KEY ENERGY SERVICES INC - Annual Report: 2019 (Form 10-K)
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. | ||
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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.” |
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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
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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
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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.
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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
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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
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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,
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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.
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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 |
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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
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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.
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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 | )% | ||||
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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 | )% | ||||
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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.
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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 | ) | |||||||||||||
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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.
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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.
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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
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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.
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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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Key Energy Services, Inc. and Subsidiaries
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page | |
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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
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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
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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
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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
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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
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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 | ) | $ | (120,589 | ) | ||
Adjustments to reconcile net loss to net cash used in operating activities: | |||||||||||
Depreciation and amortization expense | 56,969 | 82,639 | 84,542 | ||||||||
Impairment expense | — | — | 187 | ||||||||
Bad debt expense | 912 | 286 | 1,420 | ||||||||
Accretion of asset retirement obligations | 168 | 164 | 221 | ||||||||
Loss from equity method investments | — | — | 560 | ||||||||
Amortization of deferred financing costs | 433 | 476 | 476 | ||||||||
Deferred income tax benefit | — | — | (35 | ) | |||||||
Gain on disposal of assets, net | (5,870 | ) | (9,618 | ) | (27,583 | ) | |||||
Share-based compensation | 684 | 5,910 | 7,591 | ||||||||
Changes in working capital: | |||||||||||
Accounts receivable | 22,250 | (5,220 | ) | 669 | |||||||
Other current assets | (1,891 | ) | 6,486 | 7,764 | |||||||
Accounts payable and accrued liabilities | (1,061 | ) | (564 | ) | (13,017 | ) | |||||
Share-based compensation liability awards | (71 | ) | 253 | — | |||||||
Other assets and liabilities | (4,116 | ) | 6,139 | 6,427 | |||||||
Net cash used in operating activities | (29,011 | ) | (1,845 | ) | (51,367 | ) | |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||
Capital expenditures | (18,302 | ) | (37,535 | ) | (16,079 | ) | |||||
Proceeds from sale of assets | 14,563 | 15,403 | 32,992 | ||||||||
Net cash provided by (used in) investing activities | (3,739 | ) | (22,132 | ) | 16,913 | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||
Repayments of long-term debt | (1,875 | ) | (2,500 | ) | (2,500 | ) | |||||
Repayments of financing lease obligations | (160 | ) | — | — | |||||||
Payment of deferred financing costs | (811 | ) | — | (350 | ) | ||||||
Repurchases of common stock | (39 | ) | (280 | ) | (697 | ) | |||||
Proceeds from exercise warrants | — | 3 | — | ||||||||
Net cash used in financing activities | (2,885 | ) | (2,777 | ) | (3,547 | ) | |||||
Effect of changes in exchange rates on cash | — | — | (146 | ) | |||||||
Net decrease in cash, cash equivalents and restricted cash | (35,635 | ) | (26,754 | ) | (38,147 | ) | |||||
Cash, cash equivalents, and restricted cash, beginning of period | 50,311 | 77,065 | 115,212 | ||||||||
Cash, cash equivalents, and restricted cash, end of period | $ | 14,676 | $ | 50,311 | $ | 77,065 | |||||
See the accompanying notes which are an integral part of these consolidated financial statements
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Key Energy Services, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(in thousands, except per share data)
COMMON STOCKHOLDERS | Total | |||||||||||||||||||||
Common Stock | Additional Paid-in Capital | Accumulated Other Comprehensive Income (Loss) | Retained Earnings (Deficit) | |||||||||||||||||||
Number of Shares | Amount at par | |||||||||||||||||||||
BALANCE AT DECEMBER 31, 2016 | 402 | $ | 201 | $ | 252,421 | $ | 239 | $ | (10,244 | ) | $ | 242,617 | ||||||||||
Foreign currency translation | — | — | — | (239 | ) | — | (239 | ) | ||||||||||||||
Common stock purchases | (1 | ) | (1 | ) | (696 | ) | — | — | (697 | ) | ||||||||||||
Share-based compensation | 3 | 2 | 7,589 | — | — | 7,591 | ||||||||||||||||
Net loss | — | — | — | — | (120,589 | ) | (120,589 | ) | ||||||||||||||
BALANCE AT DECEMBER 31, 2017 | 404 | 202 | 259,314 | — | (130,833 | ) | 128,683 | |||||||||||||||
Common stock purchases | (1 | ) | — | (280 | ) | — | — | (280 | ) | |||||||||||||
Exercise of warrants | — | — | 3 | — | — | 3 | ||||||||||||||||
Share-based compensation | 4 | 2 | 5,908 | — | — | 5,910 | ||||||||||||||||
Net loss | — | — | — | — | (88,796 | ) | (88,796 | ) | ||||||||||||||
BALANCE AT DECEMBER 31, 2018 | 407 | 204 | 264,945 | — | (219,629 | ) | 45,520 | |||||||||||||||
Common stock purchases | (1 | ) | — | (39 | ) | — | — | (39 | ) | |||||||||||||
Share-based compensation | 5 | 2 | 682 | — | — | 684 | ||||||||||||||||
Net loss | — | — | — | — | (97,418 | ) | (97,418 | ) | ||||||||||||||
BALANCE AT DECEMBER 31, 2019 | 411 | $ | 206 | $ | 265,588 | $ | — | $ | (317,047 | ) | $ | (51,253 | ) | |||||||||
See the accompanying notes which are an integral part of these consolidated financial statements
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Key Energy Services, Inc., and its wholly owned subsidiaries (collectively, “Key,” the “Company,” “we,” “us,” “its,” and “our”) provide a full range of well services to major oil companies, 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 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.
Basis of Presentation
The consolidated financial statements included in this Annual Report on Form 10-K present our financial position, results of operations and cash flows for the periods presented in accordance with GAAP.
The preparation of these consolidated financial statements requires us to develop estimates and to make assumptions that affect our financial position, results of operations and cash flows. These estimates also impact the nature and extent of our disclosure, if any, of our contingent liabilities. Among other things, we use estimates to (i) analyze assets for possible impairment, (ii) determine depreciable lives for our assets, (iii) assess future tax exposure and realization of deferred tax assets, (iv) determine amounts to accrue for contingencies, (v) value tangible and intangible assets, (vi) assess workers’ compensation, vehicular liability, self-insured risk accruals and other insurance reserves, (vii) provide allowances for our uncollectible accounts receivable, (viii) value our asset retirement obligations, and (ix) value our equity-based compensation. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates relate to improved information not previously available. Because of the limitations inherent in this process, our actual results may differ materially from these estimates. We believe that our estimates are reasonable.
We have evaluated events occurring after the balance sheet date included in this Annual Report on Form 10-K for possible disclosure as a subsequent event. Management monitored for subsequent events through the date that these financial statements were issued.
Principles of Consolidation
Within our consolidated financial statements, we include our accounts and the accounts of our majority-owned or controlled subsidiaries. We eliminate intercompany accounts and transactions. When we have an interest in an entity for which we do not have significant control or influence, we account for that interest using the cost method. When we have an interest in an entity and can exert significant influence but not control, we account for that interest using the equity method.
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 the RSA and the Restructuring contemplated thereby, among other things we effected the following transactions and changes to our capital structure and governance:
• | pursuant to exchange agreements entered into at the closing of the Restructuring, we 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 |
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
• | 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 “Note 12. Long-Term Debt.”
Effective immediately following the closing of the Restructuring, we completed a 1-for-50 reverse stock split of our outstanding common stock. As a result of this stock split, our issued and outstanding common stock decreased from approximately 20.7 million shares to approximately 410,000 shares. Accordingly, all share and per share information contained in these financial statements has been restated to retroactively show the effect of this stock split.
Acquisitions
From time to time, we acquire businesses or assets that are consistent with our long-term growth strategy. Results of operations for acquisitions are included in our financial statements beginning on the date of acquisition and are accounted for using the acquisition method. For all business combinations (whether partial, full or in stages), the acquirer records 100% of all assets and liabilities of the acquired business, including goodwill, at their fair values; including contingent consideration. Final valuations of assets and liabilities are obtained and recorded as soon as practicable no later than one year from the date of the acquisition.
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 |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash equivalents. As of December 31, 2019, all of our obligations under our Prior ABL Facility and Prior Term Loan Facility were secured by most of our assets, including assets held by our subsidiaries, which includes our cash and cash equivalents. We restrict investment of cash to financial institutions with high credit standing and limit the amount of credit exposure to any one financial institution.
We maintain our cash in bank deposit and brokerage accounts which exceed federally insured limits. As of December 31, 2019, accounts were guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 and substantially all of our accounts held deposits in excess of the FDIC limits.
Certain of our cash accounts are zero-balance controlled disbursement accounts that do not have right of offset against our other cash balances. We present the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets.
Accounts Receivable and Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable if we determine that there is a possibility that we will not collect all or part of the outstanding balances. We regularly review accounts over 150 days past due from the invoice date for collectability and establish or adjust our allowance as necessary using the specific identification method. If we exhaust all collection efforts and determine that the balance will never be collected, we write off the accounts receivable and the associated provision for uncollectible accounts.
From time to time we are entitled to proceeds under our insurance policies for amounts that we have reserved in our self-insurance liability. We present these insurance receivables gross on our balance sheet as a component of other assets, separate from the corresponding liability.
Concentration of Credit Risk and Significant Customers
Our customers include major oil and natural gas production companies, independent oil and natural gas production companies, and natural gas production companies. We perform ongoing credit evaluations of our customers and usually do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial position should be considered in light of the fluctuations in demand experienced by oilfield service companies as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial position as supply and demand factors directly affect utilization and hours which are the primary determinants of our net cash provided by operating activities.
During the year ended 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.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Inventories
Inventories, which consist primarily of equipment parts and spares for use in our operations and supplies held for consumption, are valued at the lower of average cost or market.
Property and Equipment
Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated depreciable lives of the assets using the straight-line method. Depreciation expense for the years ended December 31, 2019, 2018 and 2017 were $56.9 million, $82.6 million and $84.5 million, respectively. We depreciate our operational assets over their depreciable lives to their salvage value, which is a value higher than the assets’ value as scrap. Salvage value approximates 10% of an operational asset’s acquisition cost. When an operational asset is stacked or taken out of service, we review its physical condition, depreciable life and ultimate salvage value to determine if the asset is operable and whether the remaining depreciable life and salvage value should be adjusted. When we scrap an asset, we accelerate the depreciation of the asset down to its salvage value. When we dispose of an asset, a gain or loss is recognized.
As of December 31, 2019, the estimated useful lives of our asset classes are as follows:
Description | Years |
Well service rigs and components | 3-15 |
Oilfield trucks, vehicles and related equipment | 4-7 |
Fishing and rental tools, coiled tubing units and equipment, tubulars and pressure control equipment | 3-10 |
Disposal wells | 15 |
Furniture and equipment | 3-7 |
Buildings and improvements | 15-30 |
A long-lived asset or asset group should be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. For purposes of testing for impairment, we group our long-lived assets along our lines of business based on the services provided, which is the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. We would record an impairment charge, reducing the net carrying value to estimated fair value, if the asset group’s estimated future cash flows were less than its net carrying value. Events or changes in circumstance that cause us to evaluate our fixed assets for recoverability and possible impairment may include changes in market conditions, such as adverse movements in the prices of oil and natural gas, or changes of an asset group, such as its expected future life, intended use or physical condition, which could reduce the fair value of certain of our property and equipment. The development of future cash flows and the determination of fair value for an asset group involves significant judgment and estimates. See “Note 6. Property and Equipment,” for further discussion.
Asset Retirement Obligations
We recognize a liability for the fair value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as a cost of the asset. We depreciate the additional cost over the estimated useful life of the assets. Our obligations to perform our asset retirement activities are unconditional, despite the uncertainties that may exist surrounding an individual retirement activity. Accordingly, we recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. In determining the fair value, we examine the inputs that we believe a market participant would use if we were to transfer the liability. We probability-weight the potential costs a third-party would charge, adjust the cost for inflation for the estimated life of the asset, and discount this cost using our credit adjusted risk free rate. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of those cash flows. If our estimates of the amount or timing of the cash flows change, such changes may have a material impact on our results of operations. See “Note 10. Asset Retirement Obligations.”
Deposits
Due to capacity constraints on equipment manufacturers, we are sometimes required to make advanced payments for certain oilfield service equipment and other items used in the normal course of business. As of the years ended December 31, 2019 and 2018, deposits totaled $8.7 million and $1.3 million, respectively. Deposits consist primarily of deposit requirements of insurance companies and payments made related to high demand long-lead time items.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Capitalized Interest
Interest is capitalized on the average amount of accumulated expenditures for major capital projects under construction using an effective interest rate based on related debt until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets, and is included in the depreciation and amortization line in the accompanying consolidated statements of operations.
Deferred Financing Costs
Deferred financing costs associated with long-term debt are carried at cost and are amortized to interest expense using the effective interest method over the life of the related debt instrument. When the related debt instrument is retired, any remaining unamortized costs are included in the determination of the gain or loss on the extinguishment of the debt. We record gains and losses from the extinguishment of debt as a part of continuing operations. In accordance with ASU 2015-03, we record debt financing costs as a reduction of our long-term debt. See “Note 12. Long-term Debt,” for further discussion.
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.
Internal-Use Software
We capitalize costs incurred during the application development stage of internal-use software and amortize these costs over the software’s estimated useful life, generally five to seven years. Costs incurred related to selection or maintenance of internal-use software are expensed as incurred.
Litigation
When estimating our liabilities related to litigation, we take into account all available facts and circumstances in order to determine whether a loss is probable and reasonably estimable.
Various suits and claims arising in the ordinary course of business are pending against us. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and our need for the disclosure of these items. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable. See “Note 13. Commitments and Contingencies.”
Environmental
Our operations routinely involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants, and regulated substances. These operations are subject to various federal, state and local laws and regulations intended to protect the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. We record liabilities on an undiscounted basis when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. While our litigation reserves reflect the application of our insurance coverage, our environmental reserves do not reflect management’s assessment of the insurance coverage that may apply to the matters at issue. See “Note 13. Commitments and Contingencies.”
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Self-Insurance
We are primarily self-insured against physical damage to our equipment and automobiles as well as workers’ compensation claims. The accruals that we maintain on our consolidated balance sheet relate to these deductibles and self-insured retentions, which we estimate through the use of historical claims data and trend analysis. To assist management with the liability amount for our self-insurance reserves, we utilize the services of a third party actuary. The actual outcome of any claim could differ significantly from estimated amounts. We adjust loss estimates in the calculation of these accruals, based upon actual claim settlements and reported claims. See “Note 13. Commitments and Contingencies.”
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 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. See “Note 11. Income Taxes” for further discussion of accounting for income taxes, changes in our valuation allowance, components of our tax rate reconciliation and realization of loss carryforwards.
Earnings Per Share
Basic earnings per common share is determined by dividing net earnings applicable to common stock by the weighted average number of common shares actually outstanding during the period. Diluted earnings per common share is based on the increased number of shares that would be outstanding assuming conversion of dilutive outstanding convertible securities using the treasury stock and “as if converted” methods. See “Note 8. Earnings Per Share.”
Share-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 as part of those employees’ compensation and as a retention tool for non-employee directors. We calculate the fair value of the awards on the grant date and amortize that fair value to compensation expense ratably 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. The fair value of our stock option awards are estimated using a Black-Scholes fair value model.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The valuation of our stock options requires us to estimate the expected term of award, which we estimate using the simplified method, as we do not have sufficient historical exercise information. Additionally, the valuation of our stock option awards is also dependent on historical stock price volatility. 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. Fair value of performance-based stock options and restricted stock units is estimated in the same manner as our time-based awards and assumes that performance goals will be achieved and the awards will vest. If the performance based awards do not vest, any previously recognized compensation costs will be reversed. We record share-based compensation as a component of general and administrative or direct operating expense based on the role of the applicable individual. See “Note 16. Share-Based Compensation.”
Foreign Currency Gains and Losses
With respect to our former operations in Russia, which were sold in the third quarter of 2017, where the local currency was the functional currency, assets and liabilities were translated at the rates of exchange in effect on the balance sheet date, while income and expense items were translated at average rates of exchange during the period. The resulting gains or losses arising from the translation of accounts from the functional currency to the U.S. dollar were included as a separate component of stockholders’ equity in other comprehensive income until a partial or complete sale or liquidation of our net investment in the foreign entity.
From time to time our former foreign subsidiaries may have entered into transactions that are denominated in currencies other than their functional currency. These transactions were initially recorded in the functional currency of that subsidiary based on the applicable exchange rate in effect on the date of the transaction. At the end of each month, those transactions were remeasured to an equivalent amount of the functional currency based on the applicable exchange rates in effect at that time. Any adjustment required to remeasure a transaction to the equivalent amount of the functional currency at the end of the month was recorded in the income or loss of the foreign subsidiary as a component of other income, net.
Comprehensive Loss
We display comprehensive loss and its components in our financial statements, and we classify items of comprehensive income (loss) by their nature in our financial statements and display the accumulated balance of other comprehensive income (loss) separately in our stockholders’ equity.
Leases
We lease real property and equipment through various leasing arrangements. When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine whether the lease should be accounted for as an operating lease or a capital lease.
We periodically incur costs to improve the assets that we lease under these arrangements. If the value of the leasehold improvements exceeds our threshold for capitalization, we record the improvement as a component of our property and equipment and amortize the improvement over the useful life of the improvement or the lease term, whichever is shorter.
Certain of our operating lease agreements are structured to include scheduled and specified rent increases over the term of the lease agreement. These increases may be the result of an inducement or “rent holiday” conveyed to us early in the lease, or are included to reflect the anticipated effects of inflation. We recognize scheduled and specified rent increases on a straight-line basis over the term of the lease agreement. In addition, certain of our operating lease agreements contain incentives to induce us to enter into the lease agreement, such as up-front cash payments to us, payment by the lessor of our costs, such as moving expenses, or the assumption by the lessor of our pre-existing lease agreements with third parties. Any payments made to us or on our behalf represent incentives that we consider to be a reduction of our rent expense, and are recognized on a straight-line basis over the term of the lease agreement.
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.
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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.
NOTE 2. REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenues are recognized when control of the promised goods or services is transferred to our customers, in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. The following table presents our revenues disaggregated by revenue source (in thousands). Sales taxes are excluded from revenues.
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | |||||||||
Rig Services | $ | 250,532 | $ | 296,969 | $ | 248,830 | |||||
Fishing and Rental Services | 54,511 | 64,691 | 59,172 | ||||||||
Coiled Tubing Services | 37,964 | 71,013 | 41,866 | ||||||||
Fluid Management Services | 70,847 | 89,022 | 80,726 | ||||||||
International | — | — | 5,571 | ||||||||
Total | $ | 413,854 | $ | 521,695 | $ | 436,165 | |||||
Disaggregation of Revenue
We have disaggregated our revenues by our reportable segments including Rig Services, Fishing & Rental Services, Coiled Tubing Services and Fluid Management Services.
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.
We recognize revenue within the Rig Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed. Rig Services are billed monthly. Payment terms for Rig Services are usually 30 days from invoice receipt.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Fishing and Rental Services
We offer a full line of services and rental equipment designed for use in providing 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, foam air units.
We recognize revenue within the Fishing and Rental Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed. Fishing and Rental Services are billed and paid monthly. Payment terms for Fishing and Rental Services are usually 30 days from invoice receipt.
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 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.
We recognize revenue within the Coiled Tubing Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue, typically daily, as the services are provided as we have the right to invoice the customer for the services performed. Coiled Tubing Services are billed and paid monthly. Payment terms for Coiled Tubing Services are usually 30 days from invoice receipt.
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 wells owned by us or a third party.
We recognize revenue within the Fluid Management Services segment by measuring progress toward satisfying the performance obligation in a manner that best depicts the transfer of goods or services to the customer. The control over services is transferred as the services are rendered to the customer. Specifically, we recognize revenue as the services are provided, typically daily, as we have the right to invoice the customer for the services performed. Fluid Management Services are billed and paid monthly. Payment terms for Fluid Management Services are usually 30 days from invoice receipt.
International
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.
We recognized revenue within the International segment by measuring progress toward satisfying the performance obligation in a manner that best depicted the transfer of goods or services to the customer. The control over services was transferred as the services were rendered to the customer. Specifically, we recognized revenue as the services were provided, typically daily, as we had the right to invoice the customer for the services performed. Services within the international segment were billed and paid monthly. Payment terms for services within the International segment were usually 30 days from invoice receipt.
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Arrangements with Multiple Performance Obligations
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.
Contract Balances
Under our revenue contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our revenue contracts do not give rise to contract assets or liabilities under ASC 606.
Practical Expedients and Exemptions
We generally expense sales commissions when incurred because the amortization period would have been one year or less. These costs are recorded within general and administrative expenses.
The majority of our services are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
Additionally, our payment terms are short-term in nature with settlements of one year or less. We have, therefore, utilized the practical expedient in ASC 606-10-32-18 exempting the Company from adjusting the promised amount of consideration for the effects of a significant financing component given that the period between when the entity transfers a promised good or service to a customer and when the customer pays for that good or service will be one year or less.
Further, in many of our service contracts we have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the entity’s performance completed to date (for example, a service contract in which an entity bills a fixed amount for each hour of service provided). For those contracts, we have utilized the practical expedient in ASC 606-10-55-18 exempting the Company from disclosure of the entity to recognize revenue in the amount to which the Company has a right to invoice.
Accordingly, we do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.
NOTE 3. OTHER BALANCE SHEET INFORMATION
The table below presents comparative detailed information about other current assets at December 31, 2019 and 2018 (in thousands):
December 31, | |||||||
2019 | 2018 | ||||||
Other current assets: | |||||||
Prepaid current assets | $ | 13,118 | $ | 11,207 | |||
Reinsurance receivable | 6,475 | 6,365 | |||||
Operating lease right-of-use assets | 2,394 | — | |||||
Other | 273 | 501 | |||||
Total | $ | 22,260 | $ | 18,073 | |||
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The table below presents comparative detailed information about other non-current assets at December 31, 2019 and 2018 (in thousands):
December 31, | |||||||
2019 | 2018 | ||||||
Other non-current assets: | |||||||
Reinsurance receivable | $ | 6,887 | $ | 6,743 | |||
Deposits | 8,689 | 1,309 | |||||
Operating lease right-of-use assets | 2,404 | — | |||||
Other | 386 | 510 | |||||
Total | $ | 18,366 | $ | 8,562 | |||
The table below presents comparative detailed information about other current liabilities at December 31, 2019 and 2018 (in thousands):
December 31, | |||||||
2019 | 2018 | ||||||
Other current liabilities: | |||||||
Accrued payroll, taxes and employee benefits | $ | 14,463 | $ | 19,346 | |||
Accrued operating expenditures | 12,919 | 15,861 | |||||
Income, sales, use and other taxes | 5,115 | 8,911 | |||||
Self-insurance reserves | 25,366 | 25,358 | |||||
Accrued interest | 15,476 | 7,105 | |||||
Accrued insurance premiums | 4,990 | 5,651 | |||||
Unsettled legal claims | 7,020 | 4,356 | |||||
Accrued severance | 2,636 | 83 | |||||
Operating leases | 2,502 | — | |||||
Other | 228 | 706 | |||||
Total | $ | 90,715 | $ | 87,377 | |||
The table below presents comparative detailed information about other non-current liabilities at December 31, 2019 and 2018 (in thousands):
December 31, | |||||||
2019 | 2018 | ||||||
Other non-current liabilities: | |||||||
Asset retirement obligations | $ | 9,035 | $ | 9,018 | |||
Environmental liabilities | 2,047 | 2,227 | |||||
Accrued sales, use and other taxes | 17,005 | 17,024 | |||||
Operating leases | 2,590 | — | |||||
Other | 33 | 67 | |||||
Total | $ | 30,710 | $ | 28,336 | |||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 4. OTHER INCOME, NET
The table below presents comparative detailed information about our other income and expense for 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 | |||||||||
Interest income | $ | (723 | ) | $ | (820 | ) | $ | (711 | ) | ||
Other | (1,293 | ) | (1,534 | ) | (6,476 | ) | |||||
Total | $ | (2,016 | ) | $ | (2,354 | ) | $ | (7,187 | ) | ||
NOTE 5. ALLOWANCE FOR DOUBTFUL ACCOUNTS
The table below presents a rollforward of our allowance for doubtful accounts for the years ended December 31, 2019, 2018 and 2017 (in thousands):
Balance at Beginning of Period | Charged to Expense | Deductions | Balance at End of Period | ||||||||||||
As of December 31, 2019 | $ | 1,056 | $ | 912 | $ | (1,087 | ) | $ | 881 | ||||||
As of December 31, 2018 | 875 | 286 | (105 | ) | 1,056 | ||||||||||
As of December 31, 2017 | 168 | 1,420 | (713 | ) | 875 | ||||||||||
NOTE 6. PROPERTY AND EQUIPMENT
Property and equipment consist of the following (in thousands):
December 31, | |||||||
2019 | 2018 | ||||||
Major classes of property and equipment: | |||||||
Oilfield service equipment | $ | 286,345 | $ | 284,943 | |||
Disposal wells | 41,127 | 30,863 | |||||
Motor vehicles | 11,416 | 44,286 | |||||
Furniture and equipment | 31,216 | 6,469 | |||||
Buildings and land | 60,097 | 65,328 | |||||
Work in progress | 956 | 7,154 | |||||
Right-of-use assets under finance leases | 1,760 | — | |||||
Gross property and equipment | 432,917 | 439,043 | |||||
Accumulated depreciation | (205,352 | ) | (163,333 | ) | |||
Net property and equipment | $ | 227,565 | $ | 275,710 | |||
NOTE 7. INTANGIBLE ASSETS
The components of our intangible assets as of December 31, 2019 and 2018 are as follows (in thousands):
December 31, | |||||||
2019 | 2018 | ||||||
Gross carrying value | $ | 520 | $ | 520 | |||
Accumulated amortization | (173 | ) | (116 | ) | |||
Net carrying value | $ | 347 | $ | 404 | |||
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The weighted average remaining amortization periods and expected amortization expense for the next five years for our definite lived intangible assets are as follows (in thousands):
Weighted average remaining amortization period (years) | Expected Amortization Expense | ||||||||||||||||||||
2020 | 2021 | 2022 | 2023 | 2024 | |||||||||||||||||
Trademarks | 6.0 | $ | 58 | $ | 58 | $ | 58 | $ | 58 | $ | 58 | ||||||||||
Amortization expense for our intangible assets was less than $0.1 million for the years ended December 31, 2019, 2018 and 2017.
NOTE 8. EARNINGS PER SHARE
The following table presents our basic and diluted earnings per share (“EPS”) for the years ended December 31, 2019, 2018 and 2017 (in thousands, except per share amounts):
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | |||||||||
Basic and diluted EPS Calculation: | |||||||||||
Numerator | |||||||||||
Net loss | $ | (97,418 | ) | $ | (88,796 | ) | $ | (120,589 | ) | ||
Denominator | |||||||||||
Weighted average shares outstanding | 408 | 405 | 402 | ||||||||
Basic loss per share | $ | (238.77 | ) | $ | (219.25 | ) | $ | (299.97 | ) | ||
Stock options, warrants and stock appreciation rights (“SARs”) are included in the computation of diluted earnings per share using the treasury stock method. Restricted stock awards are legally considered issued and outstanding when granted and are included in basic weighted average shares outstanding.
The company has issued potentially dilutive instruments such as RSUs, stock options, SARs and warrants. However, the company did not include these instruments in its calculation of diluted loss per share during the periods presented, because to include them would be anti-dilutive. The following table shows potentially dilutive instruments (in thousands):
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||
RSUs | 37 | 24 | 36 | |||||
Stock options | 1 | 3 | 14 | |||||
Warrants | 37 | 37 | 37 | |||||
Total | 75 | 64 | 87 | |||||
There have been no material changes in share amounts subsequent to the balance sheet date that would have a material impact on the earnings per share calculation.
NOTE 9. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash, cash equivalents, accounts receivable, accounts payable and accrued liabilities. These carrying amounts approximate fair value because of the short maturity of the instruments or because the carrying value is equal to the fair value of those instruments on the balance sheet date.
Prior Term Loan Facility due 2021. Because the variable interest rates of these loans approximate current market rates, the fair values of the loans borrowed under this facility approximate their carrying values. The Prior Term Loan was replaced with the New Term Loan on March 9, 2020, which also has variable interest rates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 10. ASSET RETIREMENT OBLIGATIONS
In connection with our well servicing activities, we operate a number of saltwater disposal (“SWD”) facilities. Our operations involve the transportation, handling and disposal of fluids in our SWD facilities that are by-products of the drilling process. SWD facilities used in connection with our fluid hauling operations are subject to future costs associated with the retirement of these properties. As a result, we have incurred costs associated with the proper storage and disposal of these materials.
Annual accretion of the assets associated with the asset retirement obligations were $0.2 million, $0.2 million and $0.2 million for the years ended December 31, 2019, 2018 and 2017. A summary of changes in our asset retirement obligations is as follows (in thousands):
Balance at December 31, 2016 | $ | 9,069 | |
Additions | 36 | ||
Costs incurred | (147 | ) | |
Accretion expense | 221 | ||
Disposals | (248 | ) | |
Balance at December 31, 2017 | 8,931 | ||
Additions | 340 | ||
Costs incurred | (417 | ) | |
Accretion expense | 164 | ||
Balance at December 31, 2018 | 9,018 | ||
Costs incurred | (151 | ) | |
Accretion expense | 168 | ||
Balance at December 31, 2019 | $ | 9,035 | |
NOTE 11. INCOME TAXES
The U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”) was enacted on December 22, 2017. The 2017 Tax Act is comprehensive tax reform legislation that contains significant changes to corporate taxation. Provisions on the enacted law include a permanent reduction of the corporate income tax rate from 35% to 21%, imposing a mandatory one-time tax on un-repatriated 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, 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), and other related provisions to maintain the U.S. tax base.
We recognized the income tax effects of the 2017 Tax Act in accordance with Staff Accounting Bulletin No. 118 ("SAB 118") during 2017. SAB 118 provided SEC staff guidance for the application of ASC Topic 740, Income Taxes, and allowed for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. As such, our 2017 financial results reflected the provisional income tax effects of the 2017 Tax Act for which the accounting under ASC Topic 740 was incomplete but a reasonable estimate could be determined. We did not identify any items for which the income tax effects of the 2017 Tax Act could not be reasonably estimated as of December 31, 2017. Additional clarifying guidance and law corrections were issued by the U.S. government during 2018 related to the 2017 Tax Act, which provided further insight into properly accounting for the impacts of U.S. tax reform. During 2018, we finalized our accounting for this matter and concluded that no adjustments were required from our provisionally recorded amounts from 2017. We no longer have any provisionally recorded items related to the enactment of the 2017 Tax Act as of December 31, 2018. In addition, there were no material 2017 Tax Act changes or clarifications that affected our accounting for the year ended December 31, 2019.
The components of our income tax expense are as follows (in thousands):
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | |||||||||
Current income tax benefit | $ | 3,975 | $ | 1,979 | $ | 1,667 | |||||
Deferred income tax benefit | — | — | 35 | ||||||||
Total income tax benefit | $ | 3,975 | $ | 1,979 | $ | 1,702 | |||||
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We made federal income tax payments of zero for the years ended December 31, 2019, 2018 and 2017. In addition, we received federal income tax refunds of $4.4 million, 1.1 million and zero during the years ended December 31, 2019, 2018 and 2017, respectively.
Income tax (expense) benefit differs from amounts computed by applying the statutory federal rate as follows:
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | ||||||
Income tax benefit computed at Federal statutory rate | 21.0 | % | 21.0 | % | 35.0 | % | ||
State taxes | (0.4 | )% | (0.2 | )% | — | % | ||
Meals and entertainment | (0.2 | )% | (0.4 | )% | (0.4 | )% | ||
Foreign rate difference | — | % | — | % | 0.4 | % | ||
Non-taxable cancellation of debt income | — | % | 2.6 | % | — | % | ||
Penalties and other non-deductible expenses | (0.1 | )% | — | % | — | % | ||
Change in valuation allowance | (20.4 | )% | (20.1 | )% | (33.8 | )% | ||
Equity compensation | (0.4 | )% | (0.7 | )% | (1.0 | )% | ||
U.S. tax reform - impact to deferred tax assets and liabilities | — | % | — | % | (67.4 | )% | ||
U.S. tax reform - change in valuation allowance | — | % | — | % | 67.4 | % | ||
Other | 4.4 | % | — | % | 1.2 | % | ||
Effective income tax rate | 3.9 | % | 2.2 | % | 1.4 | % | ||
As of December 31, 2019 and 2018, our deferred tax assets and liabilities consisted of the following (in thousands):
December 31, | |||||||
2019 | 2018 | ||||||
Deferred tax assets: | |||||||
Net operating loss and tax credit carryforwards | $ | 115,811 | $ | 113,230 | |||
Capital loss carryforwards | 15,320 | 15,826 | |||||
Foreign tax credit carryforward | 17,095 | 17,095 | |||||
Self-insurance reserves | 8,619 | 8,581 | |||||
Interest expense limitation | 12,943 | 6,055 | |||||
Accrued liabilities | 9,842 | 9,213 | |||||
Share-based compensation | 507 | 1,221 | |||||
Intangible assets | 37,099 | 44,748 | |||||
Other | 2,333 | 670 | |||||
Total deferred tax assets | 219,569 | 216,639 | |||||
Valuation allowance for deferred tax assets | (201,666 | ) | (190,791 | ) | |||
Net deferred tax assets | 17,903 | 25,848 | |||||
Deferred tax liabilities: | |||||||
Property and equipment | (16,817 | ) | (25,848 | ) | |||
Other | (1,086 | ) | — | ||||
Total deferred tax liabilities | (17,903 | ) | (25,848 | ) | |||
Net deferred tax asset (liability), net of valuation allowance | $ | — | $ | — | |||
The December 31, 2019 net deferred tax asset is comprised of $219.6 million deferred tax assets before valuation allowance, and $17.9 million deferred tax liabilities. The valuation allowance against the net deferred tax asset increased by approximately $10.9 million from December 31, 2018 to December 31, 2019.
Deferred tax assets and liabilities are recognized for the estimated future tax effects of temporary differences between the tax basis of an asset or liability and its reported amount in the Consolidated Financial Statements. The measurement of deferred
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tax assets and liabilities is based on enacted tax laws and rates currently in effect in each of the jurisdictions in which we have operations.
In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those deferred income tax assets would be deductible. We consider the scheduled reversal of deferred income tax liabilities and projected future taxable income for this determination. Due to the history of losses in recent years and the continued challenges in the oil and gas industry, management continues to believe that it is more likely than not that we will not be able to realize our net deferred tax assets, and therefore a valuation allowance remains on the net deferred tax asset balance.
We estimate that as of December 31, 2019, 2018 and 2017, we have available $465.3 million, $434.2 million and $373.1 million (after attribute reduction), respectively, of federal net operating loss carryforwards. However, Internal Revenue Code Sections 382 and 383 impose limitations on a corporation’s ability to utilize tax attributes if the corporation experiences an “ownership change.” The Company experienced an ownership change on December 15, 2016, as the emergence of the Company and certain of its domestic subsidiaries from chapter 11 bankruptcy proceedings is considered a change in ownership for purposes of IRC Section 382. With the completion of the Company's Restructuring on March 6, 2020 an ownership change occurred which will cause the Company’s use of remaining U.S. tax attributes may be further limited.
We estimate that as of December 31, 2019, 2018 and 2017, we have available $453.4 million, $429.3 million and $485.6 million, respectively, of state net operating loss carryforwards that will expire between 2020 and 2039. We estimate that we have remaining capital loss carryforward of $73.0 million. Our remaining capital loss carryforwards will expire in 2021.
We are no longer subject examination for tax years before 2015 in federal and most state jurisdictions.
Upon emergence from bankruptcy on December 15, 2016, a substantial portion of the Company’s pre-petition debt securities, revolving credit facility and other obligations were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (“IRC”), provides that a debtor in a bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from chapter 11 bankruptcy proceedings, the estimated amount of U.S. CODI is approximately $295.8 million, which reduced the value of Key’s U.S. net operating losses including federal and state that had a value of $518.8 million as of December 15, 2016. The actual reduction in tax attributes did not occur until the first day of the Company’s tax year subsequent to the date of emergence, or December 16, 2016.
Uncertainty in Income Taxes
As of December 31, 2019, 2018 and 2017, we had zero, zero and $0.1 million, respectively, of unrecognized tax benefits which, if recognized, would impact our effective tax rate. For the years ended December 31, 2019, 2018 and 2017, we recognized a net tax benefit of zero, $0.1 million and $0.3 million, respectively, for statutes of limitations expiration. As of December 31, 2019 our ending balance for uncertain tax position remains at zero, due to the statute of limitations lapse. A reconciliation of the gross change in the unrecognized tax benefits is as follows (in thousands):
Balance at December 31, 2016 | $ | 360 | |
Reductions as a result of a lapse of the applicable statute of limitations | (252 | ) | |
Balance at December 31, 2017 | 108 | ||
Reductions as a result of a lapse of the applicable statute of limitations | (108 | ) | |
Balance at December 31, 2018 | — | ||
Balance at December 31, 2019 | $ | — | |
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 12. LONG-TERM DEBT
The components of our long-term debt as of December 31, 2019 and 2018 are as set forth in the table below (in thousands). Subsequent to the periods presented, this debt was substantially exchanged for shares of our common stock pursuant to the Restructuring. See below for additional information.
December 31, | |||||||
2019 | 2018 | ||||||
Term Loan Facility due 2021 | $ | 243,125 | $ | 245,000 | |||
Unamortized debt issuance costs | (1,799 | ) | (1,421 | ) | |||
Finance lease obligation | 1,600 | — | |||||
Total | 242,926 | 243,579 | |||||
Less current portion | (2,919 | ) | (2,500 | ) | |||
Long-term debt | $ | 240,007 | $ | 241,079 | |||
Prior Long-Term Debt Arrangements
As previously announced, on October 29, 2019, the Company entered into a forbearance agreement (as amended on December 6, 2019, December 20, 2019, January 10, 2020 and January 31, 2020, the “ABL Forbearance Agreement”) with Bank of America, N.A., as administrative agent (the “Administrative Agent”), and all of the lenders party thereto (the “Lenders”) regarding a cross-default under the Loan and Security Agreement, dated as of December 15, 2016, by and among Key, the Administrative Agent and the Lenders.
On February 28, 2020, the Company and the Lenders party thereto amended the ABL Forbearance Agreement (the “Forbearance Agreement Amendment”). Pursuant to the Forbearance Agreement Amendment, the Lenders party thereto have agreed, among other things, to extend the forbearance period until the earliest of (i) March 6, 2020, (ii) the occurrence of certain specified early termination events and (iii) the date on which the previously announced Restructuring Support Agreement between the Company and certain lenders under the Company’s term loan facility is terminated in accordance with its terms. In connection with the forbearance agreement, the Company elected not to make a scheduled interest payments due October 18, 2019 and January 20, 2020 under the Term Loan Facility. The Company’s failure to make these interest payments resulted in a default under the Term Loan Facility and a cross default under the ABL Facility (such defaults, the “Specified Defaults”).
Prior to the Restructuring, the Company was party to two credit facilities. The Company and Key Energy Services, LLC, were borrowers (the “ABL Borrowers”) under an ABL Facility with the financial institutions party thereto from time to time as lenders (the “ABL Lenders”), Bank of America, N.A., as administrative agent for the lenders (the “Administrative Agent”) and Bank of America, N.A., as sole collateral agent for the lenders, providing for aggregate commitments from the ABL Lenders of $100 million (the “Prior ABL Facility”). In addition, on December 15, 2016, the Company entered into the 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 (collectively, the “Term Loan Lenders”) and Cortland Capital Market Services LLC and Cortland Products Corp., as agent for the Lenders (the “Prior Term Loan Facility”).
Effective March 6, 2020 upon the closing of the Restructuring, we entered into the New Term Loan Facility and the New ABL Facility, which superseded the Prior Term Loan Facility and Prior ABL Facility. A description of each of the new and prior facilities follows.
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
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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”).
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
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Key Energy Services, Inc. and Subsidiaries
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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.
Prior ABL Facility
As described above, the Company and Key Energy Services, LLC were borrowers under the Prior ABL Facility that provided for aggregate commitments from the ABL Lenders of $80 million.
On April 5, 2019, the ABL Borrowers, as borrowers, the financial institutions party thereto as lenders and Bank of America, N.A. (the “ABL Agent”), as administrative agent for the lenders, entered into Amendment No. 1 (“Amendment No. 1”) to the Prior ABL Facility, among the ABL Borrowers, the financial institutions party thereto from time to time as lenders, the ABL Agent and the co-collateral agents for the lenders, Bank of America, N.A. and Wells Fargo Bank, National Association. The amendment, among other things, lowered the applicable margin for borrowings to (i) from between 2.50% and 4.50% to between 2.00% and 2.50% for LIBOR borrowings and (ii) from 1.50% and 3.50% to between 1.00% and 1.50% for base rate borrowings. On December 20, 2019, the Company and the Lenders amended the ABL Forbearance Agreement and the Loan Agreement to, among other things, (i) reduce the minimum availability Key is required to maintain under the ABL Forbearance Agreement from $12.5 million to $10 million and (ii) reduce the aggregate revolving commitments under the Loan Agreement from $100 million to $80 million.
The Prior ABL Facility provided 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) $35 million and (y) 25% of the Commitments.
The contractual interest rates under the Prior ABL Facility were, 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 2.50% to 4.50% 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 varied from 1.50% to 3.50% depending on the ABL Borrowers’ fixed charge coverage ratio at such time. In addition, the Prior ABL Facility provided for unused line fees of 1.0% to 1.25% per year, depending on utilization, letter of credit fees and certain other factors.
As of December 31, 2019, we had no borrowings outstanding under the ABL Facility and $34.6 million of letters of credit outstanding with borrowing capacity of $11.9 million available subject to covenant constraints under our ABL Facility.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Prior Term Loan Facility
As described above, the Company and certain subsidiaries were parties to the Prior Term Loan Facility, which had an initial outstanding principal amount of $250 million.
Borrowings under the Prior Term Loan Facility bore interest, at the Company’s option, at a per annum rate equal to (i) LIBOR for one, two, three, six, or, with the consent of the Term Loan Lenders, 12 months, plus 10.25% 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% and (z) 30-day LIBOR, plus 1.0% plus (b) 9.25%.
The weighted average interest rates on the outstanding borrowings under the Prior Term Loan Facility for the year ended December 31, 2019 was as follows:
Year Ended December 31, 2019 | ||
Term Loan Facility | 13.11 | % |
Long-Term Debt Principal Repayment and Interest Expense
Presented below is a schedule of the repayment requirements of long-term debt as of December 31, 2019 (in thousands). Subsequent to December 31, 2019, the debt described below was substantially exchanged for shares of our common stock pursuant to the Restructuring.
Principal Amount of Long-Term Debt | |||
2020 | $ | 2,500 | |
2021 | 240,625 | ||
Total long-term debt | $ | 243,125 | |
Interest expense for the years ended December 31, 2019, 2018 and 2017 consisted of the following (in thousands):
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | |||||||||
Cash payments | $ | 34,129 | $ | 32,718 | $ | 30,397 | |||||
Commitment and agency fees paid | 608 | 969 | 924 | ||||||||
Amortization of deferred financing costs | 433 | 476 | 476 | ||||||||
Leases | 353 | — | — | ||||||||
Net interest expense | $ | 35,523 | $ | 34,163 | $ | 31,797 | |||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Deferred Financing Costs
A summary of deferred financing costs including capitalized costs and amortization are presented in the table below (in thousands):
Balance at December 31, 2016 | $ | 2,023 | |
Capitalized costs | 350 | ||
Amortization | (476 | ) | |
Balance at December 31, 2017 | 1,897 | ||
Capitalized costs | — | ||
Amortization | (476 | ) | |
Balance at December 31, 2018 | 1,421 | ||
Capitalized costs | 811 | ||
Amortization | (433 | ) | |
Balance at December 31, 2019 | $ | 1,799 | |
NOTE 13. COMMITMENTS AND CONTINGENCIES
Operating Lease Arrangements
We lease certain property and equipment under non-cancelable operating leases that expire at various dates through 2030, with varying payment dates throughout each month. In addition, we have a number of leases scheduled to expire during 2020.
As of December 31, 2019, the future minimum lease payments under non-cancelable operating leases are as follows (in thousands):
Lease Payments | |||
2020 | $ | 5,013 | |
2021 | 3,358 | ||
2022 | 1,934 | ||
2023 | 1,868 | ||
2024 | 1,489 | ||
Thereafter | 1,311 | ||
Total | $ | 14,973 | |
We are also party to a significant number of month-to-month leases that can be cancelled at any time. Operating lease expenses were $4.6 million, $4.8 million and $6.4 million for the years ended December 31, 2019, 2018 and 2017, respectively.
Litigation
Various suits and claims arising in the ordinary course of business are pending against us. We conduct business throughout the continental United States and may be subject to jury verdicts or arbitrations that result in outcomes in favor of the plaintiffs. We continually assess our contingent liabilities, including potential litigation liabilities, as well as the adequacy of our accruals and the need for disclosure of these items, if any. We establish a provision for a contingent liability when it is probable that a liability has been incurred and the amount is reasonably estimable. As of December 31, 2019, the aggregate amount of our liabilities related to litigation that are deemed probable and reasonably estimable is $7.0 million. We do not believe that the disposition of any of these matters will result in an additional loss materially in excess of amounts that have been recorded. Our liabilities related to litigation matters that were deemed probable and reasonably estimable as of December 31, 2018 were $4.4 million.
Tax Audits
We are routinely the subject of audits by tax authorities, and in the past have received material assessments from tax auditors. As of December 31, 2019 and 2018, we have recorded reserves that management feels are appropriate for future potential liabilities as a result of prior audits. While we believe we have fully reserved for these assessments, the ultimate amount of settlements can vary from our estimates.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Self-Insurance Reserves
We maintain reserves for workers’ compensation and vehicle liability on our balance sheet based on our judgment and estimates using an actuarial method based on claims incurred. We estimate general liability claims on a case-by-case basis. We maintain insurance policies for workers’ compensation, vehicular liability and general liability claims. These insurance policies carry self-insured retention limits or deductibles on a per occurrence basis. The retention limits or deductibles are accounted for in our accrual process for all workers’ compensation, vehicular liability and general liability claims. The deductibles have a $5 million maximum per vehicular liability claim, and a $2 million maximum per general liability claim and a $1 million maximum per workers’ compensation claim. As of December 31, 2019 and 2018, we have recorded $51.4 million and $50.1 million, respectively, of self-insurance reserves related to workers’ compensation, vehicular liabilities and general liability claims. Partially offsetting these liabilities, we had approximately $13.4 million and $13.1 million of insurance receivables as of December 31, 2019 and 2018, respectively. We believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued for existing claims.
Environmental Remediation Liabilities
For environmental reserve matters, including remediation efforts for current locations and those relating to previously-disposed properties, we record liabilities when our remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated. As of December 31, 2019 and 2018, we have recorded $2.0 million and $2.2 million, respectively, for our environmental remediation liabilities. We believe that the liabilities we have recorded are appropriate based on the known facts and circumstances and do not expect further losses materially in excess of the amounts already accrued.
We provide performance bonds to provide financial surety assurances for the remediation and maintenance of our SWD properties to comply with environmental protection standards. Costs for SWD properties may be mandatory (to comply with applicable laws and regulations), in the future (required to divest or cease operations), or for optimization (to improve operations, but not for safety or regulatory compliance).
NOTE 14. EMPLOYEE BENEFIT PLANS
We maintain a 401(k) plan as part of our employee benefits package. In the third quarter of 2015, management suspended the 401(k) matching program as part of our cost cutting efforts. The 401(k) matching program was reinstated January 1, 2019, pursuant to which we matched 100% of employee contributions up to 4% of the employee’s salary, which vest immediately, into our 401(k) plan, subject to maximums of $11,200, $11,000 and $10,800 for the years ended December 31, 2019, 2018 and 2017, respectively. Our matching contributions were $4.5 million, zero and zero for the years ended December 31, 2019, 2018 and 2017, respectively. We do not offer participants the option to purchase shares of our common stock through a 401(k) plan fund.
NOTE 15. STOCKHOLDERS’ EQUITY
Preferred Stock
As of December 31, 2019, we had 10,000,000 shares of preferred stock authorized with a par value of $0.50 per share. As of December 31, 2019, the sole share of the Company’s Series A Preferred Stock, which conferred certain rights to elect directors (but has no economic rights), was held by Soter. Subsequent to December 31, 2019, in connection with the completion of the Restructuring, the share of Series A Preferred Stock was redeemed and cancelled for no consideration and the Series A Preferred Stock was eliminated from our certificate of incorporation.
Common Stock
As of December 31, 2019 and December 31, 2018, we had 2,000,000 shares of common stock authorized of which 410,990 and 407,264 shares were issued and outstanding, respectively. Subsequent to December 31, 2019, in connection with the completion of the Restructuring, we increased the number of shares of common stock authorized to 150,000,000 and 13,775,267 shares were issued and outstanding, after giving effect to the 1-for-50 reverse stock split, as of the closing of the Restructuring. During 2019, 2018 and 2017, no dividends were declared or paid and we currently do not intend to pay dividends.
Tax Withholding
We repurchase shares of restricted common stock that have been previously granted to certain of our employees, pursuant to an agreement under which those individuals are permitted to sell shares back to us in order to satisfy the minimum income tax withholding requirements related to vesting of these grants. We repurchased a total of 826 shares, 968 shares and 1,127 shares for an aggregate cost of less than $0.1 million, $0.3 million, $0.7 million during the years ended December 31, 2019, 2018 and 2017, respectively, which represented the fair market value of the shares based on the price of our stock on the dates of purchase.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
NOTE 16. SHARE-BASED COMPENSATION
Equity and Cash Incentive Plan
On May 1, 2019, our stockholders approved the 2019 Equity and Cash Incentive Plan (the “2019 Incentive Plan”). The 2019 Incentive Plan was established as a successor incentive compensation plan to the 2016 (the “2016 Incentive Plan”) and provide the Company with an omnibus plan under which the Company may continue to design and structure awards of restricted stock, restricted stock units, options, stock appreciation rights and cash-based awards, for distribution to officers, directors and employees of the Company and its subsidiaries as determined by the Board. The Board or an authorized committee thereof is authorized, without further approval of Key equity holders, to execute and deliver all agreements, documents, instruments and certificates relating to the 2019 Incentive Plan and to perform their obligations thereunder in accordance with, and subject to, the terms of the 2019 Incentive Plan.
On March 6, 2020, the Board approved an amendment and restatement of the 2019 Incentive Plan to, among other things, reserve 1,239,775 shares of our common stock for the grant of awards under the plan following the closing of the Restructuring, in addition to any shares remaining available for grant under the 2016 Plan and any additional shares that become available for grant due to the termination, expiration, forfeiture, cancellation, or cash settlement of awards.
Stock Option Awards
Stock option awards granted under our 2016 Incentive Plans have a maximum contractual term of ten years from the date of grant. Shares issuable upon exercise of a stock option are issued from authorized but unissued shares of our common stock.
The following tables summarize the stock option activity for the year ended December 31, 2019 (shares in thousands):
Year Ended December 31, 2019 | ||||||||||
Options | Weighted Average Exercise Price | Weighted Average Fair Value | ||||||||
Outstanding at beginning of period | 1.48 | $ | 1,746.00 | $ | 541.00 | |||||
Granted | — | $ | — | $ | — | |||||
Exercised | — | $ | — | $ | — | |||||
Cancelled or expired | (0.40 | ) | $ | 1,912.32 | $ | 666.47 | ||||
Outstanding at end of period | 1.08 | $ | 1,683.50 | $ | 493.79 | |||||
Exercisable at end of period | 1.08 | $ | 1,683.50 | $ | 493.79 | |||||
No stock options were granted or exercised for the year ended December 31, 2019. The total fair value of stock options vested during the year ended December 31, 2019, 2018 and 2017 was zero, zero and $1.7 million, respectively. For the years ended December 31, 2019, 2018 and 2017, we recognized zero, zero and $1.8 million of pre-tax expenses related to stock options, respectively. All outstanding stock options are vested as of December 31, 2019. The weighted average remaining contractual term for stock option awards exercisable as of December 31, 2019 is 7.0 years.
Common Stock Awards
Our common stock awards under our 2019 and 2016 Incentive Plans include restricted stock awards and restricted stock units. The weighted average grant date fair market value of all common stock awards granted during the years ended December 31, 2019, 2018 and 2017 were $111.84, $687.00 and $618.50, respectively. The total fair market value of all common stock awards vested during the years ended December 31, 2019, 2018 and 2017 were $2.0 million, $2.3 million, $6.2 million, respectively.
The following tables summarize information for the year ended December 31, 2019 about our unvested common stock awards that we have outstanding (shares in thousands):
Year Ended December 31, 2019 | ||||||
Outstanding | Weighted Average Issuance Price | |||||
Shares at beginning of period | 14.58 | $ | 626.00 | |||
Granted | 28.44 | $ | 111.84 | |||
Vested | (4.55 | ) | $ | 447.13 | ||
Cancelled | (24.55 | ) | $ | 285.38 | ||
Shares at end of period | 13.92 | $ | 235.03 | |||
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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. We recognize compensation expense ratably over the graded vesting period of the grant, net of forfeitures.
For the years ended December 31, 2019, 2018 and 2017, we recognized $0.7 million, $5.9 million and $5.7 million, respectively, of pre-tax expenses from continuing operations associated with common stock awards. For the unvested common stock awards outstanding as of December 31, 2019, we anticipate that we will recognize $1.0 million of pre-tax expense over the next 0.9 years weighted average years.
Phantom Share Plan
In December 2017, we implemented a “Phantom Share Plan,” in which certain of our employees were granted “Phantom Shares.” Phantom Shares vest ratably over a three-year period and convey the right to the grantee to receive a cash payment on the anniversary date of the grant equal to the fair market value of the Phantom Shares vesting on that date. Grantees are not permitted to defer this payment to a later date. The Phantom Shares are a “liability” type award and we account for these awards at fair value. We recognize compensation expense related to the Phantom Shares based on the change in the fair value of the awards during the period and the percentage of the service requirement that has been performed, net of forfeitures, with an offsetting liability recorded on our consolidated balance sheets.
For the years ended December 31, 2019, 2018 and 2017, we recognized less than $0.1 million, $0.3 million and zero, respectively, of pre-tax expenses from continuing operations associated with phantom share awards. For the unvested phantom share awards outstanding as of December 31, 2019, we anticipate that we will recognize zero of pre-tax expense over the next 1 weighted average year.
NOTE 17. TRANSACTIONS WITH RELATED PARTIES
The Company has purchased or sold equipment or services from a few affiliates of certain directors. Additionally, the Company was previously party to a corporate advisory services agreement with Platinum Equity Advisors, LLC (“Platinum”) pursuant to which Platinum provided certain business advisory services to the Company. The corporate advisory services agreement expired in 2019. The dollar amounts related to these related party activities are not material to the Company’s condensed consolidated financial statements.
The Company is also party to the Stockholders Agreement with the Supporting Term Lenders who are also lenders under our New Term Loan Facility.
NOTE 18. SUPPLEMENTAL CASH FLOW INFORMATION
Presented below is a schedule of noncash investing and financing activities and supplemental cash flow entries (in thousands):
Year Ended December 31, 2019 | Year Ended December 31, 2018 | Year Ended December 31, 2017 | |||||||||
Supplemental cash flow information: | |||||||||||
Cash paid for interest | $ | 34,129 | $ | 32,718 | $ | 30,397 | |||||
Cash paid for taxes | 284 | 40 | — | ||||||||
Tax refunds | 6,208 | 1,097 | — | ||||||||
Cash paid for interest includes cash payments for interest on our long-term debt and finance lease obligations, and commitment and agency fees paid.
NOTE 19. SEGMENT INFORMATION
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, Fishing and
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Rental Services, Coiled Tubing Services, Fluid Management Services operate geographically within the United States. 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. We evaluate the performance of our segments based on gross margin measures. All inter-segment sales pricing is based on current market conditions. We aggregate services that create our reportable segments in accordance with ASC 280, and the accounting policies for our segments are the same as those described in “Note 1. Organization and Summary of Significant Accounting Policies” above.
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 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.
Fishing and Rental Services
We offer a full line of services and rental equipment designed for use in providing 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, 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 business were sold in the second quarter of 2017.
Demand for our Fishing and Rental Services is closely related to capital spending by oil and natural gas producers, which is generally driven by oil and natural gas prices.
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 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.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 SWD wells owned by us or a third party. In addition, we operate a fleet of hot oilers capable of pumping heated fluids used to clear soluble restrictions in a wellbore. Demand and pricing for these services generally correspond to demand for our well service rigs.
International
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
Our Functional Support segment includes unallocated overhead costs associated with administrative support for our U.S. and International reporting segments.
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Financial Summary
The following table presents our segment information as of and for the years ended December 31, 2019, 2018 and 2017 (in thousands):
As of and for the year ended December 31, 2019
Rig Services | Fishing and Rental Services | Coiled Tubing Services | Fluid Management Services | Functional Support(2) | Reconciling Eliminations | Total | |||||||||||||||||||||
Revenues from external customers | $ | 250,532 | $ | 54,511 | $ | 37,964 | $ | 70,847 | $ | — | $ | — | $ | 413,854 | |||||||||||||
Intersegment revenues | 478 | 1,623 | — | 147 | — | (2,248 | ) | — | |||||||||||||||||||
Depreciation and amortization | 24,037 | 16,212 | 5,276 | 8,856 | 2,588 | — | 56,969 | ||||||||||||||||||||
Other operating expenses | 210,633 | 45,782 | 36,529 | 61,578 | 70,249 | — | 424,771 | ||||||||||||||||||||
Operating income (loss) | 15,862 | (7,483 | ) | (3,841 | ) | 413 | (72,837 | ) | — | (67,886 | ) | ||||||||||||||||
Interest expense, net of amounts capitalized | 105 | 27 | 55 | 45 | 35,291 | — | 35,523 | ||||||||||||||||||||
Income (loss) before taxes | 15,817 | (7,497 | ) | (3,893 | ) | 390 | (106,210 | ) | — | (101,393 | ) | ||||||||||||||||
Long-lived assets(1) | 118,013 | 37,915 | 16,443 | 44,607 | 28,957 | 343 | 246,278 | ||||||||||||||||||||
Total assets | 156,552 | 48,142 | 22,523 | 54,927 | 55,957 | 9,769 | 347,870 | ||||||||||||||||||||
Capital expenditures | 4,237 | 2,801 | 4,494 | 2,146 | 4,624 | — | 18,302 | ||||||||||||||||||||
As of and for the year ended December 31, 2018
Rig Services | Fishing and Rental Services | Coiled Tubing Services | Fluid Management Services | Functional Support | Reconciling Eliminations | Total | |||||||||||||||||||||
Revenues from external customers | $ | 296,969 | $ | 64,691 | $ | 71,013 | $ | 89,022 | $ | — | $ | — | $ | 521,695 | |||||||||||||
Intersegment revenues | 710 | 2,465 | 48 | 1,101 | — | (4,324 | ) | — | |||||||||||||||||||
Depreciation and amortization | 31,519 | 23,361 | 5,223 | 20,091 | 2,445 | — | 82,639 | ||||||||||||||||||||
Other operating expenses | 245,898 | 49,983 | 60,594 | 77,781 | 63,766 | — | 498,022 | ||||||||||||||||||||
Operating income (loss) | 19,552 | (8,653 | ) | 5,196 | (8,850 | ) | (66,211 | ) | — | (58,966 | ) | ||||||||||||||||
Interest expense, net of amounts capitalized | — | — | — | — | 34,163 | — | 34,163 | ||||||||||||||||||||
Income (loss) before taxes | 19,689 | (8,622 | ) | 5,201 | (8,773 | ) | (98,270 | ) | — | (90,775 | ) | ||||||||||||||||
Long-lived assets(1) | 141,469 | 50,629 | 17,274 | 55,263 | 19,637 | 404 | 284,676 | ||||||||||||||||||||
Total assets | 192,376 | 65,711 | 27,283 | 70,003 | 80,507 | 7,294 | 443,174 | ||||||||||||||||||||
Capital expenditures | 18,126 | 3,671 | 4,872 | 2,907 | 7,959 | — | 37,535 | ||||||||||||||||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
As of and for the year ended December 31, 2017
Rig Services | Fishing and Rental Services | Coiled Tubing Services | Fluid Management Services | International | Functional Support | Reconciling Eliminations | Total | ||||||||||||||||||||||||
Revenues from external customers | $ | 248,830 | $ | 59,172 | $ | 41,866 | $ | 80,726 | $ | 5,571 | $ | — | $ | — | $ | 436,165 | |||||||||||||||
Intersegment revenues | 325 | 3,181 | 60 | 1,218 | — | — | (4,784 | ) | — | ||||||||||||||||||||||
Depreciation and amortization | 31,493 | 23,454 | 5,187 | 21,917 | 791 | 1,700 | — | 84,542 | |||||||||||||||||||||||
Impairment expense | — | — | — | — | 187 | — | — | 187 | |||||||||||||||||||||||
Other operating expenses | 220,957 | 28,212 | 35,048 | 78,341 | 9,586 | 75,472 | — | 447,616 | |||||||||||||||||||||||
Operating income (loss) | (3,620 | ) | 7,506 | 1,631 | (19,532 | ) | (4,993 | ) | (77,172 | ) | — | (96,180 | ) | ||||||||||||||||||
Reorganization items, net | — | — | — | — | — | 1,501 | — | 1,501 | |||||||||||||||||||||||
Interest expense, net of amounts capitalized | — | — | — | — | — | 31,797 | — | 31,797 | |||||||||||||||||||||||
Income (loss) before taxes | (3,449 | ) | 7,748 | 1,643 | (19,537 | ) | (298 | ) | (108,398 | ) | — | (122,291 | ) | ||||||||||||||||||
Long-lived assets(1) | 160,170 | 63,340 | 19,064 | 74,591 | 7 | 122,965 | (97,819 | ) | 342,318 | ||||||||||||||||||||||
Total assets | 287,856 | 360,581 | 41,523 | (985 | ) | 9,473 | 513,393 | (682,720 | ) | 529,121 | |||||||||||||||||||||
Capital expenditures | 8,375 | 741 | 886 | 3,288 | 475 | 2,314 | — | 16,079 | |||||||||||||||||||||||
(1) | Long-lived assets include: fixed assets, goodwill, intangibles and other assets. |
NOTE 20. UNAUDITED QUARTERLY RESULTS OF OPERATIONS
The following table presents our summarized, unaudited quarterly information for the two most recent years covered by these consolidated financial statements (in thousands, except for per share data):
Quarter Ended | |||||||||||||||
March 31 | June 30 | September 30 | December 31 | ||||||||||||
Year Ended December 31, 2019: | |||||||||||||||
Revenues | $ | 109,273 | $ | 112,943 | $ | 106,523 | $ | 85,115 | |||||||
Direct operating expenses | 88,194 | 90,564 | 87,956 | 66,748 | |||||||||||
Net loss | (23,441 | ) | (18,303 | ) | (25,489 | ) | (30,185 | ) | |||||||
Loss per share(1): | |||||||||||||||
Basic and diluted | (57.59 | ) | (44.86 | ) | (62.32 | ) | (73.62 | ) | |||||||
Quarter Ended | |||||||||||||||
March 31 | June 30 | September 30 | December 31 | ||||||||||||
Year Ended December 31, 2018: | |||||||||||||||
Revenues | $ | 125,316 | $ | 144,405 | $ | 134,721 | $ | 117,253 | |||||||
Direct operating expenses | 98,211 | 109,747 | 106,103 | 92,335 | |||||||||||
Net loss | (24,963 | ) | (16,895 | ) | (23,860 | ) | (23,078 | ) | |||||||
Loss per share(1): | |||||||||||||||
Basic and Diluted | (61.79 | ) | (41.72 | ) | (58.91 | ) | 56.84 | ||||||||
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(1) | Quarterly earnings per common share are based on the weighted average number of shares outstanding during the quarter, and the sum of the quarters may not equal annual earnings per common share. |
NOTE 21. LEASES
We have operating leases for certain corporate offices and operating locations and finance leases for certain vehicles. We determine if a contract is a lease or contains an embedded lease at the inception of the contract. Operating lease right-of-use (“ROU”) assets are included in other current and other non-current assets, operating lease liabilities are included in other current and other non-current liabilities in our consolidated balance sheets. Finance lease ROU assets are included in property and equipment, net, and finance lease liabilities are included in our current portion of long-term debt, and long-term debt on our consolidated balance sheets.
ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating and finance lease ROU assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. As most of our leases do not provide an implicit rate, we use our risk adjusted incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. We use the implicit rate when readily determinable. Our lease terms may include options to extend or terminate the lease. Our leases have remaining lease terms of less than one year to five years, some of which include options to extend the leases for up to five years, and some of which include options to terminate the leases within one year. Lease expense for lease payments is recognized on a straight-line basis over the non-cancelable term of the lease.
We recognized $3 million of costs related to our operating leases during the twelve months ended December 31, 2019. As of December 31, 2019, our operating leases have a weighted average remaining lease term of 2.6 years and a weighted average discount rate of 5.88%. We recognized $0.2 million of costs related to our finance leases during the twelve months ended December 31, 2019. As of December 31, 2019, our finance leases have a weighted average remaining lease term of 3.6 years and a weighted average discount rate of 4.77%.
Supplemental balance sheet information related to leases as of December 31, 2019 are as follows (in thousands):
December 31, 2019 | |||
Right-of-Use Assets under Operating Leases | |||
Operating lease right-of-use assets, current portion | $ | 2,394 | |
Operating lease right-of-use assets, non-current portion | 2,404 | ||
Total operating lease assets | $ | 4,798 | |
Operating lease liabilities, current portion | $ | 2,502 | |
Operating lease liabilities, non-current portion | 2,590 | ||
Total operating lease liabilities | $ | 5,092 | |
Right-of-Use Assets under Finance Leases | |||
Property and equipment, at cost | $ | 1,760 | |
Less accumulated depreciation | 183 | ||
Property and equipment, net | $ | 1,577 | |
Current portion of long-term debt | $ | 419 | |
Long-term debt | 1,181 | ||
Total finance lease liabilities | $ | 1,600 | |
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Key Energy Services, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The maturities of our operating and finance lease liabilities as of December 31, 2019 are as follows (in thousands):
December 31, 2019 | |||||||
Operating Leases | Finance Leases | ||||||
2020 | $ | 2,719 | $ | 485 | |||
2021 | 1,552 | 485 | |||||
2022 | 519 | 485 | |||||
2023 | 493 | 282 | |||||
2024 | 188 | — | |||||
Total lease payments | 5,471 | 1,737 | |||||
Less imputed interest | (379 | ) | (137 | ) | |||
Total | $ | 5,092 | $ | 1,600 | |||
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We maintain a set of disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, our principal executive and financial officers have concluded that our disclosure controls and procedures were effective as of the end of such period.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting. 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. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting can also be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. 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. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.
A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.
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Management conducted an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria described in 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2019.
Our internal control over financial reporting has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report included herein.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during our last fiscal quarter of 2019, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
In connection with the Restructuring, on March 10, 2020 the Company amended and restated its 2019 Equity and Cash Incentive Plan (the “2019 ECIP” and, as amended and restated, the “MIP”) and approved a form of restricted stock unit award agreement to be used for grants thereunder following the closing of the Restructuring (the “MIP Award Agreement”). The MIP Award Agreement provides that fifty percent (50%) of the restricted stock units underlying each award will be subject to time-vesting conditions, and will vest in equal annual installments on the first three anniversaries of the date of grant. The remaining fifty percent (50%) of the restricted stock units underlying the award will be subject to performance-vesting conditions, to be earned and vested over each of three annual performance periods following the date of grant, subject to the achievement of specified performance goals determined by the Board.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Board of Directors
As a result of the Company’s Restructuring pursuant to the RSA and the Company’s Amended and Restated Certificate of Incorporation, our seven-member Board consists of our interim chief executive officer and six other directors appointed by various Supporting Term Lenders pursuant to the RSA and the Stockholders Agreement. These directors will serve for a term that commenced March 6, 2020 and will conclude upon the election of directors at the 2021 annual stockholders meeting or until their successors have been duly elected and qualified. Accordingly, due to the closing of the Restructuring, the Company does not expect to hold an annual meeting of stockholders at which directors will be elected to the Company’s Board until 2021, at which time the Company will also conduct the next “say-on-pay” and “say-on-frequency” votes with respect to the compensation of the Company’s named executive officers.
Below is the name, age and certain other information with respect to each member of our Board, including information regarding the positions each director holds, his or her principal occupation and business experience for the past five years and the names of other publicly held companies for which he or she currently serves as a director or has served as a director during the past five years. In addition to the information presented below regarding each director’s specific experience, qualifications, attributes and skills that led our Board to the conclusion that he or she should serve as a director, we also believe that all of our directors exhibit high standards of integrity, honesty and ethical values.
J. Marshall Dodson, age 48. Mr. Dodson has served on the Board since March 6, 2020. Mr. Dodson is Key’s Senior Vice President, Interim Chief Executive Officer, Chief Financial Officer and Treasurer. Mr. Dodson joined Key as Vice President and Chief Accounting Officer on August 22, 2005 and served in that capacity until being appointed Vice President and Treasurer on June 8, 2009. From February 6, 2009, until March 26, 2009, Mr. Dodson served in the additional capacity as interim principal financial officer and was appointed Senior Vice President and Chief Financial Officer on March 25, 2013. From May 11, 2018 to August 20, 2018, Mr. Dodson served as Senior Vice President, Interim Chief Executive Officer, Chief Financial Officer & Treasurer and then from August 2018, Mr. Dodson served as Senior Vice President, Chief Financial Officer & Treasurer until he was appointed Senior Vice President, Interim Chief Executive Officer, Chief Financial Officer & Treasurer on December 30, 2019. Prior to joining Key, Mr. Dodson served in various capacities at Dynegy, Inc., an electric energy production and services company, from 2002 to August 2005, most recently serving as Managing Director and Controller, Dynegy Generation since 2003. Mr. Dodson started his career with Arthur Andersen LLP in Houston, Texas in 1993, serving most recently as a senior manager prior to joining Dynegy, Inc. Mr. Dodson received a BBA from the University of Texas at Austin in 1993. Mr. Dodson also served as a director for Enduro Resource Partners LLC, a private exploration and production company from November 2017 until July 2018. Mr. Dodson’s
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extensive industry experience, deep knowledge of our business and our customers and financial expertise qualifies him to serve on our Board and lead our management team.
Jacob Kotzubei, age 51. Mr. Kotzubei has served as a director for the Company since December 15, 2016. Mr. Kotzubei joined Platinum Equity in 2002 and is a Partner at the firm and a member of the firm’s Investment Committee. Mr. Kotzubei serves as an officer and/or director of a number of Platinum’s portfolio companies. Prior to joining Platinum in 2002, Mr. Kotzubei worked for the Goldman Sachs Investment Banking Division in New York City from 1998 to 2002. Previously, he was an attorney at Sullivan & Cromwell LLP in New York City, specializing in mergers and acquisitions. Mr. Kotzubei received a Bachelor’s degree from Wesleyan University and holds a Juris Doctor from Columbia University School of Law where he was elected a member of the Columbia Law Review. Mr. Kotzubei is also currently a director of Ryerson Holdings Corporation (“Ryerson), a metal supplier and fabricating company and Kemet Corporation, a global manufacturer of passive electronic components, Vertiv Corporation, a global manufacturer of critical digital infrastructure equipment, and is the Chairman of the Board of Verra Mobility Corp., a provider of smart traffic solutions. Mr. Kotzubei served as a director of CanWel Building Materials Group until April 11, 2016. Mr. Kotzubei’s experience in executive management oversight, private equity, capital markets and transactional matters has led the Board to conclude that he has the varied expertise necessary to serve as a director of the Company.
Alan B. Menkes, age 60. Mr. Menkes has served as a director of the Company since March 6, 2020. Mr. Menkes has been a private equity investor for over 30 years and is currently the Managing Partner of Empeiria Capital Partners, a private equity firm that he co-founded in 2002. From 2011 to 2012, he was the CEO of Empeiria Acquisition Corp., a special purpose acquisition company that closed its merger with an operating company in December 2012 and was subsequently renamed Integrated Drilling Equipment Holdings Corp, a publicly traded company. From 2009-2010 he was affiliated with G2 Investment Group LLC, a diversified asset management firm. From 2007-2008, Mr. Menkes was a Partner of Enterprise Infrastructure Ventures, a real estate investment firm, and the Chief Strategic and Investment Officer of CS Technology, an affiliate of Enterprise Infrastructure Ventures. Prior to founding Empeiria, from December 1998 through February 2002, Mr. Menkes was Co-Director of Private Equity and a member of the Executive Committee of Thomas Weisel Partners. Prior to that, Mr. Menkes was a Partner of Hicks, Muse, Tate & Furst, where he was employed for almost seven years. Mr. Menkes was with The Carlyle Group from its founding in 1987 to 1992. Mr. Menkes currently serves on the Boards of Directors of SAExploration Holdings, a publicly traded company, PLH Group and Empeiria BBRSS Holdings LLC. Mr. Menkes earned a B.A. in Economics with Highest Distinction from the University of Virginia in 1980 and a M.B.A. with Distinction from the Wharton School at the University of Pennsylvania in 1982. The Company believes that Mr. Menkes is qualified to serve on the Board based on his significant investment and leadership skills and board experience.
Marcus C. Rowland, age 67. Mr. Rowland has served as a director of the Company since March 6, 2020. Mr. Rowland is currently the Senior Managing Director and founding partner of IOG Capital, LP, an oil and gas investment company and is the Chairman of the Board of Silverbow Resources, Inc. and Interim Chairman of the Board for Chaparral Energy, Inc. He is also on the board of Mitcham Industries. Previously, Mr. Rowland served as the Chief Executive Officer at FTS International, Inc. (formally Frac Tech International, LLC). He served as the President and Chief Financial Officer of Frac Tech Services, LLC and Frac Tech International, LLC from November 2010 to May 2011. Mr. Rowland is the former Executive Vice President and Chief Financial Officer of Chesapeake Energy Corporation, where he worked for 18 years in roles of increasing levels of responsibility. Mr. Rowland served as Chief Operating Officer of Anglo-Suisse, LP from 1990 to 1993, assigned to the White Nights Russian Enterprise, a joint venture of Anglo-Suisse, LP and Phibro Energy Corporation, a major foreign operation which was granted the right to engage in oil and gas operations in Russia. Mr. Rowland holds a Bachelor’s degree from Wichita State University, is a 1975 alumnus of Wichita State University and serves on the Wichita State University Foundation Investment Committee and the National Advisory Council. Our Board believes that Mr. Rowland’s operational and financial experience in various senior management positions and his experience as a director of a public company enable him to effectively serve as a director.
Harry F. Quarls, age 68. Mr. Quarls has served as Chairman of the Board of Directors for the Company since March 6, 2020. Mr. Quarls currently serves as a director for Rosehill Resources, PetroQuest Energy and chairman of the board for Sunrise Oil & Gas. Mr. Quarls previously served as chairman of the board for Penn Virginia Corporation, SH 130 Concessions Company, Trident Resources Corp, Woodbine Acquisition Corp and US Oil Sands Corp. Mr. Quarls also served as a director and chairman of the strategic alternatives committee for Gastar Exploration Inc. and as a director for Fairway Resources and Opal Resources. Mr. Quarls served as a Managing Director at Global Infrastructure Partners retiring after over a decade of service. Additionally, Mr. Quarls served as Managing Director and practice leader for Global Energy, as well as a member of the board of directors at Booz & Company, a leading international management consulting firm. Mr. Quarls earned an M.B.A. from Stanford University and holds ScM and B.S. degrees, both in chemical engineering, from M.I.T. and Tulane University, respectively. Mr Quarls’ broad knowledge on the energy industry, experience in energy investing, as well as experience on the boards of public and private energy companies led the Board to conclude that he has the expertise necessary to serve as a director of the Company.
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Sherman K. Edmiston III, age 57. Mr. Edmiston has served on the Board since December 15, 2016. Mr. Edmiston is a senior restructuring executive and has over 25 years of experience working with companies undergoing transformation. From 2016 Mr. Edmiston has served as the Managing Member of HI CapM Advisors, Ltd., a consulting firm that provides strategic and financial advisory services to private equity funds, hedge funds, asset managers and corporations. Mr. Edmiston was a Partner and Managing Director at Zolfo Cooper LLC from November 2009 until December 2015. Mr. Edmiston served as Chief Restructuring Officer of Xinergy, Ltd, a Central Appalachian producer of thermal and metallurgical coal, and previously served as Chairman of the Finance and Transaction committee of JL French Automotive Castings, Inc. Mr. Edmiston currently serves on the board of directors of Arch Coal, Inc, a publicly traded American coal mining and processing company. Mr. Edmiston received his B.S. in mechanical Engineering from Arizona State University and his MBA from the University of Michigan. Mr. Edmiston’s expertise in strategic planning, finance and board leadership and his experience as a director of other public companies, including those undergoing significant transitions as well as his qualification as an “audit committee financial expert”, led the Board to conclude that he has the expertise necessary to serve as a director of the Company.
H.H. “Tripp” Wommack, III, age 64. Mr. Wommack has served on the Board since December 15, 2016. Mr. Wommack is currently the Chairman, President and Chief Executive Officer of Anchor Energy Resources, LLC, an oil and gas company that focuses on acquisition and exploration efforts in the Permian Basin of West Texas and Southeast New Mexico. Mr. Wommack has served in this position since July 2016. Mr. Wommack is also currently Chairman, President and CEO of Velocity Financial, LLC, a Midland, Texas based Factoring company. Mr. Wommack has served in this position since January 2019. In addition, Mr. Wommack serves as the Chairman of Cibolo Creek Partners, LLC, which specializes in commercial real estate investments, a position he has held since January 1993. Mr. Wommack also serves as Chairman, CEO, and President of Warrior Technologies, LLC, which is involved in tank bottom cleaning in the Permian Basin of West Texas and Southeastern New Mexico. Mr. Wommack previously served as Chairman, President and Chief Executive Officer of Southwest Royalties, Inc. from August 1983 to August 2004 and Saber Resources from July 2004 until August 2008. Additionally, Mr. Wommack served on the board of directors of C&J Energy Services, Inc. from March 2015 through December 2016. Mr. Wommack was the founder, Chairman and Chief Executive Officer of Basic Energy Services (formerly Sierra Well Services, Inc.), and following its initial public offering, Mr. Wommack continued to serve on the board of directors of Basic Energy Services through June 2009. Mr. Wommack graduated with a B.A. from the University of North Carolina, Chapel Hill, and earned a J.D. from the University of Texas. Mr. Wommack was selected as a director because of his extensive executive-level management experience and proven leadership and business capabilities in the oil and gas industry and his qualification as an "audit committee financial expert". Additionally, Mr. Wommack’s knowledge and experience from serving as chairman and chief executive officer of a company that went through an initial public offering adds a unique and valuable perspective to the Company.
General
This section describes our principal corporate governance guidelines and practices. Complete copies of our Corporate Governance Guidelines, committee charters and codes of business conduct described below are available on our website at www.keyenergy.com. You can also request a copy of any of these documents by writing to: Investor Relations, Key Energy Services, Inc., 1301 McKinney Street, Suite 1800, Houston, Texas 77010. Our Board strongly believes that good corporate governance is important to ensure that Key is managed for the long-term benefit of our stockholders.
Corporate Governance Guidelines
Our Board has adopted the Corporate Governance Guidelines, which address significant issues of corporate governance and set forth the procedures by which the Board carries out its responsibilities. Among the areas addressed by the Corporate Governance Guidelines are director qualifications and responsibilities, Board committee responsibilities, director compensation and tenure, director orientation and continuing education, access to management and independent advisors, succession planning and management development, and Board and committee performance evaluations. The nominating and governance committee (the “NGC”) is responsible for assessing and periodically reviewing the adequacy of these guidelines and recommending proposed changes to the Board, as appropriate. The Corporate Governance Guidelines are posted on our website at www.keyenergy.com. We will provide these guidelines in print, free of charge, to stockholders who request them.
Director Independence
Currently, our common stock is not listed on a national securities exchange and accordingly we are not subject to the board independence requirements of any national securities exchange. Nonetheless, each year our Board assesses director independence on a case-by-case basis, in each case consistent with the applicable rules and regulations of the NYSE and the Securities and Exchange Commission (the “SEC”). The NYSE rules require listed companies to have a board of directors with at least a majority of independent directors. Additionally, each of the Audit Committee and Nominating, Governance and Compensation Committee are required to be comprised solely of independent directors, as that term is defined by the applicable
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rules and regulations of the NYSE and SEC. After reviewing all relationships each director may have directly and indirectly with the Company and its management, our Board has affirmatively determined that each of Messrs. Quarls, Rowland, Menkes, Edmiston and Wommack has no material relationships with the Company and, therefore, is “independent” as defined under NYSE rules. Mr. Dodson, our Senior Vice President and Interim Chief Executive Officer, Chief Financial Officer & Treasurer President, is not considered to be “independent” because of his employment position with the Company. Mr. Kotzubei is not considered to be “independent” due to his employment relationship with an affiliate of Soter. In addition, each of Messrs. Rowland, Edmiston and Wommack have been affirmatively determined by the Board to be independent under SEC Rule 10A-3 and NYSE listing standards applicable to Audit Committee service. Moreover, each of Messrs. Edmiston, Quarls and Menkes have been affirmatively determined by the Board to be independent under SEC rules and NYSE listing applicable to Nominating, Governance and Compensation Committee service.
Board Leadership Structure
Our Board currently consists of Mr. Quarls, the Chairman of the Board, and six other directors. Our Corporate Governance Guidelines provide that non-employee directors will meet in executive session on a regular basis without management present. Mr. Quarls presides at all meetings of the Board, as well as executive sessions of non-employee directors and, in consultation with the CEO, non-employee directors and management, establishes the agenda for each Board meeting. In the event that the non-employee directors include directors who are not independent under the listing requirements of the NYSE, as is currently the case, our Corporate Governance Guidelines provide that at least once a year, there shall be an executive session including only independent directors and the director who presides at these meetings is Mr. Quarls. The Board has also delegated certain matters to its committees.
Director Nomination Process
Pursuant to the Stockholders Agreement and our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws, as of the closing of the Restructuring our Board consists of our chief executive officer and six other members appointed by various Supporting Term Lenders, as described in “Board of Directors” above. 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 will be 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 will be entitled to nominate one director. All appointees or nominees of Supporting Term Lenders, other than any director appointed or nominated by Soter, must meet the “independent director” requirements set forth in Section 303A of the NYSE Listed Company Manual.
Other than as contemplated by the Stockholders Agreement, the NGC is responsible for identifying individuals who are qualified to become Board members. Nominees for directorship are selected by the NGC in accordance with the policies and principles of its charter. Although there is no formal diversity policy, our Board believes that the backgrounds and qualifications of its directors, considered as a group, should provide a composite mix of experience, knowledge and abilities that will allow it to fulfill its responsibilities. Pursuant to its charter, the NGC is tasked with recommending director candidates who will assist in achieving this mix of Board members having diverse professional backgrounds and a broad spectrum of knowledge, experience and capability. Subject to the Stockholders Agreement, at least once a year, the NGC will review the size and structure of the Board and its committees, including recommendations on Board committee structure and responsibilities.
In accordance with NYSE requirements, the NGC also oversees an annual performance evaluation process for the Board, the audit committee, the compensation committee and the NGC. In this process, anonymous responses from directors on a number of topics, including matters related to experience of Board and committee members, are discussed in executive sessions at Board and committee meetings. Although the effectiveness of this consideration of the diversity of director nominees has not been separately assessed, it is within the general subject matter covered in the NGC’s annual assessment and is reviewed in connection with Board and committee structure and responsibilities, as well as within the Board and committee annual performance evaluation process.
Board Role in Risk Oversight
The Board’s role in the risk oversight process includes receiving regular reports from members of senior management on areas of material risk to Key, including operational, financial, legal and regulatory, and strategic and reputational risks. The full Board (or the appropriate committee in the case of risks that are under the purview of a particular committee) receives these reports from the appropriate “risk owner” within the organization to enable it to understand our risk identification, risk management and risk mitigation strategies. When a committee receives the report, the chair of the relevant committee reports on the discussion to the full Board during the committee reports portion of the next Board meeting. This enables the Board and its committees to
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coordinate the risk oversight role, particularly with respect to risk interrelationships that may fall under the purview of multiple committees. In addition, in carrying out its duties under its charter, the audit committee regularly reviews and discusses with management, our internal auditors and our independent registered public accounting firm, Key’s policies relating to risk assessment and risk management. The compensation committee also specifically reviews and discusses risks that relate to compensation policies and practices.
2019 Board Meetings and Attendance
During 2019, the Board held 11 Board meetings. In addition, non-employee directors met regularly in executive session and management frequently discussed matters with the directors on an informal basis. Each director attended, either in person or by telephone conference, at least 75% of the aggregate of the total number of meetings of the Board and the total number of meetings held by all Board committees on which he or she served as a committee member in 2019. The Company expects the directors to attend Key’s annual meetings of stockholders.
Board Committees
The Board has established three standing committees: the Audit Committee, the Compensation Committee, and the NGC. Current copies of the charters of each of these committees are posted in the “Corporate Governance” section of our website, www.keyenergy.com.
Audit Committee
The current members of our Audit Committee are Messrs. Wommack, Edmiston and Rowland, with Mr. Rowland serving as the chair. The Board has determined that all of the members of the Audit Committee are independent under the NYSE rules, including the independence requirements contemplated by Rule 10A-3 under the Exchange Act. All members of the Audit Committee meet the financial literacy standard required by the NYSE rules and qualify as having accounting or related financial management expertise under the NYSE rules. In addition, the Board has determined that all members of the Audit Committee satisfy the definition of “audit committee financial expert,” and has designated each member of the Audit Committee as an “audit committee financial expert” under the Sarbanes-Oxley Act of 2002 and SEC rules. An “audit committee financial expert” is defined as a person who, based on his or her experience, satisfies all of the following attributes:
• | an understanding of generally accepted accounting principles and financial statements; |
• | an ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves; |
• | experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by Key’s financial statements, or experience actively supervising one or more persons engaged in such activities; |
• | an understanding of internal control over financial reporting; and |
• | an understanding of audit committee functions. |
For more information about each Audit Committee member’s background and experience, see “Board of Directors” above.
Our Board has adopted a written charter for the Audit Committee, pursuant to which the audit committee has, among others, the following duties and responsibilities:
• | appointing, evaluating, approving the services provided by and the compensation of, and assessing the independence of, our independent registered public accounting firm; |
• | overseeing the work of our independent registered public accounting firm, including through the receipt and consideration of certain reports from such firm; |
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• | reviewing with the internal auditors and our independent registered public accounting firm the overall scope and plans for audits, and reviewing with the independent registered public accounting firm any audit problems or difficulties and management’s response; |
• | reviewing and discussing with management and the independent registered public accounting firm our annual and quarterly financial statements and related disclosures; |
• | reviewing and discussing with management and the independent registered public accounting firm our system of internal controls, financial and critical accounting practices and policies relating to risk assessment and risk management; |
• | reviewing the effectiveness of our system for monitoring compliance with laws and regulations; and |
• | preparing the Audit Committee Report required by SEC rules (which is included under the heading “Report of the Audit Committee” below). |
During 2019, the Audit Committee held six meetings. In addition, members of the Audit Committee speak regularly with our independent registered public accounting firm and separately with the members of management to discuss any matters that the Audit Committee or these individuals believe should be discussed, including any significant issues or disagreements concerning our accounting practices or financial statements. For further information, see “Report of the Audit Committee” below.
The Audit Committee has the authority to retain legal, accounting or other experts that it determines to be necessary or appropriate to carry out its duties. We will provide the appropriate funding, as determined by the Audit Committee, for the payment of compensation to our independent registered public accounting firm and to any legal, accounting or other experts retained by the Audit Committee and for the payment of the Audit Committee’s ordinary administrative expenses necessary and appropriate for carrying out the duties of the Audit Committee.
The Audit Committee charter provides that a member of the Audit Committee may not simultaneously serve on the Audit Committees of more than two other public companies. Currently, no member of the Audit Committee serves on the Audit Committees of more than two other public companies.
The charter of our Audit Committee can be accessed on the “Corporate Governance” section of our website, www.keyenergy.com.
Compensation Committee
Our Compensation Committee reviews and recommends policies relating to compensation and benefits of our executive officers and employees, including reviewing and approving corporate goals and objectives relevant to the compensation of our chief executive officer and other executive officers, evaluating the performance of those officers in light of those goals and objectives and setting compensation for those officers based on such evaluations. During 2019, the Compensation Committee met six times. The current Compensation Committee consists of Messrs. Wommack, Quarls, Menkes and Kotzubei, with Mr. Wommack serving as the chair. No Compensation Committee member participates in any of our employee compensation programs other than the Key Energy Services, Inc. 2019 Equity and Cash Incentive Plan (the “2019 ECIP”).
The Compensation Committee has responsibility for establishing, implementing and continually monitoring adherence with our compensation philosophy. Our Board has adopted a written charter for the Compensation Committee, pursuant to which the compensation committee has, among others, the following duties and responsibilities:
• | reviewing and approving corporate goals and objectives relevant to the compensation of the CEO; |
• | evaluating the CEO’s performance in light of corporate goals and objectives and determining and approving the CEO’s compensation level based on this evaluation; |
• | reviewing and approving the compensation of executive officers other than the CEO, including severance arrangements and change-in-control agreements and provisions; |
• | reviewing and approving any incentive compensation plans or equity-based plans; |
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• | approving material changes to existing equity compensation plans where stockholder approval is not required by law and has not been obtained; |
• | in consultation with management, overseeing regulatory compliance with respect to compensation matters, including overseeing Key’s policies on structuring compensation programs to preserve tax deductibility; |
• | reviewing any potential conflicts of interest of our compensation consultant; |
• | preparing an annual report of the compensation committee on executive compensation for inclusion in Key’s annual proxy statement or annual report in accordance with applicable SEC rules and regulations; and |
• | reviewing and approving the Compensation Disclosure and Analysis for inclusion in Key’s annual proxy statement or annual report in accordance with applicable SEC rules and regulations. |
The Compensation Committee has the sole authority to select, retain, terminate and approve the fees and other retention terms of special counsel or other experts or consultants, as it deems appropriate in order to carry out its responsibilities, without seeking approval of the Board or management, including compensation consultants retained to assist in the evaluation of director, CEO or executive officer compensation.
The charter of our compensation committee can be accessed in the “Corporate Governance” section of our website, www.keyenergy.com.
Nominating and Governance Committee
The current NGC consists of Messrs. Edmiston, Quarls and Menkes, with Mr. Edmiston serving as the chair. During 2019, the NGC met five times. Our Board has adopted a written charter for the NGC, pursuant to which the NGC has, among others, the following duties and responsibilities:
• | identifying and recommending individuals to the Board for nomination as members of the Board and its committees, consistent with criteria approved by the Board; |
• | developing and recommending to the Board corporate governance guidelines applicable to Key; and |
• | overseeing the evaluation of the Board and management of Key. |
The NGC has the authority and funding to retain counsel and other experts or consultants, including the sole authority to select, retain and terminate any search firm to be used to identify director candidates and to approve the search firm’s fees and other retention terms.
The charter of our NGC can be accessed in the “Corporate Governance” section of our website, www.keyenergy.com.
Code of Business Conduct and Code and Ethics
Our Code of Business Conduct and Ethics applies to all of our employees and directors, CEO, Chief Financial Officer and senior financial and accounting officers. Among other matters, the Code of Business Conduct establishes policies to deter wrongdoing and to promote both honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of Business Conduct and Ethics. We also have an Ethics and Compliance committee, composed of members of management, which administers our ethics and compliance program with respect to our employees. In addition, we provide an ethics line for reporting any violations on a confidential basis. Our Code of Business Conduct and Ethics is available in the “Corporate Governance” section of our website at www.keyenergy.com. We will post on our website all waivers to or amendments of our Code of Business Conduct and Ethics that are required to be disclosed by applicable law and the NYSE listing standards.
Executive Officers
Below are the names, ages and certain other information on each of our current executive officers, other than Mr. Dodson, whose information is provided above.
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Katherine I. Hargis, age 48, Senior Vice President, Chief Administrative Officer, General Counsel and Secretary. Ms. Hargis joined Key in July 2013 as Associate General Counsel, Corporate and Transactional & Assistant Secretary and was promoted to Vice President, Associate General Counsel & Assistant Secretary in November 2015, promoted to Vice President, Chief Legal Officer and Secretary on January 1, 2016, promoted to her current position as Senior Vice President, General Counsel and Secretary on September 12, 2017 and was recently promoted to her current position as Senior Vice President, Chief Administrative Officer, General Counsel & Secretary on January 23, 2020. Prior to joining Key, she served as the Vice President, General Counsel and Corporate Secretary for U.S. Concrete, Inc., a publicly traded company providing ready-mixed concrete and aggregates, from June 2012 through July 2013, and as its Deputy General Counsel & Corporate Secretary from December 2011 through June 2012, and as its Assistant General Counsel from December 2006 through December 2011. From February 2006 through December 2006, Ms. Hargis served as an attorney with King & Spalding LLP. From August 2002 through February 2006, Ms. Hargis served as an attorney for Andrews Kurth Kenyon LLP. Ms. Hargis received her B.S. in Administration of Justice from Arizona State University in 1999 and her J.D. from Tulane University in 2002.
Louis Coale, age 53, Vice President and Controller serving as the Company’s principal accounting officer. Mr. Coale served as the Vice President and Operations Controller of the Company’s wholly owned subsidiary, Key Energy Services, LLC since May 2017 and was promoted to Vice President and Controller of the Company on October 3, 2018. Prior to joining Key, Mr. Coale most recently served as the Managing Principal at Coale’s Consulting from June 2016 to May 2018. Coale’s Consulting provides Business, IT and Financial consulting to various industries. Prior to his time at Coale’s Consulting, Mr. Coale served as the Vice President and CFO at Baker Hughes (Baker Oil Tools Divestiture) from 2015 to May 2016, Vice President of the Finance, Planning and Analysis - Commercial Analytics Modeling Dept. from 2014 to 2015, Vice President and CFO of the Global Products & Technology Dept. from 2013 to 2014, Vice President/Transformation Leader (Baker Hughes Finance) from 2009 to 2013, Vice President/Division CFO (Drilling Fluids) from 2007 to 2009, WW Controller (Baker Oil Tools - Completions) from 2005 to 2007 and WW Controller, Wireline Service from 2003 to 2005. Mr. Coale also served as the Expat Finance Lead (Wireline Services: Asia-Pacific from 2001 to 2003, Argentina/Bolivia/Brazil from 1999 to 2001 and Venezuela from 1996 to 1998.
ITEM 11. EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
This section of Annual Report describes our executive compensation philosophy and program in the context of the compensation paid to our Named Executive Officers for 2019. Our Named Executive Officers and their titles during the 2019 calendar year are listed below:
Name | Title |
J. Marshall Dodson | Senior Vice President, Interim Chief Executive Officer, Chief Financial Officer and Treasurer (1) |
Katherine I. Hargis | Senior Vice President, General Counsel and Secretary (2) |
Louis Coale | Vice President and Controller |
Robert Saltiel | Former President, Chief Executive Officer (3) |
Scott P. Miller | Former Senior Vice President, Operations Services and Chief Administrative Officer (4) |
(1) | Mr. Dodson was appointed as Senior Vice President, Interim Chief Executive Officer and Director effective December 30, 2019. |
(2) | Ms. Hargis served was appointed Senior Vice President, Chief Administrative Officer, General Counsel & Secretary effective January 23, 2020. |
(3) | Mr. Saltiel terminated his employment with the Company effective December 30, 2019. |
(4) | Mr. Miller terminated his employment effective April 1, 2019. Both Messrs. Saltiel and Miller were no longer with the Company at the end of the 2019 fiscal year, but are still considered NEOs for the 2019 year under SEC disclosure rules. |
Executive Summary
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The oilfield services industry has faced many challenges in the past several years and Key has faced similar challenges and was not immune to the volatility in the industry. In recent years, the Company has undergone a Chapter 11 restructuring process, from which it emerged in December 2016, CEO transitions in 2016 and 2018, respectively, and at the end of fiscal year 2019, the Company began discussion around the Restructuring and experienced another CEO transition, as described below. These macro-economic and industry challenges in combination with multiple management transitions had an impact on the compensation designs and outcomes for 2019, as described in more detail in this Compensation Discussion & Analysis.
Chief Executive Officer Transition
On December 30, 2019, Mr. Saltiel terminated his position as President and Chief Executive Officer with the Company and the Board appointed Mr. Dodson to serve as Interim Chief Executive Officer while the Board conducted an executive search for the new President and Chief Executive Officer. Mr. Saltiel entered into a separation agreement in connection with his termination and Mr. Dodson entered into an amendment to his employment agreement in connection with being named as Interim CEO. In connection with his departure, Mr. Saltiel forfeited 767,438 RSUs and received no annual cash incentive compensation for the period of 2019 that he served as the Company’s CEO.
In an effort to retain key management in place during and through the close of the Restructuring, on November 18, 2019 the Board granted a retention award to Mr. Coale in the amount of $60,000, 50% of which was paid on December 13, 2019 and the other 50% of which will vest on June 1, 2020. In the event Mr. Coale resigns his employment prior to June 1, 2019, the amount paid on December 13, 2019 is subject to clawback by the Company.
Executive Compensation Philosophy and Objectives
The core principle of our executive compensation philosophy is to pay for performance in ways that we believe will motivate our executives to develop and execute strategies that deliver performance improvements and create shareholder value over the short and long term. Accordingly, our compensation philosophy has historically been to heavily weight executive compensation toward “at-risk” and performance-based compensation in order to align the interests of our executive officers with our stockholders and ensure progress towards the successful attainment of our vision, values and business objectives. The primary objectives of our compensation program are to attract and retain the talent we need to successfully manage the Company, reward exceptional organizational and individual performance improvements, and accomplish these objectives at a reasonable total cost in relation to performance and market conditions.
We believe that our executive compensation program fairly and appropriately compensates our executive officers. We have three principal elements of total direct compensation: base salary, annual incentive compensation and long-term incentive compensation. These elements provide our Compensation Committee with a platform to reinforce our pay-for-performance and “at-risk” compensation philosophy while addressing our business needs and goals with appropriate flexibility. For example, in early 2019, during lower for longer than expected oil prices, executive turnover and extreme market volatility, in the interest of retaining our Named Executive Officers who we believe have the unique capabilities and experience to enable the Company to achieve our financial and operational goals, along with other corporate objectives, we increased our time-based long-term incentive compensation for our Named Executive Officers.
We want our executives to be motivated to achieve Key's short-term and long-term goals, without sacrificing our financial and corporate integrity in trying to achieve those goals. While an executive’s overall compensation should be strongly influenced by the achievement of specific financial and operational targets, we also believe that a portion of an executive’s compensation should be awarded in components that provide a degree of financial certainty and stability, due to the volatility and cyclicality inherent in our industry and the impact of oil and gas commodity prices on our business.
We have worked extensively and deliberately to develop a thoughtful, fair, and effective compensation program for our Named Executive Officers that is designed and operated to incentivize our executives to engage in business activities that support the value of Key and its stockholders. In an effort to achieve these goals in support of long-term, sustainable growth, we have implemented the best practices described in the chart below:
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What we do | What we don’t do | ||
a | Grant short and long-term incentive awards that are performance-based or “at-risk” | r | No single-trigger change of control vesting |
a | Equity awards for executive officers subject to three-year vesting periods | r | No excessive perquisites |
a | Policy prohibiting hedging and pledging transactions and short sales by executives | r | No payment of dividends on unvested restricted stock units |
a | Compensation Committee engages an Independent Compensation Consultant | r | No “golden parachute” excise tax gross-ups for severance or change of control payments |
a | Stock ownership guidelines for non-employee directors and executives | r | No fixed-term employment agreements |
a | Annual compensation risk assessment | ||
a | All incentive-compensation is subject to a clawback policy | ||
How We Make Compensation Decisions
Role of the Compensation Committee
The Compensation Committee has the responsibility to review and approve the compensation policies, programs, and plans for our executive officers (including the Named Executive Officers) and non-employee directors. The Compensation Committee’s responsibilities include administering the 2019 ECIP, which provides for the grant of cash and equity-based awards. The Compensation Committee also reviews the Compensation Discussion and Analysis section of our annual report or annual proxy statement and produces the Compensation Committee Report with respect to our executive compensation disclosures for inclusion in our annual report or annual proxy statement. In addition, the Compensation Committee regularly reviews current best compensation and governance practices to ensure that our executive compensation program is consistent with recent developments and market practice. The Compensation Committee, in overseeing the compensation of our directors and executive officers, employs several analytic tools and considers information from multiple resources. Subject in certain circumstances to Board approval, the Compensation Committee has the sole authority to make final decisions with respect to our executive compensation program, and the Compensation Committee is under no obligation to utilize the input of other parties. For more detailed information regarding the Compensation Committee, please refer to the Compensation Committee Charter, which is posted on the Corporate Governance section of the Company’s website at www.keyenergy.com.
Determining Compensation Levels
As discussed above, the Compensation Committee has the overall responsibility for establishing the elements, terms and target value of compensation paid or delivered to our Named Executive Officers. The Compensation Committee strives to develop a competitive, but not excessive, compensation program for our Named Executive Officers in order to recruit and retain the best possible talent in our industry. An important element of the Compensation Committee’s decision-making is compensation data produced by its independent compensation consultant, Meridian Compensation Partners, LLC (“Meridian”), including direct data from our peer group (described below), other industry compensation surveys (including the 2018 U.S. Mercer Total Compensation Survey), and proprietary data developed by Meridian. In addition, the Compensation Committee considers information provided by our executive officers in designing and implementing our executive compensation program. This data assists the Compensation Committee in evaluating appropriate compensation levels for each Named Executive Officer in relation to market practice and in designing an effective executive compensation program for the Company. The roles of Meridian and our executive officers in the Compensation Committee’s decision-making process are described more fully below.
Role of Compensation Consultant in Compensation Decisions
During the second quarter of 2019, as in 2018, the Compensation Committee retained Meridian as its independent compensation consultant. Meridian provides advice to and works with the Compensation Committee in designing and implementing the structure and mechanics of the Company’s executive compensation regime as well as other matters related to officer and director compensation and corporate governance. For example, Meridian regularly updates the Compensation Committee on regulatory changes impacting executive compensation, proxy advisor policies, compensation-related risks, and industry compensation trends. In addition, Meridian provides the Compensation Committee with external context such as relevant market regarding non-employee director compensation practices. This information assists the Compensation Committee in making executive officer and director compensation decisions based on market pay levels and best practices.
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Meridian reports directly and exclusively to the Compensation Committee and does not provide any other services to management, the Company or its affiliates. Meridian does not make compensation-related decisions for the Compensation Committee or otherwise with respect to the Company, and, while the Compensation Committee generally reviews and considers information and recommendations provided by Meridian, the Compensation Committee has the final authority to make compensation-related decisions. The Compensation Committee has the discretion to allow Meridian to work directly with management in preparing or reviewing materials for the Compensation Committee’s consideration. During 2019, and after taking into consideration the factors listed in Section 303A.05(c)(iv) of the NYSE Listed Company Manual, the Compensation Committee concluded that neither it nor the Company has any conflicts of interest with Meridian, and that Meridian is independent from management. Other than Meridian, no other compensation consultants provided services to the Compensation Committee
Role of Executive Officers in Compensation Decisions
In determining the compensation of our Chief Executive Officer, the Compensation Committee considers the information and advice provided by its compensation consultant, and other factors, which may include, our corporate goals, historic and projected performance, the current economic and commodities environment, and other relevant factors. With respect to the compensation of the Named Executive Officers other than our Chief Executive Officer, the Compensation Committee also considers the recommendations of our Chief Executive Officer. Additionally, in light of the Named Executive Officers’ integral role in establishing and executing the Company’s overall operational and financial objectives, the Compensation Committee requests that the Named Executive Officers provide recommendations on the appropriate goals for the qualitative and quantitative performance metrics used in our short-term cash incentive program. As discussed above, the Compensation Committee retains sole discretion to make final compensation determinations, and the Compensation Committee may accept, modify or reject any recommendations or observations made by our Named Executive Officers. In addition, the Compensation Committee may invite any Named Executive Officer to attend Compensation Committee meetings to report on the Company’s progress with respect to the annual quantitative and qualitative performance metrics, but any such officer is excluded from any decisions or discussions regarding his or her individual compensation.
The Compensation Committee, with input from Meridian, determined in November 2019 that the peer group of the Company to be used for compensation comparisons did not need to be updated as it properly reflects our operational focus, market capitalization, revenues and enterprise value and the expectation of continued consolidation and volatility in the energy industry. Accordingly, our peer group for 2019 continued to be comprised of the following:
Basic Energy Services, Inc. Forbes Energy Services, Inc. | Mammoth Energy Services, Inc. Pioneer Energy Services, Corp. | |
C&J Energy Services, Inc. Newpark Resources, Inc. Quintana Energy Services, Inc. Superior Energy Services, Inc. Ranger Energy Services, Inc. | Nuverra Environmental Solutions, Inc. NCS Multistage Holdings, Inc. TETRA Technologies, Inc. Select Energy Services, Inc. Nine Energy Services, Inc. | |
As described above, compensation data from the above peer group was considered by the Compensation Committee when making decisions regarding the 2019 compensation paid to our Named Executive Officers.
Elements of Compensation; 2019 Compensation Decisions
The principal components of our executive compensation program are base salary, cash incentive bonuses and long-term incentive awards in the form of equity, including performance-based equity. We blend these elements in order to formulate compensation packages that provide competitive pay, reward the achievement of financial, operational and strategic objectives on a short-term and long-term basis, and align the interests of our executive officers with those of our stockholders. We strive to hire and retain talented people who are compatible with our corporate culture and committed to our core values and who want to make a contribution to our mission.
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Base Salary
Base salary is an integral component of our compensation and a crucial aspect of retaining top executive talent. Each Named Executive Officer’s base salary is a fixed component of compensation each year for performing specific job duties and functions. This provides a level of financial certainty and stability in an industry with historic volatility and cyclicality. The base salaries are designed to reflect the experience, education, responsibilities and contribution of the individual executive officers. Base salary is an integral component of our compensation and a crucial aspect of retaining top executive talent. The Compensation Committee sets our Chief Executive Officer’s base salary and works together with our Chief Executive Officer to determine what adjustments, if any, should be made to the base salaries of our other Named Executive Officers. With the exception of base salary increases in connection with promotions, the Compensation Committee generally evaluates whether to increase the base salaries of our Named Executive Officers in June of each year. The base salary rates for the Named Executive Officers are modified based upon consideration of factors that the Compensation Committee deems relevant, including but not limited to: (i) any increase or decrease in the executive’s responsibilities; (ii) the executive’s experience; (iii) the executive’s job performance; and (iv) the level of compensation paid to executives in similar roles of other companies with which we compete for executive talent, as estimated based on data provided by Meridian, publicly available information, and the experience of the members of the Compensation Committee.
The following table sets forth the changes, if any, to our Named Executive Officers’ 2019 base salaries as compared to their 2018 base salaries. The 2019 base salary increases for Mr. Dodson, Ms. Hargis and Mr. Saltiel were effective December 30, 2019, May 1, 2019 and January 1, 2019, respectively:
2019 Base Salaries | 2018 Base Salaries | ||
Name | |||
Robert Saltiel (1)(3) | $800,000 | $750,000 | |
J. Marshall Dodson (2) | $575,000 | $425,000 | |
Katherine I. Hargis (4) | $375,000 | $310,000 | |
Scott P. Miller (3) | $310,000 | $310,000 | |
Louis Coale | $240,000 | $240,000 | |
(1) | Mr. Saltiel’s base salary was increased from $750,000 to $800,000 effective January 1, 2019 pursuant to the terms of his Employment Agreement. |
(2) | Mr. Dodson’s base salary was increased from $425,000 to $575,000 effective December 30, 2019 in connection with his promotion to Senior Vice President, Interim Chief Executive Officer, Chief Financial Officer & Treasurer. |
(3) | Messrs. Saltiel and Miller each terminated employment with the Company during 2019, effective as of December 30, 2019 and April 1, 2019, respectively. |
(4) | Ms. Hargis’ base salary was increased from $310,000 to $375,000 effective May 1, 2019 in order to align her more closely with market levels. |
The total base salary paid to each of our Named Executive Officers for services provided during 2019 is reported in the “Salary” column of the “2019 Summary Compensation Table” below.
Incentive Compensation
Annual Cash Incentive; 2019 Annual Incentive Plan
Each year, the annual cash bonus incentive is designed to pay for performance and align the interests of our executives with stockholder interests. The cash bonus incentive plan provides variable cash compensation earned only when established performance goals are achieved. It is designed to reward plan participants, including our Named Executive Officers, who have achieved certain individual corporate and executive performance objectives and have contributed to the achievement of certain objectives of Key.
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In January 2019, the Compensation Committee approved a performance-based cash bonus plan for 2019, the 2019 Annual Incentive Plan (the “2019 AIP”), pursuant to which the Named Executive Officers were eligible to receive cash bonuses based on the achievement of certain performance metrics, subject to their continued employment with the Company through payout of the 2019 AIP in 2020. The 2019 AIP was promulgated under the successor to the 2019 ECIP. Individual target bonuses under the 2019 AIP were based on a percentage of each eligible employee’s base salary. Performance metrics under the 2019 AIP consisted of (i) adjusted earnings before interest expense, taxes, depreciation and amortization (“Adjusted EBITDA,” weighted 60%), (ii) safety performance (weighted 20%) and (iii) individual performance (weighted 20%), as described in more detail below. For all Named Executive Officers, the 2019 AIP consists of four quarterly measurement periods from January 1, 2019 to December 31, 2019 (the “Performance Periods”), collectively equal to 100% of an individual’s bonus opportunity. The 2019 AIP goals and related actual performance were as follows:
Adjusted EBITDA (weighted 60%). A portion of the financial target was based on Adjusted EBITDA, which is a non-GAAP financial measure defined as total revenue, less operating expenses (excluding depreciation and amortization), adjusted for non-recurring and non-cash charges as disclosed in public reporting documents. (For a reconciliation of net loss as presented in accordance with United States generally accepted accounting principles (“GAAP”) to Adjusted EBITDA as required under Regulation G of the Securities Exchange Act of 1934 see the Company’s press release dated November 7, 2019 filed as Exhibit 99.1 on the Company’s Form 8-K dated November 7, 2019) Payout of the Adjusted EBITDA portion of the cash bonus could range between 0% and 150% of the applicable target. The Adjusted EBITDA goals are set quarterly by the compensation committee. In the event the Adjusted EBITDA target is less than $5 million for a quarter, it is not eligible to be paid at more than 100% of target.
Level | Threshold | Target | Maximum | Q1 2019 Achievement |
Adj. EBITDA | $0.6 million | $1.0 million | $1.0 million (1) | $0.898 million |
Potential Payout | 60% of target | 100% of target | 150% of target | 89% of target |
Level | Threshold | Target | Maximum | Q2 2019 Achievement |
Adj. EBITDA | $2.8 million | $4.6 million | $4.6 million | $1.6 million |
Potential Payout | 60% of target | 100% of target | 150% of target | 35% of target |
Level | Threshold | Target | Maximum | Q3 2019 Achievement |
Adj. EBITDA | $2.2 million | $3.7 million | $3.7 million | $(3.6) million |
Potential Payout | 60% of target | 100% of target | 150% of target | 0% of target |
Level | Threshold | Target | Maximum | Q4 2019 Achievement |
Adj. EBITDA | $0 million | $0 million | $0 million | $0 million |
Potential Payout | 60% of target | 100% of target | 150% of target | 0% of target |
(1) Pursuant to the 2019 AIP, Targets set for less than $5 million were not eligible for the maximum payout at 150%
There is no payout for the Adjusted EBITDA component upon achievement below threshold. The Adjusted EBITDA results for the First Quarter Performance Period were $898,000, which exceeded the threshold payout but was under the target payout. The Adjusted EBITDA thresholds for the second, third and fourth quarter performance periods were not achieved resulting in 0% payout. Therefore, the Company attained 20% of the Adjusted EBITDA target for the full year period.
Safety (weighted 20%). Positive safety results are critical in this industry to ensure the safety of our people. This goal represents the improvement required by the Company in the safety performance index made up of the Occupational Safety and Health Administration, or OSHA, total recordable incident rate (“TRIR”). TRIR is measured on an annual performance period beginning January 1, 2019 and ending December 31, 2019. Achievement of greater than a 2.0 annual TRIR results in payment at 0% of target, achievement of an annual TRIR between 1.75 and 2.0 results in payment at 50% of target, achievement of between 1.75 and 1.5 TRIR results in payment at 100% of target and a TRIR of less than 1.5 % is eligible for payment at 150% of target. The annual TRIR attained for 2019 was 1.48 which exceeded the maximum target. However, the Compensation Committee exercised its discretion to reduce the actual payout of the safety component and awarded 100% target of bonus with respect to the safety component of target in consideration of the Restructuring.
Individual (weighted 20%). Individual performance was measured on annual basis using the performance period of January 1, 2019, to December 31, 2019. The compensation committee used the Adjusted EBITDA target as a starting point for this metric, but is granted discretion to alter the actual payout amount based on several factors, including but not limited to (i) individual performance, (ii) attrition improvement, (iii) pricing improvement, (iv) success of strategic initiatives, (v) cost efficiencies and (vi) market factors. In light of the Restructuring, the compensation committee exercised negative discretion and awarded 0% for the Individual Performance Component.
The final payout percentage earned for the Performance Period was 32.0%.
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Metric | Weighting | Percent Earned | Weighted Payout |
Adjusted EBITDA | 60% at target | 20% of target goal (1) | 12% of target |
Safety | 20% at target | 100% of target goal | 20% of target |
Individual | 20% at target | 0% of target goal | 0% of target |
Total Payout | 32.0% of target | ||
(1) The Company attained 89% of its target goal for Adjusted EBITDA for Q1 and 0% for Q2, Q3 and Q4.
With the exception of Messrs. Saltiel and Miller, the final payout percentage of 32.0%, as determined above, was then multiplied by (i) each Named Executive Officer’s target bonus opportunity of the Named Executive Officer and (ii) such Named Executive Officer’s base salary in effect as of December 29, 2019, in order to calculate the total bonus payable to each Named Executive Officer. Messrs. Saltiel and Miller did not receive an annual incentive bonus as they were not employed by the Company at the time of payment.
The annual bonus amounts paid to the Named Executive Officers for the 2019 fiscal year under the 2019 AIP are outlined in the chart below and are reported in the “2019 Summary Compensation Table” in the “Non-Equity Incentive Plan Compensation” column:
Name | Base Salary as of 12/29/19 ($) (1) | Target Bonus as % of Base Salary | Percentage of Payout | Actual 2019 Bonus Award | |||
J. Marshall Dodson | $425,000 | X | 80% | X | 32.0% | = | $108,800 |
Katherine I. Hargis | $375,000 | X | 80% | X | 32.0% | = | $96,000 |
Louis Coale | $240,000 | X | 50% | X | 32.2% | = | $38,400 |
Robert J. Saltiel | N/A | X | 125% | X | N/A | = | $0 |
Scott Miller | N/A | X | 80% | X | N/A | = | $0 |
(1) For purposes of calculating the 2019 AIP Payouts, the Board used Mr. Dodson’s base salary as of December 29, 2019.
Long-Term Incentive Compensation
2019 Equity Award Grants
The purpose of our long-term incentive compensation is to align the interests of our executives with those of our stockholders and to retain our executives and other eligible employees over the long term. We want our executives to be focused on increasing stockholder value, and we used the 2019 ECIP as the long-term vehicle to encourage and establish this focus.
In addition to the award of annual long-term incentive compensation in accordance with our pay-for-performance philosophy, the Compensation Committee may elect to grant equity-based awards under the 2019 ECIP to Named Executive Officers in connection with such employee’s initial hire, promotion and other events.
As mentioned above, due to the current industry environment and recent leadership transitions, the recent rapid decline in the value of our stock, made awarding long-term incentive compensation in 2019 challenging. In an effort to control dilution levels as a result of the decline in our stock price at the time of grant, and based on the belief that there is significant upside value in our stock, the Compensation Committee elected to grant annual 2019 long-term incentive (“LTI”) awards at values that are significantly lower than typical targeted LTI values for our NEOs, and to award a portion of our 2019 LTI awards in equity and a portion in cash. The reduced award values were determined by first, subtracting the amount of the 2019 LTI award that was to be paid in cash to each executive from such executive’s original LTI target, as set by the Compensation Committee, and then second, dividing the remaining target LTI award value for each executive by an imputed $6.00 stock price, which approximates the 5-month average closing trading price of our stock as of the grant date. This resulted in fewer shares being granted than would have been granted using the closing stock price of $2.19 on the grant date, February 4, 2019 (the “Award Date”), and a total LTI award to each executive lower than target.
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Target and Actual 2019 LTI Awards
The following table presents information on the 2019 LTI awards paid or our Named Executive Officers as compared to each Named Executive Officer’s target award.
Name | Grant Date | Target LTI Value $ | 2019 LTI Cash Award | 2019 LTI Equity Grant (# of RSUs)(1) | Value of 2019 LTI Equity Grant, based on the closing stock price as of Feb 4, 2019 of $2.19 | 2019 Grant Date LTI Total Value | |
Robert J. Saltiel | 2/4/2019 | $ 3,500,000 | $1,000,000 | 12,000 | $ 1,314,000 | $2,314,000 | |
J. Marshall Dodson | 2/4/2019 | $ 1,000,000 | $150,000 | 2,833 | $ 310,251 | $460,251 | |
Scott P. Miller | 2/4/2019 | $ 500,000 | $150,000 | 1,167 | $ 127,749 | $277,749 | |
Katherine I. Hargis | 2/4/2019 | $ 500,000 | $150,000 | 1,167 | $ 127,749 | $277,749 | |
Louis Coale | 2/4/2019 | $ 250,000 | $75,000 | 583 | $ 63,876 | $138,876 | |
1. | The number of RSUs set forth in this column is the number of RSUs subject to each grant after giving effect to the reverse stock split of the Company’s common stock effected on March 6, 2020 in connection with the Restructuring. |
Due to the significantly reduced 2019 LTIP payment values, the Compensation Committee determined it was appropriate to only grant time-based awards for this grant cycle. The Compensation Committee intends to re-evaluate its LTI program strategy for 2020 based on industry and market conditions present at that time.
The time-vesting restricted stock units (“RSUs”) granted as the equity component of the 2019 LTI will vest in equal installments on the first three anniversaries of the Award Date and the cash component of the long-term incentive award (“Cash LTI Award”) will vest 40% on the first anniversary of the Award Date and 60% on the second anniversary of the Award Date.
The RSU grants to Messrs. Dodson and Miller and Ms. Hargis were contingent upon stockholder approval of the 2019 ECIP at the Company’s 2019 annual meeting of the stockholders, which occurred on May 1, 2019. Mr. Coale’s award was granted under the predecessor plan to the 2019 ECIP, the 2016 Equity and Cash Incentive Plan.
Other Components of Total Compensation
The total compensation program for our Named Executive Officers also consists of the following components:
• | retirement, health and welfare benefits; |
• | limited perquisites; and |
• | certain post-termination payments. |
Retirement, Health and Welfare Benefits
We offer a 401(k) savings plan and health and welfare programs to all eligible employees. Under the terms of their employment agreements, the Named Executive Officers are eligible to participate in the same broad-based benefit programs on the same basis as the rest of our employees. Our health and welfare programs include medical, pharmacy, dental, vision, life insurance and accidental death and disability. For additional information about employment agreements of our Named Executive Officers, see “Compensation of Executive Officers-Employment Agreements” below.
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Under the 401(k) plan, eligible employees may elect to contribute up to 100% of their eligible compensation on a pre-tax basis in accordance with the limitations imposed under the Internal Revenue Code of 1986, as amended, and the regulations promulgated there under (collectively, the “Code”). Amounts contributed under the 401(k) plan are held in a trust and invested among various investment funds in accordance with the directions of each participant. Effective as of January 1, 2019, the Company implemented a 100% company matching contribution on the first 4% of eligible compensation contributed by an employee, subject to a cap of $19,500 or $26,000 if the employee is over the age of 50. For the year ended December 31, 2019, we made employer matching contributions to the 401(k) plan in the amount of $4,499,052.43.
Limited Perquisites
We provide our Named Executive Officers with the opportunity to receive certain perquisites that we believe are reasonable and consistent with the practices of our peer group, such as payment for eligible covered out-of-pocket medical and dental expenses not otherwise covered by insurance under certain circumstances. These reimbursements are made under the terms of, and subject to the limitations set forth in, our Executive Health Reimbursement Plan. These programs are intended to promote the health and financial security of our executives. The programs are provided at competitive market levels to attract, retain and reward superior executives in key positions. Perquisites did not constitute a material portion of the compensation to the Named Executive Officers for 2019. The value of these benefits for Named Executive Officers in 2019 is reflected under “All Other Compensation” column of the “2019 Summary Compensation Table” below.
Employment Agreements
We believe that it is appropriate to formally document the employment relationships that we have with certain executive officers of the Company, and we have entered into employment agreements with Mr. Dodson and Ms. Hargis and a Change of Control Agreement with Mr. Coale, each of which offers specified severance payments and other benefits following certain terminations of the applicable executive officer’s employment, as described below. Prior to his termination of employment at the end of 2019, the Company was also party to an employment agreement with Mr. Saltiel. Mr. Saltiel’s employment agreement provided for a base salary of at least $800,000 for fiscal years following 2018, a target annual incentive bonus opportunity of at least 100% of base salary, a target annual long-term incentive opportunity of at least $3,500,000 for 2019 and $3,750,000 for 2020 and the years that follow, and a special sign on RSU equity award with a grant date fair value of $2,000,000. Mr. Saltiel’s employment agreement also provided for certain specified severance payments and benefits following certain terminations of employment; however, Mr. Saltiel waived his right to receive these payments in connection with his departure in exchange for the payment of a $2,500,000 lump sum cash severance payment pursuant to his Separation and Release Agreement with the Company, as described further in “Potential Payments Upon Terminations or Change of Control.” The Company believes that offering severance benefits is important in attracting and retaining key executive talent, encourages the retention of executive officers during the pendency of a potential change of control transaction or other organizational changes within the Company and otherwise generally protects the Company’s interest.
The employment arrangements in place with Mr. Dodson and Ms. Hargis provide for severance compensation if the executive’s employment is terminated by Key without “cause” or by the executive for “good reason” (each as defined in the applicable employment agreement), including additional severance upon such termination scenarios during the one-year period following a change of control of Key. Mr. Coale’s Change of Control Agreement provides for severance compensation if his employment is terminated by Key without “cause” or by Mr. Coale due to a “change in circumstances” (each, as defined in Mr. Coale’s Change of Control Agreement) during the one-year period following a change of control. These change of control benefits are structured as “double trigger” benefits such that benefits are paid only if the executive’s employment of is terminated during a specified period after a change of control. We believe a “double trigger” benefit maximizes stockholder value because it prevents an unintended windfall to executives in the event of a change of control where executives retain their positions and compensation is not reduced, while still providing appropriate incentives to cooperate in negotiating any change of control. In addition, these agreements avoid distractions involving executive management regarding their own continued employment that arise when the Board is considering possible strategic transactions involving a change of control, ensuring continuity of executive management during negotiations and objective input from executives to the Board when it is considering any strategic transaction. For additional information concerning severance and change of control benefits contained in the employment agreements of our Named Executive Officers, see “Compensation of Executive Officers-Payments Upon Termination or Change of Control” below.
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Tax and Accounting Considerations
We account for equity-based compensation in accordance with the requirements of FASB ASC Topic 718, “Stock Compensation.” The tax and accounting consequences of utilizing various forms of compensation are considered by the Compensation Committee when adopting new or modifying existing compensation.
Risk Assessment and Mitigation
The Compensation Committee has reviewed our executive and non-executive compensation programs and believes that they do not encourage excessive or unnecessary risk-taking. In designing and implementing our award structure, we and the Compensation Committee worked closely with Meridian to mitigate any risks and to minimize the creation of imprudent incentives for our executives. We do not believe that our performance-based compensation encourages unnecessary risks because the executive pay mix is sufficiently diversified over several performance metrics as well as over short-term and long-term compensation. Our compensation program structure and policy includes the following features to prevent and safeguard against excessive risk-taking:
a | Payments under our short-term cash incentive program are based upon the Compensation Committee’s certification and review of a variety of performance metrics, thereby diversifying the risk associated with any single performance indicator; |
a | Our long-term equity compensation rewards have performance or time-based vesting periods of at least three years for executives, which encourages executives to focus on sustaining the performance of the Company and its stock price; |
a | We pay compensation that is competitive with the market and our industry peers, while not being excessive; |
a | Our compensation mix is balanced among fixed and variable components, annual and long-term compensation, and cash and equity and includes multiple performance metrics intended to create rewards based on our Company’s and our executives’ long-term performance; |
a | Our incentive compensation plans cap the maximum payout and implement design features that do not encourage excessive risk-taking; |
a | Our Compensation Committee has an appropriate level of discretion, including the ability to reduce payments under the short-term cash incentive program; |
a | Our Compensation Committee adopted a clawback policy and stock ownership guidelines, which provide additional levels of accountability for decision-making; |
a | Our insider trading policy contains a general anti-hedging and anti-pledging policy for all insiders; and |
a | We do not have any agreements that provide for payments solely upon the occurrence of a change in control (except for performance-based equity awards, which vest based on the actual achievement of the applicable performance conditions through the date immediately prior to the change of control). |
We believe that our executive compensation program provides our executive officers with appropriate rewards for sustained performance, without giving unnecessary weight to any one factor or type of compensation and avoids excessive risk. Our compensation structure is designed to encourage sustained performance over a long-term period. Based on the foregoing, the Compensation Committee has concluded that the risks arising from our compensation policies and programs are not reasonably likely to have a material adverse effect on us.
Recoupment of Compensation
Upon the recommendation of the Compensation Committee, in 2018, the Board adopted a clawback policy that allows for the recoupment of cash- and equity-based incentive-based compensation, at the sole discretion of our Board of Directors or Compensation Committee, in the event of a financial restatement that resulted in excess compensation being paid to current or former executive officers within a twenty-four month period preceding the date on which the Company is required to prepare the financial restatement. This clawback policy can be found in the Corporate Governance section of the Company’s website at www.keyenergy.com.
Insider Trading Policy; Anti-Hedging and Anti-Pledging
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We maintain an insider trading policy that prohibits insiders from trading shares of our Common Stock when in possession of material non-public information. The policy also prohibits the pledging and hedging of our shares, including transactions involving short-sales, margin accounts and derivative securities.
Stock Ownership Guidelines
Upon the recommendation of the Compensation Committee, in 2018, the Board adopted stock ownership guidelines for our non-employee directors and executive officers, including our Named Executive Officers. The details of the stock ownership guidelines applicable to our executives (including our Named Executive Officers) are outlined below.
Title | Ownership Guidelines |
Chief Executive Officer | Six times annual base salary |
Direct Reports of the Chief Executive Officer | Three times annual base salary |
Non-executive Board Member | Three times annual cash retainer |
It is the responsibility of the non-employee directors and our executive officers to achieve and maintain compliance with this policy by the later of December 31, 2023 or at the end of five years of continuous service with the Company as an executive officer or member of the Board.
Compensation Committee Report
The compensation committee reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with our management. Based on this review and discussion, the compensation committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K for the year ended December 31, 2019.
By the compensation committee of the Board of Directors of Key Energy Services, Inc.
H.H. “Tripp” Wommack, III
Harry F. Quarls
Jacob Kotzubei
Alan B. Menkes
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Compensation of Executive Officers
2019 Summary Compensation Table
The following table contains information about the compensation that our NEOs earned for fiscal years 2019, 2018 and 2017 as applicable to their status as NEOs for each given year:
Name and Principal Position | Year | Salary ($) | Bonus ($)(1) | Stock Awards ($)(2) | Option Awards ($)(2) | Non-equity Incentive Plan Compensation ($)(3) | All Other Compensation ($)(4) | Total | |||||||
J. Marshall Dodson Senior Vice President, Interim Chief Executive Officer, Chief Financial Officer and Treasurer | 2019 2018 2017 | $ $ $ | 425,000 399,039 375,000 | $ $ $ | 159,375 - 283,333 | $ $ $ | 310,251 - 1,808,886 | $ $ $ | - - - | $ $ $ | 163,047 178,989 165,262 | $ $ $ | 26,427 18,603 13,420 | $ $ $ | 1,084,101 596,631 2,645,901 |
Katherine I. Hargis Senior Vice President, Chief Administrative Officer, General Counsel | 2019 2018 2017 | $ $ $ | 352,000 304,808 276,442 | $ $ $ | 77,500 - 80,000 | $ $ $ | 127,749 - 1,070,661 | $ $ $ | - - 109,002 | $ $ $ | 150,247 130,557 132,210 | $ $ $ | 12,568 1,341 594 | $ $ $ | 720,064 436,706 1,668,909 |
Louis Coale Vice President & Controller | 2019 2018 | $ $ | 240,000 144,077 | $ $ | 30,000 - | $ $ | 63,876 324,800 | $ $ | - - | $ $ | 65,523 60,170 | $ $ | 8,174 644 | $ $ | 407,573 529,521 |
Separated During 2019 | |||||||||||||||
Robert J. Saltiel Former Chief Executive Officer | 2019 2018 | $ $ | 800,000 269,615 | $ $ | - 273,288 | $ $ | 1,314,000 3,255,008 | $ $ | - - | $ $ | - - | $ $ | 2,513,298 484 | $ $ | 4,627,298 3,788,395 |
Scott P. Miller Former Chief Administrative Officer | 2019 2018 2017 | $ $ $ | 104,923 291,827 275,000 | $ $ $ | - - 100,000 | $ $ $ | - - 840,260 | $ $ $ | - - - | $ $ $ | - 130,557 121,192 | $ $ $ | 4,061 1,191 486 | $ $ $ | 108,984 423,575 1,336,938 |
_______________________
(1) | Amounts in this column for 2019 for Mr. Dodson and Ms. Hargis, represent payment on July 1, 2019 of 25% of the retention bonus granted to each of Mr. Dodson and Ms. Hargis on July 1, 2018, as discussed further in “Potential Payments Upon Termination or Change of Control” and for Mr. Coale, represent payment on December 13, 2019 of 50% of the retention bonus granted to Mr. Coale on November 18, 2019, as discussed further in “Potential Payments Upon Termination or Change of Control.” The amount in this column for 2018 consists of Mr. Saltiel’s pro-rata 2018 bonus paid pursuant to the terms of his Employment Agreement. Amounts in this column for 2017 consist of remaining payments made pursuant to cash retention awards granted on January 28, 2016 to Mr. Dodson, Ms. Hargis and Mr. Miller ($283,333, $80,000 and $100,000, respectively). |
(2) | The amounts in these columns represent the aggregate grant date fair value dollar amounts with respect to RSUs, PSUs granted in 2017 and 2018 under the 2016 Cash and Equity Incentive Plan and, in 2019, under the 2019 Cash and equity Incentive Plan, as applicable, calculated on the respective grant date of each such award in accordance with FASB ASC Topic 718. For the 2019 awards, the assumptions made in the valuation of the expense amounts included in these columns are discussed in Note 16 in the notes to our consolidated financial statements, entitled “Share-Based Compensation,” which is included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2019. See the section of our Compensation Discussion and Analysis above entitled “2019 Equity Award Grants” and the “2019 Grants of Plan-Based Awards” table below for additional information regarding these awards. For 2018, amounts for Mr. Coale in connection with his grant on July 1, 2018 of performance-based RSUs reflect performance at target, the probable outcome of the performance conditions underlying those awards as of the date of grant. If Mr. Coale’s performance-based RSUs had been valued at maximum performance the amount would have been $487,200. For 2017, amounts for each NEO include the value of Replacement Awards (granted |
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50% in the form of time-based RSUs vesting in three equal installments over a three-year period from the date of grant and 50% in the form of performance-based RSUs with a three-year performance period using an EBITDA performance metric) granted on December 31, 2017 in exchange for the forfeiture of all outstanding unvested equity awards, including time and performance-based options, performance-based RSUs and time-based RSUs. The value of the portion of the Replacement Awards granted in the form of performance-based RSUs reflects performance at target, the probable outcome of the performance conditions underlying those awards as of the date of grant. If the Replacement Awards granted in the form of performance-based RSUs had been valued at maximum performance, the awards for Mr. Dodson, Ms. Hargis and Mr. Miller would have been $2,713,328, $1,152,450 and $1,260,390, respectively.
(3) | The amounts shown in this column consist of annual bonus payments made to the Named Executive Officers under each of the 2019 AIP and the 2018 and 2017 annual cash bonus incentive plans. The 2019 AIP annual bonus payment made to each of Mr. Dodson, Ms. Hargis and Mr. Coale was $108,800, $96,000 and $38,400, respectively. In addition, the amounts shown for 2019 include a pro-rated amount of the Cash LTI Awards granted on February 4, 2019 to each of Mr. Dodson, Ms. Hargis and Mr. Coale ($150,000, $150,000 and $75,000, respectively) which is forfeitable only in the event of a termination for Cause. On February 4, 2020, 40% of the 2019 Cash LTI Awards vested and the remaining 60% of the 2019 Cash LTI Awards will vest on February 4, 2021. |
(4) A breakdown of the amounts shown in this column for 2019 for each of the Named Executive Officers is set forth in the table below.
.
Medical Expenses(b) | Savings Plan Contributions(d) | ||||||||||||||||||
Name | Insurance(a) | Other(c) | Severance (e) | Total | |||||||||||||||
J. Marshall Dodson | $ | 1,320 | $ | 17,204 | $ | 270 | $ | 7,634 | $ | — | $ | 26,428 | |||||||
Katherine I. Hargis | $ | 1,098 | $ | — | $ | 270 | $ | 11,200 | $ | — | $ | 12,568 | |||||||
Louis Coale | $ | 922 | $ | — | $ | 414 | $ | 6,838 | $ | — | $ | 8,174 | |||||||
Robert J. Saltiel | $ | 1,324 | $ | — | $ | 774 | $ | 11,200 | $ | 2,500,000 | $ | 2,513,298 | |||||||
Scott P. Miller | $ | 293 | $ | — | $ | 48 | $ | 3,720 | $ | — | $ | 4,061 | |||||||
(a) | Includes premiums paid by the Company on behalf of the Named Executive Officers for life insurance, accidental death and disability or other insurance policy for which the officer (or his or her family) is the beneficiary. |
(b) | Represents out-of-pocket medical expenses not covered by insurance that are reimbursed to the Named Executive Officers. |
(c) | Includes amounts for imputed income with respect to life insurance and other benefits, including the Excess Group Life Policies. |
(d) | Includes contributions by Key on behalf of the Named Executive Officers to our 401(k) Plan. |
(e) | Represents $2,500,000 severance payable to Mr. Saltiel in connection with his departure, as discussed further in “Potential Payments Upon Termination or Change of Control” below. Mr. Miller did not receive any severance payments or benefits in connection with his departure. |
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2019 Grants of Plan-Based Awards
The following table presents information on plan-based awards made to the Named Executive Officers in fiscal 2019:
Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (1) | Estimated Future Payouts Under Equity Incentive Plan Awards | All Other Stock Awards: Number of Shares of Stock or Units (#)(2) | All Other Option Awards: Number of Securities Underlying Options (#) | Exercise or Base Price of Option Awards ($/Sh) | Grant Date Fair Value of Stock and Option Awards ($)(3) | ||||||||||||||||||||||
Name | Grant Date | Target ($) | Maximum Awards ($) | Threshold (#) | Target (#) | Maximum # | |||||||||||||||||||||
J. Marshall Dodson | 2/4/2019 | $ | 340,000 | $ | 442,000 | — | — | — | 2,833 | — | — | $ | 310,251 | ||||||||||||||
— | — | — | — | — | — | — | |||||||||||||||||||||
Katherine I. Hargis | 2/4/2019 | $ | 300,000 | $ | 390,000 | — | — | — | 1,167 | — | — | $ | 127,749 | ||||||||||||||
— | — | — | — | — | — | — | |||||||||||||||||||||
Louis Coale | 2/4/2019 | $ | 120,000 | $ | 156,000 | — | — | — | 583 | — | — | $ | 63,876 | ||||||||||||||
— | — | — | — | — | — | — | |||||||||||||||||||||
Robert J. Saltiel | 2/4/2019 | N/A | — | — | — | 12,000 | — | — | $ | 1,314,000 | |||||||||||||||||
— | — | — | — | — | — | — | |||||||||||||||||||||
Scott P. Miller | 2/4/2019 | N/A | — | — | — | 1,167 | — | — | $ | 127,749 | |||||||||||||||||
— | — | — | — | — | — | — | |||||||||||||||||||||
_________________________
(1) | The amounts in these columns represent the potential annual value of the payout for each Named Executive Officer under the 2019 AIP if the target or maximum goals are satisfied. For a detailed description of the cash bonus incentive plan, see “Elements of Compensation; 2019 Compensation Decisions - Annual Cash Incentive; 2019 Incentive Plan” above. Amounts actually paid for the 2019 year are reflected in the “Non-Equity Incentive Plan Compensation” column of the “2019 Summary Compensation Table” above. Mr. Saltiel and Mr. Miller were not employed with the Company at the time of bonus payouts and as such were not eligible to receive bonus compensation. |
(2) | The number of RSUs set forth in this column is the number of RSUs subject to each grant after giving effect to the reverse stock split of the Company’s common stock effected on March 6, 2020 in connection with the Restructuring. |
(3) | These amounts represent the grant date fair value calculated in accordance with FASB ASC Topic 718. |
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2019 Outstanding Equity Awards at Fiscal Year-End
The following table provides information with respect to outstanding stock options, time-based RSUs and performance-based RSUs held by the Named Executive Officers as of December 31, 2019:
OPTION AWARDS | STOCK AWARDS | |||||||||||||||||||||||||||||
Name | Number of Securities Underlying Unexercised Options (#) Exercisable (1) | Number of Securities Underlying Unexercised Options (#) Unexercisable | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | Option Exercise Price ($)(1) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (#)(3) | Market Value of Shares or Units of Stock That Have Not Vested ($)(2) | Equity Incentive Plan Awards: Number of Unearned Performance Units That Have Not Vested (#)(3) | Equity Incentive Plan Awards: Market Value of Unearned Units That Have Not Vested ($)(2) | |||||||||||||||||||||
J. Marshall Dodson | 255 | — | — | $ | 967.50 | 12/15/26 | 3,343 | $ | 16,717 | 1,020 | $ | 5,101 | ||||||||||||||||||
255 | — | — | $ | 2,399.50 | 12/20/26 | — | — | — | — | |||||||||||||||||||||
Katherine I. Hargis | 99 | — | — | $ | 967.50 | 12/15/26 | 1,383 | $ | 6,917 | 433 | $ | 2,167 | ||||||||||||||||||
99 | — | — | $ | 2,399.50 | 12/20/26 | — | — | — | — | |||||||||||||||||||||
Louis Coale | — | — | — | $ | — | 717 | $ | 3,583 | 133 | $ | 667 | |||||||||||||||||||
— | — | — | $ | — | — | — | — | — | ||||||||||||||||||||||
Robert J. Saltiel (4) | — | — | — | $ | — | — | $ | — | — | $ | — | |||||||||||||||||||
— | — | — | $ | — | — | — | — | — | ||||||||||||||||||||||
Scott P. Miller (4) | 118 | — | — | $ | 967.50 | 12/15/26 | — | $ | — | — | $ | — | ||||||||||||||||||
118 | — | — | $ | 2,399.50 | 12/20/26 | — | — | — | — | |||||||||||||||||||||
_________________________
(1) | The number of options and the weighted average exercise price set forth in these columns are the number of shares subject to each grant or the weighted average exercise price after giving effect to the reverse stock split of the Company’s common stock effected on March 6, 2020 in connection with the Restructuring. |
(2) | The market price of stock awards is determined by multiplying the number of shares by the closing price of the stock on the last trading day of the year. The closing price quoted on the OTC on December 31, 2019 was $0.10. |
(3) | Represents RSUs which vest in annual increments beginning on the one-year anniversary of the date of grant. The number of RSUs set forth in this column is the number of RSUs subject to each grant after giving effect to the reverse stock split of the Company’s common stock effected on March 6, 2020 in connection with the Restructuring. Performance-based RSUs are shown assuming target performance. With respect to each NEO, the vesting applicable to each outstanding award as of December 31, 2019 (including performance-based RSUs, assuming target performance) is as follows: |
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Name | Number of Shares | Vesting Date | ||||
J. Marshall Dodson | 944 | February 4, 2020 | ||||
1,530 | December 31, 2020 | |||||
944 | February 4, 2021 | |||||
944 | February 4, 2022 | |||||
Katherine I. Hargis | 389 | February 4, 2020 | ||||
650 | December 31, 2020 | |||||
389 | February 4, 2021 | |||||
389 | February 4, 2022 | |||||
Louis Coale | 194 | February 4, 2020 | ||||
67 | July 1, 2020 | |||||
194 | February 4, 2021 | |||||
200 | July 1, 2021 | |||||
194 | February 4, 2022 | |||||
(4) | All outstanding awards for Messrs. Saltiel and Miller were terminated as of their respective dates of termination. Accordingly, as of December 31, 2019, they did not have any outstanding equity awards. |
2019 Stock Vested
The following table sets forth certain information regarding options and stock awards exercised and vested, respectively, during 2019 for the Named Executive Officers:
Option Awards | Stock Awards | ||||||||||||
Name | Number of Shares Acquired on Exercise (#) | Value Realized on Exercise ($) | Number of Shares Acquired on Vesting (#)(1) | Value Realized on Vesting ($)(2) | |||||||||
J. Marshall Dodson | — | — | 510 | $ | 2,551 | ||||||||
Katherine I. Hargis | — | — | 217 | $ | 1,083 | ||||||||
Louis P. Coale | — | — | 67 | $ | 8,502 | ||||||||
Separated during 2019 | |||||||||||||
Robert J. Saltiel | — | — | 1,674 | $ | 108,836 | ||||||||
Scott P. Miller | — | — | — | $ | — | ||||||||
_________________________
(1) | Represents the number of shares of time-based RSUs that vested during 2019. The number of shares set forth in this column is the number of shares acquired upon vesting after giving effect to the reverse stock split of the Company’s common stock effected on March 6, 2020 in connection with the Restructuring. |
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(2) | The value realized on vesting of restricted stock was calculated as the number of shares acquired on vesting (including shares withheld for tax withholding purposes) multiplied by the market value of our common stock on each respective vesting date. Market value is determined in accordance with the terms of the applicable incentive plan under which the restricted stock was granted, and, in the table above, was either (i) the closing price of our common stock on the NYSE or OTC Market for vesting dates that were trading days or (ii) using the average of the closing price of a share of Common Stock on the immediately preceding trading day and the opening price of a share of Common Stock on the immediately following trading day for vesting dates that were on a weekend or holidays. |
Potential Payments Upon Termination or Change of Control
Key has entered into employment or change of control agreements with each Named Executive Officer that provide for certain payments upon a termination of employment, depending upon the circumstances of the Named Executive Officer’s separation from Key, as summarized below. Our rationale for maintaining certain severance and change in control benefits is described above in “Other Components of Total Compensation-Employment Agreements”. Each of the arrangements with our NEOs that was effective for the 2019 year is summarized below.
J. Marshall Dodson, Senior Vice President, Interim Chief Executive Officer, Chief Financial Officer and Treasurer
On March 25, 2013, the Company entered into an employment agreement with Mr. Dodson pursuant to which Mr. Dodson would serve as the Company’s Senior Vice President, Chief Financial Officer and Treasurer. The employment agreement provides for an initial two-year term expiring on the second anniversary of the effective date of the agreement. The term will be automatically renewed for an additional one-year period on that date (and on each subsequent anniversary of the effective date of the agreement) unless either party gives written notice of its intent not to extend the term. The agreement provides for an annual base salary of $350,000 that may be increased at the discretion of the Chief Executive Officer and the Compensation Committee and an annual incentive bonus opportunity based on the achievement of performance objectives established by the Compensation Committee. In January 2014, the Compensation Committee increased Mr. Dodson’s base salary to $375,000. In July, 2018 the Compensation Committee increased Mr. Dodson’s annual base salary to $425,000. Mr. Dodson is entitled to at least four weeks of vacation per year and to participate in the Company’s Executive Health Reimbursement Plan, Director and Officer Liability Insurance, voluntary annual physicals and other benefit plans on terms consistent with those applicable to the Company’s employees generally, including, without limitation, personal time off, group medical and dental, life, accident and disability insurance, retirement plans and supplemental and excess retirement benefits as the Company may from time-to-time provide to similarly situated employees. Pursuant to his employment agreement, Mr. Dodson agreed not to compete with Key or to solicit customers or employees of Key after the termination of his employment for a period of time equal to (i) that during which he receives severance compensation, (ii) three years following a termination of employment by the Company other than for Cause, based on non-renewal of the employment agreement or due to Disability or by Mr. Dodson for Good Reason, in each case, during the one-year period following a Change of Control (as defined in his agreement) or (iii) for a period of 12 months following a termination of employment by the Company for Cause or by Mr. Dodson other than for Good Reason.
If Mr. Dodson’s employment with the Company is terminated by the Company without Cause or by Mr. Dodson for Good Reason (as such terms are defined in the employment agreement), or due to non-renewal of the agreement by the Company, subject to Mr. Dodson’s delivery of a release of claims in favor of the Company, Mr. Dodson will be entitled to a severance benefit equal to (i) two times his base salary in effect on the termination date payable in twenty-four equal monthly installments, (ii) full vesting of all outstanding equity-based incentive awards, and (iii) the cost of COBRA premiums for continued medical insurance coverage for Mr. Dodson and his dependents until the earlier of two years from the date of termination or the date on which he commences full-time employment with another employer. In the event Mr. Dodson terminates his employment for Good Reason or is terminated without Cause (including non-renewal of his agreement by the Company) within one year following a Change of Control (as such term is defined in his employment agreement), Mr. Dodson shall receive a severance benefit equal to (i) three times his base salary in effect on the termination date payable in twenty-four equal monthly installments plus three times his annual target cash bonus payable in a lump sum, (ii) full vesting of all equity-based incentive awards, and (iii) a lump sum payment in cash equal to the cost of COBRA premiums for continued medical insurance coverage for Mr. Dodson and his dependents for two years from the date of termination. If Mr. Dodson’s employment with the Company is terminated by reason of Disability (as defined in his employment agreement), Mr. Dodson shall receive a severance benefit equal to (i) 12 months’ base salary in effect on the termination date, payable in twelve equal monthly installments, reduced by the amount of any disability insurance proceeds actually paid to Mr. Dodson or for his benefit from the Company’s disability plans and programs during such time period, (ii) full vesting of all equity-based incentive awards, and (iii) the cost of COBRA premiums for continued medical insurance coverage for Mr. Dodson and his dependents until the earlier of two years from the date of termination or the date on which he commences full-time employment with another employer. If Mr. Dodson’s employment is terminated by reason of death, Mr. Dodson shall not receive any severance payments pursuant to his agreement; however, his spouse and his dependents shall be entitled to receive continued
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group health, dental and vision coverage under the Company’s Welfare Plans and the Company shall pay all required COBRA premiums until the earlier of the second anniversary of his death or the date on which his spouse and his dependents receive replacement coverage that would have terminated their COBRA rights and all outstanding unvested equity awards vest in full.
On July 1, 2018, the Company entered into a retention bonus award agreement with Mr. Dodson providing for payment of a retention bonus (the “Retention Bonus”) in the amount of $637,500 with 25% of the bonus vesting July 1, 2019 and the remainder vesting July 1, 2020. In the event Mr. Dodson is terminated without Cause (as defined in the 2016 ECIP), any unvested portion of the Retention Bonus will vest in full.
On December 30, 2019, in connection with his appointment as Interim Chief Executive Officer, Mr. Dodson entered into a letter agreement with the Company increasing his base salary to $575,000 during his tenure as Interim Chief Executive Officer and providing that, in the event the Board appoints someone other than Mr. Dodson as Chief Executive Officer of the Company and Mr. Dodson elects to terminate his employment at that time, he may accelerate the payment of the Retention Bonus, with such Retention Bonus to be paid in a lump sum cash payment on the next regularly scheduled payroll date following the earlier of July 1, 2020 and the date that is 60 days following Mr. Dodson’s notice of termination.
Katherine I. Hargis, Senior Vice President, General Counsel & Secretary
On May 1, 2019, the Compensation Committee approved certain amendments to the terms of the employment agreement between the Company and Katherine Hargis, the Company’s Senior Vice President, Chief Administrative Officer, General Counsel and Corporate Secretary , dated as of December 4, 2017, and authorized the amendment and restatement of such employment agreement, The amendments to Ms. Hargis’ employment agreement included an increase in annual base salary from $310,000 to $375,000 and an increase in Ms. Hargis’ target annual long-term incentive compensation award from $500,000 to $650,000, with such amended target long-term incentive award amount to be effective as of the Company’s next annual long-term incentive grant cycle for fiscal year 2020.
The amendments to Ms. Hargis’ employment agreement also eliminated her right to a gross-up for any excise taxes incurred in connection with a “change in control” of the Company and provide for amended treatment upon a termination of Ms. Hargis’ employment under certain circumstances. In the event that Ms. Hargis’ employment is terminated by the Company without Cause or due to Non-Renewal, by Ms. Hargis for Good Reason, or due to Death or Disability (as such terms are defined in her employment agreement),subject to Ms. Hargis’ execution and delivery of a release of claims in favor of the Company in accordance with her employment agreement, Ms. Hargis will be eligible to receive (i) a lump sum severance payment equal to two times annual base salary in a lump sum on the thirtieth day following termination, (ii) reimbursement for up to 12 months of medical and dental coverage, and (iii) accelerated vesting of all outstanding and unvested equity awards, with the vesting of any performance-based awards determined by the Board (or a committee thereof). In addition, in the event that Ms. Hargis’ employment is terminated by the Company without Cause or by Ms. Hargis with Good Reason within one year following a Change in Control of the Company (as defined the employment agreement), Ms. Hargis will also be eligible to receive any unpaid prior year bonus and a pro-rata annual bonus for the year of termination (determined at target).
On July 1, 2018, the Company entered into a retention bonus award agreement with Ms. Hargis providing for payment of a retention bonus (the “Retention Bonus”) in the amount of $310,000 with 25% of the bonus vesting July 1, 2019 and the remainder vesting July 1, 2020. In the event Ms. Hargis is terminated without Cause (as defined in the 2016 ECIP), any unvested portion of the Retention Bonus will vest in full.
Louis Coale, Vice President and Controller
On May 7, 2019, the Company entered into a Change of Control Agreement with Mr. Coale. providing Mr. Coale with the following severance payments and benefits in the event that he experiences an Involuntary Termination within one year following the date of a Change of Control of the Company (as such terms are defined in Mr. Coale’s Change of Control Agreement: (i) an amount equal to one and one half (1.5) times Mr. Coale’s base salary payable in a cash lump sum, (ii) any unpaid bonus for completed performance periods, (iii) a pro-rata annual bonus for the year of termination (determined at target), and (iv) reimbursement for 12 months of COBRA coverage. Mr. Coale’s receipt of the severance payments and benefits described in the foregoing sentence are subject to Mr. Coale’s execution and delivery of a release of claims in favor of the Company in accordance with the terms of his Change of Control Agreement. Mr. Coale’s Change of Control Agreement includes non-competition and non-solicitation of customers and employees obligations for one year following termination.
On November 18, 2019, the Company entered into a retention agreement with Mr. Coale providing for payment of a retention bonus of $60,000, pursuant to which the Company paid $30,000 on December 13, 2019 and will pay $30,000 on June
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1, 2020 if Mr. Coale is still employed with the Company on June 1, 2020. In the event Mr. Coale resigns his employment prior to June 1, 2019, the amount paid on December 13, 2019 is subject to clawback by the Company.
The following tables reflect the potential payments to which our Named Executive Officers (“NEOs”) would have been entitled upon termination of employment and/or a change in control event that occurred on December 31, 2019. The closing price of a share of our common stock on December 31, 2019, the last trading day of the year, was $0.10. The actual amounts to be paid out to executives upon termination can only be determined at the time of each NEO’s separation from Key.
Name | Non-Renewal (1) | For Cause or Voluntary Resignation (2) | Death (3) | Disability (4) | Without Cause or For Good Reason (5) | Change of Control (No Termination) (6) | Change of Control and Termination (7) | |||||||||||||||||||||
J. Marshall Dodson | ||||||||||||||||||||||||||||
Cash Severance | $ | 1,150,000 | $ | — | $ | — | $ | 575,000 | $ | 1,150,000 | $ | — | $ | 3,105,000 | ||||||||||||||
RSU(9) | $ | 21,818 | $ | — | $ | 21,818 | $ | 21,818 | $ | 21,818 | $ | — | $ | 21,818 | ||||||||||||||
Health & Welfare(10) | $ | 62,697 | $ | — | $ | 80,955 | $ | 83,595 | $ | 62,697 | $ | — | $ | 83,595 | ||||||||||||||
Retention(11) | $ | 478,125 | $ | — | $ | 478,125 | $ | 478,125 | $ | 478,125 | $ | — | $ | 478,125 | ||||||||||||||
LTI Cash Award(12) | $ | 54,247 | $ | — | $ | 54,247 | $ | 54,247 | $ | 54,247 | $ | — | $ | 54,247 | ||||||||||||||
Pro Rata Bonus(13) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Total Benefit | $ | 1,766,887 | $ | — | $ | 635,145 | $ | 1,212,785 | $ | 1,766,887 | $ | — | $ | 3,742,785 | ||||||||||||||
Name | Non-Renewal (1) | For Cause or Voluntary Resignation (2) | Death (3) | Disability (4) | Without Cause or For Good Reason (5) | Change of Control (No Termination) (6) | Change of Control and Termination (7) | |||||||||||||||||||||
Katherine Hargis | ||||||||||||||||||||||||||||
Cash Severance(8) | $ | 750,000 | $ | — | $ | 750,000 | $ | 750,000 | $ | 750,000 | $ | — | $ | 721,732 | ||||||||||||||
RSU(9) | $ | 6,917 | $ | — | $ | 6,917 | $ | 6,917 | $ | 6,917 | $ | — | $ | 6,917 | ||||||||||||||
Health & Welfare(10) | $ | 24,928 | $ | — | $ | 24,928 | $ | 24,928 | $ | 24,928 | $ | — | $ | 24,928 | ||||||||||||||
Retention(11) | $ | 232,500 | $ | — | $ | 232,500 | $ | 232,500 | $ | 232,500 | $ | — | $ | 232,500 | ||||||||||||||
LTI Cash Award(12) | $ | 54,247 | $ | — | $ | 54,247 | $ | 54,247 | $ | 54,247 | $ | — | $ | 54,247 | ||||||||||||||
Pro Rata Bonus(13) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 300,000 | ||||||||||||||
Total Benefit | $ | 1,068,592 | $ | — | $ | 1,068,592 | $ | 1,068,592 | $ | 1,068,592 | $ | — | $ | 1,340,324 | ||||||||||||||
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Name | Non-Renewal (1) | For Cause or Voluntary Resignation (2) | Death (3) | Disability (4) | Without Cause or For Good Reason (5) | Change of Control (No Termination) (6) | Change of Control and Termination (7) | |||||||||||||||||||||
Louis Coale | ||||||||||||||||||||||||||||
Cash Severance | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 360,000 | ||||||||||||||
RSU(9) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 3,583 | ||||||||||||||
Health & Welfare(10) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 15,504 | ||||||||||||||
Retention(11) | $ | — | $ | — | $ | 30,000 | $ | 30,000 | $ | 30,000 | $ | — | $ | 30,000 | ||||||||||||||
LTI Cash Award(12) | $ | — | $ | — | $ | 27,123 | $ | 27,123 | $ | 27,123 | $ | — | $ | 27,123 | ||||||||||||||
Pro Rata Bonus(13) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 120,000 | ||||||||||||||
Total Benefit | $ | — | $ | — | $ | 57,123 | $ | 57,123 | $ | 57,123 | $ | — | $ | 556,210 | ||||||||||||||
Name | Non-Renewal (1) | For Cause or Voluntary Resignation (2) | Death (3) | Disability (4) | Without Cause or For Good Reason (5) | Change of Control (No Termination) (6) | Change of Control and Termination (7) | |||||||||||||||||||||
Robert Saltiel(14) | ||||||||||||||||||||||||||||
Cash Severance | $ | — | $ | — | $ | — | $ | — | $ | 2,500,000 | $ | — | $ | — | ||||||||||||||
RSU(9) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Health & Welfare(10) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Retention(11) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
LTI Cash Award(12) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Pro Rata Bonus(13) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Total Benefit | $ | — | $ | — | $ | — | $ | — | $ | 2,500,000 | $ | — | $ | — | ||||||||||||||
Name | Non-Renewal (1) | For Cause or Voluntary Resignation (2) | Death (3) | Disability (4) | Without Cause or For Good Reason (5) | Change of Control (No Termination) (6) | Change of Control and Termination (7) | |||||||||||||||||||||
Scott Miller(14) | ||||||||||||||||||||||||||||
Cash Severance | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
RSU(9) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Health & Welfare(10) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Retention(11) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
LTI Cash Award(12) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Pro Rata Bonus(13) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Total Benefit | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
_________________________
(1) | Represents compensation payable if Key does not renew the NEO’s employment agreement after the initial term or an extension of the agreement. |
2) | Represents compensation payable if Key terminates the NEO’s employment for “Cause” or the NEO otherwise resigns without “Good Reason” as defined in the respective employment agreements. |
3) | Represents compensation due to the NEO’s estate upon his or her death. |
4) | Represents compensation payable to the NEO upon termination following determination of NEO’s permanent disability. |
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5) | Represents compensation due to the NEO if terminated by Key without “Cause” or, if the NEO resigns for “Good Reason,” as each such term is defined in the respective employment and equity agreements. |
6) | Represents payments due to the NEO in connection with a “Change of Control” (as defined in the respective employment agreements and equity agreements) in which the NEO is not terminated. |
7) | Represents payments due to the NEO if the NEO is terminated without “Cause” or for “Good Reason”, or for Mr. Coale’s Change of Control Agreement, pursuant to an “Involuntary Termination,” in connection with a “Change of Control” (as such terms are defined in the respective employment agreements and equity agreements). |
8) | It is of greater benefit to Ms. Hargis to have her change in control “Cash Severance” payments cutback to the Section 280G safe harbor in order to avoid paying the excise tax under this method. Accordingly, for purposes of this analysis, the value of Ms. Hargis’ “Cash Severance” shown above has been reduced by the applicable cutback as prescribed by her employment agreement |
9) | Represents the value of RSUs determined by multiplying the number of awards vesting by $0.10, the closing price on December 31, 2019. |
10) | Represents the value of health and welfare benefits at December 31, 2019 determined under each NEO’s employment or change of control agreement. |
11) | Represents the benefit of a retention award for Mr. Dodson and Ms. Hargis pursuant to a Retention Bonus Award Agreement dated July 1, 2018, and a retention award for Mr. Coale pursuant to a Retention Bonus Award Agreement dated November 18, 2019. |
12) | Represents the benefit of long term incentive cash for Messrs. Dodson and Coale and Ms. Hargis pursuant to a Long Term Incentive Cash Award dated February 4, 2019. |
13) | Represents annual incentive bonus prorated for the number of full months employed during the performance period (including the date of employment termination). |
14) | Messrs. Saltiel and Miller terminated employment with the Company on December 30, 2019 and April 1, 2019, respectively, and the amounts set forth in the table above represent the actual amounts paid in connection with each executive’s departure, if any, as permitted by SEC rules. |
15) | Represents amounts paid under the Separation and Release Agreement entered into between the Company and Mr. Saltiel in connection with his termination of employment pursuant to which Mr. Saltiel was paid $2,500,000 in a lump sum cash payment subject to the execution of a release of claims in favor of the Company. This payment was made in lieu of, and in settlement and full satisfaction of, any other payments or benefits (including any severance payments or benefits) under Mr. Saltiel’s employment agreement or any other agreement between him and the Company or that may otherwise have been due in connection with Mr. Saltiel’s termination of employment. |
Compensation Committee Interlocks and Insider Participation
The Compensation Committee consists of Messrs. Wommack, Quarls, Menkes and Kotzubei, all of whom are non-employee directors. None of the Compensation Committee members has served as an officer or employee of Key and none of Key’s executive officers has served as a member of a compensation committee or board of directors of any other entity that has an executive officer serving as a member of the Board.
2019 CEO Pay Ratio Calculations
As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, as amended (the “Dodd-Frank Act”), and SEC regulations, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of J. Marshall Dodson, who is currently serving as our Interim CEO. Under SEC regulations, when a company has multiple CEOs during the last completed fiscal year, it may elect to look at the CEO serving on the date it selects to identify the median employee and annualize that CEO’s compensation. The Company selected December 31, 2019 as the date to identify the median employee for purposes of the CEO pay ratio calculation, notwithstanding that this date differs from the date of determination used for last year’s calculation, in order to align this year’s calculation with the compensation of our current Interim CEO. Accordingly, the Company elected to look at Mr. Dodson’s compensation on December 31, 2019, and annualized his compensation, as described further below.
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For 2019, our last completed fiscal year:
• | The median of the annual total compensation of all employees of our Company (other than our Interim CEO) was $77,594. |
• | The total compensation of our CEO, on an annualized basis, would have been $1,272,501. |
• | Based on this information, for 2019 the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all employees was reasonably estimated to be 16 to 1. |
To identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our Interim CEO’s annualized, we took the following steps:
• | We determined that, as of December 31, 2019, our employee population consisted of approximately 1,961 individuals with all of these individuals located in the United States (as reported in Part I, Item 1 of this Form 10-K). This population consisted of our full-time, part-time, and temporary employees, as we do not have seasonal workers. |
• | We used a consistently applied compensation measure to identify our median employee of comparing the amount of salary or wages reflected in our payroll records as reported to the Internal Revenue Service on Form W-2 for 2019. We do not widely distribute annual equity awards to our employees, therefore such awards were excluded from our compensation measure. |
• | After we identified our median employee, we calculated the median employee’s annual total compensation using the same methodology that we used to determine our Interim CEO’s total compensation for the 2019 Summary Compensation Table, resulting in annual total compensation of $77,594. The difference between our median employee’s salary, wages and overtime pay and the employee’s annual total compensation represents the estimated value of such employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $294) for the 2019 year. |
• | With respect to the annual total compensation of our Interim CEO, we used his annualized compensation of $1,272,501. We determined his annualized compensation by assuming (i) $575,000 full-year base salary, (ii) $147,200 full-year target annual bonus, calculated by applying Mr. Dodson’s annual bonus opportunity as Interim CEO, as a percentage of base salary, to his increased base salary as Interim CEO and further modifying to reflect actual performance for NEO awards under the 2019 AIP, (iii) $310,251 for the full-year 2019 LTIP equity awards he received in 2019 plus $54,247, which represents a pro-rated portion of his 2019 Cash LTI Award that is forfeitable only in the event of a termination for Cause, (iv) $159,375 representing 25% of the retention bonus granted to Mr. Dodson on July 1, 2018, as discussed further in “Potential Payments Upon Termination or Change of Control”, and (v) $26,428 for the full-year insurance premiums and other expenses described in footnote 4 to the “All Other Compensation” column of our “Summary Compensation Table” above. |
Director Compensation
Pursuant to the compensation program for independent directors adopted by our Compensation Committee in connection with the Company’s reorganization, our independent directors received an annual fee equal to $125,000 in 2019. In addition, the independent directors also received an annual equity award of 20,833 shares, which, following the reverse stock split effective as of March 6, 2020 in connection with the Restructuring, equals a total of 417 shares (which for 2019 was granted in the form of RSUs), and are reimbursed for travel and other expenses directly associated with Key business. Additionally, the Lead Director receives a recurring annual retainer of an additional $20,000 per year for his service. All members of the Audit Committee, excluding the chair, receive an additional $10,000 per year for their service. All annual director fees are paid in quarterly installments.
The following table discloses the cash and equity awards earned, paid or awarded, as the case may be, to each of our non-employee directors during the fiscal year ended December 31, 2019. As a director who was also an employee, Mr. Saltiel received no additional compensation for his service as a director. Mr. Dodson, who is currently serving as our Interim Chief Executive Officer, received no additional compensation for his service as a director during the fiscal year ended December 31, 2019.
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Fees Earned or Paid in Cash ($) | Stock Awards ($) (1) | |||||
Name | Total ($) | |||||
C. Christopher Gaut(1) | $10,192 | $-- | $10,192 | |||
Scott D. Vogel(2) | $40,179 | $23,128 | $63,307 | |||
Sherman K. Edmiston III(2) | $135,000 | $45,624 | $180,624 | |||
H.H. Tripp Wommack, III(2) | $135,000 | $45,624 | $180,624 | |||
Steven H. Pruett(2) | $155,000 | $45,624 | $200,624 | |||
Paul T. Bader(2)(3) | $97,328 | $64,582 | $161,910 | |||
_________________________
(1) | Mr. Gaut resigned effective January 25, 2019, accordingly he did not receive a grant in 2019 and his director’s fees were paid in a pro-rated amount based on his service as a director during the first quarter of 2019. |
(2) | The February 4, 2019 grant to directors was made pursuant to the 2016 ECIP and consisted of 20,833 shares, which, following the reverse stock split effective as of March 6, 2020 in connection with the Restructuring, equals a total of 417 shares of RSUs granted to each non-employee director that vested in four equal quarterly installments beginning March 31, 2019. The grant date fair values of the RSUs set forth in this column are based on the closing price per share of our common stock on February 4, 2019, the grant date ($2.19) and are calculated in accordance with FASB ASC Topic 718. Mr. Vogel resigned effective April 26, 2019, and accordingly his stock awards vested in a pro-rated amount based on his service as a director during the first two quarters of 2019. In addition, and as stated above, Mr. Pruett, who was appointed Lead Director on January 25, 2019 after Mr. Gaut’s resignation, received an additional annual retainer for his service as Lead Director in the amount of $20,000. |
(3) | Mr. Bader was granted an award on May 10, 2019 which was made pursuant to the 2019 ECIP and consisted of 20,833 shares, which, following the reverse stock split effective as of March 6, 2020 in connection with the Restructuring, equals a total of 417 shares of RSUs that will vest in four equal quarterly installments beginning June 30, 2019. The grant date fair value of the RSUs set forth in this column is based on the closing price per share of our common stock on May 10, 2019, the grant date ($3.10) and is calculated in accordance with FASB ASC Topic 718. |
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Stock Ownership of Certain Beneficial Owners and Management
This section provides information about the beneficial ownership of our common stock by our directors and executive officers. The number of shares of our common stock beneficially owned by each person is determined under the rules of the SEC, and the information is not necessarily indicative of beneficial ownership for any other purpose. Under these rules, beneficial ownership includes any shares as to which the individual has sole or shared voting power or investment power and also any shares that the individual has the right to acquire within 60 days through the exercise of any stock options or other rights. Unless otherwise indicated, each person has sole investment and voting power, or shares such power with his or her spouse, with respect to the shares set forth in the following table. The inclusion in this table of any shares deemed beneficially owned does not constitute an admission of beneficial ownership of those shares.
The address for each person identified below is care of Key Energy Services, Inc., 1301 McKinney Street, Suite 1800, Houston, Texas 77010.
Throughout this Form 10-K, the individuals who served as our Principal Executive Officer and Principal Financial Officer during fiscal year 2019, and each of our other most highly compensated executive officers that are required to be in our executive compensation disclosures in fiscal year 2019 are referred to as the “Named Executive Officers” or “NEOs.”
Set forth below is certain information with respect to beneficial ownership of our common stock as of March 9, 2020 by each of our NEOs, each of our directors, as well as the directors and all executive officers as a group:
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Total Beneficial Ownership (1)(2) | Percent of Outstanding Shares (1)(2) | ||||||
Name of Beneficial Owner | |||||||
Non-Management Directors: | |||||||
Harry F. Quarls | — | * | |||||
Sherman K. Edmiston, III | 707 | * | |||||
H.H. Tripp Wommack, III | 688 | * | |||||
Alan B. Menkes | — | * | |||||
Marcus C. Rowland | — | * | |||||
Jacob Kotzubei | — | * | |||||
Named Executive Officers: | |||||||
J. Marshall Dodson (3) | 5,115 | * | |||||
Katherine I. Hargis (4) | 2,166 | * | |||||
Louis Coale (5) | 783 | * | |||||
Current Directors and NEOs as a group (14 Persons): | — | 3.75% | |||||
*Less than 1% | |||||||
(1) | Total beneficial ownership amounts give effect to the reverse stock split of the Company’s common stock effected on March 6, 2020 pursuant to which the Company’s total number of shares of common stock outstanding decreased from 20,659,654 to 413,258. An individual’s percentage ownership is based on 13,775,267 shares, which is comprised of the 413,258 shares outstanding immediately following the reverse stock split, plus the 13,367,009 shares issued to the Supporting Term Lenders pursuant to the RSA. |
(2) | Includes all shares with respect to which each director or executive officer directly or indirectly, through any contract, arrangement, understanding, relationship or otherwise, has or shares the power to vote or to direct voting of such shares and/or the power to dispose or to direct the disposition of such shares. Shares of common stock subject to stock options and warrants currently exercisable or exercisable within 60 days, are deemed outstanding for purposes of the percentage ownership of the person holding such securities but are not deemed outstanding for computing the percentage ownership of any other person. |
(3) | Includes 2,399 unvested restricted stock units. |
(4) | Includes 994 unvested restricted stock units. |
(5) | Includes 522 unvested restricted stock units. |
The following table sets forth certain information regarding the beneficial ownership of Common Stock by each person, other than our directors or executive officers, who is known by us to beneficially own more than 5% of the outstanding shares of our Common Stock.
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Shares Beneficially Owned | |||||
Name and Address of Beneficial Owner | Number | Percent (1) | |||
Goldman Sachs & Co. LLC(2) | 4,731,473 | 34.4 | % | ||
200 West Street | |||||
New York, NY 10282 | |||||
BlueMountain Capital Management, LLC(3) | 4,135,114 | 30.0 | % | ||
280 Park Avenue, 12th Floor | |||||
New York, NY 10017 | |||||
Black Rock, Inc.(4) | 2,245,994 | 16.3 | % | ||
55 East 22nd | |||||
New York, NY 10005 | |||||
Soter Capital, LLC(5) | 1,850,579 | 13.4 | % | ||
360 North Crescent Drive, South Building | |||||
Beverly Hills, CA 90210 | |||||
(1) | Percentage beneficially owned is based on 13,775,267 shares, which is comprised of the 413,258 shares outstanding immediately following the reverse stock split, plus the 13,367,009 shares issued to the Supporting Term Lenders pursuant to the RSA. |
(2) | Number of shares beneficially owned is based solely on the information contained within the Stockholders Agreement dated as of March 6, 2020, filed as an exhibit to this Annual Report on Form 10-K. Goldman Sachs & Co. LLC, a Delaware limited liability company (“Goldman Sachs”) is a member of the New York Stock Exchange and other national exchanges and a wholly-owned subsidiary of The Goldman Sachs Group, Inc., a Delaware corporation (“GS Group”). GS Group is a public entity and its common stock is publicly traded on the NYSE. GS Group may be deemed to beneficially own the securities held by Goldman Sachs. GS Group disclaims beneficial ownership of such securities to the extent of its pecuniary interest therein. The mailing address for Goldman Sachs is 200 West Street, New York, NY 10282. |
(3) | Number of shares beneficially owned is based solely on the information contained within the Stockholders Agreement dated as of March 6, 2020, filed as an exhibit to this Annual Report on Form 10-K, on behalf of each of (i) BlueMountain Capital Management, LLC, a Delaware limited liability company, (ii) BlueMountain GP Holdings, LLC, a Delaware limited liability company, (iii) BlueMountain Foinaven Master Fund L.P., a Cayman Islands exempted limited partnership, (iv) Blue Mountain Credit Alternatives Master Fund L.P., a Cayman Islands exempted limited partnership, (v) BlueMountain Guadalupe Peak Fund L.P., a Delaware limited partnership, (vi) BlueMountain Logan Opportunities Master Fund L.P., a Cayman Islands exempted limited partnership, (vii) BlueMountain Montenvers Master Fund SCA SICAV-SIF, an investment company with variable capital organized as a specialized investment fund in the form of a corporate partnership limited by shares under the laws of Luxembourg, (viii) BlueMountain Summit Trading L.P., a Delaware limited partnership, (ix) BlueMountain Timberline Ltd., a Cayman Islands exempted limited company, (x) BlueMountain Kicking Horse Fund L.P., a Cayman Islands exempted limited partnership, (xi) BlueMountain Foinaven GP, LLC, a Delaware limited liability company, (xii) Blue Mountain CA Master Fund GP, Ltd., a Cayman Islands exempted limited company, (xiii) BlueMountain Long/Short Credit GP, LLC, a Delaware limited liability company, (xiv) BlueMountain Logan Opportunities GP, LLC, a Delaware limited liability company, (xv) BlueMountain Montenvers GP S.à r.l., a private limited company incorporated under the laws of Luxembourg, (xvi) BlueMountain Summit Opportunities GP II, LLC, a Delaware limited liability company, (xvii) BlueMountain Kicking Horse Fund GP, LLC, a Delaware limited liability company and (xviii) Blue Mountain Credit GP, LLC, a Delaware limited liability company. The address of the foregoing entities is c/o BlueMountain Capital Management, LLC, 280 Park Avenue, 12th Floor, New York, NY 10017 |
(4) | Number of shares beneficially owned is based solely on the information contained within the Stockholders Agreement dated as of March 6, 2020, filed as an exhibit to this Annual Report on Form 10-K. The registered holders of the referenced shares are funds and accounts under management by investment adviser subsidiaries of BlackRock, Inc. BlackRock, Inc. is the ultimate parent holding company of such investment adviser entities. On behalf of such investment adviser entities, the applicable portfolio managers, as managing directors (or in other capacities) of such entities, and/or the applicable investment committee members of such funds and accounts, have voting and investment power over the shares held by |
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the funds and accounts which are the registered holders of the referenced shares. Such portfolio managers and/or investment committee members expressly disclaim beneficial ownership of all shares held by such funds and accounts. The address of such funds and accounts, such investment adviser subsidiaries and such portfolio managers and/or investment committee members is either 55 East 52nd Street, New York, NY 10055 or 2951 28th Street, Suite 1000, Santa Monica, CA 90405
(5) | Number of shares beneficially owned is based solely on the information contained within the Stockholders Agreement dated as of March 6, 2020, filed as an exhibit to this Annual Report on Form 10-K, on behalf of each of: (i) Soter Capital, LLC, a Delaware limited liability company, (ii) Soter Capital Holdings, LLC, a Delaware limited liability company, (iii) PE Soter Holdings, LLC, a Delaware limited liability company, (iv) Platinum Equity Capital Soter Partners, L.P., a Delaware limited partnership, (v) Platinum Equity Partners III, LLC, a Delaware limited liability company, (vi) Platinum Equity Investment Holdings III, LLC, a Delaware limited liability company, (vii) Platinum Equity InvestCo, L.P., a Cayman Islands limited partnership, (viii) Platinum Equity Investment Holdings IC (Cayman), LLC, a Delaware limited liability company, (ix) Platinum InvestCo (Cayman), LLC, a Cayman Islands limited liability company (x) Platinum Equity Investment Holdings, LLC, a Delaware limited liability company, (xi) Platinum Equity Investment Holdings III Manager, LLC, a Delaware limited liability company, (xii) Platinum Equity, LLC, a Delaware limited liability company and (xiii) Tom Gores, an individual. |
We have not made any independent determination as to the beneficial ownership of each stockholder, and are not restricted in any determination we may make by reason of inclusion of such stockholder or its shares in this table.
Delinquent Section 16(A) Reports
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers and persons who beneficially own more than 10% of a registered class of our equity securities, to file initial reports of ownership on Form 3 and changes in ownership on Forms 4 or 5 with the SEC. Such officers, directors and 10% stockholders also are required by SEC rules to furnish Key with copies of all Section 16(a) reports they file. Based solely on its review of the copies of such forms furnished or available to us, we believe that our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements for the fiscal year ended December 31, 2019. In making these statements, we have relied upon an examination of the copies of Forms 3, 4 and 5, and amendments thereto, and the written representations of our directors, executive officers and 10% stockholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Prior Term Loan Facility
Affiliates of each of Soter and the Contrarian Funds were term lenders under our Prior Term Loan Facility (both before and following the Restructuring, affiliates of Soter owned more than 5% of the outstanding shares of our common stock, and before the Restructuring affiliates of the Contrarian Funds owned more than 5% of the outstanding shares of our common stock). Affiliates of Soter held $XX million and affiliates of the Contrarian Funds held $1.25 million, respectively, of the outstanding principal amount of the Prior Term Loan Facility at the time of the Restructuring. During the year ended December 31, 2019, the borrowings under the Prior Term Loan Facility bore a weighted average interest rate of 13.11%.
Pursuant to the RSA and an exchange agreement entered into at the time of closing of the Restructuring, the Company exchanged approximately $241.9 million aggregate outstanding principal of term loans (together with accrued interest thereon) held by Supporting Term Lenders, including the affiliates of Soter, under the Prior Term Loan Facility into (i) 13,699,667 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) and (ii) $20 million of term loans under the New Term Loan Facility, each on a pro rata basis based on their holdings of term loans under the Prior Term Loan Facility. Affiliates of the Contrarian Funds continued to hold their principal amount in a senior secured term loan tranche under the New Term Loan Facility.
New Term Loan Facility
Each of the Supporting Term Lenders is a lender under our New Term Loan Facility (following the Restructuring, each of the Supporting Term Lenders or its affiliates owns more than 5% of the outstanding shares of our common stock). The New Term Loan Facility includes a $50 million senior secured term loan, of which $30 million was funded with new cash proceeds provided by the Supporting Term Lenders and $20 million was issued in exchange for the existing term loans held by the Supporting Term Lenders. The New Term Loan Facility will mature 5.5 years after the closing date. Soter provided $7.5 million of the $30 million of new funding under the New Term Loan Facility and the Supporting Term Lenders provided the rest of
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such $30 million on a pro rata basis based on their holdings of existing term loans. Borrowings under the New Term Loan Facility bear interest at an annual rate equal to LIBOR plus 10.25%.
Stockholders Agreement
At the closing of the Restructuring, the Company and the Supporting Term Lenders entered into the Stockholders Agreement 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 held 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 held between 10% and 25% of the Company’s outstanding shares as of the closing of the Restructuring are entitled to nominate one director. In addition, pursuant to the Stockholders Agreement, Supporting Term Lenders are entitled to appoint a non-voting board observer subject to specified ownership thresholds. The Stockholders Agreement contains customary registration and information rights in favor of the Supporting Term Lenders and, in the event the Company does not file reports with the SEC, customary tag-along, drag-along and preemptive rights.
Corporate Advisory Services Agreement
On December 15, 2016, the Company entered into a corporate advisory services agreement (the “CASA”) with Platinum, an affiliate of Soter. Pursuant to the CASA, Platinum provided certain business advisory services to Key in consideration for an advisory fee of $2.75 million per year (subject to certain limitations and adjustments). In addition, Key reimbursed Platinum for ordinary course, reasonable and documented out-of-pocket expenses of up to an aggregate amount of $375,000, on an annual basis, subject to certain limitations. The CASA expired by its terms on December 31, 2019. No advisory fee was paid to Platinum in cash during the course of the CASA and, at expiration, accrued fees payable to Platinum amounted to $8.25 million. In connection with the closing of the Restructuring, the Company and Platinum entered into agreements pursuant to which Platinum agreed to release the Company from the $8.25 million accrued fees payable obligation and Platinum received the potential right to payment of $4.0 million upon the occurrence of certain reorganization events involving the Company.
Review and Approval Policies and Procedures for Related Party Transactions
On November 2, 2018, our Board adopted our Related Party Transaction Policy. The Related Party Transaction Policy prohibits the Company from entering any transaction with certain affiliates for an amount exceeding $120,000 during the fiscal year in which such affiliate has a direct or indirect material interest, unless the transaction is approved or ratified by our Audit Committee. For this purpose, affiliates include directors (including director nominees), executive officers, people known to the Company to own more than 5% of the Company’s voting securities, and immediate family members of any of the foregoing. In addition, certain categories of transactions are exempted from review under the Related Party Transaction Policy, including certain indemnification payments, ordinary course business expenses and reimbursements, compensation to directors and executive officers in their capacity as such, and arm’s length transactions with Platinum or certain of its affiliates if the aggregate transaction value is less than $1 million per calendar year. When determining whether to approve a related party transaction, the Audit Committee must consider, among other factors, whether the terms of the transaction are fair to the Company, whether there are business reasons for the Company to enter the transaction, whether the transaction would impair the independence of an outside director under NYSE rules, the dollar amount involved, reputational issues, and whether the transaction would present an improper conflict of interest.
In addition, we require each of our directors and executive officers to complete an annual Directors and Officers Questionnaire to describe certain information and relationships (including those involving their immediate family members) that may be required to be disclosed in our Form 10-K, annual proxy statement and other filings with the SEC. Director nominees and newly appointed executive officers must complete the questionnaire at or before the time they are nominated or appointed. Directors and executive officers must immediately report to Key any changes to the information reported in their questionnaires arising throughout the year, including changes in relationships between immediate family members and Key, compensation paid from third parties for services rendered to Key not otherwise disclosed, interests in certain transactions and other facts that could affect director independence. Directors are required to disclose in the questionnaire, among other things, any transaction that the director or any immediate family member has entered into with Key or relationships that a director or an immediate family member has with Key, whether direct or indirect. This information is provided to our legal department for review and, if required, submitted to the Board for the process of determining independence.
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ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
Fees of Independent Registered Public Accounting Firm
Audit Fees
The following table sets forth the fees for the fiscal period to which the fees relate. The Audit Committee approved all such fees in accordance with the Audit and Non-Audit Services Pre-Approval Policy described below.
2019 | 2018 | |||||
Audit fees | $ | 1,073,318 | $ | 1,079,402 | ||
Audit-related fees | — | — | ||||
Tax fees | — | — | ||||
All other fees | — | — | ||||
Total | $ | 1,073,318 | $ | 1,079,402 | ||
Audit fees consist of professional services rendered for the audit of our annual financial statements, the audit of the effectiveness of our internal control over financial reporting and the reviews of the quarterly financial statements. This category also includes fees for issuance of comfort letters, consents, assistance with and review of documents filed with the SEC, statutory audit fees, work done by tax professionals in connection with the audit and quarterly reviews and accounting consultations and research work necessary to comply with the standards of the Public Company Accounting Oversight Board. Fees are generally presented in the period to which they relate as opposed to the period in which they were billed. Other services performed include certain advisory services and do not include any fees for financial information systems design and implementation.
Policy for Pre-Approval of Audit and Non-Audit Fees
The Audit Committee has an Audit and Non-Audit Services Pre-Approval Policy. The policy requires the Audit Committee to pre-approve the audit and non-audit services performed by our independent registered public accounting firm. Under the policy, the Audit Committee establishes the audit, audit-related, tax and all other services that have the approval of the Audit Committee. The term of any such pre-approval is twelve months from the date of pre-approval, unless the Audit Committee adopts a shorter period and so states. The Audit Committee will periodically review the list of pre-approved services and will add to or subtract from the list of pre-approved services from time to time. The Audit Committee will also establish annually pre-approval fee levels or budgeted amounts for all services to be provided by the independent registered public accounting firm. Any proposed services exceeding these levels or amounts will require specific pre-approval by the Audit Committee.
The Audit Committee has delegated to its chair the authority to pre-approve services, not previously pre-approved by the Audit Committee, that involve aggregate payments (with respect to each such service or group of related services) of $50,000 or less. The chair will report any such pre-approval to the Audit Committee at its next scheduled meeting.
The policy contains procedures for a determination by the CFO that proposed services are included within the list of services that have received pre-approval of the Audit Committee. Proposed services that require specific approval by the Audit Committee must be submitted jointly by the independent registered public accounting firm and the CFO and must include backup statements and documentation regarding the proposed services and whether the proposed services are consistent with SEC and NYSE rules on auditor independence.
Report of the Audit Committee
The Audit Committee reviewed and discussed the Company’s audited consolidated financial statements for the year ended December 31, 2019 with management and with Grant Thornton LLP, the Company’s independent registered public accounting firm. The Audit Committee has also received from, and discussed with, Grant Thornton LLP, the Company’s independent registered public accounting firm, various communications that the Company’s independent registered public accounting firm is required to provide to the Audit Committee and has discussed with Grant Thornton LLP the matters required to be discussed by the applicable requirements of the Public Company Accounting Oversight Board (“PCAOB”) and the SEC.
The Company’s independent registered public accounting firm also provided the Audit Committee with the written disclosures and the letter required by applicable requirements of the PCAOB regarding Grant Thornton LLP’s communication
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with the Audit Committee concerning independence. The Audit Committee has discussed with the independent registered public accounting firm their independence from Key.
As set forth in the Audit Committee charter, it is not the responsibility of the Audit Committee to plan or conduct audits or to determine that the Company’s financial statements and disclosures are complete and accurate and are in accordance with GAAP and applicable laws, rules and regulations. It is furthermore not the responsibility of the Audit Committee to maintain the accounting and financial reporting principles and policies and internal controls and procedures that provide for compliance with accounting standards and applicable laws and regulations, or to plan and carry out the audit of the Company’s internal control over financial reporting. These are the responsibilities of management, the internal auditor and the independent registered public accounting firm.
Furthermore, the members of the Audit Committee are not full-time employees of the Company and are not performing the functions of auditors or accountants. As such, it is not the responsibility of the Audit Committee or its members to conduct “field work” or other types of auditing or accounting reviews or procedures or to set auditor independence standards. Members of the Audit Committee necessarily rely on the information provided to them by management and the independent registered public accounting firm. Accordingly, the Audit Committee’s considerations and discussions referred to above do not assure that the audits of the Company’s financial statements and internal control over financial reporting have been carried out in accordance with generally accepted auditing standards, that the financial statements are presented in accordance with GAAP or that the Company’s auditors are in fact “independent.”
Based on the reports and discussions described in this report, and subject to the limitations on the role and responsibilities of the Audit Committee referred to above and in the Audit Committee charter, the Audit Committee recommended to the Board of Directors of the Company that the audited financial statements be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2019.
By the Audit Committee of the Board of Directors | |
Marcus C. Rowland, Chair Sherman K. Edmiston, III H.H. “Tripp” Wommack, III | |
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
The following financial statements and exhibits are filed as part of this report:
1. Financial Statements — See “Index to Consolidated Financial Statements” at Page 41.
2. We have omitted all financial statement schedules because they are not required or are not applicable, or the required information is shown in the financial statements or the notes to the financial statements.
3. Exhibits
The Exhibit Index, which follows the signature pages to this report and is incorporated by reference herein, sets forth a list of exhibits to this report.
ITEM 16. FORM 10-K SUMMARY
Not applicable.
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EXHIBIT INDEX
Exhibit No. | Description | |
3.1 | ||
3.2 | ||
4.1.1 | ||
4.1.2 | ||
4.1.3 | ||
4.1.4 | ||
4.1.5 | ||
4.2.1* | ||
4.2.2 | ||
4.2.3 | ||
4.3* | ||
10.1 | ||
10.2.1 | ||
10.2.2* | ||
10.3* | ||
10.4* | ||
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Exhibit No. | Description | |
10.5.1† | ||
10.5.2† | Key Energy Services, Inc. 2015 Equity and Cash Incentive Plan. (Incorporated by reference to Exhibit 10.1 to our registration statement on Form S-8 filed on December 19, 2016, File No. 333-215175.) | |
10.5.3† | ||
10.5.4† | ||
10.5.5† | ||
10.5.6† | ||
10.5.7† | ||
10.5.8† | ||
10.5.9† | ||
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Exhibit No. | Description | |
10.5.10† | ||
10.5.11† | ||
10.5.12† | ||
10.5.13† | ||
10.5.14† | ||
10.5.15† | ||
10.5.16† | ||
10.5.17† | ||
10.5.18† | ||
10.5.19† | ||
10.5.20† | ||
10.5.21†* | ||
10.5.22†* | ||
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Exhibit No. | Description | |
10.6.1 | ||
10.6.2 | ||
10.6.3 | ||
10.6.4 | ||
10.7† | ||
21.1* | ||
23.1* | ||
31.1* | ||
31.2* | ||
32* | ||
101.INS* | XBRL Instance Document | |
101.SCH* | XBRL Taxonomy Extension Schema Document | |
101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document | |
104 | Cover Page Interactive Data File | |
† | Indicates a management contract or compensatory plan, contract or arrangement in which any Director or any Executive Officer participates. | |
* | Filed herewith. | |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
KEY ENERGY SERVICES, INC.
Date: | March 12, 2020 | By: | /s/ J. MARSHALL DODSON | |
J. Marshall Dodson, | ||||
Interim Chief Executive Officer, Senior Vice President and Chief Financial Officer (As duly authorized officer and Principal Financial Officer) | ||||
POWER OF ATTORNEY
Each person whose signature appears below hereby constitutes and appoints J. Marshall Dodson, and him, his true and lawful attorney-in-fact and agent, with full powers of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting to said attorneys-in-fact, and each of them, full power and authority to perform any other act on behalf of the undersigned required to be done in connection therewith.
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in their capacities and on March 12, 2020.
Signature | Title | |
/s/ HARRY QUARLS | Chairman | |
Harry Quarls | ||
/s/ J. MARSHALL DODSON | Senior Vice President, Chief Financial Officer and Interim Chief Executive Officer | |
J. Marshall Dodson | (Principal Financial and Executive Officer) | |
/s/ LOUIS COALE | Vice President and Controller | |
Louis Coale | (Principal Accounting Officer) | |
/s/ ALAN MENKES | Director | |
Alan Menkes | ||
/s/ H.H. TRIPP WOMMACK, III | Director | |
H.H. Tripp Wommack, III | ||
/s/ JACOB KOTZUBEI | Director | |
Jacob Kotzubei | ||
/s/ MARCUS ROWLAND | Director | |
Marcus Rowland | ||
/s/ SHERMAN K. EDMISTON, III | Director | |
Sherman K. Edmiston, III | ||
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