly maintained and they have not been found to become generic. Registrations of trademarks can generally be renewed indefinitely as long as the trademarks are in use. While our patents and trademarks, in the aggregate, are of considerable importance to maintaining our competitive position, no single patent or trademark is considered to be of a critical or essential nature to our business.
We also rely on a combination of trade secret laws, copyright and contractual provisions to establish and protect proprietary rights in our products and services. We typically enter into confidentiality agreements with our employees, strategic partners and suppliers and limit access to the distribution of our proprietary information.
Employees
As of December 31, 2019, we employed approximately two thousand persons. Our employees are not represented by a labor union and are not covered by collective bargaining agreements. As noted below in “Item 1A. Risk Factors,” we have historically experienced a high employee turnover rate. We have not experienced any significant work stoppages associated with labor disputes or grievances and consider our relations with our employees to be generally satisfactory.
Governmental Regulations
Our operations are subject to various federal, state and local laws and regulations pertaining to health, safety and the environment. We cannot predict the level of enforcement of existing laws or regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. We also cannot predict whether additional laws and regulations affecting our business will be adopted, or the effect such changes might have on us, our financial condition or our business. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our operations are subject and for which a lack of compliance may have a material adverse impact on our results of operations, financial position or cash flows. We believe that we are in material compliance with all such laws.
Environmental Regulations
Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and other regulated substances. Various environmental laws and regulations require prevention, and where necessary, cleanup of spills and leaks of such materials, and some of our operations must obtain permits that limit the discharge of materials. Failure to comply with such environmental requirements or permits may result in fines and penalties, remediation orders and revocation of permits.
Hazardous Substances and Waste
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as “CERCLA” or the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct of certain defined persons, including current and prior owners or operators of a site where a release of hazardous substances occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be jointly and severally liable for the costs of cleaning up the hazardous substances, for damages to natural resources and for the costs of certain health studies.
In the course of our operations, we occasionally generate materials that are considered “hazardous substances” and, as a result, may incur CERCLA liability for cleanup costs. Also, claims may be filed for personal injury and property damage allegedly

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caused by the release of hazardous substances or other pollutants. We also generate solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or “RCRA,” and comparable state statutes.
Although we use operating and disposal practices that are standard in the industry, hydrocarbons or other wastes may have been released at properties owned or leased by us now or in the past, or at other locations where these hydrocarbons and wastes were taken for treatment or disposal. Under CERCLA, RCRA and analogous state laws, we could be required to clean up contaminated property (including contaminated groundwater), or to perform remedial activities to prevent future contamination.
Air Emissions
The Clean Air Act, as amended, or “CAA,” and similar state laws and regulations restrict the emission of air pollutants and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain approvals or permits for construction, modification or operation of certain projects or facilities and may require use of emission controls.
Global Warming and Climate Change
Some scientific studies suggest that emissions of greenhouse gases (including carbon dioxide and methane) may contribute to warming of Earth’s atmosphere. While we do not believe our operations raise climate change issues different from those generally raised by commercial use of fossil fuels, legislation or regulatory programs that restrict greenhouse gas emissions in areas where we conduct business could increase our costs in order to comply with any new laws.
Water Discharges
We operate facilities that are subject to requirements of the Clean Water Act, as amended, or “CWA,” and analogous state laws that impose restrictions and controls on the discharge of pollutants into navigable waters. Spill prevention, control and counter-measure requirements under the CWA require implementation of measures to help prevent the contamination of navigable waters in the event of a hydrocarbon spill. Other requirements for the prevention of spills are established under the Oil Pollution Act of 1990, as amended, or “OPA,” which applies to owners and operators of vessels, including barges, offshore platforms and certain onshore facilities. Under OPA, regulated parties are strictly and jointly and severally liable for oil spills and must establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible.
Occupational Safety and Health Act
We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or “OSHA,” and comparable state laws that regulate the protection of employee health and safety. OSHA’s hazard communication standard requires that information about hazardous materials used or produced in our operations be maintained and provided to employees and state and local government authorities.
Saltwater Disposal Wells
We operate SWD wells that are subject to the CWA, Safe Drinking Water Act, and state and local laws and regulations, including those established by the Underground Injection Control Program of the Environmental Protection Agency, or “EPA,” which establishes the minimum program requirements. Most of our SWD wells are located in Texas. We also operate SWD wells in Arkansas, Louisiana and New Mexico. Regulations in these states require us to obtain an Underground Injection Control permit to operate each of our SWD wells. The applicable regulatory agency may suspend or modify one or more of our permits if our well operations are likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or if the well leaks into the environment.
Company Reports and Access to these Reports
We are subject to the informational requirements of the Securities Exchange Act of 1934 (the “Exchange Act”), as amended, and file or furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, proxy statements and other information with the Securities and Exchange Commission (“SEC”). Our Web site address is www.keyenergy.com, and we make available free of charge through our Web site such reports, proxy statements and all amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Our Web site also includes general information about us, including our Corporate Governance Guidelines and charters for the committees of our board of directors. Information on our Web site or any other Web site is not a part of this report.

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ITEM 1A.     RISK FACTORS
In addition to the other information in this report, the following factors should be considered in evaluating us and our business.
Risks Related to Our Business
The depressed conditions in our industry have materially and adversely affected our results of operations, cash flows and financial condition and, unless conditions in our industry improve, this trend will continue during 2020 and potentially beyond.
Oil and natural gas prices began a rapid and substantial decline in the fourth quarter of 2014. Depressed commodity price conditions persisted and worsened during 2015 and while improved, remained volatile through 2019. While oil prices in 2019 began to recover from the lows experienced in late 2018, we experienced a decline in revenue compared to the corresponding 2018 periods due to lower spending by our customers and increased competition, primarily in completion activities. In early March of 2020, the market has experienced a precipitous decline in oil prices in response to oil demand concerns due to the economic impacts of the COVID-19 virus and anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia. Generally, demand for our products and services has declined substantially, and the prices we are able to charge our customers for our products and services also declined substantially. These trends materially and adversely affected our results of operations, cash flows and financial condition during 2019 and, unless conditions in our industry improve, this trend will continue during 2020 and potentially beyond.
Although we are continuing to pursue cost reduction initiatives, there can be no assurance that we will be able to successfully consummate these initiatives or that they will be successful to improve our financial condition and liquidity. We had substantial net losses during the last several years and our cash flow used by operations was $29.0 million during 2019. If industry conditions do not improve, we may continue to suffer net losses and negative cash flows from operations.
Our business is cyclical and depends on conditions in the oil and natural gas industry, especially oil and natural gas prices and capital and operating expenditures by oil and natural gas companies. A continuation of the depressed state of our industry, tight credit markets and disruptions in the U.S. and global economies and financial systems may adversely impact our business.
Prices for oil and natural gas historically have been volatile as a result of changes in the supply of, and demand for, oil and natural gas and other factors. The significant decline in oil and natural gas prices during the last several years caused many of our customers to significantly change and reduce drilling, completion and other production activities and related spending on our products and services in those years. In addition, the reduction in demand from our customers has resulted in an oversupply of many of the services and products we provide, and such oversupply substantially reduced the prices we can charge our customers for our services.
We depend on our customers’ willingness to make capital expenditures to explore for, develop and produce oil and natural gas. Therefore, weakness in oil and natural gas prices (or the perception by our customers that oil and natural gas prices will remain reduced or will continue to decrease in the future) has and may continue to result in a reduction in the utilization of our equipment and in lower rates for our services. In addition to adversely affecting us, the continuation and worsening of these conditions have resulted and may continue to result in a material adverse impact on certain of our customers’ liquidity and financial position resulting in further spending reductions, delays in payment of, or non-payment of, amounts owing to us and similar impacts. These conditions have had and may continue to have an adverse impact on our financial conditions, results of operations and cash flows, and it is difficult to predict how long the current uncertain commodity price environment will continue.
Many factors affect the supply of and demand for oil and natural gas and, therefore, influence product prices, including:
prices, and expectations about future prices, of oil and natural gas;
domestic and worldwide economic conditions;
domestic and foreign supply of and demand for oil and natural gas;
the price and quantity of imports of foreign oil and natural gas including the ability of OPEC to set and maintain production levels for oil;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the level of excess production capacity, available pipeline, storage and other transportation capacity;
lead times associated with acquiring equipment and products and availability of qualified personnel;
the expected rates of decline in production from existing and prospective wells;
the discovery rates of new oil and gas reserves;
federal, state and local regulation of exploration and drilling activities and equipment, material or supplies that we furnish;
public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;
weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area and severe winter weather that can interfere with our operations;

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political instability in oil and natural gas producing countries;
advances in exploration, development and production technologies or in technologies affecting energy consumption;
global or national health concerns, including the outbreak of pandemic or contagious diseases such as the coronavirus (COVID-19) outbreak;
the price and availability of alternative fuel and energy sources;
uncertainty in capital and commodities markets; and
changes in the value of the U.S. dollar relative to other major global currencies.
Spending by exploration and production companies has also been, and may continue to be, impacted by conditions in the capital markets. Limitations on the availability of capital, and higher costs of capital, for financing expenditures have contributed to exploration and production companies making materially significant reductions to capital or operating budgets and such limitations may continue if oil and natural gas prices remain at current levels or decrease further. Such cuts in spending have curtailed, and may continue to curtail, drilling programs as well as discretionary spending on well services, which has resulted, and may continue to result, in a reduction in the demand for our services, the rates we can charge and the utilization of our assets. Moreover, reduced discovery rates of new oil and natural gas reserves, and a decrease in the development rate of reserves in our market areas whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, have had, and may continue to have, a material adverse impact on our business, even in a stronger oil and natural gas price environment.
A substantial decline in oil and natural gas prices generally leads to decreased spending by our customers and, even when oil prices improve, our clients may not react as favorably as expected to improved oil prices with higher spending or increases in planned expenditures that would increase demand for our services further. While higher oil and natural gas prices may lead to increased spending by our customers, sustained high energy prices can be an impediment to economic growth, and can therefore negatively impact spending by our customers. Our customers also take into account the volatility of energy prices and other risk factors by requiring higher returns for individual projects if there is higher perceived risk. Any of these factors could affect the demand for oil and natural gas and could have a material adverse effect on our business, financial condition, results of operations and cash flow.
We may not be able to generate sufficient cash flow to meet our debt service and other obligations.
Our ability to make payments on our indebtedness and to fund planned capital expenditures and other costs of our operations depends on our ability to generate cash in the future. This, to a large extent, is subject to conditions in the oil and natural gas industry, including commodity prices, demand for our services and the prices we are able to charge for our services, general economic and financial conditions, competition in the markets in which we operate, the impact of legislative and regulatory actions on how we conduct our business and other factors, all of which are beyond our control. As discussed above, the depressed conditions in our industry lead to our inability to service our debt obligations in 2019 and to the need to undertake the Restructuring. While the Restructuring substantially reduced our debt obligations, our ability to service our debt and other obligations and make capital expenditures will continue to be subject to these industry trends.
The amount of our debt and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.
While the Restructuring significantly reduced the amount of our debt, we had $51.2 million in debt as of the closing of the Restructuring. Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including:
making it more difficult for us to satisfy our obligations under the agreements governing our indebtedness and increasing the risk that we may default on our debt obligations;
requiring us to dedicate a substantial portion of our cash flow from operations to required payments on indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;
limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes and other activities;
limiting management’s flexibility in operating our business;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
diminishing our ability to successfully withstand a downturn in our business or the economy generally;
placing us at a competitive disadvantage against less leveraged competitors; and
making us vulnerable to increases in interest rates, because our debt has variable interest rates.
As with our Prior ABL Facility (as defined below) and Prior Term Loan Facility (as more fully described in “Notes To Consolidated Financial Statements - Note. 12 Long-Term Debt”), each of our New ABL Facility and New Term Loan Facility contain affirmative and negative covenants, including financial ratios and tests, with which we must comply. These covenants

12


include, among others, covenants that restrict our ability to take certain actions without the permission of the holders of our indebtedness, including the incurrence of debt, the granting of liens, the making of investments, the payment of dividends and the sale of assets, and the financial ratios and tests include, among others, a requirement that we comply with a minimum liquidity covenant, a minimum asset coverage ratio and, during certain periods, a minimum fixed charge coverage ratio. In addition, under our New Term Loan Facility and New ABL Facility, we are required to take certain steps to perfect the security interest in the collateral within specified periods following the closing of those facilities.
Our ability to satisfy required financial covenants, ratios and tests in our debt agreements can be affected by events beyond our control, including commodity prices, demand for our services, the valuation of our assets, as well as prevailing economic, financial and industry conditions, and we can offer no assurance that we will be able to remain in compliance with such covenants or that the holders of our indebtedness will not seek to assert that we are not in compliance with our covenants. For example, in the fourth quarter of 2019, we failed to maintain the required minimum availability threshold set forth in respect of our Prior ABL Facility. A breach of any of these covenants, ratios or tests could result in a default under our indebtedness. If we default, lenders under our New ABL Facility will no longer be obligated to extend credit to us, and they and the administrative agent under our New Term Loan Facility could declare all amounts of outstanding debt, together with accrued interest, to be immediately due and payable. The results of such actions would have a significant negative impact on our results of operations, financial position and cash flows, and absent strategic alternatives such as refinancing or restructuring our indebtedness or capital structure, we would not have sufficient liquidity to repay all of our outstanding indebtedness. If such a result were to occur, we may be forced into bankruptcy or forced to again seek bankruptcy protection to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our financial statements.
We may incur more debt and long-term lease obligations in the future.
The agreements governing our long-term debt restrict, but do not prohibit, us from incurring additional indebtedness and other obligations in the future. As of the closing of the Restructuring, we had $51.2 million of total debt.
An increase in our level of indebtedness could exacerbate the risks described in the immediately preceding risk factor and the occurrence of any of such events could result in a material adverse effect on our business, financial condition, results of operations, and business prospects.
Variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under our New ABL Facility and our New Term Loan Facility bear interest at variable rates, exposing us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed would remain the same, and our net income and cash available for servicing our indebtedness would decrease.
We may be unable to implement price increases or maintain existing prices on our core services.
From time to time we seek to increase the prices of our services to offset rising costs and to generate higher returns for our stockholders. Currently, the prices we are able to charge for our services and the demand for such services are severely depressed. Even when industry conditions are favorable, we operate in a very competitive industry and as a result, we are not always successful in raising, or maintaining our existing prices. Additionally, during periods of increased market demand, a significant amount of new service capacity, including new well service rigs, fluid hauling trucks, coiled tubing units and new fishing and rental equipment, may enter the market, which also puts pressure on the pricing of our services and limits our ability to increase or maintain prices. Furthermore, during periods of declining pricing for our services, we may not be able to reduce our costs accordingly, which could further adversely affect our profitability.
Even when we are able to increase our prices, we may not be able to do so at a rate that is sufficient to offset such rising costs. In periods of high demand for oilfield services, a tighter labor market may result in higher labor costs. During such periods, our labor costs could increase at a greater rate than our ability to raise prices for our services. Also, we may not be able to successfully increase prices without adversely affecting our activity levels. The inability to maintain our prices or to increase our prices as costs increase could have a material adverse effect on our business, financial position and results of operations.
We participate in a capital-intensive industry. We may not be able to finance future growth of our operations or future acquisitions.
Our activities require substantial capital expenditures. If our cash flow from operating activities and borrowing availability under the New ABL Facility are not sufficient to fund our capital expenditure budget, we would be required to reduce these expenditures or fund these expenditures through debt or equity or alternative financing plans, such as refinancing or restructuring our debt or selling assets.
Our ability to raise debt or equity capital or to refinance or restructure our debt will depend on the condition of the capital markets and our financial condition at such time, among other things. The Restructuring of our Prior Term Loan Facility resulted

13


in a higher interest rate, and any further refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.
Increased labor costs or the unavailability of skilled workers could hurt our operations.
Companies in our industry, including us, are dependent upon the available labor pool of skilled employees. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions, which can increase our labor costs or subject us to liabilities to our employees. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. Labor costs may increase in the future or we may not be able to reduce wages when demand and pricing falls, and such changes could have a material adverse effect on our business, financial condition and results of operations.
Our future financial results could be adversely impacted by asset impairments or other charges.
We have recorded goodwill impairment charges and asset impairment charges in the past. We periodically evaluate our long-lived assets such as our property and equipment for impairment. We perform the assessment of potential impairment for our property and equipment whenever facts and circumstances indicate that the carrying value of those assets may not be recoverable due to various external or internal factors. If conditions in our industry do not improve or worsen, we could record additional impairment charges in future periods, which could have a material adverse effect on our financial position and results of operations.
Our business involves certain operating risks, which are primarily self-insured, and our insurance may not be adequate to cover all insured losses or liabilities we might incur in our operations.
Our operations are subject to many hazards and risks, including the following:
accidents resulting in serious bodily injury and the loss of life or property;
liabilities from accidents or damage by our fleet of trucks, rigs and other equipment;
pollution and other damage to the environment;
reservoir damage;
blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into the atmosphere or an underground formation; and
fires and explosions.
These hazards can result in suspension of operations, damage to or destruction of our equipment and the property of others, or injury or death to our or a third party’s personnel.
We self-insure against a significant portion of these liabilities. For losses in excess of our self-insurance limits, we maintain insurance from unaffiliated commercial carriers. However, our insurance may not be adequate to cover all losses or liabilities that we might incur in our operations. Furthermore, our insurance may not adequately protect us against liability from all of the hazards of our business. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. We also are subject to the risk that we may be unable to maintain or obtain insurance of the type and amount we desire at a reasonable cost. If we were to incur a significant liability for which we were uninsured or for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows.
We operate in a highly competitive industry, with intense price competition, which may intensify as our competitors expand their operations.
The market for oilfield services in which we operate is highly competitive and includes numerous small companies capable of competing effectively in our markets on a local basis, as well as several large companies that possess substantially greater financial resources than we do. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers.
The principal competitive factors in our markets are product and service quality and availability, responsiveness, experience, technology, equipment quality, reputation for safety and price. The competitive environment has intensified as recent mergers among exploration and production companies reduced the number of available customers. The fact that drilling rigs and other vehicles and oilfield services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. We may be competing for work against competitors that may be better able to withstand industry downturns and may be better suited to compete on the basis of price, retain skilled personnel and acquire new equipment and technologies, all of which could affect our revenues and profitability.

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Historically, we have experienced a high employee turnover rate. Any difficulty we experience replacing or adding workers could adversely affect our business.
We believe that the high turnover rate in our industry is attributable to the nature of oilfield services work, which is physically demanding and performed outdoors. As a result, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. The potential inability or lack of desire by workers to commute to our facilities and job sites, as well as the competition for workers from competitors or other industries, are factors that could negatively affect our ability to attract and retain workers. We may not be able to recruit, train and retain an adequate number of workers to replace departing workers. The inability to maintain an adequate workforce could have a material adverse effect on our business, financial condition and results of operations.
We may not be successful in implementing and maintaining technology development and enhancements. New technology may cause us to become less competitive.
The oilfield services industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to implement new technologies before we can. If we are unable to develop and implement new technologies or products on a timely basis and at competitive cost, our business, financial condition, results of operations and cash flows could be adversely affected.
A component of our business strategy is to incorporate the KeyView® system, our proprietary technology, into our well service rigs. The inability to successfully develop, integrate and protect this technology could:
limit our ability to improve our market position;
increase our operating costs; and
limit our ability to recoup the investments made in this technological initiative.
The loss of or a substantial reduction in activity by one or more of our largest customers could materially and adversely affect our business, financial condition and results of operations.
Our ten largest customers represented approximately 51% of our consolidated revenues for the year ended December 31, 2019. The loss of or a substantial reduction in activity by one or more of these customers could have an adverse effect on our business, financial condition and results of operations.
Potential adoption of future state or federal laws or regulations surrounding the hydraulic fracturing process could make it more difficult to complete oil or natural gas wells and could materially and adversely affect our business, financial condition and results of operations.
Many of our customers utilize hydraulic fracturing services during the life of a well. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in underground formations where water, sand and other additives are pumped under high pressure into the formation. Although we are not a provider of hydraulic fracturing services, many of our services complement the hydraulic fracturing process.
Legislation has been introduced in Congress to provide for broader federal regulation of hydraulic fracturing operations and the reporting and public disclosure of chemicals used in the fracturing process. Additionally, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the Safe Drinking Water Act and in May 2012 issued draft guidance for fracturing operations that involved diesel fuels. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our customers’ business and operations could be subject to delays and increased operating and compliance costs, which could negatively impact the number of active wells in the marketplaces we serve. New regulations addressing hydraulic fracturing and chemical disclosure have been approved or are under consideration by a number of states and some municipalities have sought to restrict or ban hydraulic fracturing within their jurisdictions. For example, in June 2015, the New York Department of Environmental Conservation issued a findings statement concluding its seven-year study of high-volume hydraulic fracturing, thereby officially prohibiting the practice in New York. Additionally, in California, legislation regarding well stimulation, including hydraulic fracturing, has been adopted. The law mandates technical standards for well construction, hydraulic fracturing water management, groundwater monitoring, seismicity monitoring during hydraulic fracturing operations and public disclosure of hydraulic fracturing fluid constituents. These and other new federal, state or municipal laws regulating the hydraulic fracturing process could negatively impact our business, financial condition and results of operations.

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Permit conditions, legislation or regulatory initiatives could restrict our ability to dispose of fluids produced subsequent to well completion, which could have a material adverse effect on our business.
As part of our fluid management services, we provide disposal services for fluids produced subsequent to well completion. These fluids are removed from the well site and transported for disposal in SWD wells. We operate SWD wells that are subject to the CWA, the Safe Drinking Water Act, and state and local laws and regulations, including those established by the Underground Injection Control Program of the EPA, which establishes the minimum program requirements. Most of our SWD wells are located in Texas. We also operate SWD wells in Arkansas, Louisiana and New Mexico. Regulations in these states require us to obtain an Underground Injection Control permit to operate each of our SWD wells. The applicable regulatory agency may suspend or modify one or more of our permits if our well operations are likely to result in pollution of freshwater or substantial violation of permit conditions or applicable rules, or if the well leaks into the environment.
In addition, there exists a growing concern that the injection of produced fluids into belowground disposal wells may trigger seismic activity in certain areas. In response to these concerns, regulators in some states are pursuing initiatives designed to impose additional requirements in connection with the permitting of SWD wells or otherwise to assess any relationship between seismicity and oil and gas operations. For example, in 2014, the Texas Railroad Commission, or TRC, published a rule governing permitting or re-permitting of disposal wells in Texas that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If a permittee or a prospective permittee fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well.
The imposition of permit conditions or the adoption and implementation of any new laws, regulations, or directives that restrict our ability to dispose of produced fluids, including by restricting disposal well locations, changing the depths of disposal wells, reducing the volume of wastewater disposed in wells, or requiring us to shut down disposal wells or otherwise, could lead to operational delays and increased operating costs, which could materially and adversely affect our business, financial condition and results of operations.
We may incur significant costs and liabilities as a result of environmental, health and safety laws and regulations that govern our operations.
Our operations are subject to U.S. federal, state and local laws and regulations that impose limitations on the discharge of pollutants into the environment and establish standards for the handling, storage and disposal of waste materials, including toxic and hazardous wastes. To comply with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various governmental authorities. While the cost of such compliance has not been significant in the past, new laws, regulations or enforcement policies could become more stringent and significantly increase our compliance costs or limit our future business opportunities, which could have a material adverse effect on our financial condition and results of operations.
Our operations pose risks of environmental liability, including leakage from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. Therefore, in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, results of operations and cash flow. Additionally, an increase in regulatory requirements on oil and natural gas exploration and completion activities could significantly delay or interrupt our operations.
The scope of regulation of our services may increase in light of the April 2010 Macondo accident and resulting oil spill in the Gulf of Mexico, including possible increases in liabilities or funding requirements imposed by governmental agencies. In 2012, the Bureau of Safety and Environmental Enforcement, or “BSEE,” expanded its regulatory oversight beyond oil and gas operators to include service and equipment contractors. In addition, U.S. federal law imposes on certain entities deemed to be “responsible parties” a variety of regulations related to the prevention of oil spills, releases of hazardous substances, and liability for removal costs and natural resource, real property and certain economic damages arising from such incidents. Some of these laws may impose strict and/or joint and several liability for certain costs and damages without regard to the conduct of the parties. As a provider of services and rental equipment for offshore drilling and workover services, we may be deemed a “responsible party” under federal law. The implementation of such laws and the adoption and implementation of future regulatory initiatives, or the specific responsibilities that may arise from such initiatives may subject us to increased costs and liabilities, which could interrupt our operations or have an adverse effect on our revenue or results of operations.

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Severe weather could have a material adverse effect on our business.
Our business could be materially and adversely affected by severe weather. Our customers’ oil and natural gas operations located in Louisiana and parts of Texas have been and may in the future be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. Furthermore, our customers’ operations may be adversely affected by seasonal weather conditions. Adverse weather can also directly impede our own operations. Repercussions of severe weather conditions may include:
curtailment of services;
weather-related damage to facilities and equipment, resulting in suspension of operations;
inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and
loss of productivity.
In the past, these constraints resulted in delays in our operations and materially increased our operating and capital costs and could do so in the future. Unusually warm winters may also adversely affect the demand for our services by decreasing the demand for natural gas.
Acquisitions and divestitures - we may not be successful in identifying, making and integrating acquisitions or limiting ongoing costs associated with the operations we divest.
An important component of our growth strategy is to make acquisitions that will strengthen our core services or presence in selected markets. The success of this strategy will depend, among other things, on our ability to identify suitable acquisition candidates, to negotiate acceptable financial and other terms, to timely and successfully integrate acquired business or assets into our existing businesses and to retain the key personnel and the customer base of acquired businesses. Any future acquisitions could present a number of risks, including but not limited to:
incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;
failure to successfully integrate the operations or management of any acquired operations or assets in a timely manner;
failure to retain or attract key employees;
diversion of management’s attention from existing operations or other priorities;
the inability to implement promptly an effective control environment;
potential impairment charges if purchase assumptions are not achieved or market conditions decline;
the risks inherent in entering markets or lines of business with which the company has limited or no prior experience; and
inability to secure sufficient financing or sufficient financing on economically attractive terms that may be required for any such acquisition or investment.
Our business strategy anticipates, and is based upon our ability to successfully complete and integrate, acquisitions of other businesses or assets in a timely and cost effective manner. Our failure to do so could adversely affect our business, financial condition or results of operations.
We also make strategic divestitures from time to time. In the case of divestitures, we may agree to indemnify acquiring parties for certain liabilities arising from our former businesses. These divestitures may also result in continued financial involvement in the divested businesses, including through guarantees, service level agreements, or other financial arrangements, following the transaction. Lower performance by those divested businesses could affect our future financial results if there is contingent consideration associated.
Compliance with climate change legislation or initiatives could negatively impact our business.
Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases, or “GHG,” from stationary sources, which may include our equipment and operations. At the federal level, the EPA has already issued regulations that require us to establish and report an inventory of GHG emissions. The EPA also has established a GHG permitting requirement for large stationary sources and may lower the threshold of the permitting program, which could include our equipment and operations. Legislative and regulatory proposals for restricting GHG emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for natural gas and oil. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our GHG emissions and administer and manage a GHG emissions program.
In addition, in December, 2014, California adopted GHG emission rules for heavy duty vehicles equivalent to EPA rules and an optional lower emission standard for nitrogen oxides (“NOx”) in California. California has stated its intention to lower NOx standards for California-certified engines and has also requested that the EPA lower its standards. In June 2016, several regional air quality management districts in California and other states, as well as the environmental agencies for several states,

17


petitioned the EPA to adopt lower NOx emission standards for on-road heavy duty trucks and engines. We expect that heavy duty vehicle and engine fuel economy and GHG emissions rules will be under consideration in other jurisdictions in the future. We may incur significant capital expenditures and administrative costs as we update our transportation fleet to comply with emissions laws and regulations.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation could reduce demand for oil and natural gas. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas. Management cannot predict the impact of the changing demand for oil and natural gas services and products, and any major changes may have a material effect on our business, financial condition, results of operations and cash flows.
Our operations may be subject to cyber-attacks that could have an adverse effect on our business operations. 
Like most companies, we rely heavily on information technology networks and systems, including the Internet, to process, transmit and store electronic information, to manage or support a variety of our business operations, and to maintain various records, which may include information regarding our customers, employees or other third parties, and the integrity of these systems are essential for us to conduct our business and operations. We make significant efforts to maintain the security and integrity of these types of information and systems (and maintain contingency plans in the event of security breaches or system disruptions), however, we have experienced and expect to continue to experience, unauthorized access to our systems, loss or destruction of data, account takeovers, and other forms of cyber-attacks or similar events, whether caused by mechanical failures, human error, fraud, malice, sabotage or otherwise. Cyber-attacks include, but are not limited to, malicious software, attempts to gain unauthorized access to data, unauthorized release of confidential or otherwise protected information and corruption of data. The frequency, scope and sophistication of cyber-attacks continue to grow, which increases the possibility that our security measures will be unable to prevent our systems’ improper functioning or the improper disclosure of proprietary information. Any failure of our information or communication systems, whether caused by attacks, mechanical failures, natural disasters or otherwise, could interrupt our operations, damage our reputation, or subject us to claims, any of which could materially adversely affect us.
Risks Related to Our Common Stock
Our stockholder base is highly concentrated; the resale of shares of our common stock by existing stockholders, as well as shares issuable upon exercise of our warrants, may adversely affect the market price of our common stock.
The Restructuring resulted in the issuance to the Supporting Term Lenders of a number of shares of common stock that constituted the vast majority of our outstanding shares. Specifically, as a result of the Restructuring, and after giving effect to the reverse stock split, the five Supporting Term Lenders own in the aggregate approximately 13.4 million shares of common stock, representing 97% of the outstanding shares of common stock after giving effect to such issuance (in each case subject to potential dilution as a result of the New Warrants). In addition, pursuant to the Restructuring, we distributed to our common stockholders as of prior to the closing of the Restructuring Series A New exercisable in the aggregate for 1,669,730 shares of common stock and Series B Warrants exercisable in the aggregate for 1,252,297 shares of common stock.
The sale of a significant number of shares of our common stock by any of these stockholders, or the issuance and sale of shares upon exercise of our warrants, may adversely affect the market price of our common stock.
We cannot assure you that an active trading market for our common stock will develop or be maintained, and the market price of our common stock may be volatile, which could cause the value of your investment to decline.
On December 23, 2019, our common stock was delisted from the NYSE and, as a result, our common stock is currently quoted on the over the counter (OTC) market with limited trading activity. An active public market for our common stock may not develop and, if it develops, may not be sustained. In the absence of an active public trading market, it may be difficult to liquidate your investment in our common stock.
The trading price of our common stock may fluctuate substantially. Numerous factors, including many over which we have no control, may have a significant impact on the market price of our common stock. These risks include those described or referred to in this “Risk Factors” section as well as, among other things:
our operating and financial performance and prospects;
our ability to repay our debt;
our access to financial and capital markets to refinance our debt or replace the existing credit facilities;
investor perceptions of us and the industry and markets in which we operate;
future sales of equity or equity-related securities;
changes in earnings estimates or buy/sell recommendations by analysts; and
general financial, domestic, economic and other market conditions.

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The Company does not expect to pay dividends on its common stock in the foreseeable future.
We do not anticipate to pay cash dividends or other distributions with respect to shares of our common stock in the foreseeable future, and we cannot assure that such dividends or other distributions will be paid at any time in the future or at all. In addition, restrictive covenants in our debt agreement limit our ability to pay dividends. As a result, holders of shares of common stock likely will not be able to realize a return on their investment, if any, until the shares are sold.
Certain provisions of our corporate documents and Delaware law, as well as change of control provisions in our debt agreements, could delay or prevent a change of control, even if that change would be beneficial to stockholders, or could have a material negative impact on our business.
Certain provisions in our certificate of incorporation, bylaws and debt agreements may have the effect of deterring transactions involving a change in control, including transactions in which stockholders might receive a premium for their shares.
Our amended and restated certificate of incorporation provides for the issuance of up to 50,000,000 shares of preferred stock with such designations, rights and preferences as may be determined from time to time by our board of directors. The authorization of preferred shares empowers our board, without further stockholder approval, to issue preferred shares with dividend, liquidation, conversion, voting or other rights which could adversely affect the voting power or other rights of the holders of the common stock. If issued, the preferred stock could also dilute the holders of our common stock and could be used to discourage, delay or prevent a change of control.
Furthermore, our debt agreements contain provisions pursuant to which an event of default or mandatory prepayment offer may result if certain “persons” or “groups” become the beneficial owner of more than 50.1% of our common stock. This could deter certain parties from seeking to acquire us, and if any “person” or “group” were to become the beneficial owner of more than 50.1% of our common stock, we may not be able to repay our indebtedness.
While we are currently not subject to Section 203 of the Delaware General Corporation Law (the “DGCL”), we will become subject to Section 203 at such point as the Supporting Term Lenders and their Permitted Transferees (as defined in the Stockholders Agreement) collectively hold 50% or less of our common stock. In general, Section 203 of the DGCL prevents an “interested stockholder” (as defined in the DGCL) from engaging in a “business combination” (as defined in the DGCL) with us for three years following the date that person becomes an interested stockholder unless one or more of the following occurs:
Before that person became an interested stockholder, our board of directors approved the transaction in which the interested stockholder became an interested stockholder or approved the business combination;
Upon consummation of the transaction that resulted in the interested stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding for purposes of determining the voting stock outstanding stock held by certain directors and employee stock plans; or
Following the transaction in which that person became an interested stockholder, the business combination is approved by our board of directors and authorized at a meeting of stockholders by the affirmative vote of the holders of at least 66 2/3% of our outstanding voting stock not owned by the interested stockholder.
The DGCL generally defines “interested stockholder” as any person who, together with affiliates and associates, is the owner of 15% or more of our outstanding voting stock or is our affiliate or associate and was the owner of 15% or more of our outstanding voting stock at any time within the three-year period immediately before the date of determination.
Furthermore, while stockholders may currently take action by written consent and holders of a majority of our outstanding common stock may call a special meeting of the stockholders, once Supporting Term Lenders and their Permitted Transferees collectively hold 50% or less of the outstanding common stock our stockholders will not be able to call a special meeting or take action by written consent. The inability of our stockholders to take action by written consent or call a special meeting may have an anti-takeover effect in that a person seeking to change the composition of the Board to include directors supportive of an acquisition of the Company or to implement other changes to our amended and restated certificate of incorporation conducive to an acquisition of the Company may be required to wait until our next annual meeting before presenting such action to our stockholders.
All of these factors could materially adversely affect the price of our common stock.
ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.

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ITEM 2.    PROPERTIES
We lease office space for our principal executive offices in Houston, Texas. Additionally, we own or lease numerous rig facilities, storage facilities, truck facilities and sales and administrative offices throughout the geographic regions in which we operate. We lease temporary facilities to house employees in regions where infrastructure is limited. In connection with our Fluid Management Services, we operate a number of owned and leased SWD facilities, and brine and freshwater stations. Our leased properties are subject to various lease terms and expirations.
We believe all properties that we currently occupy are suitable for their intended uses. We believe that our current facilities are sufficient to conduct our operations. However, we continue to evaluate the purchase or lease of additional properties or the consolidation of our properties, as our business requires.
The following table shows our active owned and leased properties, as well as active SWD facilities as of December 31, 2019:
 
Office, Repair  &
Service and Other(1)
 
SWDs, Brine and
Freshwater Stations(2)
 
Operational Field
Services Facilities
Owned
57

 
27

 
29

Leased
22

 
33

 
22

TOTAL
79

 
60

 
51

(1)
Includes 4 residential properties leased for the purpose of housing employees.
(2)
Includes SWD facilities as “leased” if we own the wellbore for the SWD but lease the land. In other cases, we lease both the wellbore and the land. Lease terms vary among different sites, but with respect to some of the SWD facilities for which we lease the land and own the wellbore, the land owner has an option under the land lease to retain the wellbore at the termination of the lease.
ITEM 3.    LEGAL PROCEEDINGS
We are subject to various suits and claims that have arisen in the ordinary course of business. We do not believe that the disposition of any of our ordinary course litigation will result in a material adverse effect on our consolidated financial position, results of operations or cash flows.
ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.


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PART II

ITEM 5.        MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market and Information
Our common stock is traded on the OTC under the symbol “KEGX.” As of March 6, 2020, there were 85 registered holders of 13,775,267 issued and outstanding shares of common stock. This number of registered holders does not include holders that have shares of common stock held for them in “street name,” meaning that the shares are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that have shares held in “street name” are not. All shares prices below have been adjusted to reflect the 1-for-50 reverse stock split, which was effective March 6, 2020.
Issuer Purchases of Equity Securities
During the fourth quarter of 2019, we repurchased an aggregate of 354 shares of our common stock. The repurchases were to satisfy tax withholding obligations that arose upon vesting of restricted stock. Set forth below is a summary of the share repurchases:
Period
Total Number of Shares Purchased
 
Average Price Paid Per Share
 
Total Number of  Shares
Purchased as Part of
Publicly Announced 2016 Bankruptcy
Plans(1)
 
Maximum Number of Shares That May Yet Be Purchased Under the 2016 Bankruptcy
Plan(1)
October 1, 2019 to October 31, 2019

 
$

 

 

November 1, 2019 to November 30, 2019

 
$

 

 

December 1, 2019 to December 31, 2019
354

 
$
5.00

 

 

(1) The Company did not have at any time between October 1, 2019 and December 31, 2019, and currently does not have, a share repurchase program in place.
Equity Compensation Plan Information
The following table sets forth information as of December 31, 2019 with respect to equity compensation plans (including individual compensation arrangements) under which our common stock is authorized for issuance. The material features of each of these plans are described in “Note 16. Share-Based Compensation” in “Item 8. Financial Statement and Supplementary Date.”All share numbers and weighted average exercise prices below reflect the reverse stock split of the Company’s common stock effected on March 6, 2020 in connection with the Restructuring.
Plan Category
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants And Rights
(a)(2)
 
Weighted Average
Exercise Price of
Outstanding
Options, Warrants
And Rights
(b)(3)
 
Number of Securities  Remaining
Available for Future Issuance
Under Equity Compensation
Plans (Excluding Securities
Reflected in Column (a))
(c)(4)
 
(in thousands)
 
 
 
(in thousands)
Equity compensation plans approved by stockholders(1)
15

 
$
1,683.50

 
52

Equity compensation plans not approved by stockholders

 
 
 

Total
15

 
 
 
52

(1)
Represents stock-based awards outstanding under the 2019 Equity and Cash Incentive Plan (the “2019 ECIP”).
(2)
Represents shares that may be issued upon vesting of restricted stock units (“RSUs”).
(3)
RSUs do not have an exercise price; therefore, RSUs are excluded from weighted average exercise price of outstanding awards.
(4)
Represents the number of shares remaining available for grant under the 2019 ECIP as of December 31, 2019.

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ITEM 6.    SELECTED FINANCIAL DATA
Not applicable.
ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes thereto in “Item 8. Financial Statements and Supplementary Data.” The discussion below contains forward-looking statements that are based upon our current expectations and are subject to uncertainty and changes in circumstances including those identified in “Cautionary Note Regarding Forward-Looking Statements” above. Actual results may differ materially from these expectations due to potentially inaccurate assumptions and known or unknown risks and uncertainties. Such forward-looking statements should be read in conjunction with our disclosures under “Item 1A. Risk Factors.”
Overview
We provide a full range of well services to major oil companies and independent oil and natural gas production companies to produce, maintain and enhance the flow of oil and natural gas throughout the life of a well. These services include rig-based and coiled tubing-based well maintenance and workover services, well completion and recompletion services, fluid management services, fishing and rental services and other ancillary oilfield services. Additionally, certain of our rigs are capable of specialty drilling applications. We operate in most major oil and natural gas producing regions of the continental United States. We previously had operations in Canada and Russia, which were sold in the second and third quarters of 2017, respectively.
The demand for our services fluctuates, primarily in relation to the price (or anticipated price) of oil and natural gas, which, in turn, is driven primarily by the supply of, and demand for, oil and natural gas. Generally, as supply of those commodities decreases and demand increases, service and maintenance requirements increase as oil and natural gas producers attempt to maximize the productivity of their wells in a higher priced environment. However, in the lower oil and natural gas price environment that has persisted since late 2014, demand for service and maintenance has decreased as oil and natural gas producers decrease their activity. In particular, the demand for new or existing field drilling and completion work is driven by available investment capital for such work and our customers have significantly curtailed their capital spending beginning in 2015 and continuing into 2019. Because these types of services can be easily “started” and “stopped,” and oil and natural gas producers generally tend to be less risk tolerant when commodity prices are low or volatile, we may experience a more rapid decline in demand for well maintenance services compared with demand for other types of oilfield services. Further, in a lower-priced environment, fewer well service rigs are needed for completions, as these activities are generally associated with drilling activity.
In the fourth quarter of 2019, we took steps to reduce our labor costs and exit certain operations and areas to focus on certain markets. Additionally, we took steps to reduce our overhead, given the reduced operating footprint, which we believe will improve our operating cash flows and reduce our operating losses.
Restructuring and Reverse Stock Split
On March 6, 2020, we closed the previously announced restructuring of our capital structure and indebtedness (the “Restructuring”) pursuant to the Restructuring Support Agreement, dated as of January 24, 2020 (the “RSA”), with lenders under our Prior Term Loan Facility (as defined below) collectively holding over 99.5% (the “Supporting Term Lenders”) of the principal amount of the Company’s then outstanding term loans. Pursuant to or in connection with the RSA and the Restructuring contemplated thereby, among other things we effected the following transactions and changes to our capital structure and governance:
immediately prior to the closing of the Restructuring, we completed a 1-for-50 reverse stock split of our outstanding common stock as a result of which our issued and outstanding common stock decreased from 20,659,654 to 413,258 shares; accordingly, all share and per share information contained in this report has been restated to retroactively show the effect of this stock split;
pursuant to exchange agreements entered into at the closing of the Restructuring, we then exchanged approximately $241.9 million aggregate outstanding principal of our term loans (together with accrued interest thereon) held by Supporting Term Lenders under our Prior Term Loan Facility into (i) 13,362,009 newly issued shares of common stock representing 97% of the Company’s outstanding shares after giving effect to such issuance (and without giving effect to dilution by the New Warrants and MIP (each as defined below)) and (ii) $20 million of term loans under our new $51.2 million term loan facility (the “New Term Loan Facility”), each on a pro rata basis based on their holdings of term loans under the Prior Term Loan Facility;
distributed to our common stockholders of record as of February 18, 2020 two series of warrants (the “New Warrants”);

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entered into the $51.2 million New Term Loan Facility, of which (i) $30 million was funded at closing of the Restructuring with new cash proceeds from the Supporting Term Lenders and $20 million was issued in exchange for term loans held by the Supporting Term Lenders under the Prior Term Loan Facility as described above and (ii) an approximate $1.2 million was a senior secured term loan tranche in respect of term loans held by lenders under the Prior Term Loan Facility who were not Supporting Term Lenders;
entered into the New ABL Facility (as defined below);
adopted a new management incentive plan (the “MIP”) representing up to 9% of the Company’s outstanding shares after giving effect to the issuance of shares described above; and
made certain changes to the Company’s governance, including changes to our Board of Directors (the “Board”), amendments to our governing documents and entry into the Stockholders Agreement (as defined below) with the Supporting Term Lenders.
In accordance with the RSA at the closing of the Restructuring, the Company amended and restated its certificate of incorporation and entered into a stockholders agreement (the “Stockholders Agreement”) with the Supporting Term Lenders in order to, among other things, provide for a Board of seven members. Pursuant to the Stockholders Agreement, our Board consists of our chief executive officer and six other members appointed by various Supporting Term Lenders. Specifically, pursuant to the Stockholders Agreement, Supporting Term Lenders who hold more than 25% of the Company’s outstanding shares as of the closing of the Restructuring are entitled to nominate two directors and Supporting Term Lenders who hold between 10% and 25% of the Company’s outstanding shares as of the closing of the Restructuring are entitled to nominate one director. All appointees or nominees of Supporting Term Lenders, other than any directed appointed or nominated by Soter Capital LLC (“Soter”), must meet the “independent director” requirements set forth in Section 303A of the NYSE Listed Company Manual. In addition, pursuant to the Stockholders Agreement, Supporting Term Lenders are entitled to appoint a non-voting board observer subject to specified ownership thresholds.
In accordance with the RSA and following the closing of the Restructuring, the Company distributed to stockholders of record as of February 18, 2020 the New Warrants. The New Warrants were issued in two series each with a four-year exercise period. The first series entitles the holders to purchase in the aggregate 1,669,730 newly issued shares of common stock, representing 10% of the Company’s common shares at the closing of the Restructuring on an as-exercised basis (after giving effect to the exercise of all New Warrants, but subject to dilution by issuances under the MIP). The aggregate exercise price of the first series of New Warrants is $19.23 and was determined based on the aggregate outstanding principal amount of term loans under the Prior Term Loan Facility plus accrued interest thereon at the default rate as of the closing of the Restructuring. The second series of New Warrants entitles the holders to purchase in the aggregate 1,252,297 newly issued shares of common stock, representing 7.5% of the Company’s common shares at the closing of the Restructuring on an as-exercised basis (after giving effect to the exercise of all New Warrants, but subject to dilution by issuances under the MIP). The aggregate strike price of the second series of New Warrants is $28.85 and was determined based on the product of (i) the aggregate outstanding principal amount of term loans under the Prior Term Loan Facility plus accrued interest thereon at the default rate as of the closing of the Restructuring, multiplied by (ii) 1.50.
For more information on our New Term Loan Facility and New ABL Facility entered into in connection with the Restructuring, see “-Liquidity and Capital Resources” below.
Business and Growth Strategies
Focus on Production Related Services
Over the life of an oil and gas well, regular maintenance of well bore and artificial lift systems is required to maintain production and offset natural production declines. In most of these interventions, a well service rig is required to remove and replace items needing repair, or to perform activities that would increase the oil and gas production from current levels. In many instances these interventions require additional assets or services to perform. With the decline in oil prices beginning in 2014, we believe that a number of oil and gas producers in the United States significantly curtailed their recurring well maintenance activities. We believe that a recovery in oil prices will result in oil and gas producers making the decision to resume regular well maintenance activities. Additionally, we believe that in many instances since the oil price decline began in 2014, oil and gas producers have foregone regular maintenance activities, and that additional demand for our services will be provided by oil and gas producers seeking to improve their production by repairing their wells. Key is well positioned to capitalize on these trends through its fleet of active and warm stacked well service rigs and the additional fishing and rental service offerings it provides and we will continue to invest, either in equipment or through acquisition to grow and take advantage of this dynamic.

23


Growth in Population of Horizontal Oil and Gas Wells
Since the revolution of horizontal well drilling and hydraulic fracturing began in the United States, thousands of new horizontal oil wells have been added, many in the period from 2012 to 2014. As the initial production from these wells declines over their first several years of production, and these wells are placed on artificial lift systems to maintain production, we believe that these wells will require periodic maintenance similar to a conventional oil well. In many instances due to the depth and long lateral sections of these wells, a larger well service rig with a higher rated derrick capacity will be needed to do this maintenance. We intend to invest in this portion of our well service rig fleet, and the needed rental equipment and services, either through organic capital deployment or acquisition to capitalize on this trend and the growing population of horizontal wells that have entered or will enter the phase of their life where regular maintenance is required.
PERFORMANCE MEASURES
The Baker Hughes U.S. rig count data, which is publicly available on a weekly basis, is often used as a coincident indicator of overall Exploration and Production (“E&P) company spending and broader oilfield activity. In assessing overall activity in the U.S. onshore oilfield service industry in which we operate, we believe that the Baker Hughes U.S. land drilling rig count is the best barometer of E&P companies’ capital spending and resulting activity levels. Historically, our activity levels have been highly correlated to U.S. onshore capital spending by our E&P company customers as a group.
Year
WTI Cushing  Crude
Oil(1)
 
NYMEX Henry Hub
Natural Gas(1)
 
Average Baker  Hughes
U.S. Land Drilling  Rigs(2)
 
Average AESC Well Service Active Rig Count(3)
2015
$
48.66

 
$
2.62

 
943

 
1,481

2016
$
43.29

 
$
2.52

 
486

 
1,061

2017
$
50.80

 
$
2.99

 
856

 
1,187

2018
$
65.23

 
$
3.15

 
1,013

 
1,292

2019
$
56.98

 
$
2.56

 
920

 
1,253

(1)
Represents the average of the monthly average prices for each of the years presented. Source: U.S. Energy Information Administration, Bloomberg.
(2)
Source: www.bakerhughes.com
(3)
Source: www.aesc.net

24


Internally, we measure activity levels for our well servicing operations primarily through our rig and trucking hours. Generally, as capital by E&P companies increases, demand for our services also rises, resulting in increased rig and trucking services and more hours worked. Conversely, when activity levels decline due to lower spending by E&P companies, we generally provide fewer rig and trucking services, which results in lower hours worked. The following table presents our quarterly rig and trucking hours from 2017 through 2019.
 
Rig Hours
 
Trucking Hours
 
Key’s U.S.
Working Days(1)
 
U.S.
 
International
 
Total
 
 
 
 
2019:
 
 
 
 
 
 
 
 
 
First Quarter
151,309

 

 
151,309

 
150,740

 
63

Second Quarter
154,017

 

 
154,017

 
144,996

 
63

Third Quarter
142,151

 

 
142,151

 
150,518

 
64

Fourth Quarter
114,727

 

 
114,727

 
121,152

 
62

Total 2019
562,204

 

 
562,204

 
567,406

 
252

2018:
 
 
 
 
 
 
 
 
 
First Quarter
175,232

 

 
175,232

 
214,194

 
63

Second Quarter
187,578

 

 
187,578

 
201,427

 
64

Third Quarter
180,943

 

 
180,943

 
184,310

 
63

Fourth Quarter
156,453

 

 
156,453

 
179,405

 
62

Total 2018
700,206

 

 
700,206

 
779,336

 
252

2017:
 
 
 
 
 
 
 
 
 
First Quarter
165,968

 
2,462

 
168,430

 
179,215

 
64

Second Quarter
163,966

 
1,701

 
165,667

 
185,398

 
63

Third Quarter
161,725

 
2,937

 
164,662

 
197,319

 
63

Fourth Quarter
164,480

 

 
164,480

 
223,478

 
61

Total 2017
656,139

 
7,100

 
663,239

 
785,410

 
251

(1)
Key’s U.S. working days are the number of weekdays during the quarter minus national holidays.
MARKET AND BUSINESS CONDITIONS AND OUTLOOK
Our core businesses depend on our customers’ willingness and ability to make expenditures to produce, develop and explore for oil and natural gas in onshore U.S. basins. Industry conditions are influenced by numerous factors, such as oil and natural gas prices, the supply of and demand for oil and natural gas, domestic and worldwide economic conditions, political instability in oil producing countries, and available supply of and demand for the services we provide. Higher oil prices have historically spurred additional demand for our services as oil and gas producers increase spending on production, maintenance and drilling and completion of new wells.
In 2019, oil prices began to recover from the lows experienced in late 2018. However, many of our clients did not react as favorably as expected to improved oil prices with higher spending or increases in planned expenditures that would have increased demand for our services further. We believe this is a result of our customers’ managing their activity to achieve cash flow targets and a prioritization of their maintenance activities to the highest return opportunities due to continued uncertainty around future commodity prices and their access to capital. Lower spending by our customers and increased competition, primarily in completion activities, also resulted in lower activity than in the corresponding period in 2018.
During the fourth quarter of 2019, we took steps to internally realign our operations. We exited operations and areas to focus on certain markets where we had the best competitive positions. We also took steps to reduce our overhead costs, given the reduced operating footprint. While we received some benefit from these changes in the fourth quarter of 2019, we expect to see the full benefit of the lower cost structure in 2020.
In the first quarter of 2020, we completed the Restructuring thereby reducing our long-term debt and future interest expense. In addition, we received cash proceeds in the Restructuring that improved our cash position. In early March of 2020, the market has experienced a precipitous decline in oil prices in response to oil demand concerns due to the economic impacts of the COVID-19 virus and anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia. While the impact of this oil price decline has yet to be felt in demand for our services, we expect that in response our customers will reduce activity during

25


this period of commodity price weakness and will also seek price reductions for our services. This current uncertainty gives us limited visibility into near term demand for our services.
Longer term however, we believe that commodity prices will stabilize and the continued aging of horizontal wells will increase demand for well maintenance services as customers seek to maintain or increase production through accretive regular well maintenance at economically supportive oil prices.
RESULTS OF OPERATIONS
Consolidated Results of Operations
The following tables set forth consolidated results of operations and financial information by operating segment and other selected information for the years ended December 31, 2019, 2018 and 2017.
Years Ended December 31, 2019 and 2018
 
Year Ended December 31,
 
 
 
 
 
2019
 
2018
 
Change
 
% Change
REVENUES
$
413,854

 
$
521,695

 
$
(107,841
)
 
(21
)%
COSTS AND EXPENSES:
 
 
 
 
 
 
 
Direct operating expenses
333,462

 
406,396

 
(72,934
)
 
(18
)%
Depreciation and amortization expense
56,969

 
82,639

 
(25,670
)
 
(31
)%
General and administrative expenses
91,309

 
91,626

 
(317
)
 
 %
Operating loss
(67,886
)
 
(58,966
)
 
(8,920
)
 
15
 %
Interest expense, net of amounts capitalized
35,523

 
34,163

 
1,360

 
4
 %
Other income, net
(2,016
)
 
(2,354
)
 
338

 
(14
)%
Loss before income taxes
(101,393
)
 
(90,775
)
 
(10,618
)
 
12
 %
Income tax benefit
3,975

 
1,979

 
1,996

 
101
 %
NET LOSS
$
(97,418
)
 
$
(88,796
)
 
$
(8,622
)
 
10
 %
Revenues
Our revenues for the year ended December 31, 2019 decreased $107.8 million, or 20.7%, to $413.9 million from $521.7 million for the year ended December 31, 2018, due to lower spending from our customers as a result of lower oil prices. These market conditions resulted in reduced customer activity, Additionally, in the fourth quarter of 2019, the company strategically exited a number of non-core and underperforming locations. See “Segment Operating Results — Years Ended December 31, 2019 and 2018 below for a more detailed discussion of the change in our revenues.
Direct operating expenses
Our direct operating expenses decreased $72.9 million, or 17.9%, to $333.5 million (80.6% of revenues) for the year ended December 31, 2019, compared to $406.4 million (77.9% of revenues) for the year ended December 31, 2018. This decrease is primarily a result of a decrease in employee compensation costs, fuel expense and repair and maintenance expense due to a decrease in activity levels. See “Segment Operating Results — Years Ended December 31, 2019 and 2018 below for a more detailed discussion of the change in our direct operating expenses.
Depreciation and amortization expense
Depreciation and amortization expense decreased $25.7 million, or 31.1%, to 57.0 million (13.8% of revenues) for the year ended December 31, 2019, compared to $82.6 million (15.8% of revenues) for the year ended December 31, 2018. This decrease is primarily due to certain assets becoming fully depreciated during the fourth quarter of 2018.
General and administrative expenses
General and administrative expenses decreased $0.3 million, or 0.3%, to $91.3 million (22.1% of revenues) for the year ended December 31, 2019, compared to $91.6 million (17.6% of revenues) for the year ended December 31, 2018. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels partially offset by $4.6 million of severance costs and $4.0 million in expenses related to the restructuring of debt.

26


Interest expense, net of amounts capitalized
Interest expense increased $1.4 million to $35.5 million (8.6% of revenues) for the year ended December 31, 2019, compared to $34.2 million (6.5% of revenues) for the year ended December 31, 2018. This increase is primarily related to the increase in the variable interest rate on our long-term debt.
Other income, net
During the year ended December 31, 2019, we recognized other income, net, of $2.0 million, compared to $2.4 million for the year ended December 31, 2018. The table below presents comparative detailed information about combined other loss, net at December 31, 2019 and 2018:
 
Year Ended December 31,
 
 
 
 
 
2019
 
2018
 
Change
 
% Change
Interest income
$
(723
)
 
$
(820
)
 
$
97

 
(12
)%
Other
(1,293
)
 
(1,534
)
 
241

 
(16
)%
Total
$
(2,016
)
 
$
(2,354
)
 
$
338

 
(14
)%
Income tax benefit
Our income tax benefit was $4.0 million (3.9% effective rate) on a pre-tax loss of $101.4 million for the year ended December 31, 2019, compared to an income tax benefit of $2.0 million (2.2% effective rate) on a pre-tax loss of $90.8 million for the year ended December 31, 2018. Our effective tax rates differ from the applicable U.S. statutory rate of 21%, including expenses subject to statutorily imposed limitations such as meals and entertainment expenses, that affect book income but do not affect taxable income and discrete tax adjustments, such as valuation allowances against deferred tax assets. 
Years Ended December 31, 2018 and 2017
 
Year Ended December 31,
 
 
 
 
 
2018
 
2017
 
Change
 
% Change
REVENUES
$
521,695

 
$
436,165

 
$
85,530

 
20
 %
COSTS AND EXPENSES:
 
 
 
 
 
 
 
Direct operating expenses
406,396

 
332,332

 
74,064

 
22
 %
Depreciation and amortization expense
82,639

 
84,542

 
(1,903
)
 
(2
)%
General and administrative expenses
91,626

 
115,284

 
(23,658
)
 
(21
)%
Impairment expense

 
187

 
(187
)
 
(100
)%
Operating loss
(58,966
)
 
(96,180
)
 
37,214

 
(39
)%
Reorganization items, net

 
1,501

 
(1,501
)
 
(100
)%
Interest expense, net of amounts capitalized
34,163

 
31,797

 
2,366

 
7
 %
Other loss, net
(2,354
)
 
(7,187
)
 
4,833

 
(67
)%
Loss before income taxes
(90,775
)
 
(122,291
)
 
31,516

 
(26
)%
Income tax (expense) benefit
1,979

 
1,702

 
277

 
16
 %
NET LOSS
$
(88,796
)
 
$
(120,589
)
 
$
31,793

 
(26
)%

27


Revenues
Our revenues for the year ended December 31, 2018 increased $85.5 million, or 19.6%, to $521.7 million from $436.2 million for the year ended December 31, 2017, due to an increase in spending from our customers as they reacted to improving commodity prices and our ability to increase prices for our services. Internationally, we had no revenue in 2018 as a result of the sale our operations in Canada and Russia. See “Segment Operating Results — Years Ended December 31, 2018 and 2017 below for a more detailed discussion of the change in our revenues.
Direct operating expenses
Our direct operating expenses increased $74.1 million, or 22.3%, to $406.4 million (77.9% of revenues) for the year ended December 31, 2018, compared to $332.3 million (76.2% of revenues) for the year ended December 31, 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense, due to an increase in activity levels and, with respect to the increase in repair and maintenance expense, due to costs associated with making idle equipment ready for work and the decrease in gain on sale of assets related to the sale of our frac stack equipment and well testing services business which were sold in the second quarter of 2017. See “Segment Operating Results — Years Ended December 31, 2018 and 2017 below for a more detailed discussion of the change in our direct operating expenses.
Depreciation and amortization expense
Depreciation and amortization expense decreased $1.9 million, or 2.2%, to $82.6 million (15.8% of revenues) for the year ended December 31, 2018, compared to $84.5 million (19.4% of revenues) for the year ended December 31, 2017. This decrease is primarily due to the sale of businesses of our former International segment and our frac stack equipment and well-testing services business in 2017.
General and administrative expenses
General and administrative expenses decreased $23.7 million, or 20.6%, to $91.6 million (17.6% of revenues) for the year ended December 31, 2018, compared to $115.3 million (26.4% of revenues) for the year ended December 31, 2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels and a decrease in legal settlement expenses.
Impairment expense
During the year ended December 31, 2018, we did not record an impairment. During the year ended December 31, 2017, we recorded a $0.2 million impairment to reduce the carrying value of assets and related liabilities of our Russian business unit, which was sold in the third quarter of 2017, to fair market value.
Reorganization items, net
During the year ended December 31, 2018, we recorded zero reorganization items, compared to $1.5 million for the year ended December 31, 2017, primarily consisting of professional fees incurred in connection with our emergence from voluntary reorganization in 2016.
Interest expense, net of amounts capitalized
Interest expense increased $2.4 million to $34.2 million (6.5% of revenues), for the year ended December 31, 2018, compared to $31.8 million (7.3% of revenues) for the year ended December 31, 2017. This increase is primarily related to the increase in the variable interest rate on our long-term debt.
Other (income) loss, net
During the year ended December 31, 2018, we recognized other income, net, of $2.4 million, compared to $7.2 million for the year ended December 31, 2017. Other income, net for the year ended December 31, 2017 includes a $4.7 million gain on sale related to our Russian subsidiary which was disposed of in the third quarter of 2017.
The table below presents comparative detailed information about combined other loss, net at December 31, 2018 and 2017:
 
Year Ended December 31,
 
Change
 
% Change
 
2018
 
2017
 
 
 
 
Interest (Income) expense
$
(820
)
 
$
(711
)
 
$
(109
)
 
15
 %
Other
(1,534
)
 
(6,476
)
 
4,942

 
(76
)%
Total
$
(2,354
)
 
$
(7,187
)
 
$
4,833

 
(67
)%

28


Income tax (expense) benefit
Our income tax benefit was $2.0 million (2.2% effective rate) on a pre-tax loss of $90.8 million for the year ended December 31, 2018, compared to an income tax benefit of $1.7 million (1.4% effective rate) on a pre-tax loss of $122.3 million for the year ended December 31, 2017. Our effective tax rates for the 2018 and 2017 periods differ from the U.S. statutory rate of 21% and 35%, respectively, due to a number of factors, including the mix of profit and loss between domestic and international taxing jurisdictions and the impact of permanent items, including expenses subject to statutorily imposed limitations such as meals and entertainment expenses, that affect book income but do not affect taxable income and discrete tax adjustments, such as valuation allowances against deferred tax assets and tax expense or benefit recognized for uncertain tax positions.
The U.S. enacted into law the Tax Cuts and Jobs Act (“2017 Tax Act”) on December 22, 2017. The 2017 Tax Act is comprehensive tax reform legislation that, among other things, contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate from 35% to 21%, imposing a mandatory one-time tax on accumulated earnings of foreign subsidiaries, a partial limitation on the deductibility of business interest expense, a limitation on net operating losses to 80% of taxable income each year, and a shift of the U.S. taxation of multinational corporations from a tax on worldwide income to a partial territorial system (along with rules that create a new U.S. minimum tax on earnings of foreign subsidiaries).


Segment Operating Results
Years Ended December 31, 2019 and 2018
The following table shows operating results for each of our reportable segments for the years ended December 31, 2019 and 2018 (in thousands):
For the year ended December 31, 2019
 
Rig Services
 
Fishing and Rental Services
 
Coiled Tubing Services
 
Fluid Management Services
 
Functional
Support
 
Total
Revenues from external customers
$
250,532

 
$
54,511

 
$
37,964

 
$
70,847

 
$

 
$
413,854

Operating expenses
234,670

 
61,994

 
41,805

 
70,434

 
72,837

 
481,740

Operating income (loss)
15,862

 
(7,483
)
 
(3,841
)
 
413

 
(72,837
)
 
(67,886
)
For the year ended December 31, 2018
 
Rig Services
 
Fishing and Rental Services
 
Coiled Tubing Services
 
Fluid Management Services
 
Functional
Support
 
Total
Revenues from external customers
$
296,969

 
$
64,691

 
$
71,013

 
$
89,022

 
$

 
$
521,695

Operating expenses
277,417

 
73,344

 
65,817

 
97,872

 
66,211

 
580,661

Operating income (loss)
19,552

 
(8,653
)
 
5,196

 
(8,850
)
 
(66,211
)
 
(58,966
)
Rig Services
Revenues for our Rig Services segment decreased $46.4 million, or 15.6%, to $250.5 million for the year ended December 31, 2019, compared to $297.0 million for the year ended December 31, 2018. The decrease for this segment is primarily due to lower spending from our customers as a result of lower oil prices. These market conditions resulted in reduced customer activity.
Operating expenses for our Rig Services segment were $234.7 million during the year ended December 31, 2019, which represented a decrease of $42.7 million, or 15.4%, compared to $277.4 million for the year ended December 31, 2018. This decrease is primarily a result of a decrease in employee compensation costs, fuel expense and repair and maintenance expense due to a decrease in activity levels and a decrease in depreciation expense.
Fishing and Rental Services
Revenues for our Fishing and Rental Services segment decreased $10.2 million, or 15.7%, to $54.5 million for the year ended December 31, 2019, compared to $64.7 million for the year ended December 31, 2018. The decrease for this segment is primarily due to lower spending from our customers on oil and gas well drilling and completion, as a result of lower oil prices. These market conditions resulted in reduced customer activity.

29


Operating expenses for our Fishing and Rental Services segment were $62.0 million during the year ended December 31, 2019, which represented a decrease of $11.4 million, or 15.5%, compared to $73.3 million for the year ended December 31, 2018. This decrease is primarily a result of a decrease in employee compensation costs and repair and maintenance expense due to a decrease in activity levels and a decrease in depreciation expense.
Coiled Tubing Services
Revenues for our Coiled Tubing Services segment decreased $33.0 million, or 46.5%, to $38.0 million for the year ended December 31, 2019, compared to $71.0 million for the year ended December 31, 2018. The decrease for this segment is primarily due to lower spending from our customers on oil and gas well drilling and completion, as a result of lower oil prices, and the increase in competition. These market conditions resulted in reduced customer activity and a reduction in the price received for our services.
Operating expenses for our Coiled Tubing Services segment were $41.8 million during the year ended December 31, 2019, which represented a decrease of $24.0 million, or 36.5%, compared to $65.8 million for the year ended December 31, 2018. This decrease is primarily a result of a decrease in employee compensation costs, fuel expense and repair and maintenance expense due to a decrease in activity levels.
Fluid Management Services
Revenues for our Fluid Management Services segment decreased $18.2 million, or 20.4%, to $70.8 million for the year ended December 31, 2019, compared to $89.0 million for the year ended December 31, 2018. The decrease for this segment is primarily due to lower spending from our customers on oil and gas well drilling and completion, as a result of lower oil prices. These market conditions resulted in reduced customer activity. Additionally, in the fourth quarter of 2019, the company strategically exited a number of non-core and underperforming locations.
Operating expenses for our Fluid Management Services segment were $70.4 million during the year ended December 31, 2019, which represented a decrease of $27.4 million, or 28.0%, compared to $97.9 million for the year ended December 31, 2018. This decrease is primarily a result of a decrease in employee compensation costs, fuel expense and repair and maintenance expense due to a decrease in activity levels and a decrease in depreciation expense.
Functional support
Operating expenses for our Functional Support segment increased $6.6 million, or 10.0%, to $72.8 million (17.6% of consolidated revenues) for the year ended December 31, 2019 compared to $66.2 million (12.7% of consolidated revenues) for the year ended December 31, 2018. The increase is primarily due to increase in legal settlements and professional fee partially offset by lower employee compensation costs due to reduced staffing levels, a decrease in facilities costs and legal settlements.
Years Ended December 31, 2018 and 2017
The following table shows operating results for each of our reportable segments for the years ended December 31, 2018 and 2017 (in thousands):
For the year ended December 31, 2018
 
Rig Services
 
Fishing and Rental Services
 
Coiled Tubing Services
 
Fluid Management Services
 
Functional
Support
 
Total
Revenues from external customers
$
296,969

 
$
64,691

 
$
71,013

 
$
89,022

 
$

 
$
521,695

Operating expenses
277,417

 
73,344

 
65,817

 
97,872

 
66,211

 
580,661

Operating income (loss)
19,552

 
(8,653
)
 
5,196

 
(8,850
)
 
(66,211
)
 
(58,966
)

30


For the year ended December 31, 2017
 
Rig Services
 
Fishing and Rental Services
 
Coiled Tubing Services
 
Fluid Management Services
 
International
 
Functional
Support
 
Total
Revenues from external customers
$
248,830

 
$
59,172

 
$
41,866

 
$
80,726

 
$
5,571

 
$

 
$
436,165

Operating expenses
252,450

 
51,666

 
40,235

 
100,258

 
10,564

 
77,172

 
532,345

Operating income (loss)
(3,620
)
 
7,506

 
1,631

 
(19,532
)
 
(4,993
)
 
(77,172
)
 
(96,180
)
Rig Services
Revenues for our Rig Services segment increased $48.1 million, or 19.3%, to $297.0 million for the year ended December 31, 2018, compared to $248.8 million for the year ended December 31, 2017. The increase for this segment is primarily due to an increase in completion and production spending from our customers as they reacted to improving commodity prices and our ability to increase prices for our services.
Operating expenses for our Rig Services segment were $277.4 million during the year ended December 31, 2018, which represented an increase of $25.0 million, or 9.9%, compared to $252.5 million for the year ended December 31, 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels and an increase in wages for our employees.
Fishing and Rental Services
Revenues for our Fishing and Rental Services segment increased $5.5 million, or 9.3%, to $64.7 million for the year ended December 31, 2018, compared to $59.2 million for the year ended December 31, 2017. The increase in revenue for this segment is primarily due an increase in completion and production spending from our customers as they react to improving commodity prices and our ability to increase prices for our services. This increase was partially offset by the sale of our frac stack and well-testing services business which was sold in 2017.
Operating expenses for our Fishing and Rental Services segment were $73.3 million during the year ended December 31, 2018, which represented a increase of $21.7 million, or 42.0%, compared to $51.7 million for the year ended December 31, 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels and an increase in wages for our employees.
Coiled Tubing Services
Revenues for our Coiled Tubing Services segment increased $29.1 million, or 69.5%, to $71.0 million for the year ended December 31, 2018, compared to $41.9 million for the year ended December 31, 2017. The increase for this segment is primarily due to an increase in completion spending from our customers as they reacted to improving commodity prices and our ability to increase prices for our services.
Operating expenses for our Coiled Tubing Services segment were $65.8 million during the year ended December 31, 2018, which represented an increase of $25.6 million, or 63.6%, compared to $40.2 million for the year ended December 31, 2017. This increase is primarily a result of an increase in employee compensation costs, fuel expense and repair and maintenance expense due to an increase in activity levels and an increase in wages for our employees.
Fluid Management Services
Revenues for our Fluid Management Services segment increased $8.3 million, or 10.3%, to $89.0 million for the year ended December 31, 2018, compared to $80.7 million for the year ended December 31, 2017. The increase for this segment is primarily due to an increase in spending from our customers as they reacted to improving commodity prices and our ability to increase prices for our services.
Operating expenses for our Fluid Management Services segment were $97.9 million during the year ended December 31, 2018, which represented a decrease of $2.4 million, or 2.4%, compared to $100.3 million for the year ended December 31, 2017. This decrease is primarily a result of a decrease in legal settlement expenses partially offset by an increase in employee compensation costs due to an increase in activity levels and an increase in wages for our employees.
International
We sold the remaining businesses of our former International segment, our Canadian subsidiary and our Russian subsidiary in the second and third quarters of 2017, respectively. Accordingly, for 2018, we no longer have an International segment.

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Revenues for our International segment for the year ended December 31, 2017 were $5.6 million. Operating expenses for our International segment were $10.6 million. These expenses were related to employee compensation costs and equipment expense and a $0.2 million impairment to reduce the carrying value of the assets and related liabilities of our Russian business unit to fair market value.
Functional support
Operating expenses for our Functional Support segment decreased $11.0 million, or 14.3%, to $66.2 million (12.7% of consolidated revenues) for the year ended December 31, 2018 compared to $77.2 million (17.7% of consolidated revenues) for the year ended December 31, 2017. The decrease is primarily due to lower employee compensation costs due to reduced staffing levels and a decrease in legal settlement expenses.
Liquidity and Capital Resources
Effective as of March 6, 2020, we completed the Restructuring of our capital structure and indebtedness and, among other things, reduced our outstanding debt from $242.9 million as of December 31, 2019 to $51.2 million as of the closing of the Restructuring. For more information on the Restructuring, see “--Restructuring and Reverse Stock Split” above.
We require capital to fund our ongoing operations, including maintenance expenditures on our existing fleet and equipment, organic growth initiatives, investments and acquisitions, our debt service payments and our other obligations. Following the Restructuring, we believe that our internally generated cash flows from operations, current reserves of cash and availability under the New ABL Facility are sufficient to finance our cash requirements for current and future operations, budgeted capital expenditures, debt service and other obligations for the next twelve months.
Current Financial Condition and Liquidity
As of December 31, 2019, our working capital was $(0.7) million compared to $55.0 million as of December 31, 2018. Our working capital decreased during 2019 primarily as a result of a decrease in cash and cash equivalents and accounts receivable. As of immediately following the closing of the Restructuring, our working capital was $7.5 million.
Cash Flows
Cash used in operating activities were $29.0 million and $1.8 million for the years ended December 31, 2019 and 2018, respectively. Cash used in operating activities for the years ended December 31, 2019 and was primarily related to net loss adjusted for noncash items.
Cash used in investing activities was $3.7 million for the year ended December 31, 2019, compared to cash provided by investing activities of $22.1 million for the ended December 31, 2018. Cash outflows during these periods consisted of capital expenditures. Our capital expenditures are primarily related to the addition of new equipment and the ongoing maintenance of our equipment. Cash inflows during these periods consisted of proceeds from sales of fixed assets.
Cash used in financing activities were $2.9 million and $2.8 million for the years ended December 31, 2019 and 2018, respectively. Financing cash outflows during these periods primarily relate to the repayment of long-term debt.
The following table summarizes our cash flows for the years ended December 31, 2019, 2018 and 2017 (in thousands):
 
 
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Year Ended December 31, 2017
Net cash used by operating activities
$
(29,011
)
 
$
(1,845
)
 
$
(51,367
)
Cash paid for capital expenditures
(18,302
)
 
(37,535
)
 
(16,079
)
Proceeds from sale of assets
14,563

 
15,403

 
32,992

Repayments of long-term debt
(1,875
)
 
(2,500
)
 
(2,500
)
Repayments of financing lease obligations
(160
)
 

 

Payment of deferred financing costs
(811
)
 

 
(350
)
Other financing activities, net
(39
)
 
(277
)
 
(697
)
Effect of changes in exchange rates on cash

 

 
(146
)
Net decrease in cash, cash equivalents and restricted cash
$
(35,635
)
 
$
(26,754
)
 
$
(38,147
)

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Debt Service
At December 31, 2019, our annual maturities on our indebtedness, consisting only of our Prior Term Loan Facility at year-end, were as follows (in thousands). Subsequent to December 31, 2019, the debt in the table below was substantially exchanged for shares of our common stock pursuant to the Restructuring:
 
Principal Payments
2020
$
2,500

2021
240,625

Total
$
243,125


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New ABL Facility
On March 6, 2020, the Company and Key Energy Services, LLC, as borrowers (the “ABL Borrowers”), entered into Amendment No. 3 to the Company’s existing ABL facility, dated as of December 15, 2016 (as amended, the “New ABL Facility”) with the financial institutions party thereto from time to time as lenders (the “ABL Lenders”) and Bank of America, N.A., as administrative agent and collateral agent (the “ABL Agent”) for the ABL Lenders. The New ABL Facility provides for aggregate commitments from the ABL Lenders of $70 million, which mature on the earlier of (x) April 5, 2024 and (y) 181 days prior to the scheduled maturity date of the Company’s term loan facility or the scheduled maturity date of the Company’s other material debt in an aggregate principal amount exceeding $15 million.
The New ABL Facility provides the ABL Borrowers with the ability to borrow up to an aggregate principal amount equal to the lesser of (i) the aggregate revolving commitments then in effect and (ii) the sum of (a) 85% of the value of eligible accounts receivable plus (b) 80% of the value of eligible unbilled accounts receivable, subject to a limit equal to the greater of (x) $30 million and (y) 25% of the commitments. The amount that may be borrowed under the New ABL Facility is subject to increase or reduction based on certain segregated cash or reserves provided for by the New ABL Facility. In addition, the percentages of accounts receivable and unbilled accounts receivable included in the calculation described above is subject to reduction to the extent of certain bad debt write-downs and other dilutive items provided in the New ABL Facility.
Borrowings under the New ABL Facility will bear interest, at the ABL Borrowers’ option, at a per annum rate equal to (i) LIBOR for 30, 60, 90, 180, or, with the consent of the ABL Lenders, 360 days, plus an applicable margin that varies from 2.75% to 3.25% depending on the ABL Borrowers’ fixed charge coverage ratio at such time or (ii) a base rate equal to the sum of (a) the greatest of (x) the prime rate, (y) the federal funds rate, plus 0.50% or (z) 30-day LIBOR plus 1.0% plus (b) an applicable margin that varies from 1.75% to 2.25% depending on the ABL Borrowers’ fixed charge coverage ratio at such time. The New ABL Facility provides that, in the event LIBOR becomes unascertainable for the requested interest period or otherwise becomes unavailable or replaced by other benchmark interest rates, then the Company and the ABL Agent may amend the New ABL Facility for the purpose of replacing LIBOR with one or more SOFR-based rates or another alternate benchmark rate giving consideration to the general practice in similar U.S. dollar denominated syndicated credit facilities.
In addition, the New ABL Facility provides for unused line fees of 0.5% to 0.375% per year, depending on utilization, letter of credit fees and certain other factors. The New ABL Facility may in the future be guaranteed by certain of the Company’s existing and future subsidiaries (the “ABL Guarantors,” and together with the ABL Borrowers, the “ABL Loan Parties”). To secure their obligations under the New ABL Facility, each of the ABL Loan Parties has granted or will grant, as applicable, to the ABL Agent a first-priority security interest for the benefit of the ABL Lenders in its present and future accounts receivable, inventory and related assets and proceeds of the foregoing (the “ABL Priority Collateral”). In addition, the obligations of the ABL Loan Parties under the ABL Facility are secured by second-priority liens on the Term Priority Collateral (as described below under “New Term Loan Facility”).
The revolving loans under the New ABL Facility may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to breakage or similar costs.
The New ABL Facility contains certain affirmative and negative covenants, including covenants that restrict the ability of the ABL Loan Parties to take certain actions including, among other things and subject to certain significant exceptions, the incurrence of debt, the granting of liens, the making of investments, entering into transactions with affiliates, the payment of dividends and the sale of assets. The New ABL Facility also contains a requirement that the ABL Borrowers comply, during certain periods, with a fixed charge coverage ratio of 1.00 to 1.00. As of March 6, 2020, we had no borrowings outstanding under the New ABL Facility and $36.3 million of letters of credit outstanding with borrowing capacity of $13.6 million available subject to covenant constraints under our New ABL Facility.
New Term Loan Facility
On March 6, 2020, the Company entered into the amendment and restatement agreement with the Supporting Term Lenders and Cortland Capital Market Services LLC and Cortland Products Corp., as agent (the “Term Agent”), which amended and restated the Prior Term Loan Facility, among the Company, as borrower, certain subsidiaries of the Company named as guarantors therein, the financial institutions party thereto from time to time as lenders and the Term Agent (as amended and restated by the amendment and restatement agreement, the “New Term Loan Facility”). Prior to the closing of the Restructuring, there were approximately $243.1 million aggregate principal amount of term loans outstanding under the Prior Term Loan Facility. Following the closing of the Restructuring, the New Term Loan Facility is comprised of (i) $30 million new money term loans funded by the Supporting Term Lenders and $20 million amended term loans issued in exchange for existing term loans held by the Supporting Term Lenders (collectively, the “New Term Loans”) and (ii) an approximate $1.2 million senior secured term loan tranche in respect of the existing term loans held by lenders who are not Supporting Term Lenders (the “Continuing Term Loans”).

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The New Term Loan Facility will mature on August 28, 2025, with respect to the New Term Loans, and on December 15, 2021 with respect to the Continuing Term Loans. Such maturity date may, at the Company’s request, be extended by one or more of the term loan lenders pursuant to the terms of the New Term Loan Facility. The New Term Loans will bear interest at a per annum rate equal to LIBOR for six months, plus 10.25%. The Company has the option to pay interest in kind at an annual rate of LIBOR plus 12.25% on the outstanding principal amount of the New Term Loans for the first two years following the closing of the Restructuring. The Continuing Term Loans will bear interest at a per annum rate equal to LIBOR for one, two, three, six or, with the consent of all term loan lenders, up to 12 months, and the Company has the option to pay interest in kind of up to 100 basis points of the per annum interest due on the Continuing Term Loans.
The New Term Loan Facility is guaranteed by certain of the Company’s existing and future subsidiaries (the “Term Loan Guarantors,” and together with the Company, the “Term Loan Parties”). To ensure their obligations under the New Term Loan Facility, each of the Term Loan Parties has granted or will grant, as applicable, to the Term Agent a first-priority security interest for the benefit of the Term Loan Lenders in substantially all of each Term Loan Party’s assets other than certain excluded assets and the ABL Priority Collateral (the “Term Priority Collateral”). In addition, the obligations of the Term Loan Parties under the New Term Loan Facility are secured by second-priority liens on the ABL Priority Collateral (as described above under “ABL Facility”).
The New Term Loans may be prepaid at the Company’s option, subject to the payment of a prepayment premium (which may be waived by lenders holding New Term Loans under the New Term Loan Facility representing at least two-thirds of the aggregate outstanding principal amount of the New Term Loans) in certain circumstances as provided in the New Term Loan Facility. If a prepayment is made prior to the first anniversary of the closing of the Restructuring, such prepayment premium is equal to 3% of the principal amount of the New Term Loans prepaid; if a prepayment is made from the first anniversary to the second anniversary of the closing of the Restructuring, the prepayment premium is equal to 2% of the principal amount of the New Term Loans prepaid; if a prepayment is made from the second anniversary to the third anniversary of the closing of the Restructuring, the prepayment premium is equal to 1% of the principal amount of the New Term Loans prepaid; and there is no prepayment premium thereafter. The Company is required to make principal payments in respect of the Continuing Term Loans in the amount of $3,125 per quarter commencing with the quarter ending March 31, 2020, and is required to pay $1,190,625 on the maturity date of the Continuing Term Loans.
In addition, pursuant to the New Term Loan Facility, the Company must prepay or offer to prepay, as applicable, term loans with the net cash proceeds of certain debt incurrences and asset sales, excess cash flow, receipt of extraordinary cash proceeds (e.g., tax and insurance) and upon certain change of control transactions, subject in each case to certain exceptions.
The New Term Loan Facility contains certain affirmative and negative covenants, including covenants that restrict the ability of the Term Loan Parties to take certain actions including, among other things and subject to certain significant exceptions, the incurrence of debt, the granting of liens, the making of investments, entering into transactions with affiliates, the payment of dividends and the sale of assets. The New Term Loan Facility also contains a financial covenant requiring that the Company maintain Liquidity (as defined in the New Term Loan Facility) of not less than $10 million as of the last day of any fiscal quarter, subject to certain exceptions and cure rights.
Off-Balance Sheet Arrangements
At December 31, 2019, we did not, and we currently do not, have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Capital Expenditures
During the year ended December 31, 2019, our capital expenditures totaled $18.3 million, primarily related to the ongoing replacement to our rig service fleet, coiled tubing units, fluid transportation equipment and rental equipment. Our capital expenditure plan for 2020 contemplates spending between $15 million and $20 million, subject to market conditions. This is primarily related to the addition of new equipment needed and the ongoing maintenance of our equipment. Our capital expenditure program for 2020 is subject to market conditions, including activity levels, commodity prices, industry capacity and specific customer needs as well as cash flows, including cash generated from asset sales. Our focus for 2020 will be the maximization of our current equipment fleet, but we may choose to increase our capital expenditures in 2020 to expand our presence in a market. We currently anticipate funding our 2020 capital expenditures through a combination of cash on hand, operating cash flow and proceeds from sales of assets. Should our operating cash flows or activity levels prove to be insufficient to fund our currently planned capital spending levels, management expects it will adjust our capital spending plans accordingly. We may also incur capital expenditures for strategic investments and acquisitions.

35


Critical Accounting Policies
Our Accounting Department is responsible for the development and application of our accounting policies and internal control procedures and reports to the Chief Financial Officer.
The process of preparing our financial statements in conformity with GAAP requires us to make certain estimates, judgments and assumptions, which may affect the reported amounts of our assets and liabilities, disclosures of contingencies at the balance sheet date, the amounts of revenues and expenses recognized during the reporting period and the presentation of our statement of cash flows. We may record materially different amounts if these estimates, judgments and assumptions change or if actual results differ. However, we analyze our estimates, assumptions and judgments based on our historical experience and various other factors that we believe to be reasonable under the circumstances.
We have identified the following critical accounting policies that require a significant amount of estimation or judgment to accurately present our financial position, results of operations and cash flows:
Revenue recognition;
Estimate of reserves for workers’ compensation, vehicular liability and other self-insurance;
Contingencies;
Income taxes;
Estimates of depreciable lives;
Valuation of tangible and finite-lived intangible assets; and
Valuation of equity-based compensation.
Revenue Recognition
We recognize revenue when all of the following criteria have been met: (i) contract with a customer is identified, (ii) performance obligations in the contract is identified, (iii) transaction price is determined (iv) transaction price is allocated to the performance obligations and (v) revenue is recognized when (or as) the performance obligation(s) are satisfied.
Identifying the contract with the customer ensures that there is an understanding between the company and the customer, about the specific nature and terms of a transaction, has been finalized.
At the inception of a contract, the company assesses the goods or services promised in a contract with a customer, and identifies a performance obligation for each promise to transfer to the customer either: (i) a good or service (or a bundle of goods or services) that is distinct or (ii) a series of distinct goods or services that are substantially the same and have the same pattern of transfer to the customer.
The transaction price is the amount of consideration to which a company expects to be entitled in exchange for transferring promised goods or services to a customer, excluding amounts collected on behalf of third parties. The transaction price may include fixed amounts, variable amounts, or both. By its nature, variable amounts of a transaction price have inherent uncertainty as the amount ultimately expected to be realized is not determinable at the outset of a contract. However, the company shall estimate the amount of variable consideration at contract inception, subject to certain limitations.
Once the separate performance obligations are identified and the transaction price has been determined, the company allocates the transaction price to the performance obligations. This is generally done in proportion to their standalone selling prices. As a result, any discount within the contract is generally allocated proportionally to all of the separate performance obligations in the contract.
Revenue is only recognized when it satisfies an identified performance obligation by transferring a promised good or service to a customer. A good or service is considered transferred when the customer obtains control.
While not typical for our business, our contracts with customers may include multiple performance obligations. For such arrangements, we allocate revenues to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers or using expected cost-plus margin. For combined products and services within a contract, we account for individual products and services separately if they are distinct- i.e. if a product or service is separately identifiable from other items in the contract and if a customer can benefit from it on its own or with other resources that are readily available to the customer. The consideration (including any discounts) is allocated between separate products and services within a contract based on the prices at which we separately sell our services. For items that are not sold separately, we estimate the standalone selling prices using the expected cost-plus margin approach.

36


Workers’ Compensation, Vehicular Liability and Other Self-Insurance
The occurrence of an event not fully insured or indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not be available to cover any or all of these risks, and, if available, we might not be able to obtain such insurance without a substantial increase in premiums. It is possible that, in addition to higher premiums, future insurance coverage may be subject to higher deductibles and coverage restrictions.
We estimate our liability arising out of uninsured and potentially insured events, including workers’ compensation, employer’s liability, vehicular liability, and general liability, and record accruals in our consolidated financial statements. Reserves related to claims are based on the specific facts and circumstances of the insured event and our past experience with similar claims and trend analysis. We adjust loss estimates in the calculation of these accruals based upon actual claim settlements and reported claims. Loss estimates for individual claims are adjusted based upon actual claim judgments, settlements and reported claims. The actual outcome of these claims could differ significantly from estimated amounts. Changes in our assumptions and estimates could potentially have a negative impact on our earnings.
We are primarily self-insured against physical damage to our property, rigs, equipment and automobiles due to large deductibles or self-insurance.
Contingencies
We are periodically required to record other loss contingencies, which relate to lawsuits, claims, proceedings and tax-related audits in the normal course of our operations, on our consolidated balance sheet. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We periodically review our loss contingencies to ensure that we have recorded appropriate liabilities on the balance sheet. We adjust these liabilities based on estimates and judgments made by management with respect to the likely outcome of these matters, including the effect of any applicable insurance coverage for litigation matters. Our estimates and judgments could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. Actual results could vary materially from these reserves.
We record liabilities when environmental assessment indicates that site remediation efforts are probable and the costs can be reasonably estimated. We measure environmental liabilities based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability or the low amount in a range of estimates. These assumptions involve the judgments and estimates of management, and any changes in assumptions or new information could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.
We record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when we incur the liability. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flows change, the change may have a material impact on our results of operations.
Income Taxes
We account for deferred income taxes using the asset and liability method and provide income taxes for all significant temporary differences. Management determines our current tax liability as well as taxes incurred as a result of current operations, yet deferred until future periods. Current taxes payable represent our liability related to our income tax returns for the current year, while net deferred tax expense or benefit represents the change in the balance of deferred tax assets and liabilities reported on our consolidated balance sheets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Further, management makes certain assumptions about the timing of temporary tax differences for the differing treatment of certain items for tax and accounting purposes or whether such differences are permanent. The final determination of our tax liability involves the interpretation of local tax laws, tax treaties, and related authorities in each jurisdiction as well as the significant use of estimates and assumptions regarding the scope of future operations and results achieved and the timing and nature of income earned and expenditures incurred.
We record valuation allowances to reduce deferred tax assets if we determine that it is more likely than not (e.g., a likelihood of more than 50%) that some or all of the deferred tax assets will not be realized in future periods. To assess the likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which this taxable income is generated, to determine whether a valuation allowance is required. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character and in the related jurisdiction in the future. Evidence supporting this ability can include our current financial position, our results of operations, both actual and forecasted results, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Additionally, we record uncertain tax positions in the financial statements at their net recognizable amount, based on the

37


amount that management deems is more likely than not to be sustained upon ultimate settlement with the tax authorities in the domestic and international tax jurisdictions in which we operate.
If our estimates or assumptions regarding our current and deferred tax items are inaccurate or are modified, these changes could have potentially material negative impacts on our earnings.
Estimates of Depreciable Lives
We use the estimated depreciable lives of our long-lived assets, such as rigs, heavy-duty trucks and trailers, to compute depreciation expense, to estimate future asset retirement obligations and to conduct impairment tests. We base the estimates of our depreciable lives on a number of factors, such as the environment in which the assets operate, industry factors including forecasted prices and competition, and the assumption that we provide the appropriate amount of capital expenditures while the asset is in operation to maintain economical operation of the asset and prevent untimely demise to scrap. The useful lives of our intangible assets are determined by the years over which we expect the assets to generate a benefit based on legal, contractual or other expectations.
We depreciate our operational assets over their depreciable lives to their salvage value, which is generally 10% of the acquisition cost. We recognize a gain or loss upon ultimate disposal of the asset based on the difference between the carrying value of the asset on the disposal date and any proceeds we receive in connection with the disposal.
We periodically analyze our estimates of the depreciable lives of our fixed assets to determine if the depreciable periods and salvage value continue to be appropriate. We also analyze useful lives and salvage value when events or conditions occur that could shorten the remaining depreciable life of the asset. We review the depreciable periods and salvage values for reasonableness, given current conditions. As a result, our depreciation expense is based upon estimates of depreciable lives of the fixed assets, the salvage value and economic factors, all of which require management to make significant judgments and estimates. If we determine that the depreciable lives should be different than originally estimated, depreciation expense may increase or decrease and impairments in the carrying values of our fixed assets may result, which could negatively impact our earnings.
Valuation of Tangible and Finite-Lived Intangible Assets
Our fixed assets and finite-lived intangibles are tested for potential impairment when circumstances or events indicate a possible impairment may exist. These circumstances or events are referred to as “trigger events” and examples of such trigger events include, but are not limited to, an adverse change in market conditions, a significant decrease in benefits being derived from an acquired business, a change in the use of an asset, or a significant disposal of a particular asset or asset class.
If a trigger event occurs, an impairment test is performed based on an undiscounted cash flow analysis. To perform an impairment test, we make judgments, estimates and assumptions regarding long-term forecasts of revenues and expenses relating to the assets subject to review. Market conditions, energy prices, estimated depreciable lives of the assets, discount rate assumptions and legal factors impact our operations and have a significant effect on the estimates we use to determine whether our assets are impaired. If the results of the undiscounted cash flow analysis indicate that the carrying value of the assets being tested for impairment are not recoverable, then we record an impairment charge to write the carrying value of the assets down to their fair value. Using different judgments, assumptions or estimates, we could potentially arrive at a materially different fair value for the assets being tested for impairment, which may result in an impairment charge.
Valuation of Equity-Based Compensation
We issue or have issued time-based vesting and performance-based vesting stock options, time-based vesting and performance-based vesting restricted stock units, and restricted stock awards to our employees and non-employee directors. The options we grant are fair valued using a Black-Scholes option model on the grant date and are amortized to compensation expense over the vesting period of the option, net of forfeitures. Compensation related to restricted stock units and restricted stock awards is based on the fair value of the award on the grant date and is amortized to compensation expense over the vesting period of the award, net of forfeitures. The grant-date fair value of our time-based restricted stock units and restricted stock awards is determined using our stock price on the grant date. The grant-date fair value of our performance-based restricted stock units is determined using our stock price on the grant date assuming a 1.0x payout target, however, a maximum 2.0x payout could be achieved if certain EBITDA-based performance measures are met.
In utilizing the Black-Scholes option pricing model to determine fair values of stock options, certain assumptions are made which are based on subjective expectations, and are subject to change. A change in one or more of these assumptions would impact the expense associated with future grants. These key assumptions include the historical stock price volatility, the risk-free interest rate and the expected life of awards. In view of the limited amount of time elapsed since our reorganization, volatility is calculated based on historical stock price volatility of our peer group with a lookback period equivalent to the expected term of the award.

38


Valuation of Warrants
Upon emergence from bankruptcy on December 15, 2016, the Company issued two series of warrants to the former holders of the Predecessor Company’s common stock. One series of warrants will expire on December 15, 2020 and the other series of warrants will expire on December 15, 2021. Each warrant is exercisable for one share of the Company’s common stock, par value $0.01. At issuance, the warrants were recorded at fair value, which was determined using the Black-Scholes option pricing model. The warrants are equity classified and, at issuance, were recorded as an increase to additional paid-in capital in the amount of $3.8 million.
Recent Accounting Developments
ASU 2016-13. In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326), Measurement of Credit Losses on Financial Instruments that will change how companies measure credit losses for most financial assets and certain other instruments that aren’t measured at fair value through net income. The standard will replace today’s “incurred loss” approach with an “expected loss” model for instruments measured at amortized cost. For available-for-sale debt securities, entities will be required to record allowances rather than reduce the carrying amount. The amendments in this update will be effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The adoption of ASU 2016-13 is not expected to have a material impact on our consolidated financial statements.
ASU 2016-02. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which replaced the existing lease guidance. The new standard is intended to provide enhanced transparency and comparability by requiring lessees to record right-of-use assets and corresponding lease liabilities on the balance sheet. Additional disclosure requirements include qualitative disclosures along with specific quantitative disclosures with the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 is effective for the Company for annual reporting periods beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. As part of our assessment, we have created additional internal controls over financial reporting and made changes in business practices and processes related to the ASU. Key has elected the new prospective “Comparatives Under 840” transition method as defined in ASU 2018-11 and adopted the new standard as of January 1, 2019. As part of the adoption, the Company elected several practical expedients which, for contracts that existed at the time of the adoption, allowed the Company to not reassess whether existing contracts are or contained leases, classification of a lease (i.e., operating leases will remain operating leases), initial direct costs and land easement arrangements. As part of the adoption, the Company also made several accounting policy elections which allow the Company to not apply the standard to short term leases as well as to choose not to separate non-lease components from lease components and instead account for all components as a single lease component. The adoption of this standard did not have an impact on our consolidated statement of operations or consolidated statement of cash flows and had an immaterial impact on our consolidated balance sheet. Right of use assets obtained in exchange for operating leases liabilities was $4.1 million at the time of the adoption of the standard.    
ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
Borrowings under our New Term Loan Facility bear interest at variable interest rates, and therefore expose us to interest rate risk. The interest rate under the New Term Loans will bear interest at a per annum rate equal to LIBOR for six months, plus 10.25% and, as of March 6, 2020, we have $51.2 outstanding debt. A hypothetical 10% increase in that rate would increase the annual interest expense on those instruments by $0.5 million. The Company has the option to pay interest in kind at an annual rate of LIBOR plus 12.25% on the outstanding principal amount of the New Term Loans for the first two years following the closing of the Restructuring. The Continuing Term Loans will bear interest at a per annum rate equal to LIBOR for one, two, three, six or, with the consent of all term loan lenders, up to 12 months, and the Company has the option to pay interest in kind of up to 100 basis points of the per annum interest due on the Continuing Term Loans. Borrowings under our New ABL Facility also bear interest at variable interest rates, however, we do not currently have any borrowings under this facility.
Foreign Currency Risk
As of December 31, 2017, we no longer conduct operations in Russia. We completed the sale of our Russian subsidiary in the third quarter of 2017. We also had a Canadian subsidiary which was sold in the second quarter of 2017. The local currency was the functional currency for our former operations in Russia. For balances denominated in our former Russian subsidiary’s local currency, changes in the value of their assets and liabilities due to changes in exchange rates were deferred and accumulated in other comprehensive income until we liquidated our investment. Our former Russian subsidiary remeasured its account balances at the end of each period to an equivalent amount of U.S. dollars, with changes reflected in earnings during those periods. A hypothetical 10% decrease in the average value of the U.S. dollar relative to the value of the local currency for our former Russian subsidiary would have increased our 2017 net loss by $0.2 million.

39




40


ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Key Energy Services, Inc. and Subsidiaries
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 

41


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

Board of Directors and Shareholders
Key Energy Services, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Key Energy Services, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive loss, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the 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 three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
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 the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 12, 2020 expressed an unqualified opinion.
Change in accounting principle
As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting for leases in the year ended December 31, 2019 due to the adoption of FASB Accounting Standards Codification Topic 842, Leases.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s 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 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 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 supporting the amounts and disclosures in the 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2006.
Houston, Texas
March 12, 2020

42


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
Board of Directors and Shareholders
Key Energy Services, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Key Energy Services, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). 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 the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated March 12, 2020 expressed an unqualified opinion on those 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 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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/ GRANT THORNTON LLP
Houston, TX
March 12, 2020


43


Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share amounts)
 
December 31,
 
2019
 
2018
ASSETS
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
14,426

 
$
50,311

Restricted cash
250

 

Accounts receivable, net of allowance for doubtful accounts of $881 and $1,056
51,091

 
74,253

Inventories
13,565

 
15,861

Other current assets
22,260

 
18,073

Total current assets
101,592

 
158,498

Property and equipment, gross
432,917

 
439,043

Accumulated depreciation
(205,352
)
 
(163,333
)
Property and equipment, net
227,565

 
275,710

Intangible assets, net
347

 
404

Other assets
18,366

 
8,562

TOTAL ASSETS
$
347,870

 
$
443,174

LIABILITIES AND EQUITY
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
8,700

 
$
13,587

Other current liabilities
90,715

 
87,377

Current portion of long-term debt
2,919

 
2,500

Total current liabilities
102,334

 
103,464

Long-term debt
240,007

 
241,079

Workers’ compensation, vehicular and health insurance liabilities
26,072

 
24,775

Other non-current liabilities
30,710

 
28,336

Commitments and contingencies

 

Equity:
 
 
 
Common stock, $0.01 par value; 2,000,000 shares authorized, 410,990 and 407,264 outstanding
206

 
204

Additional paid-in capital
265,588

 
264,945

Retained earnings deficit
(317,047
)
 
(219,629
)
Total equity
(51,253
)
 
45,520

TOTAL LIABILITIES AND EQUITY
$
347,870

 
$
443,174

See the accompanying notes which are an integral part of these consolidated financial statements

44


Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
 (in thousands, except per share amounts)
 
 
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Year Ended December 31, 2017
REVENUES
$
413,854

 
$
521,695

 
$
436,165

COSTS AND EXPENSES:
 
 
 
 
 
Direct operating expenses
333,462

 
406,396

 
332,332

Depreciation and amortization expense
56,969

 
82,639

 
84,542

General and administrative expenses
91,309

 
91,626

 
115,284

Impairment expense

 

 
187

Operating loss
(67,886
)
 
(58,966
)
 
(96,180
)
Reorganization items, net

 

 
1,501

Interest expense, net of amounts capitalized
35,523

 
34,163

 
31,797

Other income, net
(2,016
)
 
(2,354
)
 
(7,187
)
Loss before income taxes
(101,393
)
 
(90,775
)
 
(122,291
)
Income tax benefit
3,975

 
1,979

 
1,702

NET LOSS
$
(97,418
)
 
$
(88,796
)
 
$
(120,589
)
Loss per share:
 
 
 
 
 
Basic and diluted
$
(238.77
)
 
$
(219.25
)
 
$
(299.97
)
Weighted Average Shares Outstanding:
 
 
 
 
 
Basic and diluted
408

 
405

 
402

See the accompanying notes which are an integral part of these consolidated financial statements

45


Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)
 
 
 
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Year Ended December 31, 2017
NET LOSS
$
(97,418
)
 
$
(88,796
)
 
$
(120,589
)
Other comprehensive loss:
 
 
 
 
 
Foreign currency translation loss

 

 
(239
)
COMPREHENSIVE LOSS
$
(97,418
)
 
$
(88,796
)
 
$
(120,828
)
See the accompanying notes which are an integral part of these consolidated financial statements

46


Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
 
 
Year Ended December 31, 2019
 
Year Ended December 31, 2018
 
Year Ended December 31, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
Net loss
$
(97,418
)
 
$
(88,796
)