Independence Contract Drilling 10K 2023 Annual report

Independence Contract Drilling (ICDIQ) 10-K2023 FY Annual report

Content analysis

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K


☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023


☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-36590

INDEPENDENCE CONTRACT DRILLING, INC.

(Exact name of registrant as specified in its charter)


Delaware		37-1653648
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

20475 State Highway 249, Suite 300
Houston, Texas		77070
(Address of principal executive offices)		(Zip code)

(281) 598-1230

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of Each Class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 par value per share	ICD	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer	☐	Accelerated filer	☐

Non-accelerated filer	☑	Smaller reporting company	☑

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. Yes ☐ No ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was approximately $28,977,915 as of June 30, 2023, the last business day of the registrant’s most recently completed second fiscal quarter (based on a closing price of $2.73 per share as reported on the New York Stock Exchange and 10,614,621 shares held by non-affiliates).

There were 15,266,773 shares of the registrant’s common stock outstanding as of February 27, 2024.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the registrant’s 2024 Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) are incorporated by reference into Part III of this Annual Report on Form 10 - K.

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INDEPENDENCE CONTRACT DRILLING, INC.

Index to Form 10-K

Part I	5
Item 1. Business	5
Item 1A. Risk Factors	14
Item 1B. Unresolved Staff Comments	28
Item 1C. Cybersecurity	28
Item 2. Properties	30
Item 3. Legal Proceedings	30
Item 4. Mine Safety Disclosures	30
Part II	31
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6. [Reserved]	32
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	47
Item 8. Financial Statements and Supplementary Data	48
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	82
Item 9A. Controls and Procedures	82
Item 9B. Other Information	82
Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections	83
Part III	83
Item 10. Directors, Executive Officers and Corporate Governance	83
Item 11. Executive Compensation	83
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters	83
Item 13. Certain Relationships and Related Transactions, and Director Independence	83
Item 14. Principal Accounting Fees and Services	83
Part IV	84
Item 15. Exhibits, Financial Statement Schedules	84
Item 16. Form 10-K Summary	84
Signatures	85

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this Annual Report on Form 10-K, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal,” “will” or other words that convey the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. These risks, contingencies and uncertainties include, but are not limited to, the following:

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a decline in or substantial volatility of crude oil and natural gas commodity prices;

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a decrease in domestic spending by the oil and natural gas exploration and production industry;

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fluctuation of our operating results and volatility of our industry;

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inability to maintain or increase pricing of our contract drilling services, or early termination of any term contract for which early termination compensation is not paid;

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our backlog of term contracts declining rapidly;

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the loss of any of our customers, customer consolidations, financial distress or management changes of potential customers or failure to obtain contract renewals and additional customer contracts for our drilling services;

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overcapacity and competition in our industry;

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an increase in interest rates and deterioration in the credit markets;

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our inability to comply with the financial and other covenants in debt agreements;

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unanticipated costs, delays and other difficulties in executing our long-term growth strategy;

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the loss of key management personnel;

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new technology that may cause our drilling methods or equipment to become less competitive;

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labor costs or shortages of skilled workers;

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the loss of or interruption in operations of one or more key vendors;

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the effect of operating hazards and severe weather on our rigs, facilities, business, operations and financial results, and limitations on our insurance coverage;

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restrictive covenants under our debt agreements limiting our ability to conduct our operations;

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inability to obtain consents from the holders of our convertible notes necessary to maintain operations of our drilling rigs;

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increased regulation of drilling in unconventional formations;

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risks related to the ongoing conflict between Russia and Ukraine and conflict in Gaza, including the effects of related sanctions and supply chain disruptions or general effects on the global economy;

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risks associated with a global pandemic that would cause a reduction in economic activity or reduction in oil and natural gas demand or prices;

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the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment; and

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the potential failure by us to establish and maintain effective internal control over financial reporting and cybersecurity risks.

All forward-looking statements are necessarily only estimates of future results, and there can be no assurance that actual results will not differ materially from expectations, and, therefore, you are cautioned not to place undue reliance on such statements. Any forward-looking statements are qualified in their entirety by reference to the factors discussed throughout this Annual Report on Form 10-K, including those described in (1) Part I, “Item 1A. Risk Factors” and (2) Part II, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” Further, any forward-looking statement speaks only as of the date on which it is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events.

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PART I

ITEM 1. BUSINESS

Overview

Except as expressly stated or the context otherwise requires, the terms “we,” “us,” “our,” the “Company” and “ICD” refer to Independence Contract Drilling, Inc. and its subsidiary.

We were incorporated in Delaware on November 4, 2011. We provide land-based contract drilling services for oil and natural gas producers targeting unconventional resource plays in the United States. We own and operate a premium fleet comprised of modern, technologically advanced drilling rigs.

Our rig fleet includes 26 pad-optimal, superspec AC powered (“AC”) rigs. We currently focus our operations on unconventional resource plays located in geographic regions that we can efficiently support from our Houston, Texas and Midland, Texas facilities in order to maximize economies of scale. Currently, our rigs are operating in the Permian Basin and the Haynesville Shale; however, our rigs have previously operated in the Eagle Ford Shale, Mid-Continent and Eaglebine regions as well.

Our business depends on the level of exploration and production activity by oil and natural gas companies operating in the United States, and in particular, the regions where we actively market our contract drilling services. The oil and natural gas exploration and production industry is historically cyclical and characterized by significant changes in the levels of exploration and development activities. Oil and natural gas prices and market expectations of potential changes in those prices significantly affect the levels of those activities. Worldwide political, regulatory, economic, and military events, as well as natural disasters have contributed to oil and natural gas price volatility historically and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities in the United States and the regions where we market our contract drilling services, whether resulting from changes in oil and natural gas prices or otherwise, could materially and adversely affect our business.

Our principal executive offices are located at 20475 Hwy 249, Houston, Texas 77070. Our common stock is traded on the NYSE under the symbol “ICD.”

Industry Trends

Super-Spec, Pad Optimal Equipment

Cost-effective development drilling in a manufacturing wellbore model requires more complex well designs, shorter cycle times, and the use of innovative technology in order to reduce an E&P company’s overall field development costs. Drilling rigs that are designed to maximize drilling efficiency, reduce cycle times, maximize energy efficiency, increase penetration rates while drilling, and drill longer-reach horizontal wells will reduce an E&P company’s overall field development costs and provide them with greater optionality when designing their field development program.

We believe that E&P companies drilling horizontal wells increasingly demand not only AC rigs that are optimal for horizontal drilling, but premium Super-Spec, Pad Optimal AC rigs such as our ShaleDriller rigs. All of our marketed drilling fleet is comprised of Super-Spec, Pad Optimal rigs. The following describes the minimum characteristics of a super-spec, pad optimal rig:

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AC Programmable. AC rigs use a variable frequency drive that allows precise computer control of motor speed during operations. This greater control of motor speed provides more precise drilling of the wellbore. Among other attributes, when compared to electrical SCR rigs and mechanical rigs, AC rigs are electrically more efficient, produce consistent torque, utilize regenerative braking, and have digital controls and AC motors that require less maintenance. AC rigs allow our customers to drill faster, which, in general, eliminates reservoir permeability damage, and to drill wellbores that more precisely track planned

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trajectories without doglegs. This, in turn, minimizes open hole time and enables our customers to more effectively and efficiently run casing, cement and successfully complete their wells.

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Pad Optimized, Omni-Directional Walking System. Omni-directional walking systems are designed to optimize pad drilling economics for our customers. Pad drilling involves the drilling of multiple wells from a single location, which provides benefits to the E&P company in the form of cost savings and accelerated cash flows. Our walking rigs move in any direction quickly between wellheads, rapidly and efficiently adjust to misaligned wellbores, walk over raised wellheads, and increase operational safety due to fewer required rig up and rig down movements.

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Efficient Mobilization Between Drilling Sites. A rig that can rapidly move between drilling sites has become increasingly desired by, and impactful to, E&P companies because it reduces cycle times allowing them to drill more wells in the same period of time. Our ShaleDriller rigs move rapidly on conventional rig moves between drilling sites.

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1500-HP Drawworks. 1500-HP drawworks are well suited for the development of the vast majority of our customers’ unconventional resource assets. Compared to a 1000-HP or smaller rig, a 1500-HP rig has superior capability to handle extended drill string lengths required to drill long horizontal wells, which are becoming more common in the markets we serve.

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Three Mud-Pump/4^th Engine Systems. The drilling of longer laterals necessitates the use of higher-pressure mud pumps to pump fluids through significantly longer wellbores. The competitive advantage of higher-pressure mud pumps grows as the lateral length gets longer, as only high-pressure pumps can effectively address the severe pressure drop while providing the required hydraulic horsepower at the bit face and sufficient flow to remove drill cuttings and keep the hole clean. All of our ShaleDriller rigs are equipped with three simultaneously operating 7500psi mud pumps powered by four engines.

We refer to our rigs that meet the minimum characteristics of a super-spec, pad optimal rig described above as our 200 Series rigs. However, in addition to these minimum characteristics, we believe E&P operators also increasingly desire drilling contractors with the ability to provide other flexible and varying equipment packages depending upon the specific nature of their drilling program and their field-development plans. Such equipment package options include greater setback capacity allowing efficient drilling of ultra-long horizontal laterals, high-torque top drives and high-torque iron roughnecks capable of handling larger diameter drill pipe and premium threaded connections. We refer to our ShaleDriller fleet that is outfitted with one or more of these additional equipment packages as our 300 Series rigs.

There has been a growing demand for rigs meeting the characteristics of our 300 Series rigs and in response we began converting our 200 Series rigs equipment packages to 300 Series specification in late 2022. In response to customer demand, these conversions accelerated significantly during the later part of 2023, with the Company having performed four conversions during the past five months. As a result, the Company currently has only one 200 Series rig operating with over 90% of its current operating fleet being classified as 300 Series rigs. This compares to only 50% of its operating fleet being classified as 300 Series rigs as of January 1, 2023.

Shift to Manufacturing Wellbore Model

As a result of significant investments made in unconventional resource plays, exploration and production ("E&P") companies are now focused on developing these investments in a systematic manner. Efficient development of these resource plays involves drilling programs requiring large numbers of wells to be drilled in succession, as opposed to a single or a few wells designed to delineate a field or hold a lease. We view this as analogous to a manufacturing process that requires an engineered program and is focused on economies of scale to reduce overall field development costs. Cost-effective development drilling requires more complex well designs, shorter cycle times, and the use of innovative technology in order to reduce an E&P company’s overall field development costs.

One method in which an E&P operator may reduce overall field development costs is through the use of a multi-well pad development program. Pad drilling involves the drilling of multiple wells from a single location, which provides benefits to the E&P company in the form of per well cost savings and accelerated cash flows as compared to non-pad developments. These cost savings result from reduced time required to move the rig between wells, centralized

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hydraulic fracturing operations and the efficient installation of central production facilities and pipelines. In addition, by performing drilling operations on one well with simultaneous completion operations on a second well, operators do not need to wait until drilling on the entire pad is complete to begin earning a return on their investment. Pad drilling promotes “manufacturing” efficiencies by enabling “batch” drilling, whereby an operator drills all of the wells’ surface holes as the first batch, then drills all of the intermediate sections as the second batch, and concludes with the drilling of all of the laterals as the final batch. Efficiencies are created because hole sizes change less frequently, and operators use the same mud system and tools repeatedly. We believe as operators have shifted over time to horizontal drilling, they have implemented pad drilling in order to maximize economics and optimize development plans. In order to maximize the efficiencies gained from pad drilling, a rig must be capable of moving quickly from one well to another and be able to address the complexities associated with the growing number of wells per pad. In addition to quickly moving from well to well, omni-directional walking systems are ideally suited for pad drilling because they are capable of efficiently addressing situations on a pad in which wellbores are not precisely aligned or when level variations exist on the pad, which becomes increasingly likely as pads become larger and more complex.

Another method utilized by operators to increase efficiencies and maximize well economics is the drilling of longer lateral horizontal wells. Operators in our target areas have continued to increase the lateral length of their horizontal wells. Longer laterals provide greater production zones as the portion of the wellbore that passes through the target formation increases, optimizing the impact of hydraulic fracturing and stimulation. The drilling of longer laterals necessitates the use of increased horsepower drawworks and top drive systems, which provide maximum torque and rotational control and allows the operator to maintain the integrity of its drilling plan throughout the wellbore. Additionally, higher pressure mud pumps are required to pump fluids through significantly longer wellbores. The competitive advantage of higher pressure mud pumps grows as the lateral length increases, as only high pressure pumps can effectively address the severe pressure drop, while providing the required hydraulic horsepower at the bit face and sufficient flow to remove drill cuttings and keep the hole clean.

Customer Contracts and Backlog

Drilling contracts are obtained through competitive bidding or as a result of negotiations with customers and may cover multi-well and multi-year projects. Each of our rigs operates under a separate drilling contract or drilling order subject to a master drilling contract. We perform drilling services on a “daywork” contract basis, under which we charge a specified rate per day. The dayrate under each of our contracts is a negotiated price determined by the location, depth and complexity of the wells to be drilled, operating conditions, the duration of the contract, and market conditions. We have not accepted, and do not anticipate entering into, any “turn-key” (fixed sum to deliver a hole to a stated depth) or “footage” (fixed rate per foot of hole drilled) contracts. The duration of land drilling contracts can vary from “well-to-well” or to a fixed term ranging from a few months to several years. The revenue generated by a rig in a given year is the product of the dayrate fee and the number of days the rig is earning this fee based on activity and the terms of the contract, referred to as utilization. “Well-to-well” contracts are typically cancelable at the option of either party upon the completion of drilling at a particular site. Fixed-term contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to the drilling contractor if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, the drilling contractor’s bankruptcy, sustained unacceptable performance by the drilling contractor or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the drilling contractor. Drilling contracts also contain provisions regarding indemnification against certain types of claims involving injury to persons, property and for acts of pollution, which are subject to negotiation on a contract-by-contract basis.

Under a typical daywork contract, we earn a dayrate fee while the rig is operating, and we earn a moving rate fee while the rig is moving between wells or drilling locations under the contract. If the rig is on standby or is not drilling due to a force majeure event unrelated to damage to the rig, contracts typically provide that we earn a rate during this period of time, which rate may be equal to or less than the operating rate.

Mobilization rates are determined by market conditions and are generally reimbursed by the customer. In most instances, contracts typically provide for additional payments associated with the initial mobilization of a drilling rig and, in certain circumstances, we receive a demobilization fee at the end of the contract term equal to the estimated cost to transport the rig from the final drilling location and to compensate us for the estimated demobilization time.

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Drilling contracts typically provide that the contractor continues to earn the operating dayrate while a rig is not operating but under repair or maintenance, so long as the non-operating time due to repair and maintenance does not exceed a specified number of hours in a given day or calendar month.

As of December 31, 2023, our backlog of term contracts with original terms of six months or more was $82.9 million, of which $62.0 million is expected to be realized during 2024 and $20.9 million is expected to be realized during 2025. Our backlog does not include potential reductions in rates for unscheduled standby during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of contractually allowed downtime. It also does not include increases in rates for the billing of ancillary services under the contract, if such ancillary “adder” services are periodic in nature and are not expected to occur on a daily basis over the term of the contract. In addition, rigs under term contracts may realize revenue on a standby-without-crew basis, which allows us to preserve our expected cash margins from the contract but reduces our overall top line revenue. To the extent that we have rigs under term contracts operating on a standby or standby-without-crew basis, our top line revenues will be less than our reported backlog from term contracts.

Our Customers

Customers for contract drilling services in the United States include major oil and natural gas companies, independent oil and natural gas companies, as well as numerous small to mid-sized publicly-traded and privately held oil and natural gas companies. We market our contract drilling services to all such customers. During 2023, our customer representing more than 10% of our revenues was Endeavor Energy Resources.

Industry/Competition

To a large degree, our business depends on the level of capital spending by oil and natural gas companies for exploration, development and production activities. A sustained increase or decrease in the price of oil and natural gas could have a material impact on the exploration, development and production activities of our customers and could materially affect our financial position, results of operations and cash flows.

The contract drilling industry is highly competitive and has become even more so under current market conditions. The price for contract drilling services is a key competitive factor in the United States land contract drilling markets, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe the principal competitive factors in our markets are availability and condition of equipment, efficiency of equipment, quality of personnel, service quality, experience and safety record.

Many of our competitors are larger, publicly-held corporations with significantly greater resources and longer operating histories than us. Our largest competitors for high-end AC land drilling contract services are Helmerich & Payne, Inc., Patterson-UTI Energy, Inc., Nabors Industries, Ltd. and Precision Drilling Corporation.

Many of our larger competitors are able to offer ancillary products and services with their contract drilling services, and recently, some of our larger competitors have begun integrating and offering contract drilling services in connection with directional drilling and other services that we do not offer.

Government and Environmental Regulation

All of our operations and facilities are subject to numerous federal, state and local laws, rules and regulations related to various aspects of our business, including:

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drilling of oil and natural gas wells;

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the relationships with our employees;

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containment and disposal of hazardous materials, oilfield waste, other waste materials and acids; and

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use of underground storage tanks.

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To date, we do not believe such rules and regulations, including applicable environmental laws and regulations, in the United States have required the expenditure by the contract drilling industry of significant resources outside the ordinary course of business. However, compliance costs under existing laws or under any new requirements could become material, and we could incur liability in any instance of noncompliance.

Our business is generally affected by political developments and by federal, state and local laws and regulations that relate to the oil and natural gas industry. The adoption of laws and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling and production, and otherwise have an adverse effect on our operations. Federal, state and local environmental laws and regulations currently apply to our operations and may become more stringent in the future. Any suspension or moratorium of the services we provide, whether or not short-term in nature, by a federal, state or local governmental authority, could have a material adverse effect on our business, financial condition and results of operation.

In the United States, the federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended (“CERCLA”), and comparable state statutes impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include:

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current and past owners and operators of the site where the release occurred, and

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persons who disposed of or arranged for the disposal of “hazardous substances” released at the site.

Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA excludes certain classes of exploration and production wastes from regulation as hazardous waste under Subtitle C of RCRA, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.

The federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and the Oil Pollution Act of 1990, as amended (the “Oil Pollution Act”), and analogous state laws and their respective implementing regulations govern:

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the prevention of discharges of pollutants, including oil and produced water spills, into waters of the United States; and

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liability for drainage into waters of the United States.

The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Administrative, civil or criminal penalties may also be imposed for violation of federal safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.

The Oil Pollution Act also expands the authority and capability of the federal government to direct and manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or into navigable waters. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to administrative, civil or criminal actions. Although the liability for owners and operators is the same

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under the federal Water Pollution Control Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.

Our contract drilling services will be marketed in oil and natural gas producing regions that utilize hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shales. Due to concerns raised relating to potential impacts of hydraulic fracturing on ground water quality and the increased occurrence of seismic activity, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Any efforts to limit or ban hydraulic fracturing could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the contract drilling services that we render for our exploration and production customers.

Our operations are also subject to federal, state and local laws, rules and regulations for the control of air emissions, including the federal Clean Air Act. The federal Clean Air Act, and comparable state laws, regulates emissions of various air pollutants through, for example, air emissions permitting programs. In addition, the Environmental Protection Agency (the "EPA") has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources including the energy extraction sector. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Finally, more stringent federal, state and local regulations, such as rules issued by the EPA that add new requirements for the oil and natural gas sector under the New Source Review Program and the National Emission Standards for Hazardous Air Pollutants program, could result in increased costs and the need for operational changes. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

On December 7, 2009, the EPA announced its findings that emissions of greenhouse gases present an “endangerment to human health and the environment.” The EPA based this finding on a conclusion that greenhouse gases are contributing to the warming of the Earth’s atmosphere and other climate changes. The EPA began to adopt regulations that would require a reduction in emissions of greenhouse gases from certain stationary sources and has required monitoring and reporting for other stationary sources. Mandatory reporting requirements for additional regional, federal or state requirements have been imposed and additional requirements may be imposed in the future. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our services. For example, during 2012, the EPA published rules that include standards to reduce methane emissions associated with oil and natural gas production. In May 2016, the EPA finalized regulations that set methane emission standards for new and modified oil and natural gas facilities, including production facilities. On December 2, 2023, the EPA issued a final rule that strengthened standards for methane and other air pollutants from new, modified and reconstructed sources. In addition, the Inflation Reduction Act of 2022 (the “IRA”), which was signed into law in August 2022, contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies. The IRA could accelerate the transition to a low carbon economy and could impose new costs on our operations. The IRA also imposes a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds. In January 2024, the EPA issued a proposed rule to impose and collect the methane emissions charge authorized under the IRA. Compliance with more stringent federal, state and local requirements and imposition of a methane fee could result in increased costs and the need for operational changes. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about

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hazardous materials used or produced in our operations. We believe that we are in compliance with these applicable requirements and with other OSHA and comparable requirements.

Additionally, environmental laws, such as the federal Endangered Species Act (“ESA”) and the Migratory Bird Treaty Act, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our customers’ properties may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species or the designation of previously unprotected areas as a critical habitat could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Risks and Insurance

Our operations are subject to the many hazards inherent in the drilling business, including: accidents at the work location; blow-outs; cratering; fires; and explosions. These and other hazards could cause personal injury or death, suspension of drilling operations, damage or destruction of our equipment and that of others, damage to producing formations and surrounding areas, or environmental damage.

Damage to the environment, including property contamination in the form of soil or ground water contamination, could also result from our operations, including through oil or produced water spillage, natural gas leaks, and fires.

We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we may not be fully insured against all risks, either because insurance is not available or because of the high premium costs. Such risks include personal injury, well disasters, extensive fire damage, damage to the environment, and other hazards. The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our rigs and other assets, employer’s liability, automobile liability, commercial general liability insurance and workers compensation insurance. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and other assets, such insurance does not cover the full replacement cost of the rigs or other assets, and we do not carry insurance against loss of earnings resulting from such damage. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our financial condition and results of operations. Further, we may experience difficulties in collecting from insurers, or such insurers may deny all or a portion of our claims for insurance coverage.

In addition to insurance coverage, we also attempt to obtain indemnification from our customers for certain risks. These indemnities typically require our customers to hold us harmless in the event of loss of production or reservoir damage. There is no assurance that we will obtain such contractual indemnity, and if obtained, whether such indemnity will be enforceable, whether the customer will be able to satisfy such indemnity or whether such indemnity will be supported by adequate insurance maintained by the customer.

If a significant accident or other event occurs and is not fully covered by insurance or is not an enforceable or recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations. See “Risk Factors - Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.”

Human Capital and Sustainability

We work to provide the safest and most efficient contract drilling services in our industry in a manner which protects, develops and rewards people, while striving to protect the environment, providing positive impacts to the communities where we operate, while recognizing the needs of all our stakeholders.

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The foundation for our commitment to human capital and sustainability is illustrated in our corporate vision and values and mission statements:

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Vision: Our Vision is to be the leader in Health, Safety & Environment and Operational Excellence while providing services to support North American energy development.

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Mission: Our Mission is to provide the safest and most efficient contract drilling services in our industry.

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Core Values: Our Core Values provide the directions in achieving these objectives: (i) focus on safety, people and the environment; (ii) lead our industry with integrity and pursuit of performance excellence in everything we do; (iii) accountability to all stakeholders including employees, customers, vendors and investors; and (iv) our greatest resource is people.

Human Capital

As of February 16, 2024, we had approximately 450 employees. We believe people are our greatest resource. We are committed to fostering a work environment where all people feel valued and respected. We are committed to recruiting, hiring, training and retaining the highest caliber human talent for our business by utilizing various means including outreach initiatives and partnerships with a diverse group of organizations, industry associations and networks. We require our employees to complete training annually including our commitment to a respectful workplace.

Training and mentoring of our team members are essential to the development of our employees and providing industry leading contract drilling services. Our mentoring programs are designed to assist short-service employees, especially at the floorhand level at the rig site, with adjusting to their new careers with our company and within our industry. Our training programs are designed to create core-competencies and equip our employees for advancement and promotion opportunities. Training is provided through various means including classroom, online and on-the-job training, and competencies must be demonstrated. Adherence to our training requirements and protocols is monitored for each of our field and office employees. We consider our employee relations to be good. None of our employees are represented by a union.

Safety. The safety of our employees and others is our highest priority at the worksite, and also at home. Our safety programs were built and are maintained by Company employees. The programs undergo annual revalidation. Our safety programs are designed to comply with applicable laws and industry standards and the requirements of our customers. We maintain a robust safety management system whereby all incidents and potential incidents are reported, monitored and root cause analysis and corrective actions are documented and performed when appropriate. All field-based employees are required to follow a structured safety training regimen, including safety orientations, behavior-based safety programs, and programs regarding hazard awareness, 12 ICD life-saving skills, safe systems of work, permission to work, time out for safety, energy isolation, hazard communication and material handling. Safety is a material component of our executive, corporate, and field-based annual incentive compensation programs.

Health and Benefits. For our field employees, we provide third party medical consultation services on a 24-hour / 7-day a week basis in the event of any personal illness, first aid or injury on our work sites. We provide robust health and benefit programs for all of our employees that include an emphasis on preventative care programs.

Environment

We evaluate, pursue and implement efforts to reduce impacts from our operations on air and water quality and land usage, reduce the use of energy in our operations, and reduce waste generation. For example, our drilling rigs are equipped with dual fuel engines that reduce carbon and greenhouse emissions. Our rigs also are capable of operating on utility electrical power where feasible and we have partnered with several operators to allow our drilling rigs to utilize this power source. All of our drilling rigs are designed to be pad optimal, which enables multi-well pad drilling which reduces the number of drilling locations required and thus the environmental impact of the operations. We track spills and employ spill prevention plans and use additional protective measures in our efforts to minimize impacts to the environment.

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Social Community Engagement

By focusing on increasing employee engagement, we seek to imprint the feel of community within our employee base including their families. We utilize social media tools to help increase engagement and also promote a positive image of the Company and our industry. Annually, we participate in toy drives and other volunteer efforts to “give back” to the communities where we operate.

Governance

Overall corporate governance oversight is provided by our Board of Directors. All of our employees are required to complete annual training on our Code of Business Conduct and Ethics, which addresses conflicts of interest, confidentiality, fair dealing with others, proper use of company assets, compliance with laws, insider trading, keeping of books and records, zero tolerance for discrimination and harassment in the work environment, as well as reporting of violations. We maintain reporting mechanisms, including anonymous hotlines, for potential violations of our Code of Business Conduct and Ethics to be reported to our Board of Directors and senior management.

Seasonality

Seasonality has not significantly affected our overall operations. However, our drilling operations can be affected by severe winter storms or other weather-related events. Additionally, toward the end of some years, we experience slower contracting activity as customers’ capital expenditure budgets are depleted.

Drilling Equipment, Suppliers and Subcontractors

We use many suppliers of drilling equipment and services. Although these suppliers, drilling equipment and services have historically been available, there is no assurance that such drilling equipment and services will continue to be available on favorable terms or at all. We also utilize numerous manufacturers and independent subcontractors from various trades to supply key components for our use. These key components include masts and substructures, top drives, high pressure mud pumps, pressure control equipment, engines, and VFD control systems. We believe that we have alternative sources for each of these components.

Website Access to Our Periodic SEC Reports

Our internet address is http://www.icdrilling.com. We file and furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and amendments to these reports, with the Securities and Exchange Commission (the “SEC”), which are available free of charge through our website as soon as reasonably practicable after such reports are filed with or furnished to the SEC. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding our company that we file and furnish electronically with the SEC.

We may from time to time provide important disclosures to investors by posting them in the investor relations section of our website, as allowed by SEC rules. Information on our website is not incorporated by reference into this Annual Report on Form 10-K and you should not consider information on our website as part of this Annual Report on Form 10-K.

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ITEM 1A. RISK FACTORS

We face many challenges and risks in the industry in which we operate. You should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report on Form 10-K, including our consolidated financial statements and related notes, and the documents and other information incorporated by reference herein, before investing in our shares. The risks and uncertainties described are not the only ones we face. Additional risk factors not presently known to us or which we currently consider immaterial may also adversely affect us. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our shares could decline and you could lose all or part of your investment.

Key Risks Related to Our Business and Operations

We derive all our revenues from companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility in oil and natural gas prices.

As a provider of land-based contract drilling services, our business depends on the level of exploration and production activity by oil and natural gas companies operating in the United States, and in particular, the regions where we actively market our contract drilling services. The oil and natural gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and natural gas prices and market expectations of potential changes in those prices significantly affect the levels of those activities. Worldwide political, regulatory, economic, and military events as well as natural disasters have contributed to oil and natural gas price volatility and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities in the United States and the regions where we market our contract drilling services, whether resulting from changes in oil and natural gas prices, an increase in the use of alternative forms of energy and reduction in demand for oil and natural gas, or otherwise, could materially and adversely affect our business, results of operations and financial condition.

Depending on the market prices of oil and natural gas, oil and natural gas exploration and production companies may cancel or curtail their drilling programs and may lower production spending on existing wells, thereby reducing demand for our services. Many factors beyond our control affect oil and natural gas prices, including, but not limited to:

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the cost of exploring for, producing and delivering oil and natural gas;

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the discovery and development rate of new oil and natural gas reserves, especially shale and other unconventional natural gas resources for which we market our rigs;

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the rate of decline of existing and new oil and natural gas reserves;

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available pipeline and other oil and natural gas transportation capacity;

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the levels of oil and natural gas storage;

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the ability of oil and natural gas exploration and production companies to raise capital;

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economic conditions in the United States and elsewhere;

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actions by members of Organization of the Petroleum Exporting Countries (“OPEC”) and other oil producing nations, such as Russia, relating to oil price and production levels, including announcements of potential changes to such levels;

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political instability in the Middle East, Russia and other major oil and natural gas producing regions;

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governmental regulations, sanctions and trade restrictions, both domestic and foreign;

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domestic and foreign tax policy;

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the availability of and constraints in pipeline, storage and other transportation capacity in the basins in which we operate, including, for example, takeaway constraints experienced in the Permian Basin and Haynesville Shale;

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weather conditions in the United States;

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the pace adopted by foreign governments for the exploration, development and production of their national reserves;

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the price of foreign imports of oil and natural gas;

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the strength or weakness of the United States dollar;

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the overall supply and demand for oil and natural gas; and

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the development of alternate energy sources and the long-term effects of worldwide energy conservation measures.

In addition, if oil and natural gas prices decline, companies that planned to finance exploration, development or production projects through the capital markets may be forced to curtail, reduce, postpone or delay drilling activities even further, and also may experience an inability to pay suppliers. Adverse conditions in the global economic environment could also impact our vendors’ and suppliers’ ability to meet obligations to provide materials and services in general. If any of the foregoing were to occur, or if current depressed market conditions continue for a prolonged period of time, it could have a material adverse effect on our business and financial results and our ability to timely and successfully implement our growth strategy.

OPEC and Russia (collectively “OPEC+”) have continued production cuts, including additional voluntary and unilateral cuts instituted during 2023, in order to support oil prices. Although WTI oil prices have ranged between $68.27 and $93.67 over the past six months, the sustainability of these price levels and adherence by OPEC+ to agreed allocations remains uncertain. Because of this uncertainty, most of our exploration and production (“E&P”) customers have not significantly increased capital expenditure budgets and some have decreased budgets. If oil prices were to remain below $70 per barrel for an extended period, we believe demand for contract drilling services in oil regions such as the Permian Basin would again soften over current levels, which could have a material adverse effect on our operations and financial condition.

Natural gas prices (Henry Hub) have fallen dramatically since the third quarter of 2022. On August 22, 2022, natural gas prices reached a high of $9.85 per mmcf, but fell to $3.52 per mmcf as of December 31, 2022 and was $2.58 per mmcf as of December 31, 2023. Prices have fallen to as low as $1.50 per mmcf since year end 2023. These commodity price declines, as well as take away capacity issues, caused market conditions in the Haynesville Shale to weaken rapidly, which resulted in a reduction in the number of drilling rigs operating in the Haynesville Shale, including a reduction in our operating rigs. At the end of the first quarter of 2023, we began relocating a portion of these rigs to the Permian Basin where market conditions remain stronger. However, not all of these rigs have been able to continue drilling in the Permian Basin and there can be no assurance that market conditions in the Permian Basin will not be adversely affected by recent volatility in oil prices nor any assurance that we will be successful in marketing all of these rigs in the Permian Basin or that they will be contracted on a timely basis or upon terms that are acceptable to us.

Any loss of large customers could have a material adverse effect on our financial condition and results of operations.

Our customer base consists of E&P companies that drill oil and natural gas wells in the United States in the regions where we market our rigs. As of December 31, 2023, we had rigs operating or earning revenues from 12 different customers, including one customer who had contracted four rigs, or 25%, of our contracted rigs and one customer who had contracted two rigs, or 13%, of our contracted rigs. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. Recently, there has been an acceleration in the pace of industry consolidation by E&P customers operating in the Company’s target markets, including a recent announcement that two of our customers had signed definitive agreements to merge together. Although we often have term contracts in place that mitigate financial risks from customer consolidation, when

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consolidation transactions occur, it is not unusual for the combined companies to reduce the number of drilling rigs they are operating. In addition, the acquiror in such transactions may also have preferred suppliers of contract drilling services. If a customer decided not to continue to use our services or to terminate an existing contract, or if there is a change of management or ownership of a customer or a material adverse change in the financial condition of one of our customers, and we are not able to timely recontract such rigs, it could have a material adverse effect on our revenues, cash flows, and financial condition.

All of our operating rigs are operating under contracts with terms expiring during 2024 and 2025. If we are unable to continue to operate rigs in the spot-market or renew our expiring contracts or continue their operation in the spot-market, it could have a material adverse effect on our results of operations and financial condition.

Upon expiration of a drilling contract, our customers have no obligation to extend the contract term or recontract the drilling rig and may elect to release the rig. All of our existing contracts expire during 2024 and 2025, with the majority of our rigs operating on short-term pad-to-pad contracts. We cannot assure that a customer will continue to renew contracts as they expire or that any replacement contract can be obtained for any of our rigs operating in the spot-market or with terms expiring, and if obtained, that it would be on terms as favorable as those of our existing drilling contracts or at profitable levels. The failure to renew or timely replace one or more of our expiring contracts could have a material adverse effect on our results of operations and financial condition.

Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.

Our operations are subject to the many hazards inherent in the drilling and well services industries, including the risks of personal injury and loss of life, blowouts, cratering, fires and explosions, loss of well control, collapse of the borehole, damaged or lost drilling equipment, and damage or loss from extreme weather and natural disasters.

Any of these hazards can result in substantial liabilities or losses to us from, among other things, suspension of operations, damage to, or destruction of, our property and equipment and that of others, damage to producing or potentially productive oil and natural gas formations through which we drill, and environmental damage.

Although, we seek to protect ourselves from some but not all operating hazards through insurance coverage, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance or otherwise have the financial resources necessary to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. We do not carry loss of business insurance for a rig being out of service.

We maintain insurance against some, but not all, of the potential risks affecting our operations and only in coverage amounts and deductible levels that we believe to be economical. Our insurance coverage includes deductibles which must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable. Incurring a liability for which we are not fully insured or indemnified could have a material adverse effect on our financial condition and results of operations.

We operate in a highly competitive industry in which price competition could reduce our profitability.

We encounter substantial competition from other drilling contractors. The competition in the markets in which we operate has intensified as recent mergers among E&P companies have reduced the number of available customers and the volatility in oil prices has decreased demand for drilling rigs and resulted in downward pricing pressure on operating drilling rigs.

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As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, results of operations and financial condition. In addition, the failure to maintain an adequate safety record could harm our ability to secure new drilling contracts.

We face competition from many competitors with greater resources and greater ability to rapidly respond to changing customer requirements and market conditions.

We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Many of our larger competitors are able to offer ancillary products and services with their contract drilling services, and recently, some of our larger competitors have begun integrating and offering contract drilling services in connection with directional drilling and other services that we do not offer. In this regard, large, diversified oilfield service companies have begun to market bundled services, including contract drilling services, in the United States. If any of these combined offerings gain acceptance within the United States market, it could place us at a competitive disadvantage that has an adverse impact on our future results of operations and profitability.

Furthermore, some of our competitors’ greater capabilities in these areas may enable them to better withstand industry downturns, compete more effectively on the basis of price and technology, retain skilled rig personnel, and build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

New technology may cause our drilling methods or equipment to become less competitive.

The drilling industry is subject to the introduction of new drilling and completion methods and equipment using new technologies, some of which may be subject to patent protection. Changes in technology or improvements in competitors’ equipment could make our equipment less competitive or require significant capital investments to build and maintain a competitive advantage. Further, we may face competitive pressure to design, 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 implement new and emerging technologies on a timely basis or at an acceptable cost, it may have a material adverse effect on our business, results of operations, financial condition and growth strategy.

Our current estimated backlog of contract drilling revenue may not ultimately be realized.

As of December 31, 2023, our estimated contract drilling backlog for future revenues under term contracts, which we define as contracts with an original fixed term of six months or more, was approximately $82.9 million. 75% of this backlog expires in 2024 and 25% expires in 2025, which requires us to renew these expiring contracts as well as short-term contracts under which a large number of our rigs operate. Although we historically have been successful in obtaining extensions or follow on work for drilling rigs with expiring contracts, in periods of market decline or uncertainty such as the U.S. land contract drilling industry is experiencing, we cannot assure that we will obtain such renewals, or that such renewals will be on terms acceptable to us. Any failure to renew or find follow-on work for our drilling rigs with expiring contracts, could have a material adverse effect on our operations and financial condition.

Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to us if a contract is terminated prior to the expiration of the fixed term. Additionally, in certain circumstances, for example, destruction of a drilling rig that is not replaced within a specified period of time, our bankruptcy, or a breach of our contract obligations, the customer may not be obligated to make an early termination payment to us. Additionally, during depressed market conditions, such as those we are currently experiencing, or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate, renegotiate or fail to honor their contractual obligations. In addition, we may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or negotiate our contracts for various reasons, including those described above. As a result, we may be unable to realize all of our current contract drilling backlog. In addition, the

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renegotiation or termination of fixed-term contracts without the receipt of early termination payments could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We participate in a capital-intensive business. We may not be able to finance future growth of our operations.

The contract drilling industry is capital intensive. Our cash flow from operations and the continued availability of credit are subject to a number of variables, including general economic conditions, conditions in the oil and natural gas market, and more specifically, our rig utilization rates, operating margins and ability to control costs and obtain contracts in a competitive industry. Our cash flow from operations and present borrowing capacity may not be sufficient to fund our anticipated capital expenditures and working capital requirements. We may from time to time seek additional financing, either in the form of bank borrowings, sales of debt or equity securities or otherwise. To the extent our capital resources and cash flow from operations are at any time insufficient to fund our activities or repay our indebtedness as it becomes due, we will need to raise additional funds through public or private financing or additional borrowings. We may not be able to obtain any such capital resources in the amount or at the time when needed. Any new sources of debt capital would require substantially higher interest requirements, and any new sources of equity capital could be substantially dilutive to existing shareholders. In addition, the number of banks and other lending institutions who provide capital to the oil and gas services industry has been shrinking driven in part by ESG concerns and priorities. Any limitations on our access to capital or increase in the cost of that capital would significantly impair our operational strategies. Our ability to maintain our targeted credit profile could affect our cost of capital as well as our ability to execute our growth strategy. In addition, a variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets. If we are at any time not able to obtain the necessary capital resources, our financial condition and results of operations could be materially adversely affected.

We depend on a limited number of vendors, some of which are thinly capitalized and the loss of any of which could disrupt our operations.

Our contract drilling operations depend upon the availability of various rig equipment, including VFD drives and drillers cabins, top drives, mud pumps, engines and drill pipe, as well as replacement parts, related rig equipment and fuel. Some of these have been in short supply from time to time. In addition, key rig components critical to the operation, construction or upgrade of our rigs are either purchased from or fabricated by a limited number of vendors, including vendors that may compete against us from time to time. For many of these products and services, there are only a limited number of vendors and suppliers available to us.

We do not currently have any long-term supply contracts with any of our suppliers or subcontractors and may be at a competitive disadvantage compared to our larger competitors when purchasing from these suppliers and subcontractors. Shortages could occur in these essential components due to an interruption of supply or increased demands in the industry. If we are unable to procure certain of such rig components or services from our subcontractors we would be required to reduce or delay our rig construction and other operations, which could have a material adverse effect on our business, results of operations, financial condition and growth strategy.

We could be adversely affected if shortages of equipment or supplies occur.

Increased or decreased demand among drilling contractors and our customers for consumable supplies, including fuel, water and ancillary rig equipment, such as pumps, valves, drill pipe and engines, may lead to delays in obtaining these materials and our inability to operate our rigs in an efficient manner. We have periodically experienced increased lead times in purchasing ancillary equipment for our drilling rigs. To the extent there are significant delays in being able to purchase important components for our rigs, certain of our rigs may not be available for operation or may not be able to operate as efficiently as expected, which could adversely affect our results of operations and financial condition.

In addition, our customers typically purchase the fuel and water for their operations, including fuel that runs our drilling rigs, and thus bear the financial impact of increased prices. However, prolonged shortages in the availability of

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fuel or water to conduct drilling and completion activities could result in the suspension of our contracts or reduce demand for our contract drilling services and have a material adverse effect on our financial condition and results of operations.

Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited.

Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code of 1986, as amended) at any time during a rolling three-year period. In addition, future ownership changes or future regulatory changes could further limit our ability to utilize our NOLs. If all or a substantial part of our NOLs is lost or limited, it will result in our recognizing a net deferred tax liability and associated expense during the period of limitation.

We currently estimate that we have approximately $94.2 million of NOLs that will expire before becoming available to be utilized by us. Currently, because we have not yet generated taxable income for federal income tax purposes, all of our NOL assets in excess of the amount that we are able to offset against other deferred tax liabilities have been reserved on our balance sheet. Subsequent ownership changes under Section 382 are possible in the future and could cause further limitations in our existing NOLs as well as NOLs generated during future periods.

Legal and Regulatory Risks

Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our activities and could adversely affect our financial position, results of operations and cash flows.

Hydraulic fracturing is a commonly used process that involves injection of water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The adoption of any federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could potentially increase our costs of operations and cause a decrease in drilling activity levels in the Permian Basin and other unconventional resource plays and an associated decrease in demand for our rigs and services, any or all of which could adversely affect our financial position, results of operations and cash flows.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and natural gas or could make it more difficult to perform hydraulic fracturing in the unconventional resource plays where we focus our operations. Any such regulation that adversely affects our customers’ operations could materially impact demand for our contract drilling services which could adversely affect our financial position, results of operations and cash flows.

Legal proceedings could have a negative impact on our business.

The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations. Any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.

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Regulatory compliance costs and restrictions, as well as any delays in obtaining permits by our customers for their operations, could impair our business.

The operations of our customers are subject to or impacted by a wide array of regulations in the jurisdictions in which they operate. As a result of changes in regulations and laws relating to the oil and natural gas industry, including land drilling, our customers’ operations could be disrupted or curtailed by governmental authorities. In most states, our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions which may be imposed in connection with the granting of the permit. Additionally, the high cost of compliance with applicable regulations may cause customers to discontinue or limit their operations or defer planned drilling, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the oil and natural gas industry.

We are subject to environmental, health and safety laws and regulations that may expose us to significant liabilities for penalties, damages or costs of remediation or compliance.

Our operations are subject to federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities, the imposition of substantial liabilities for pollution resulting from our operations and the application of specific health and safety criteria addressing worker protection. Failure to comply with these laws and regulations could result in investigations, restrictions or orders suspending well operations, the assessment of administrative, civil and criminal penalties, the revocation of permits and the issuance of corrective action orders, any of which could have a material adverse effect on our business, results of operations and financial condition.

There is inherent risk of environmental costs and liabilities in our business as a result of our handling of petroleum hydrocarbons and oilfield and industrial wastes, air emissions and wastewater discharges related to our operation, and historical industry operations and waste disposal practices. Some environmental laws and regulations may impose strict, joint and several liability, which means that in some situations, we could be exposed to liability as a result of our conduct that was without fault or lawful at the time it occurred or as a result of the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition and results of operations.

Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas, could limit well servicing opportunities or impose unforeseen liabilities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance.

Potential listing of species as “endangered” under the federal ESA could result in increased costs and new operating restrictions or delays on our oil and natural gas exploration and production customers, which could adversely reduce the amount of contract drilling services that we provide to such customers.

The federal ESA and analogous state laws regulate a variety of activities, including oil and natural gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species or the designation of previously unprotected areas as a critical habitat could cause oil and natural gas exploration and production operators to incur

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additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce the amount of drilling activities in affected areas, including support services that we provide to such operators under our contract drilling services segment. Numerous species have been listed or proposed for protected status in areas in which we provide or could in the future provide field services. For instance, the sage grouse, the lesser prairie-chicken and certain wildflower species, among others, are species that have been or are being considered for protected status under the ESA and whose range can coincide with our oil and natural gas production activities. The presence of protected species in areas where operators for whom we provide contract drilling services conduct exploration and production operations could impair such operators’ ability to timely complete well drilling and development and, consequently, adversely affect the amount of contract drilling or other field services that we provide to such operators, which reduction of services could have a significant adverse effect on our results of operations and financial position.

Climate change legislation or regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for our field services.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases from industrial and energy sources contribute to increases of carbon dioxide levels in the Earth’s atmosphere and oceans and contribute to global warming and other environmental effects, the EPA has adopted various regulations under the federal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and natural gas industry. During 2012, the EPA published rules that include standards to reduce methane emissions associated with oil and natural gas production. In May 2016, the EPA finalized regulations that set methane emission standards for new and modified oil and natural gas facilities, including production facilities. On December 2, 2023, the EPA issued a final rule that strengthened standards for methane and other air pollutants from new, modified and reconstructed sources. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change and was among the 195 nations that signed an international accord in December 2015 with the objective of limiting greenhouse gas emissions. The Paris Agreement (adopted at the conference) went into effect on November 4, 2016, and the United States formally rejoined in February 2021. Additionally, certain U.S. states and regional coalitions of states have adopted measures regulating or limiting greenhouse gases from certain sources or have adopted policies seeking to reduce overall emissions of greenhouse gases. The adoption and implementation of any international treaty or of any federal or state legislation or regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with our operations and other sources within the industrial or energy sectors. Such legislation or regulations could adversely affect demand for the production of oil and natural gas and thus reduce demand for the services we provide to oil and natural gas producers as well as increase our operating costs by requiring additional costs to operate and maintain equipment and facilities, install emissions controls, acquire allowances or pay taxes and fees relating to emissions, which could adversely affect our results of operations and financial condition. For example, the IRA, which was signed into law in August 2022, contains tax inducements and other provisions that incentivize investment, development, and deployment of alternative energy sources and technologies. The IRA could accelerate the transition to a low carbon economy and could impose new costs on our operations. The IRA also imposes a methane emissions charge on certain oil and gas facilities, including onshore petroleum and natural gas production facilities, that emit 25,000 metric tons or more of carbon dioxide equivalent gas per year and exceed certain emissions thresholds. In January 2024, the EPA issued a proposed rule to impose and collect the methane emissions charge authorized under the IRA. Compliance with more stringent federal, state and local requirements and imposition of a methane fee could result in increased costs and the need for operational changes. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases may produce changes in climate or weather, such as increased frequency and severity of storms, floods and other climatic events, which if any such effects were to occur, could have adverse physical effects on our operations, physical assets and field services to exploration and production operators.

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Risks Related to Our Liquidity

The conversion of the Convertible Notes issued on March 18, 2022 into shares of our common stock would result in significant dilution to our existing stockholders.

We currently have $179.2 million of Convertible Notes outstanding as of December 31, 2023. We have the ability to issue up to an additional $7.5 million principal amount of Convertible Notes to holders willing to purchase such additional Convertible Notes. The Convertible Notes are convertible into shares of our common stock at the option of the holders at any time during the term of the Convertible Notes. The effective conversion price is $4.51 per share. In addition, we have the right to pay in-kind (“PIK”) interest for the entire term of the Convertible Notes. The election by us to PIK interest will increase outstanding principal balance under the Convertible Notes and thus the number of shares of common stock issuable upon conversion of the Convertible Notes. We elected to pay in-kind outstanding interest as of September 30, 2022, March 31, 2023, and September 30, 2023, resulting in the issuance of an additional $12.7 million, $11.6 million and $12.4 million principal amount of Convertible Notes, respectively. We also have elected to pay in-kind our interest payment due March 31, 2024, which will result in the issuance of an additional $13.6 million of Convertible Notes, and will likely pay in-kind additional interest payments due on the Convertible Notes in the future. The conversion of the Convertible Notes would result in substantial dilution in the percentage of the outstanding common stock owned by our existing stockholders.

The market price of our common stock could decline as a result of the large number of shares that will become eligible for sale following conversion of the Convertible Notes.

A substantial number of additional shares of our common stock would be eligible for resale in the public market following conversion of the Convertible Notes. Current holders of our Convertible Notes may wish to dispose of some or all of their shares of common stock acquired upon conversion of the Convertible Notes. Sales of substantial numbers of shares of both the newly issued and the existing shares of our common stock in the public market following conversion of the Convertible Notes could adversely affect the market price of our shares of common stock.

Affiliates of MSD Partners, L.P. and Glendon Capital Management, L.P. (the “Primary Noteholders”) collectively own over 10% of our common stock and have rights to acquire additional shares upon conversion of Convertible Notes held by them. The Primary Noteholders also have rights to nominate up to an aggregate of three individuals to serve on our Board of Directors. As a result, the Primary Noteholders collectively will have significant influence over the outcome of corporate actions requiring stockholder or board approval, and the priorities of the Primary Noteholders for our business may be different from our other stockholders.

The Primary Noteholders collectively own approximately 12% of the outstanding shares of our common stock, and collectively beneficially own approximately 29.8% of the outstanding shares of our common stock (after giving effect to permitted conversions of the Convertible Notes based on the current beneficial ownership limitations after giving effect to such conversions, including a 9.9% limitation on Glendon Capital Management, L.P. and 19.9% limitation on MSD Partners, L.P.). Accordingly, the affiliates of MSD Partners, L.P. acting alone, or the Primary Noteholders voting together, while not a group, may be able to significantly influence the outcome of many corporate transactions or other matters submitted to our stockholders for approval, including any merger, consolidation or sale of all or substantially all of our assets or any other significant corporate transaction, such that the Primary Noteholders collectively could potentially delay or prevent a change of control of the Company, even if such a change of control would benefit our other stockholders. The interests of the Primary Noteholders may differ from the interests of other stockholders.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the interest or principal, when due, on our indebtedness.

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At December 31, 2023, we had $5.5 million drawn under our Revolving ABL Credit Facility, which term matures on September 30, 2025. Our Convertible Notes require us to offer to purchase up to $3.5 million of Convertible Notes at par, plus accrued interest, on each of March 31, 2024, June 30, 2024, September 30, 2024, December 31, 2024 and March 31, 2025. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. In particular, our Convertible Notes do not mature until March 18, 2026 and do not permit us to refinance the obligations until September 18, 2024, and any such refinancing would be in the form of an in-substance defeasance and require the payment of a make-whole amount equal to the estimated remaining interest that would have been due through maturity, which increases the refinancing costs and options available to the Company. Any refinancing of indebtedness could be at higher interest rates, may involve the issuance of equity or equity-linked securities that could dilute shareholder ownership and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our debt facilities currently restrict our ability to dispose of assets and our use of the proceeds from such dispositions subject to certain defined exceptions. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our existing debt instruments contain a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

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incur or guarantee additional indebtedness;

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make loans to others;

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make investments;

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merge or consolidate with another entity;

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transfer, lease or dispose of all or substantially all of our assets;

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make certain payments and capital expenditures;

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create or incur liens;

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purchase, hold or acquire capital stock or certain other types of securities;

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pay cash dividends;

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enter into certain transactions with affiliates; and

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engage in certain other transactions without the prior consent of the lenders.

Our Convertible Notes include a covenant that we maintain minimum liquidity, comprised of cash and availability under our revolving line of credit, equal to at least $10 million. In addition, our Convertible Notes contain a covenant restricting capital expenditures to $14.8 million during the nine months ended September 30, 2024 and $11.25 million during the nine months ended June 30, 2025, subject to adjustment upward by $500,000 per year for each rig above 17 that operates during each year. In addition, capital expenditures are excluded from this covenant (a) if funded from equity proceeds, (b) if relating to the reactivation of a rig so long as (i) we have a signed contract with a customer with respect to each such rig of at least one (1) year duration providing for early termination payments consistent with past practice equal to at least the expected margin on the contract, (ii) the expected margin on such rig contract will be

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equal to or exceed such reactivation capital expenditures, and (iii) the reactivation capital expenditures, rig contract and the expected margin calculation are approved by our board of directors or (c) relate to other capital expenditures specifically approved by written or electronic consent by both (i) the required holders (which approval may, for the avoidance of doubt, be provided by the required holders in their sole discretion for an amount of capital expenditures to be committed or made by the Company or a subsidiary of the Company within ninety (90) days after the date of such consent) and (ii) the Board of Directors of the Company. During 2023, the holders of our Convertible Notes consented to capital expenditure adjustments under this covenant aggregating $16.9 million. If we are unable to obtain consents in the future for capital expenditures necessary to operate and maintain our rigs, it would require us to reduce the number of rigs we operate, which could have a material adverse effect on our results of operations, liquidity and financial condition.

A breach of any covenant in any of our debt instruments would result in a default. A resulting event of default, if not waived, could result in acceleration of the payment of the indebtedness outstanding under, and a termination of, these debt instruments. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

The borrowing base under our revolving credit facility may decline during 2024.

As of December 31, 2023, the borrowing base under our ABL Credit Facility was $26.3 million, and we had $20.6 million of availability remaining of our $40.0 million commitment on that date. We are required to maintain minimum availability under the ABL Credit Facility of $4.0 million; if not, we must maintain a minimum fixed charge coverage ratio (“FCCR”) of 1:1. The borrowing base under the ABL Credit Facility is calculated based upon 85% of the sum of our eligible accounts receivable. In most circumstances, all of accounts receivable are considered eligible unless they are more than 90 days past due. If at any time our borrowing base falls below our outstanding balance under our ABL Credit Facility, and we were not able to promptly repay such deficiency, we would be required to repay to the banks any deficiency amount. In such event, if our available cash balances were not sufficient to repay such amounts, we would be required to obtain other debt or equity financing necessary to cure such deficiency, and there can be no assurance that such additional financing sources would be available to us, or available on terms acceptable to us. Any inability to timely cure any deficiency between our borrowing base and credit facility balance may have a material adverse effect on our liquidity and financial condition.

A failure of any of our lenders to honor commitments or advance funds under our existing debt instruments would have a material adverse effect on our ability to fund our operations and business strategy.

Our ABL Credit Facility limits the amounts we can borrow up to a borrowing base amount which is calculated monthly and is based on a percentage of our eligible accounts receivable. If our lenders fail to honor their commitments or advance funds pursuant to such commitments, we may be unable to implement our strategic plans, make acquisitions or capital expenditures or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations.

Our ability to comply with the financial covenants contained in our debt instruments is based upon our future cash flows and debt levels.

Both our existing ABL Credit Facility and Convertible Notes Indenture contain a springing financial covenant requiring us to maintain an FCCR of 1:1. The FCCR is equal to adjusted EBITDA less capital expenditures divided by cash interest expense plus scheduled principal payments, cash dividends and finance lease obligations plus cash taxes paid. This covenant is only tested when excess availability under our ABL Credit Facility falls below 10% of the loan commitment.

In addition, our existing Convertible Notes Indenture contains a minimum liquidity covenant that requires us to maintain at all times at least $10 million of liquidity, which can be comprised of cash plus excess availability under our ABL Credit Facility. Our Convertible Notes Indenture also contains a covenant restricting the amount of capital expenditures we are able to incur during any particular year. Certain capital expenditures are excluded from this covenant, including expenditures funded with proceeds from equity offerings, rig reactivation capex associated with

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term contracts with durations of greater than one year and expected margins that exceed the amount of capital expenditures associated with the rig reactivation as well as capital expenditures specifically consented to by the Noteholders under the Convertible Notes Indenture.

Our compliance with each of these covenants depends significantly upon our level of cash flows, which are based upon factors such as future dayrates and rig utilization that are difficult to predict based upon the cyclical nature of our industry. In addition, compliance with the capital expenditures under our Convertible Notes Indenture may require us to obtain consents from our Noteholders in order to maintain our rigs or invest in rig upgrades or additional rig reactivations. If we are not able to receive such consents, we could be required to reduce our operating rig count or forgo investments in rig reactivations and rig improvements.

If we are not able to comply with the covenants contained in our debt facilities, we would be required to seek a waiver or amendment to the facility, or seek alternative financing sources, and there can be no assurance that we would be able to obtain such waivers, amendments or alternative financing sources. Any failure to comply with the financial covenants contained in our credit facility, or to cure any such non-compliance may have a material adverse effect on our liquidity and financial condition.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. Our debt carries a floating rate of interest linked to various indices, including SOFR. A change in indices, resulting in interest rate increases on our debt could adversely affect our cash flow and operating results. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for capital expenditures and place us at a competitive disadvantage. For example, total long-term debt as of December 31, 2023 included $184.7 million of floating-rate debt attributed to borrowings at an average interest rate of 14.93%, and the impact on annual cash flow of a 10% increase in the floating-rate (approximately 16.42%) would be approximately $2.8 million annually based on the floating-rate debt and other obligations outstanding as of December 31, 2023; however, there are no assurances that possible rate changes would be limited to such amounts. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our desired growth and operating results.

Inflationary and supply chain pressures may decrease our operating margins and increase working capital investments required to operate our business.

Competition for competent rig and office personnel remain strong. Inflationary pressures have increased these and other costs to operate our drilling rigs. Although our term drilling contracts typically allow us to pass-through to our customers labor costs increases and cost increases for other items (based upon changes to the applicable oilfield price index for such other items) through adjustment to contractual dayrates, the majority of our current contracts are short-term in nature, which requires us to recoup labor and other price increases through increased dayrates upon repricing of each short-term contract upon its expiration. If we are unable to recoup cost increases through adjustment to term contract dayrates or successful renegotiation of short-term contract dayrates, our daily operating margins will fall, which could materially adversely affect our operating results and financial condition.

In addition, political and economic events globally and within the United States can create supply chain pressures and bottlenecks which could reduce the availability of equipment, supplies and other products needed to operate our business. This may cause us to increase investments in critical spare inventory and capital spare items to compensate for increased delivery lead times or potential unavailability of items. If we are required to invest substantial additional amounts to increase inventory levels of critical spare inventory or capital items, it will reduce our financial resources available to invest in rig reactivations which could have a material adverse effect on our future cash flows and ability to pursue plans to reactivate additional rigs.

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Risks Related to our Common Stock

Because we have no plans to pay any dividends for the foreseeable future, investors must look solely to stock appreciation for a return on their investment in us.

We have not paid cash dividends on our common stock since our incorporation, and our credit facility prohibits us from paying cash dividends on our common stock. We do not anticipate paying any cash dividends in the foreseeable future. We currently intend to retain any future earnings to support our operations and growth. Accordingly, investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize any future gains on their investment.

Provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company at a premium that a stockholder may consider favorable, which could adversely affect the price of our common stock.

The existence of some provisions in our organizational documents and under Delaware law could delay or prevent a change in control of our company that a stockholder may consider favorable, which could adversely affect the price of our common stock. The provisions in our amended and restated certificate of incorporation and amended and restated bylaws that could delay or prevent an unsolicited change in control of our company include:

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provisions regulating the ability of our stockholders to nominate candidates for election as directors or to bring matters for action at annual meetings of our stockholders;

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limitations on the ability of our stockholders to call a special meeting and act by written consent; and

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the authorization given to our Board of Directors to issue and set the terms of preferred stock.

We may issue preferred stock or debt or equity-linked debt securities whose terms could adversely affect the voting power or value of our common stock.

Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

In addition, future offerings of debt securities, including in connection with refinancing of existing debt securities, could rank senior to our common stock in the event of our liquidation, and future offerings of equity and equity-linked securities, including in connection with refinancing of existing indebtedness, would dilute our existing stockholders or rank senior to our common stock, which may adversely affect the market value of our common stock.

Future declines in the market price for our common stock could cause us to lose our listing on the NYSE, which could have a material adverse effect on the market value of our common stock.

Under NYSE listing requirements, in order to maintain our listing status, we are required to maintain at all times a minimum 30-day trading average market capitalization of $15 million. Unlike certain other listing standards tied to minimum share price, there is no cure period or grace period associated with this listing standard. As of February 26, 2024, we believe that our 30-day average public market capitalization was approximately $29.3 million. Because we cannot predict future prices for our common stock, we cannot assure you that our common stock will remain listed on the NYSE, which could have a material adverse effect on the trading value of our common stock and our ability to raise additional funds through new issuances. If our stock could not remain listed on the NYSE, it is possible that our securities could be quoted on the over-the-counter bulletin board or the pink sheets. This could have negative

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consequences, including a negative effect on the price of our securities, reduced liquidity for stockholders, reduced trading levels for our securities, limited availability of market quotations or analyst coverage of our securities; stricter trading rules for brokers trading our securities, and reduced access to financing alternatives for us. We also would be subject to greater state securities regulation if our common stock was no longer listed on a national securities exchange.

General Risk Factors

Global health crises and pandemics have had, and in the future could have, a material adverse effect on our business, liquidity, results of operations and financial condition.

The U.S. and global economy has generally recovered from prior negative impacts of the COVID-19 pandemic, which reduced consumer activity, disrupted supply chains and resulted in a decline in demand for oil and natural gas in 2020 and early 2021, and caused our operating rig count to fall to as low as three rigs in August 2020 and resulted in our reporting negative cash flows from operations in the first quarter of 2021 through the first quarter of 2022. However, if future global health crises or pandemics occur, they could create risks and uncertainties outside of our control which could have a material adverse effect on our liquidity, results of operations and financial condition.

If our customers delay paying or fail to pay a significant amount of our outstanding receivables, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.

In most cases, we bill our customers for our services in arrears and are, therefore, subject to our customers delaying or failing to pay our invoices. In weak economic environments, we may experience increased delays and failures due to, among other reasons, a reduction in our customers’ cash flow from operations and their access to the credit markets. If our customers delay paying or fail to pay us a significant amount of our outstanding receivables, it could have a material adverse effect on our liquidity, results of operations and financial condition.

The effects of severe weather could adversely affect our operations.

Changes in climate due to global warming trends could adversely affect our operations by limiting, or increasing the costs associated with, equipment or product supplies. In addition, coastal flooding and adverse weather conditions such as increased frequency and/or severity of hurricanes could impair our ability to operate in affected regions of the country. Oil and natural gas operations of our customers located in Louisiana and parts of Texas may be adversely affected by hurricanes and tropical storms, resulting in reduced demand for our services. Repercussions of severe weather conditions may include: curtailment of services; weather-related damage to facilities and equipment; suspension of operations; inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and loss of productivity. These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters also adversely affect the demand for our services by decreasing the demand for natural gas.

Information technology failures and cybersecurity breaches could harm our business.

We use information technology and other computer resources to carry out important operational activities and to maintain our business records. These systems include systems owned and operated by us, as well as systems of third-party operators and cloud-based services. These information technology systems are dependent upon electronic systems and other aspects of the internet infrastructure. A material breach in the security of our information technology systems or other data security controls could result in third parties obtaining or corrupting customer, employee or company data. To date, we have not had a material breach of data security. These cybersecurity risks include cyber-attacks on both us and third parties who provide material services to us. In addition to disrupting operations, cyber security breaches could affect our ability to operate or control our facilities, render data or systems unusable, or result in the theft of sensitive, confidential or customer information. These events could also damage our reputation, and result in losses from remedial actions, loss of business or potential liability to third parties. Accordingly, such occurrences could have a material and adverse effect on our financial position, results of operations and cash flows. Furthermore, geopolitical tensions or conflicts, such as Russia’s invasion of Ukraine, may further heighten the risk of cybersecurity attacks.

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Any future implementation of price controls on oil and natural gas would affect our operations.

Certain groups have asserted efforts to have the United States Congress impose some form of price controls on either oil, natural gas, or both. There is no way at this time to know what results these efforts may have. However, any future limits on the price of oil or natural gas, and resulting impacts on drilling activities, could have a material adverse effect on our business, financial condition and results of operations.

Improvements in or new discoveries of alternative energy technologies could have a material adverse effect on our financial condition and results of operations.

Since our business depends on the level of drilling activity in the oil and natural gas industry, any improvement in or new discoveries of alternative energy technologies could have a material adverse effect on our business, financial condition and results of operations.

We may be adversely impacted by work stoppages or other labor matters.

We depend on skilled employees to build and operate our rigs, and any prolonged labor disruption involving our employees could have a material adverse impact on our results of operations and financial condition by disrupting our ability to perform drilling-related services for our customers. Moreover, unionization efforts have been made from time to time within our industry, with varying degrees of success. Any such unionization could increase our costs or limit our flexibility.

We depend on the services of key executives, the loss of whom could materially harm our business.

Our senior executives are important to our success because they are instrumental in setting our strategic direction, operating our business and technology, identifying, recruiting and training key personnel, and identifying customers and expansion opportunities. We also depend on the relationships that our senior management have with many of our customers. Losing the services of any of these individuals could adversely affect our business until a suitable replacement could be found. We do not maintain key man life insurance on any of our senior executives. As a result, we are not insured against any losses resulting from the death of our key employees.

Failure to hire and retain skilled personnel could adversely affect our business.

Our ability to be productive and profitable depends upon our ability to employ and retain skilled personnel, and we cannot assure that during times of high demand we will be able to retain, recruit and train an adequate number of skilled workers. The potential inability or lack of desire by workers to commute to our facilities and job sites and competition for workers from competitors or other industries are factors that could affect our ability to attract and retain workers. A significant increase in the wages paid by competing employers or other industries could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. Our inability to attract and retain skilled workers in sufficient numbers to satisfy our existing service contracts and enter into new contracts could materially adversely affect our business, financial condition, results of operations and growth strategy.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C.CYBERSECURITY

Risk Management and Strategy

We understand the importance of preventing, assessing, identifying, and managing material risks associated with cybersecurity threats. Processes designed to assess, identify and manage risks from cybersecurity threats have been incorporated as a part of the Company’s overall risk assessment process. On a regular basis we implement into our operations these processes, technologies, and controls to assess, identify, and manage material risks. Specifically, we

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engage a third-party cybersecurity firm to assist with network and endpoint monitoring, cloud system monitoring and assessment of our incident response procedures. Further, we employ periodic penetration testing and tabletop exercises to inform our risk identification and assessment of material cybersecurity threats.

To manage our material risks from cybersecurity threats and to protect against, detect, and prepare to respond to cybersecurity incidents, we undertake the below listed activities:

a. Monitor emerging data protection laws and implement changes as necessary;

b. Conduct periodic customer data handling and use requirement training for our employees;

c. Utilize third-party systems and processes that continually monitor our systems to prevent, detect and remediate cyber security threats and events;

d. Conduct annual cybersecurity management training for employees with access to our systems and processes that handle sensitive data;

e. Conduct regular phishing email simulations for employees; and

f. Carry cybersecurity risk insurance that provides protection against the potential losses arising from a cybersecurity incident.

Our incident response plan coordinates the activities that we and, as applicable, our third-party cybersecurity providers may take to prepare, respond and recover from cybersecurity incidents, which include processes to triage, assess severity, investigate, escalate, contain, and remediate an incident, as well as to comply with potentially applicable legal obligations and mitigate brand and reputational damage.

As part of the above processes, we have engaged with consultants to review our cybersecurity program to help identify areas for continued focus, improvement, and compliance.

Our processes also include assessing cybersecurity threat risks associated with our use of third-party services providers in normal course of business use, including those in our supply chain or who have access to our customer and employee data or our systems. In addition, we assess cybersecurity considerations in the selection and oversight of our third-party services providers, including due diligence on the third parties that have access to our systems and facilities that house systems and data.

We describe whether and how risks from identified cybersecurity threats have or are reasonably likely to materially affect our financial position, results of operations and cash flows, under the heading “Information technology failures and cybersecurity breaches could harm our business” included as part of our Item 1A. Risk Factors of this Annual Report on Form 10-K, which disclosures are incorporated by reference herein.

Governance

Our Audit Committee of the Board of Directors is responsible for oversight of our risk assessment, risk management, disaster recovery procedures and cybersecurity risks. Periodically during each year, the Audit Committee receives an overview from our cybersecurity risk management team, comprised of our Chief Financial Officer, our Chief Accounting Officer and our Director of IT, of our cybersecurity threat risk management and strategy processes, including potential impact on the Company, the efforts of management to manage the risks that are identified and our disaster recovery preparations. Members of the Board of Directors engage in discussions with management on cybersecurity-related news events and discuss certain updates to our cybersecurity risk management and strategy programs.

Our cybersecurity risk management and strategy processes are led by our cybersecurity risk management team. Our Director of IT has over 30 years of experience in various roles involving managing information security, developing cybersecurity strategy, and implementing cybersecurity programs. The Director of IT is informed about and monitors the

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prevention, mitigation, detection, and remediation of cybersecurity incidents through their management of the cybersecurity risk management and strategy processes, including our incident response plan.

ITEM 2. PROPERTIES

We lease an approximate 14.4 acre rig assembly yard complex located in Houston, Texas and a yard with approximately 20 acres in Odessa, Texas.

Our operations are managed from field locations that we own or lease, that contain office, shop and yard space to support day-to-day operations, including repair and maintenance of equipment, as well as storage of equipment, materials and supplies. Including the Houston, Texas and Odessa, Texas yards, we currently have six such field locations.

Additionally, we lease office space for our corporate headquarters in northwest Houston located at 20475 State Highway 249, Suite 300, Houston, Texas 77070.

We believe that all of our existing properties are suitable for their intended uses and are sufficient to support our operations. We do not believe that any single property is material to our operations and, if necessary, we could obtain a replacement facility. We continuously evaluate the needs of our business, and we will purchase or lease additional properties or reduce our properties, as our business requires.

ITEM 3. LEGAL PROCEEDINGS

We are the subject of certain legal proceedings and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such legal proceedings and claims. While the legal proceedings and claims may be asserted for amounts that may be material should an unfavorable outcome be the result, management does not currently expect that the resolution of these matters will have a material adverse effect on our financial position or results of operations. In addition, management monitors our legal proceedings and claims on a quarterly basis and establishes and adjusts any reserves as appropriate to reflect our assessment of the then-current status of such matters.

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 Information for Common Stock

Our common stock is traded on the New York Stock Exchange under the symbol “ICD”.

Holders of Record

As of February 16, 2024, there were approximately 30 record holders of our common stock as listed by our transfer agent’s records. This number includes registered stockholders and does not include stockholders who hold their shares institutionally.

Dividend Policy

We have not declared or paid any cash dividends on our common stock. Our ABL Credit Facility and indenture governing our Convertible Notes prohibits us from paying cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our Board of Directors and will depend on funds legally available, our results of operations, financial condition, capital requirements, the ability to pay cash dividends under our then existing revolving credit facility and other factors deemed relevant by our Board of Directors.

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

None.

Issuer Purchases of Equity Securities

During the fourth quarter of 2023, we withheld shares of our common stock to satisfy tax withholding obligations in connection with the vesting of certain stock awards and bought back certain shares at zero value. These shares are deemed to be “issuer purchases” of shares that are required to be disclosed pursuant to this Item but were not purchased as part of a publicly announced program to repurchase common shares. The following table provides information relating to our repurchase of shares of common stock during the three months ended December 31, 2023.


	Issuer Purchases of Equity Securities
				Total Number of	Approximate Dollar
				Shares Purchased as	Value of Shares That
	Total Number of	Average Price Paid		Part of Publicly	May Yet be Purchased
Period	Shares Purchased	Per Share		Announced Program	Under the Program (1)
October 1 — October 31	—	$	—	—	$	—
November 1 — November 30	8,892	$	—	—	$	—
December 1 — December 31	3,276	$	2.44	—	$	—
Total	12,168	$	0.81	—	$	—

(1)

We do not have a share repurchase program authorized by the board of directors.

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ITEM 6. [Reserved]

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion and analysis of our financial condition and results of operations together with the consolidated financial statements and related notes that are included in "Item 8. Financial Statements and Supplementary Data." This discussion contains forward-looking statements based upon current expectations that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including without limitation those described in Cautionary Statement Regarding Forward-Looking Statements and “Item 1A. Risk Factors” or in other parts of this Annual Report on Form 10-K.

Discussions of matters pertaining to the year ended December 31, 2021 and year-to-year comparisons between the years ended December 31, 2022 and 2021 are not included in this Form 10-K, but can be found under Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2022 that was filed on March 6, 2023.

Management Overview

Our rig fleet includes 26 AC powered (“AC”) rigs. Our first rig began drilling in May 2012.

We currently focus our operations on unconventional resource plays located in geographic regions that we can efficiently support from our Houston, Texas and Midland, Texas facilities in order to maximize economies of scale. Currently, our rigs are operating in the Permian Basin and the Haynesville Shale; however, our rigs have previously operated in the Eagle Ford Shale, Mid-Continent and Eaglebine regions as well.

Significant Developments

Market Conditions

Oil prices (WTI-Cushing) reached a high of $123.64 per barrel on March 8, 2022; however, prices have fallen since those highs. As of February 20, 2024, oil was $78.72 per barrel.

On August 22, 2022, natural gas prices reached a high of $9.85 per mmcf, but fell to $3.52 per mmcf as of December 31, 2022 and were $2.58 per mmcf as of December 31, 2023 and $1.58 per mmcf as of February 21, 2024. These commodity price declines, as well as take away capacity issues, caused market conditions in the Haynesville Shale to weaken rapidly, which resulted in a reduction in the number of drilling rigs operating in the Haynesville Shale, including a reduction in our operating rigs. At the end of the first quarter of 2023, we began relocating a portion of these rigs to the Permian Basin where market conditions were stronger. However, there can be no assurance that market conditions in the Permian Basin will remain strong and will not be adversely affected by recent volatility in oil prices nor any assurance that we will be successful in marketing all of these rigs in the Permian Basin or that they will be contracted on a timely basis or upon terms that are acceptable to us.

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Asset Impairment, net

We refer to rigs that meet the minimum characteristics of a super-spec, pad optimal rig as our 200 Series rigs. However, in addition to these minimum characteristics, we believe E&P operators also increasingly desire drilling contractors with the ability to provide other flexible and varying equipment packages depending upon the specific nature of their drilling program and their field-development plans. Such equipment package options include greater setback capacity allowing efficient drilling of ultra-long horizontal laterals, high-torque top drives and high-torque iron roughnecks capable of handling larger diameter drill pipe and premium threaded connections. We refer to our ShaleDriller fleet that is outfitted with one or more of these additional equipment packages as our 300 Series rigs.

During the fourth quarter of 2023, as a result of an accelerating trend toward rigs requiring 300 Series specifications, management reviewed its idle equipment and impaired $14.7 million of equipment and capital spares that it determined would no longer be utilized by the Company’s marketed fleet of 26 rigs.

During the year ended December 31, 2023, we also impaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries.

During the year ended December 31, 2022, we impaired certain drilling equipment that was designated held for sale as of December 31, 2022. Accordingly, we impaired the drilling equipment to fair market value less cost to sell, recorded asset impairment expense of $0.4 million in our consolidated statements of operations and recorded $0.3 million of assets held for sale on our consolidated balance sheet as of December 31, 2022.

Our Revenues

We earn contract drilling revenues pursuant to drilling contracts entered into with our customers. We perform drilling services on a “daywork” basis, under which we charge a specified rate per day, or “dayrate.” The dayrate associated with each of our contracts is a negotiated price determined by the capabilities of the rig, location, depth and complexity of the wells to be drilled, operating conditions, duration of the contract and market conditions. The term of land drilling contracts may be for a defined number of wells or for a fixed time period. We generally receive lump-sum payments for the mobilization of rigs and other drilling equipment at the commencement of a new drilling contract. Revenue and costs associated with the initial mobilization are deferred and recognized ratably over the term of the related drilling contract once the rig spuds. Costs incurred to relocate rigs and other equipment to an area in which a contract has not been secured are expensed as incurred. If a contract is terminated prior to the specified contract term, early termination payments received from the customer are only recognized as revenues when all contractual obligations, such as mitigation requirements, are satisfied. While under contract, our rigs generally earn a reduced rate while the rig is moving between wells or drilling locations, or on standby waiting for the customer. Reimbursements for the purchase of supplies, equipment, trucking and other services that are provided at the request of our customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred. Revenue is presented net of any sales tax charged to the customer that we are required to remit to local or state governmental taxing authorities.

Our Operating Costs

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operations management team as well as our safety and maintenance personnel who are not directly assigned to our rigs but are responsible for the oversight and support of our operations and safety and maintenance programs across our fleet.

How We Evaluate our Operations

We regularly use a number of financial and operational measures to analyze and evaluate the performance of our business and compensate our employees, including the following:

●

Safety Performance. Maintaining a strong safety record is a critical component of our business strategy. We measure safety by tracking the total recordable incident rate for our operations. In addition, we closely monitor and measure compliance with our safety policies and procedures, including "near miss" reports and job safety analysis compliance. We believe our Risk-Based HSE management system provides the required control, yet needed flexibility, to conduct all activities safely, efficiently and appropriately.

●

Utilization. Rig utilization measures the total amount of time that our rigs are earning revenue under a contract during a particular period. We measure utilization by dividing the total number of Operating Days for a rig by the total number of days the rig is available for operation in the applicable calendar period. A rig is available for operation commencing on the earlier of the date it spuds its initial well following construction or when it has been completed and is actively marketed. “Operating Days” represent the total number of days a rig is earning revenue under a contract, beginning when the rig spuds its initial well under the contract and ending with the completion of the rig’s demobilization.

●

Revenue Per Day. Revenue per day measures the amount of revenue that an operating rig earns on a daily basis during a particular period. We calculate revenue per day by dividing total contract drilling revenue earned during the applicable period by the number of Operating Days in the period. Revenues attributable to costs reimbursed by customers are excluded from this measure.

●

Operating Cost Per Day. Operating cost per day measures the operating costs incurred on a daily basis during a particular period. We calculate operating cost per day by dividing total operating costs during the applicable period by the number of Operating Days in the period. Operating costs attributable to costs reimbursed by customers and certain other costs are excluded from this measure.

●

Operating Efficiency and Uptime. Maintaining our rigs’ operational efficiency is a critical component of our business strategy. We measure our operating efficiency by tracking each drilling rig’s unscheduled downtime on a daily, monthly, quarterly and annual basis.

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Results of Operations

The following summarizes our financial and operating data for the years ended December 31, 2023 and 2022:


	Year Ended
(In thousands, except per share data)	2023			2022
Revenues	$	210,106		$	186,710
Costs and expenses
Operating costs		130,253			123,399
Selling, general and administrative		24,499			24,809
Depreciation and amortization		43,543			40,443
Asset impairment, net		14,905			350
Loss (gain) on disposition of assets, net		38			(196)
Other expense		585			—
Total cost and expenses		213,823			188,805
Operating loss		(3,717)			(2,095)
Interest expense		(35,955)			(29,575)
Loss on extinguishment of debt		—			(46,347)
Change in fair value of embedded derivative liability		—			(4,265)
Realized gain on extinguishment of derivative		—			10,765
Loss before income taxes		(39,672)			(71,517)
Income tax benefit		(1,975)			(6,196)
Net loss	$	(37,697)		$	(65,321)

Other financial and operating data
Number of marketed rigs (end of period)		26			26
Rig operating days (1)		5,711			6,308
Average number of operating rigs (2)		15.7			17.3
Rig utilization (3)		60	%		70	%
Average revenue per operating day (4)	$	33,548		$	27,258
Average cost per operating day (5)	$	19,093		$	16,940
Average rig margin per operating day	$	14,455		$	10,318
Oil price per Bbl (6) (end of year)	$	71.89		$	80.16
Natural gas price per Mcf (7) (end of year)	$	2.58		$	3.52

(1)

Rig operating days represent the number of days our rigs are earning revenue under a contract during the period, including days that standby revenues are earned. Rig operating days exclude rigs earning revenue on an early termination basis. During the years ended December 31, 2023 and 2022, there were 226.1 and 30.8 operating days in which we earned revenue on a standby basis, respectively. During the years ended December 31, 2023 and 2022, we recognized $5.9 million and zero of early termination revenue, respectively.

(2)	Average number of operating rigs is calculated by dividing the total number of rig operating days in the period by the total number of calendar days in the period.

(3)	Rig utilization is calculated as rig operating days divided by the total number of days our drilling rigs are available during the applicable period.

(4)

Average revenue per operating day represents total contract drilling revenues earned during the period divided by rig operating days in the period. Excluded in calculating average revenue per operating day are revenues associated with the reimbursement of (i) out-of-pocket costs paid by customers of $12.6 million and $14.8 million during the years ended December 31, 2023 and 2022, respectively and (ii) early termination revenues of $5.9 million and zero during the years ended December 31, 2023 and 2022, respectively.

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(5)

Average cost per operating day represents total operating costs incurred during the period divided by rig operating days in the period. The following costs are excluded in calculating average cost per operating day: (i) out-of-pocket costs reimbursed by customers of $12.6 million and $14.8 million during the years ended December 31, 2023 and 2022, respectively, (ii) overhead costs of $2.2 million and $1.8 million during the years ended December 31, 2023 and 2022, respectively, (iii) reactivation costs of $2.1 million and zero during the years ended December 31, 2023 and 2022, respectively, and (iv) rig decommissioning and transition costs between basins, of $4.3 million and zero during the years ended December 31, 2023 and 2022, respectively.

(6)	WTI spot price as reported by the United States Energy Information Administration.

(7)	Henry Hub spot price as reported by the United States Energy Information Administration.

Comparison of the years ended December 31, 2023 and 2022

Revenues

Revenues for the year ended December 31, 2023 were $210.1 million, representing a 12.5% increase over revenues of $186.7 million for the year ended December 31, 2022. This increase was attributable to an increase in contractual dayrates. Revenue per day increased by 23.1% to $33,548 during 2023 compared to revenue per day of $27,258 during 2022. Additionally, we recognized $5.9 million of early termination revenue during the year ended December 31, 2023. There were no early termination revenues during the year ended December 31, 2022.

Operating Costs

Operating costs for the year ended December 31, 2023 were $130.3 million, representing a 5.6% increase over operating costs for the year ended December 31, 2022 of $123.4 million. This increase was primarily attributable to higher per day operating expenses associated with higher personnel and repair and maintenance costs in the current year. Operating cost per day increased to $19,093 during 2023, representing a 12.7% increase compared to cost per day of $16,940 during 2022. We also incurred approximately $6.4 million in costs associated with reactivations and transitioning rigs from the Haynesville to the Permian Basin during the year ended December 31, 2023.

Selling, General and Administrative Expenses

Selling, general and administrative expenses for the year ended December 31, 2023 were $24.5 million, representing a 1.2% decrease over selling, general and administrative expenses for the year ended December 31, 2022 of $24.8 million. This decrease was primarily related to lower incentive compensation expense.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2023 was $43.5 million, representing a 7.7% increase compared to $40.4 million for the year ended December 31, 2022. This increase was primarily the result of asset additions related to reactivated rigs in 2022 and 2023.

Asset Impairment, net

Asset impairment, net was $14.9 million for the year ended December 31, 2023, compared to $0.4 million for the year ended December 31, 2022. During the year ended December 31, 2023, we recorded an asset impairment charge of $14.7 million relating to certain equipment and capital spares that did not meet 300 Series specifications and we impaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries. During the year ended December 31, 2022, we impaired certain drilling equipment that was designated held for sale and impaired the drilling equipment to fair market value less the cost to sell. See “Significant Developments – Asset Impairment, net” for additional information.

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Loss (Gain) on Disposition of Assets, net

A loss on the disposition of assets totaling $38 thousand and a gain on the disposition of assets totaling $0.2 million was recorded for the years ended December 31, 2023 and 2022, respectively. For the year ended December 31, 2023, the gain on disposition of assets relates to the sale of certain drilling equipment of $1.7 million offset by a loss of $1.7 million on the disposal of certain assets related to reactivations and overhauls performed during the year. For the year ended December 31, 2022, the gain on disposition of assets relates to the sale of certain drilling equipment of $1.5 million offset by a loss of $1.3 million on the disposal of certain assets related to overhauls performed during the year.

Interest Expense

Interest expense was $36.0 million for the year ended December 31, 2023 compared to $29.6 million for the year ended December 31, 2022. The increase in the current year interest expense is attributable to higher interest rates and principal debt associated with the Convertible Notes issued on March 18, 2022, as well as non-cash amortization of debt discount and deferred financing costs associated with the Convertible Notes.

Loss on Extinguishment of Debt

Loss on extinguishment of debt was $46.3 million for the year ended December 31, 2022. The debt terms of the Convertible Notes, of which affiliates of our prior Term Loan Facility are 50.1% noteholders, were determined to be substantially different terms from the Term Loan Facility and therefore required to be accounted for as an extinguishment of the Term Loan Facility. Accordingly, we recognized a non-cash loss on the extinguishment of debt of approximately $46.3 million associated with non-cash fees settled in shares and the fair value of the embedded derivatives attributable to the affiliates of our prior Term Loan Facility and the recognition of previously unamortized debt issuance costs.

Change in Fair Value of Embedded Derivative Liability

We recognized a loss of $4.3 million for the year ended December 31, 2022 related to the change in fair value of the embedded derivative liability between the issuance date of the Convertible Notes, March 18, 2022, and the date the derivative liability was extinguished, June 8, 2022. See Note 8 “Embedded Derivative Liability” in the accompanying consolidated financial statements.

Realized Gain on Extinguishment of Derivative

We recognized a gain of $10.8 million for the year ended December 31, 2022 related to the extinguishment of the variable component of the PIK interest rate feature of the derivative liability. See Note 8 “Embedded Derivative Liability” in the accompanying consolidated financial statements.

Income Tax Benefit

Our effective income tax rate fluctuates from the U.S. statutory tax rate based on, among other factors, changes in pretax income in jurisdictions with varying statutory tax rates, the impact of U.S. state and local taxes, the realizability of deferred tax assets and other differences related to the recognition of income and expense between GAAP and tax accounting.

Income tax benefit for the year ended December 31, 2023 amounted to $2.0 million compared to income tax benefit of $6.2 million for the year ended December 31, 2022. The effective tax rate was 5.0% for the year ended 2023 compared to 8.7% for the year ended 2022. Our effective tax rate for the year ended December 31, 2023 and 2022 differed from the statutory federal income tax rate primarily due to the impact of the change in valuation allowance on deferred tax assets, state taxes, and permanent items related to certain debt items that are expensed for book purposes but are not deductible for tax purposes. The impact of the permanent items related to the debt continues into 2024 but has less of an impact as a significant loss on extinguishment of debt was recorded in 2022. See Note 9 “Income Taxes” in the accompanying consolidated financial statements.

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In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, and when necessary, valuation allowances are recorded. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We assess the realizability of our deferred tax assets quarterly and consider carryback availability, the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment.

We continue to monitor income tax developments in the United States. We will incorporate into our future financial statements the impacts, if any, of future regulations and additional authoritative guidance when finalized.

Liquidity and Capital Resources

Our liquidity as of December 31, 2023 was $26.2 million, consisting of cash on hand of $5.6 million and $20.6 million of availability under our $40.0 million ABL Credit Facility, based on a borrowing base of $26.3 million.

We expect our future capital and liquidity needs to be related to operating expenses, maintenance capital expenditures, payment of mandatory offer obligations on our Convertible Notes, working capital and general corporate purposes.

Cash flow from operations was positive during 2023. We elected to PIK the outstanding interest as of March 31, 2023 and September 30, 2023 of $11.6 million and $12.4 million due under our Convertible Notes, respectively. We have the right, at our option, to PIK interest under the Convertible Notes for the entire term of the Convertible Notes and have elected to PIK the interest payment due on March 31, 2024.

We currently believe that cash generated from current operations, the actions we have taken to date and our existing sources of liquidity are sufficient to fund our operations for the next twelve months.

You should read "Item 1A Risk Factors" in particular, "Risks Related to Our Liquidity", for additional information regarding risks surrounding our operations and financial liquidity.

Contractual Obligations

As of December 31, 2023, we had contractual obligations as described below.

Our obligations include "off-balance sheet arrangements" whereby the liabilities associated with unconditional purchase obligations are not fully reflected in our consolidated balance sheets.


(in thousands)	2024		2025		2026		Total
Convertible Notes	$	—	$	—	$	161,709	$	161,709
Mandatory Offering on Convertible Notes		14,000		3,500		—		17,500
Interest on Convertible Notes		—		—		71,988		71,988
ABL Credit Facility		—		5,500		—		5,500
Interest on ABL Credit Facility		622		428		—		1,050
Finance leases		1,414		1,138		634		3,186
Purchase obligations		3,403		—		—		3,403
Total contractual obligations	$	19,439	$	10,566	$	234,331	$	264,336

Our long-term debt as of December 31, 2023 consisted of amounts due under our Convertible Notes, our ABL Credit Facility and finance leases (as defined and further described below). Interest is related to our estimated future contractual interest obligations on long-term indebtedness outstanding as of December 31, 2023. Interest payment obligations on our Convertible Notes were estimated based on the 15.1% interest rate that was in effect December 31, 2023, and the principal balance of $179.2 million as of December 31, 2023, and assuming repayment of the outstanding balance occurs on March 18, 2026. Interest payment obligations on our ABL Credit Facility were

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estimated based on the 10.25% interest rate that was in effect as of December 31, 2023, and the principal balance of $5.5 million as of December 31, 2023, and assuming repayment of the outstanding balance occurs on September 30, 2025. Additionally included in our contractual obligations are finance leases on vehicles and certain drilling equipment. These leases generally have a term of 36 months and are paid monthly.

Our purchase obligations relate primarily to outstanding purchase orders for rig equipment or components ordered but not received. We have made progress payments on these orders of approximately $0.1 million that could be forfeited if we were to cancel these orders.

Cash Flows


	Year Ended December 31,
(in thousands)	2023		2022
Net cash provided by operating activities	$	61,022	$	28,577
Net cash used in investing activities		(36,217)		(38,304)
Net cash (used in) provided by financing activities		(24,566)		10,913
Net increase in cash and cash equivalents	$	239	$	1,186

Net Cash Provided By Operating Activities

Cash provided by operating activities was $61.0 million for the year ended December 31, 2023 compared to cash provided by operating activities of $28.6 million for the year ended December 31, 2022. Factors affecting changes in operating cash flows are similar to those that impact net earnings, with the exception of non-cash items such as depreciation and amortization, impairments, gains or losses on disposals of assets, gains or losses on extinguishment of debt, non-cash interest expense, non-cash compensation, deferred taxes and amortization of debt discount and debt issuance costs. Additionally, changes in working capital items such as accounts receivable, inventory, prepaid expense, accounts payable and accrued liabilities can significantly affect operating cash flows. Cash flows from operating activities during 2023 were higher as a result of a decrease in net loss of $27.6 million, adjusted for non-cash items of $97.1 million, compared to $101.5 million in 2022. Additionally, working capital changes that increased cash flows from operating activities were $1.6 million in 2023 compared to $7.6 million working capital changes that decreased cash flows from operating activities in 2022.

Net Cash Used In Investing Activities

Cash used in investing activities was $36.2 million for the year ended December 31, 2023 compared to $38.3 million for the year ended December 31, 2022. Our primary investing activities in 2023 related to 300 Series conversions and reactivations and maintenance capital expenditures. Cash payments of $40.7 million for capital expenditures were offset by proceeds from the sale of property, plant and equipment of $4.4 million. Cash payments during 2023 included approximately $16.2 million associated with equipment purchased in 2022. During 2022, cash payments of $43.0 million for capital expenditures were offset by proceeds from the sale of property, plant and equipment of $4.6 million and proceeds from insurance claims of $0.2 million.

Net Cash (Used In) Provided By Financing Activities

Cash used in financing activities was $24.6 million for the year ended December 31, 2023 compared to cash provided by financing activities of $10.9 million for the year ended December 31, 2022. During 2023, we had repayments under our Revolving ABL Credit Facility of $41.0 million, redemption of $15.0 million of our Convertible Notes, taxes paid for vesting of restricted stock units of $0.7 million, the purchase of treasury stock of $7.0 thousand and payments for finance lease obligations of $2.6 million offset by proceeds from borrowings under our Revolving ABL Credit Facility of $34.7 million.

During 2022, we received proceeds from our Convertible Notes of $157.5 million, proceeds from borrowings under our Revolving ABL Credit Facility of $5.6 million and proceeds from the issuance of common stock through our ATM transaction, net of issuance costs, of $3.0 million offset by repayment of our Term Loan Facility of $139.1 million,

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payment of our merger consideration of $2.9 million, issuance costs paid related to our Convertible Notes of $7.0 million, financing costs paid related to our Revolving ABL Credit Facility of $0.3 million, repayments under our Revolving ABL Credit Facility of $0.1 million, taxes paid for vesting of restricted stock units of $10.0 thousand, the purchase of treasury stock of $10.0 thousand and payments for finance lease obligations of $5.8 million.

Long-term Debt

On March 18, 2022, we entered into a subscription agreement with affiliates of MSD Partners, L.P. and an affiliate of Glendon Capital Management L.P. (the “Subscription Agreement”) for the placement of $157.5 million aggregate principal amount of convertible secured PIK toggle notes due 2026 (the “Convertible Notes”), and currently have $179.2 million principal amount of Convertible Notes outstanding as of December 31, 2023. The Convertible Notes were issued pursuant to an Indenture, dated as of March 18, 2022 (the “Indenture”). The obligations under the Convertible Notes are secured by a first priority lien on collateral other than accounts receivable, deposit accounts and other related collateral pledged as first priority collateral (“Priority Collateral”) under the Revolving ABL Credit Facility (defined below). Proceeds from the private placement of the Convertible Notes were used to repay all of our outstanding indebtedness under our term loan credit agreement, to repay obligations to prior equity holders of Sidewinder Drilling LLC, and for working capital purposes. In connection with the placement of the Convertible Notes, we issued 2,268,000 shares of our common stock as a structuring fee. The structuring fee shares were issued on March 18, 2022, concurrent with the closing of the private placement of the Convertible Notes. The Convertible Notes mature on March 18, 2026.

The Convertible Notes have a cash interest rate of the Secured Overnight Financing Rate plus a 10-basis point credit spread, with a floor of 1% (collectively, “SOFR”) plus 12.5%. The Convertible Notes have a PIK interest rate of SOFR plus 9.5%. We have the right at our option, to PIK interest under the Convertible Notes for the entire term of the Convertible Notes. Interest on the Convertible Notes is due on March 31 and September 30 each year. We elected to PIK outstanding interest as of September 30, 2022, March 31, 2023, and September 30, 2023, resulting in the issuance of an additional $12.7 million, $11.6 million and $12.4 million principal amount of Convertible Notes, respectively. As of December 31, 2023, accrued PIK interest of $6.8 million, which is due March 31, 2024 and will result in the issuance of additional Convertible Notes, is classified as “Other Long-Term Liabilities” on our consolidated balance sheet. As of December 31, 2022, accrued PIK interest of $5.8 million, which was due March 31, 2023 and resulted in the issuance of additional Convertible Notes, was classified as “Other Long-Term Liabilities” on our consolidated balance sheet.

The effective conversion price of the Convertible Notes is $4.51 per share (221.72949 shares of Common Stock per $1,000 principal amount of Convertible Notes). We may issue up to $7.5 million of additional Convertible Notes. We may convert all Convertible Notes (including PIK notes) in connection with a Qualified Merger Conversion (as defined in the Indenture) and may issue additional shares of common stock upon conversion of Convertible Notes to the extent the number of shares issuable upon such conversion would exceed the number of shares of common stock issuable at the otherwise then-current conversion price.

Each noteholder has a right to convert our Convertible Notes into shares of ICD Common Stock at any time after issuance through maturity. The conversion price is $4.51 per share. Under the Indenture, a holder is not entitled to receive shares of our common stock upon conversion of any Convertible Notes to the extent to which the aggregate number of shares of common stock that may be acquired by such beneficial owner upon conversion of Convertible Notes, when added to the aggregate number of shares of common stock deemed beneficially owned, directly or indirectly, by such beneficial owner and each person subject to aggregation of common stock with such beneficial owner under Section 13 or Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and the rules promulgated thereunder at such time (an “Aggregated Person”) (other than by virtue of the ownership of securities or rights to acquire securities that have limitations on such beneficial owner’s or such person’s right to convert, exercise or purchase similar to this limitation), as determined pursuant to the rules and regulations promulgated under Section 13(d) of the Exchange Act, would exceed 9.9% (the “Restricted Ownership Percentage”) of the total issued and outstanding shares of Common Stock (the “Section 16 Conversion Blocker”); provided that any holder has the right to elect for the Restricted Ownership Percentage to be 19.9% with respect to such Holder, (x) at any time, in which case, such election will become effective sixty-one days following written notice thereof to us or (y) in the case of a holder acquiring Convertible Notes on the Issue Date, in such Holder’s Subscription Agreement. In lieu of any shares of common stock not delivered to a converting holder by operation of the Restricted Ownership Percentage limitation, we will deliver to

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such Holder Pre-Funded Warrants in respect of any equal number of shares of common stock. Such Pre-Funded Warrants will contain substantially similar Restricted Ownership Percentage terms.

The Indenture includes a mandatory redemption offer requirement (the “Mandatory Offer Requirement”). Beginning June 30, 2023, we were obligated to offer to redeem $5.0 million of Convertible Notes on a quarterly basis through December 31, 2023, and $3.5 million of Convertible Notes on a quarterly basis through March 31, 2025. The mandatory offer price is an amount in cash equal to the principal amount of such Note plus accrued and unpaid interest on such Note. During 2023, our noteholders accepted our offers to redeem $5.0 million of Convertible Notes on each of June 30, 2023, September 30, 2023 and December 31, 2023. As such, on June 30, 2023, we redeemed and paid cash for $5.0 million of principal of Convertible Notes and $0.2 million of accrued interest on such Notes; on September 30, 2023 we redeemed and paid cash for $5.0 million of principal of Convertible Notes and $0.4 million of accrued interest on such Notes; and on December 31, 2023 we redeemed and paid cash for $5.0 million of principal of Convertible Notes and $0.2 million of accrued interest on such Notes. We have the ability and intent to refinance the mandatory redemption offers that occur within the next twelve months under our Revolving ABL Credit Facility and as a result such amounts have been classified as long-term debt. On June 30, 2023, September 30, 2023 and December 31, 2023, we borrowed $5.0 million, $5.0 million and $5.0 million, respectively, under our Revolving ABL Credit Facility to refinance the accepted mandatory offerings.

The Indenture contains financial covenants, including a liquidity covenant of $10.0 million; a springing fixed charge coverage ratio covenant of 1.00 to 1.00 that is tested when availability under the Revolving ABL Credit Facility (defined below) is below $5.0 million at any time that the Convertible Notes are outstanding; and capital expenditure limits of $14.8 million during the nine months ended September 30, 2024 and $11.25 million during the nine months ended June 30, 2025, subject to adjustment upward by $500,000 per year for each rig above 17 that operates during each year. In addition, capital expenditures are excluded from this covenant (a) if funded from equity proceeds, (b) if relating to the reactivation of a rig so long as (i) we have a signed contract with a customer with respect to each such rig of at least one (1) year duration providing for early termination payments consistent with past practice equal to at least the expected margin on the contract, (ii) the expected margin on such rig contract will be equal to or exceed such reactivation capital expenditures, and (iii) the reactivation capital expenditures, rig contract and the expected margin calculation are approved by our board of directors or (c) if relating to other capital expenditures specifically approved by written or electronic consent by both (i) the required holders (which approval may, for the avoidance of doubt, be provided by the required holders in their sole discretion for an amount of capital expenditures to be committed or made by the Company or a subsidiary of the Company within ninety (90) days after the date of such consent) and (ii) the Board of Directors of the Company. The holders of our Convertible Notes consented to capital expenditure adjustments under this covenant aggregating $10.6 million in 2022 and $16.9 million in 2023. The Indenture also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments (including the payment of dividends), investments and transactions with affiliates. The Indenture also provides for customary events of default, including breaches of material covenants, defaults under the Revolving ABL Credit Facility or other material agreements for indebtedness, and a change of control. Beginning 18 months prior to maturity, we may elect to suspend the Convertible Debt covenant requirements by depositing cash and short-term treasuries with the Trustee in an amount equal to all amounts due to the noteholders including principal, premium (if any) and interest. We are in compliance with our covenants as of December 31, 2023.

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reclassification or change of our common stock (other than (x) changes solely resulting from a subdivision or combination of the common stock, (y) a change only in par value or from par value to no par value or no par value to par value and (z) stock splits and stock combinations that do not involve the issuance of any other series or class of securities); (ii) consolidation, merger, combination or binding or statutory share exchange involving us; (iii) sale, lease or other transfer of all or substantially all of the assets of ours and our Subsidiaries, taken as a whole, to any person; or (iv) other similar event, and, as a result of which, the common stock is converted into, or is exchanged for, or represents solely the right to receive, other securities, cash or other property, or any combination of the foregoing. A “Company Conversion Rate” means, in respect of any Qualified Merger, the greater of (a) the relevant Conversion Rate, (b) $1,000 divided by our Conversion VWAP, and (c) the lowest rate that would cause the MOIC Condition to be satisfied with respect to the related Qualified Merger Conversion. A “Company Conversion VWAP” means, in respect of any Qualified Merger, the average of daily VWAP over the five (5) VWAP Trading Days prior to the earlier of signing or public announcement (by any party, and whether formal or informal, including for the avoidance of doubt any media reports thereof) of a definitive agreement in respect of such Qualified Merger as calculated by the Calculation Agent. The “MOIC Condition” means, with respect to any potential Qualified Merger Conversion, MOIC is greater than or equal to the MOIC Required Level. The “MOIC Required Level” means $1,350. “MOIC” means, with respect to any potential Qualified Merger Conversion, an amount determined by the Calculation Agent equal to the aggregate return on a hypothetical Note with $1,000 face amount, issued on the Issue Date, from the Issue Date through the potential Qualified Merger Conversion Date, including (x) the aggregate amount of any cash interest paid on such hypothetical Note from the Issue Date through the potential Qualified Merger Conversion Date, (y) the aggregate fair market value of any Conversion Consideration that would be received by the Holder of such hypothetical Note on the relevant Qualified Merger Conversion Date and (z) the aggregate fair market value of any Conversion Consideration that would be received on the relevant Qualified Merger Conversion Date by the Holder of any PIK Notes issued in respect of (or the relevant increase in value of) such hypothetical Note.

The Indenture provides that at any time on or after September 18, 2024, the Company may executive an in-substance defeasance of the Convertible Notes and suspend all covenants and related security interests in the Company’s equipment and assets under the Indenture by irrevocably depositing with the trustee funds sufficient funds to pay the principal and interest on the outstanding Convertible Notes through the maturity date of the Convertible Notes.

We early adopted ASU 2020-06 as of January 1, 2022 and concluded the Convertible Notes were accounted for as debt, with embedded features. As a consequence of the embedded features, the Convertible Notes gave rise to an embedded derivative liability. See “Embedded Derivative Liability.” The debt terms of the Convertible Notes, of which affiliates of our prior Term Loan Facility are 50.1% noteholders, were determined to be substantially different terms from the Term Loan Facility and therefore required to be accounted for as an extinguishment of the Term Loan Facility. Accordingly, in the second quarter of 2022 we recognized a loss on the extinguishment of debt of approximately $46.3 million. This was a non-cash expense primarily associated with the recognition of unamortized debt issuance costs, non-cash fees settled in shares to the affiliates of our prior Term Loan Facility and the fair value of the embedded derivatives. We recorded an embedded derivative liability of $75.7 million at the time of the issuance and a debt discount of $37.8 million. Issuance costs consisting of cash fees of $7.4 million and a non-cash structuring fee settled in shares of $2.3 million along with the debt discount were recorded as a direct deduction from the Convertible Notes in the consolidated balance sheet. The debt discount and issuance costs are amortized to interest expense using the effective interest rate method over the term of the Convertible Notes. The effective interest rate for the Convertible Notes as of December 31, 2023 is 25.4%. For the year ended December 31, 2023, the contractual interest expense was $25.9 million and the debt discount and issuance cost amortization was $8.5 million. For the year ended December 31, 2022, the contractual interest expense was $18.5 million and the debt discount and issuance cost amortization was $6.7 million.

Embedded Derivative Liability

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feature as a result of violations of credit-risk related covenants. We evaluated these embedded features under the guidance of ASC 815 and determined that they required bifurcation at fair value. However, management determined the probability of a Qualified Merger to be remote and as such the fair value of the embedded conversion feature has been estimated to be zero. Management also evaluated the contingent interest feature and determined the likelihood of payment to be remote. Accordingly, the fair value of the contingent interest feature was also estimated to be zero. Lastly, management evaluated the conversion rate feature and the decrease in PIK interest feature and determined that these embedded features met all three criteria in ASC 815-15-25-1 and therefore required bifurcation. Accordingly, as of the Convertible Notes issuance date, we recorded a derivative liability representing the increase in the conversion rate feature and the decrease in PIK interest feature. The derivative liability was presented as a non-current liability in our consolidated balance sheet and was adjusted to reflect fair value at each period end with changes in fair value recorded in the “Change in fair value of embedded derivative liability” financial statement line item of our consolidated statements of operations.

After the approval of certain matters by our stockholders at our 2022 Annual Meeting of Stockholders held June 8, 2022, certain features under our Convertible Notes were modified and no longer met the criteria to bifurcate from the host debt agreement. As of December 31, 2023 and 2022, we had no embedded derivative liability recorded. See Financial Instruments and Fair Value in Note 2 “Summary of Significant Accounting Policies” for additional information.

Term Loan Facility

On October 1, 2018, we entered into a Term Loan Credit Agreement (the “Term Loan Credit Agreement”) for an initial term loan in an aggregate principal amount of $130.0 million, (the “Term Loan Facility”) and a delayed draw term loan facility in an aggregate principal amount of up to $15.0 million (the “DDTL Facility”, and together with the Term Loan Facility, the “Term Facilities”). The Term Facilities had a maturity date of October 1, 2023, but were repaid in their entirety on March 18, 2022 with proceeds from the issuance of the Convertible Notes.

Interest under the Term Loan Facility was determined by reference, at our option, to either (i) a “base rate” equal to the higher of (a) the federal funds effective rate plus 0.05%, (b) the London Interbank Offered Rate (“LIBOR”) with an interest period of one month, plus 1.0%, and (c) the rate of interest as publicly quoted from time to time by the Wall Street Journal as the “prime rate” in the United States, plus an applicable margin of 6.5%, or (ii) a “LIBOR rate” equal to LIBOR with an interest period of one month, plus an applicable margin of 7.5%. For the year ended December 31, 2022, we elected to PIK interest of $3.2 million, which increased our Term Loan balance accordingly.

Revolving ABL Credit Facility

On October 1, 2018, we entered into a $40.0 million revolving credit agreement (the “Revolving ABL Credit Facility”), including availability for letters of credit in an aggregate amount at any time outstanding not to exceed $7.5 million. Availability under the Revolving ABL Credit Facility is subject to a borrowing base calculated based on 85% of the net amount of our eligible accounts receivable, minus reserves. The Revolving ABL Credit Facility has a maturity date of September 30, 2025.

Interest under the Revolving ABL Credit Facility is determined by reference, at our option, to either (i) a “base rate” equal to the higher of (a) the floor, or 0.0%, (b) the federal funds effective rate plus 0.05%, (c) term SOFR for a one month tenor plus 1.0% based on availability and (d) the prime rate of Wells Fargo, plus in each case, an applicable base rate margin ranging from 1.0% to 1.5% based on quarterly availability, or (ii) a revolving loan rate equal to SOFR for the applicable interest period plus an applicable SOFR margin ranging from 2.36% to 2.86% based on quarterly availability. We also pay, on a quarterly basis, a commitment fee of 0.375% (or 0.25% at any time when revolver usage is greater than 50% of the maximum credit) per annum on the unused portion of the Revolving ABL Credit Facility commitment.

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asset dispositions, restricted payments (including the payment of dividends), investments and transactions with affiliates. The Revolving ABL Credit Facility also provides for customary events of default, including breaches of material covenants, defaults under the Indenture or other material agreements for indebtedness, and a change of control. We are in compliance with our financial covenants as of December 31, 2023.

The obligations under the Revolving ABL Credit Facility are secured by a first priority lien on Priority Collateral, which includes all accounts receivable and deposit accounts, and a second priority lien on the Indenture, and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries. As of December 31, 2023, the weighted-average interest rate on our borrowings was 14.93%. As of December 31, 2023, the borrowing base under our Revolving ABL Credit Facility was $26.3 million, and we had $20.6 million of availability remaining of our $40.0 million commitment on that date.

Additionally, included in our long-term debt are finance leases. These leases generally have initial terms of 36 months and are paid monthly.

Critical Accounting Estimates

The consolidated financial statements are impacted by the accounting policies and estimates and assumptions used by management during their preparation. These estimates and assumptions are evaluated on an on-going basis. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities if not readily available from other sources. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our consolidated financial statements. Other significant accounting policies are summarized in Note 2 “Summary of Significant Accounting Policies” to the consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."

Property, Plant and Equipment

Property, plant and equipment, including renewals and betterments, are stated at cost less accumulated depreciation. All property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets, which range from two to 39 years. Our determination of the useful lives and salvage value of property and equipment requires us to make various assumptions when the assets are acquired or placed into service that reflect both historical experience and expectations regarding future operations, rig utilization and asset performance. Useful lives and salvage values of rigs are difficult to estimate due to a variety of factors including technological advances that impact oil and gas drilling, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. Applying different judgments and assumptions in establishing the useful lives and salvage values would likely result in materially different net carrying amounts and depreciation expense for our assets. We reevaluate the remaining useful lives and salvage values of our rigs when certain events occur that directly impact the useful lives and salvage values of the rigs. The cost of maintenance and repairs are expensed as incurred. Major overhauls and upgrades are capitalized and depreciated over their remaining useful life.

We review our assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets that are held and used is measured by comparison of the estimated future undiscounted cash flows associated with the asset to the carrying amount of the asset. The estimates of future undiscounted cash flows are based on historical cyclical trends in the industry as well as our expectations regarding the continuation of these trends in the future. Our cash flow models are based on a number of estimates regarding future operations that may be subject to significant variability, are sensitive to changes in market conditions, and are reasonably likely to change in the future. If the carrying value of such assets is less than the estimated undiscounted cash flow, an impairment charge is recorded in the amount by which the carrying amount of the assets exceeds their estimated fair value. The use of different assumptions could increase or decrease the estimated fair value of assets and could therefore affect the impairment charge.

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Asset impairment expense was $14.9 million and $0.4 million for the years ended December 31, 2023 and 2022, respectively.

Other Matters

Off-Balance Sheet Arrangements

We are party to certain arrangements defined as “off-balance sheet arrangements” that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. These arrangements relate to non-cancelable operating leases with terms of less than twelve months and unconditional purchase obligations not fully reflected on our consolidated balance sheets. See Note 13 “Commitments and Contingencies” to our consolidated financial statements for additional information.

Recent Accounting Pronouncements

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This guidance requires an entity to disclose significant segment expenses impacting profit and loss that are regularly provided to the Chief Operating Decision Maker (“CODM”) to assess segment performance and to make decisions about resource allocations. This guidance is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We do not expect the standard to have a material impact on our financial statement disclosures.

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. This guidance requires that an entity disclose specific categories in the effective tax rate reconciliation as well as provide additional information for reconciling items that meet a quantitative threshold. Also, this guidance requires certain disclosures of state versus federal income tax expense and taxes paid. The amendments in this guidance are effective for annual periods beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact this guidance will have on our financial statement disclosures.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to a variety of market risks including risks related to potential adverse changes in interest rates and commodity prices. We actively monitor exposure to market risk and continue to develop and utilize appropriate risk management techniques. We do not use derivative financial instruments for trading or to speculate on changes in commodity prices.

Interest Rate Risk

Total long-term debt as of December 31, 2023 included $184.7 million of floating-rate debt attributed to borrowings at an average interest rate of 14.93%. As a result, our annual interest cost in 2024 will fluctuate based on short-term interest rates. The impact on annual cash flow of a 10% increase in the floating-rate (approximately 16.42%) would be approximately $2.8 million annually based on the floating-rate debt and other obligations outstanding as of December 31, 2023; however, there are no assurances that possible rate changes would be limited to such amounts.

Commodity Price Risk

Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling and production services activities. Reduced demand for oil and natural gas generally results in lower prices for these commodities and may impact the economics of planned drilling projects and ongoing production projects, resulting in the curtailment, reduction, delay or postponement of such projects for an indeterminate period of time. When drilling and production activity and spending decline, both dayrates and utilization have also historically declined. Declines in oil and natural gas prices and the general economy could materially and adversely affect our business, results of operations, financial condition and growth strategy.

In addition, if oil and natural gas prices decline, companies that planned to finance exploration, development or production projects through the capital markets may be forced to curtail, reduce, postpone or delay drilling activities even further, and also may experience an inability to pay suppliers. Adverse conditions in the global economic environment could also impact our vendors’ and suppliers’ ability to meet obligations to provide materials and services in general. If any of the foregoing were to occur, or if market conditions were depressed for a prolonged period of time, it could have a material adverse effect on our business and financial results and our ability to timely and successfully implement our growth strategy.

Our business, operating results and financial conditions are subject to various risks outlined in our Current Reports on Form 10-Q under Part II, Section 1a “Risk Factors,” as well as the risk factors outlined in this Annual Report on Form 10-K under Part I, Item 1a “Risk Factors.”

Credit and Capital Market Risk

Our customers may finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as currently being experienced, can make it difficult for our customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices, or a reduction of available financing may result in a reduction in customer spending and the demand for our drilling services. This reduction in spending could have a material adverse effect on our business, financial condition, cash flows, and results of operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Independence Contract Drilling, Inc.
Report of Independent Registered Public Accounting Firm for the year ended December 31, 2023 (PCAOB ID 659)	49
Report of Independent Registered Public Accounting Firm for the year ended December 31, 2022 (PCAOB ID 243)	50
Consolidated Balance Sheets as of December 31, 2023 and 2022	51
Consolidated Statements of Operations for the years ended December 31, 2023 and 2022	52
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2023 and 2022	53
Consolidated Statements of Cash Flows for the years ended December 31, 2023 and 2022	54
Notes to Consolidated Financial Statements	55
Schedule II - Valuation and Qualifying Accounts	81

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of

Independence Contract Drilling, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of Independence Contract Drilling, Inc. (the “Company”) as of December 31, 2023, the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended, and the related notes and schedule (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2023, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“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 the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

Critical Audit Matters

Critical audit matters are matters arising from the current period audit of the (consolidated) financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.

/s/ MOSS ADAMS, LLP

Houston, Texas

February 28, 2024

We have served as the Company’s auditor since 2023.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Independence Contract Drilling, Inc.

Houston, Texas

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Independence Contract Drilling, Inc. (the “Company”) as of December 31, 2022, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the year ended December 31, 2022, and the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022, and the results of its operations and its cash flows for the year ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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 the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ BDO USA, LLP

We served as the Company’s auditor from 2015 to 2023.

Houston, Texas

March 6, 2023

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Independence Contract Drilling, Inc.

Consolidated Balance Sheets

(In thousands, except par value and share amounts)


	December 31,		December 31,
	2023		2022
Assets
Cash and cash equivalents	$	5,565	$	5,326
Accounts receivable		31,695		39,775
Inventories		1,557		1,508
Assets held for sale		—		325
Prepaid expenses and other current assets		4,759		4,736
Total current assets		43,576		51,670
Property, plant and equipment, net		348,193		376,084
Other long-term assets, net		2,908		1,960
Total assets	$	394,677	$	429,714
Liabilities and Stockholders’ Equity
Liabilities
Current portion of long-term debt	$	1,226	$	2,485
Accounts payable		22,990		31,946
Accrued liabilities		16,371		17,608
Total current liabilities		40,587		52,039
Long-term debt, net		154,549		143,223
Deferred income taxes, net		9,761		12,266
Other long-term liabilities		8,201		7,474
Total liabilities		213,098		215,002
Commitments and contingencies (Note 13)
Stockholders’ equity
Common stock, $0.01 par value, 250,000,000 shares authorized; 14,523,124 and 13,698,851 shares issued, respectively, and 14,425,864 and 13,613,759 shares outstanding, respectively		144		136
Additional paid-in capital		622,169		617,606
Accumulated deficit		(436,794)		(399,097)
Treasury stock, at cost, 97,260 shares and 85,092 shares, respectively		(3,940)		(3,933)
Total stockholders’ equity		181,579		214,712
Total liabilities and stockholders’ equity	$	394,677	$	429,714

The accompanying notes are an integral part of these consolidated financial statements.

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Independence Contract Drilling, Inc.

Consolidated Statements of Operations

(In thousands, except per share amounts)


	Year Ended December 31,
	2023		2022
Revenues	$	210,106	$	186,710
Costs and expenses
Operating costs		130,253		123,399
Selling, general and administrative		24,499		24,809
Depreciation and amortization		43,543		40,443
Asset impairment, net		14,905		350
Loss (gain) on disposition of assets, net		38		(196)
Other expense		585		—
Total costs and expenses		213,823		188,805
Operating loss		(3,717)		(2,095)
Interest expense		(35,955)		(29,575)
Loss on extinguishment of debt		—		(46,347)
Change in fair value of embedded derivative liability		—		(4,265)
Realized gain on extinguishment of derivative		—		10,765
Loss before income taxes		(39,672)		(71,517)
Income tax benefit		(1,975)		(6,196)
Net loss	$	(37,697)	$	(65,321)
Loss per share:
Basic and diluted	$	(2.69)	$	(5.01)
Weighted average number of common shares outstanding:
Basic and diluted		14,012		13,026

The accompanying notes are an integral part of these consolidated financial statements.

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Independence Contract Drilling, Inc.

Consolidated Statements of Changes in Stockholders’ Equity

(In thousands, except share amounts)



				Additional						Total
	Common Stock			Paid-in		Accumulated		Treasury		Stockholders’
	Shares	Amount		Capital		Deficit		Stock		Equity
Balances at December 31, 2021	10,206,085	$	102	$	532,826	$	(333,776)	$	(3,923)	$	195,229
RSUs vested, net of shares withheld for taxes	81,067		1		(10)		—		—		(9)
Purchase of treasury stock	(3,246)		—		—		—		(10)		(10)
Issuance of common stock through at-the-market facility, net of offering costs	1,061,853		10		3,028		—		—		3,038
Shares issued for structuring fee	2,268,000		23		9,140		—		—		9,163
Extinguishment of derivative	—		—		69,232		—		—		69,232
Stock-based compensation	—		—		3,390		—		—		3,390
Net loss	—		—		—		(65,321)		—		(65,321)
Balances at December 31, 2022	13,613,759	$	136	$	617,606	$	(399,097)	$	(3,933)	$	214,712
RSUs vested, net of shares withheld for taxes	824,273		8		(676)		—		—		(668)
Purchase of treasury stock	(12,168)		—		—		—		(7)		(7)
Stock-based compensation	—		—		5,239		—		—		5,239
Net loss	—		—		—		(37,697)		—		(37,697)
Balances at December 31, 2023	14,425,864	$	144	$	622,169	$	(436,794)	$	(3,940)	$	181,579

The accompanying notes are an integral part of these consolidated financial statements.

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Independence Contract Drilling, Inc.

Consolidated Statements of Cash Flows

(In thousands)


	Year Ended December 31,
	2023		2022
Cash flows from operating activities
Net loss	$	(37,697)	$	(65,321)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation and amortization		43,543		40,443
Asset impairment, net		14,905		350
Stock-based compensation		5,671		4,644
Loss (gain) on disposition of assets, net		38		(196)
Non-cash interest expense		25,029		15,859
Loss on extinguishment of debt		—		46,347
Amortization of deferred financing costs		111		346
Amortization of Convertible Notes debt discount and issuance costs		8,534		6,714
Change in fair value of embedded derivative liability		—		4,265
Gain on extinguishment of derivative		—		(10,765)
Deferred income taxes		(2,505)		(6,771)
Non-cash cost to obtain revenue contract		585		—
Credit loss expense		1,177		256
Changes in operating assets and liabilities
Accounts receivable		6,318		(17,820)
Inventories		(249)		(365)
Prepaid expenses and other assets		(1,380)		266
Accounts payable and accrued liabilities		(3,058)		10,325
Net cash provided by operating activities		61,022		28,577
Cash flows from investing activities
Purchases of property, plant and equipment		(40,655)		(43,047)
Proceeds from the sale of assets		4,438		4,552
Proceeds from insurance claims		—		191
Net cash used in investing activities		(36,217)		(38,304)
Cash flows from financing activities
Proceeds from issuance of Convertible Notes		—		157,500
Payments to redeem Convertible Notes		(15,000)		—
Repayments under Term Loan Facility		—		(139,076)
Borrowings under Revolving ABL Credit Facility		34,672		5,589
Repayments under Revolving ABL Credit Facility		(40,983)		(78)
Payment of merger consideration		—		(2,902)
Proceeds from issuance of common stock through at-the-market facility, net of issuance costs		—		3,038
Purchase of treasury stock		(7)		(10)
Taxes paid for vesting of RSUs		(668)		(10)
Convertible Notes issuance costs		—		(6,986)
Financing costs paid under Revolving ABL Credit Facility		—		(341)
Payments for finance lease obligations		(2,580)		(5,811)
Net cash (used in) provided by financing activities		(24,566)		10,913
Net increase in cash and cash equivalents		239		1,186
Cash and cash equivalents
Beginning of year		5,326		4,140
End of year	$	5,565	$	5,326

The accompanying notes are an integral part of these consolidated financial statements.

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Independence Contract Drilling, Inc.

Notes to Consolidated Financial Statements

1. Nature of Operations and Recent Developments

We provide land-based contract drilling services for oil and natural gas producers targeting unconventional resource plays in the United States. We own and operate a premium fleet comprised of modern, technologically advanced drilling rigs.

Our business depends on the level of exploration and production activity by oil and natural gas companies operating in the United States, and in particular, the regions where we actively market our contract drilling services. The oil and natural gas exploration and production industry is historically cyclical and characterized by significant changes in the levels of exploration and development activities. Oil and natural gas prices and market expectations of potential changes in those prices significantly affect the levels of those activities. Worldwide political, regulatory, economic and military events, as well as natural disasters have contributed to oil and natural gas price volatility historically and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities in the United States and the regions where we market our contract drilling services, whether resulting from changes in oil and natural gas prices or otherwise, could materially and adversely affect our business.

Market Conditions

Oil prices (WTI-Cushing) reached a high of $123.64 per barrel on March 8, 2022; however, prices have fallen since those highs. As of February 20, 2024 oil was $78.72 per barrel.

Asset Impairment, net

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customer demand, these conversions accelerated significantly during the later part of 2023, with the Company having performed four conversions during the past five months. As a result, the Company currently has only one 200 Series rig operating with over 90% of its current operating fleet being classified as 300 Series rigs. This compares to only 50% of its operating fleet being classified as 300 Series rigs as of January 1, 2023.

During the fourth quarter of 2023, as a result of this accelerating trend toward rigs requiring 300 Series specifications, management reviewed its idle equipment and impaired $14.7 million of equipment and capital spares that it determined would no longer be utilized by the Company’s marketed fleet of 26 rigs.

During the year ended December 31, 2023, we also impaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries.

2. Summary of Significant Accounting Policies

Basis of Presentation

These audited consolidated financial statements include all the accounts of ICD and its subsidiary. All significant intercompany accounts and transactions have been eliminated. Except for the subsidiary, we have no controlling financial interests in any other entity which would require consolidation. These audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). As we had no items of other comprehensive income in any period presented, no other comprehensive income is presented.

Cash and Cash Equivalents

We consider short-term, highly liquid investments that have an original maturity of three months or less to be cash equivalents.

Accounts Receivable

We adopted ASU 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments on January 1, 2023. The adoption of this guidance did not have a material impact on our consolidated financial statements and did not result in a transition adjustment as of January 1, 2023. As of January 1, 2023 and December 31, 2023, our total allowance for credit losses was zero.

Accounts receivable is comprised primarily of amounts due from our customers for contract drilling services. We maintain an allowance for credit losses for accounts receivable, which is recorded as an offset to accounts receivable, and changes in such are classified as selling, general and administrative expense in the consolidated statements of income. We assess collectability by reviewing accounts receivable on a collective basis where similar characteristics exist and on an individual basis when we identify specific customers with known disputes or collectability issues. In determining the amount of the allowance for credit losses, we consider historical collectability based on past due status and make judgments about the creditworthiness of customers based on ongoing credit evaluations. We also consider customer-specific information, current market conditions, and reasonable and supportable forecasts of future economic conditions.

Inventories

Inventory is stated at lower of cost or net realizable value and consists primarily of supplies held for use in our drilling operations. Cost is determined on an average cost basis.

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Property, Plant and Equipment, net

Depreciation of property, plant and equipment is recorded based on the estimated useful lives of the assets as follows:


	Estimated Useful Life
Buildings	20	-	39 years
Drilling rigs and related equipment	3	-	20 years
Machinery, equipment and other	3	-	7 years
Vehicles	2	-	3 years

Additionally, we lease office space for our corporate headquarters in Houston, Texas. Leases are evaluated at inception or at any subsequent material modification to determine if the lease should be classified as a finance or operating lease.

Construction in progress represents the costs incurred for drilling rigs and rig upgrades under construction at the end of the period. This includes third-party costs relating to the purchase of rig components as well as labor, material and other identifiable direct and indirect costs associated with the construction of the rig.

Financial Instruments and Fair value

Fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, there exists a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1

Unadjusted quoted market prices for identical assets or liabilities in an active market;

Level 2

Quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and

Level 3

Unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date

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This hierarchy requires us to use observable market data, when available, and to minimize the use of unobservable inputs when determining fair value.

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, certain accrued liabilities and our debt. Our debt consists primarily of our Convertible Notes and Revolving ABL Facility as of December 31, 2023 and 2022. The fair value of cash and cash equivalents, accounts receivable, accounts payable and certain accrued liabilities, approximate their carrying value because of the short-term nature of these instruments.

The following table summarizes the carrying value and fair value of our long-term debt as of December 31, 2023 and 2022.


	December 31, 2023				December 31, 2022
	Carrying		Fair		Carrying		Fair
(in thousands)	Value		Value		Value		Value
Convertible Notes	$	179,209	$	164,800	$	170,166	$	159,200
Revolving ABL Credit Facility	$	5,500	$	5,500	$	11,811	$	11,870

The fair value of the Convertible Notes is determined to be a Level 3 measurement as this instrument is not actively traded and was estimated using a binomial lattice model. The factors used to determine fair value as of December 31, 2023 are subject to management's judgement and expertise and include, but are not limited to our share price, expected price volatility (58.5%), risk-free rate (4.2%), and credit spread (2,702 bps) relative to our credit rating. The factors used to determine fair value as of December 31, 2022 included, but were not limited to our share price, expected price volatility (59.0%), risk-free rate (4.2%) and credit spread (3,262 bps) relative to our credit rating.

The estimated fair value of our Revolving ABL Credit Facility is also determined to be a Level 3 measurement as our debt is not actively traded and the fair value estimate is based on discounted estimated future cash flows or a fair value in-exchange assumption, which are significant unobservable inputs in the fair value hierarchy. To determine the fair value of our outstanding floating rate debt as of December 31, 2023, we utilized a credit spread of 229 bps on the Revolving ABL Credit Facility based on an analysis of credit spreads of comparably rated public debt items as well as the original issuance price of the debt. We utilized a credit spread of 493 bps to determine the fair value of our Revolving ABL Credit Facility as of December 31, 2022.

Recurring Fair Value Measurements

As described in Note 8 “Long-term Debt,” we determined that certain features under our Convertible Notes required bifurcation from the debt host agreement in accordance with Accounting Standards Codification (“ASC”) 815 as of March 18, 2022. Accordingly, on the issuance date of the Convertible Notes, March 18, 2022, we recorded the fair value of the embedded derivative liability of $75.7 million, in our consolidated balance sheet. The change in the fair value of the embedded derivative liability was assessed quarterly and recorded in our consolidated statement of operations as “Change in fair value of embedded derivative liability” until the features underlying the instrument were exercised, redeemed, cancelled or expired.

After the approval of our stockholders on June 8, 2022, certain features under our Convertible Notes were modified and no longer met the criteria to bifurcate from the debt host agreement. We recorded the extinguishment of the embedded derivative liability by reclassifying $69.2 million to stockholders’ equity, representing the fair value of the conversion rate feature of the derivative liability on our balance sheet, as the conversion rate feature then met the criteria to be classified as equity during the second quarter of 2022. We recognized a gain on extinguishment of the derivative liability of $10.8 million in our consolidated statement of operations associated with the PIK interest rate feature of the embedded derivative liability during the second quarter of 2022. As of December 31, 2023 and 2022, we had no embedded derivative liability recorded. For more information, see our 2022 Annual Report on Form 10-K filed with the SEC on March 6, 2023.

There were no transfers between fair value measurement levels during the years ended December 31, 2023 or 2022.

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See Note 11 “Stock-Based Compensation” for fair value of liability-based awards.

Fair value measurements are applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which would consist of measurements primarily of long-lived asset impairments.

Revenue and Cost Recognition

We earn contract drilling revenues pursuant to drilling contracts entered into with our customers. We perform drilling services on a “daywork” basis, under which we charge a specified rate per day, or “dayrate.” The dayrate associated with each of our contracts is a negotiated price determined by the capabilities of the rig, location, depth and complexity of the wells to be drilled, operating conditions, duration of the contract and market conditions. The term of land drilling contracts may be for a defined number of wells or for a fixed time period. We generally receive lump-sum payments for the mobilization of rigs and other drilling equipment at the commencement of a new drilling contract. Revenue and costs associated with the initial mobilization are deferred and recognized ratably over the term of the related drilling contract once the rig spuds. Costs incurred to relocate rigs and other equipment to an area in which a contract has not been secured are expensed as incurred. Our contracts provide for early termination fees in the event our customers choose to cancel the contract prior to the specified contract term. We record a contract liability for such fees received up front and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract or until such time that all performance obligations are satisfied. While under contract, our rigs generally earn a reduced rate while the rig is moving between wells or drilling locations, or on standby waiting for the customer. Reimbursements for the purchase of supplies, equipment, trucking and other services that are provided at the request of our customers are recorded as revenue when incurred. The related costs are recorded as operating expenses or capitalized when appropriate when incurred. Revenue is presented net of any sales tax charged to the customer that we are required to remit to local or state governmental taxing authorities.

Our operating costs include all expenses associated with operating and maintaining our drilling rigs. Operating costs include all “rig level” expenses such as labor and related payroll costs, repair and maintenance expenses, supplies, workers’ compensation and other insurance, ad valorem taxes and equipment rental costs. Also included in our operating costs are certain costs that are not incurred at the rig level. These costs include expenses directly associated with our operations management team as well as our safety and maintenance personnel who are not directly assigned to our rigs but are responsible for the oversight and support of our operations and safety and maintenance programs across our fleet.

Leases

Lease liabilities are measured at the lease commencement date and are based on the present value of remaining payments contractually required under the contract. Payments that are variable in nature are excluded from the measurement of our lease liabilities and are recorded as an expense as incurred. Options to renew or extend a lease are included in the measurement of our lease liabilities only when it is reasonably certain that we will exercise these rights. In estimating the present value of our lease liabilities, payments are discounted at the interest rate stated in the applicable lease agreement or, if not available, our incremental borrowing rate (“IBR”), applied utilizing a portfolio approach. To determine our IBR, we utilize information publicly available from companies within our industry with similar credit profiles to construct a company-specific yield curve in order to estimate the rate of interest we would pay to borrow at various lease terms. At lease commencement, we recognize a lease right-of-use asset equal to our lease liability, adjusted for lease payments paid to the lessor prior to the lease commencement date, and any initial direct costs incurred. Operating lease expense is recorded on a straight-line basis over the lease term. For finance leases, we amortize our right-of-use assets on a straight-line basis over the shorter of the asset’s useful life or the lease term. Additionally, interest expense is recognized each period related to the accretion of our lease liabilities over their respective lease terms.

Stock-Based Compensation

We record compensation expense over the requisite service period for all stock-based compensation based on the grant date fair value of the award. The expense is included in selling, general and administrative expense in our statements of operations.

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Income Taxes

We use the asset and liability method of accounting for income taxes. Under this method, we record deferred income taxes based upon differences between the financial reporting basis and tax basis of assets and liabilities and use enacted tax rates and laws that we expect will be in effect when we realize those assets or settle those liabilities. We review deferred tax assets for a valuation allowance based upon management’s estimates of whether it is more likely than not that a portion of the deferred tax asset will be fully realized in a future period.

We recognize the financial statement benefit of a tax position only after determining that the relevant taxing authority would more-likely-than-not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Our policy is to include interest and penalties related to the unrecognized tax benefits within the income tax expense (benefit) line item in our statements of operations.

Use of Estimates

The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date, and the reported amounts of revenues and expenses recognized during the reporting period. Actual results could differ from these estimates. Significant estimates made by management include depreciation of property, plant and equipment, impairment of property, plant and equipment and assets held for sale, and the collectability of accounts receivable.

Recent Accounting Pronouncements

3. Revenue from Contracts with Customers

Drilling Services

Our revenues are principally derived from contract drilling services and the activities in our drilling contracts, for which revenues may be earned, include: (i) providing a drilling rig and the crews and supplies necessary to operate the rig; (ii) mobilizing and demobilizing the rig to and from the initial and final drill site, respectively; (iii) certain reimbursable activities; (iv) performing rig modification activities required for the contract; and (v) early termination revenues. We account for these integrated services provided under our drilling contracts as a single performance obligation, satisfied over time, that is comprised of a series of distinct time increments. Consideration for activities that are not distinct within the context of our contracts, and that do not correspond to a distinct time increment within the contract term, are allocated across the single performance obligation and recognized ratably in proportion to the actual

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services performed over the initial term of the contract. If taxes are required to be collected from customers relating to our drilling services, they are excluded from revenue.

Dayrate Drilling Revenue. Our drilling contracts provide that revenue is earned based on a specified rate per day for the activity performed. The majority of revenue earned under daywork contracts is variable and depends on a rate scale associated with drilling conditions and level of service provided for each fractional-hour time increment over the contract term. Such rates generally include the full operating rate, moving rate, standby rate, and force majeure rate and determination of the rate per time increment is made based on the actual circumstances as they occur. Other variable consideration under these contracts could include reduced revenue related to downtime, delays or moving caps.

Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to revenue as services are rendered over the initial term of the related drilling contract. Demobilization fee revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.

In our contracts, there is generally significant uncertainty as to the amount of demobilization fee revenue that may ultimately be collected due to contractual provisions which stipulate that certain conditions be present at contract completion for such revenue to be received. For example, the amount collectible may be reduced to zero if the rig has been contracted with a new customer upon contract completion. Accordingly, the estimate for such revenue may be constrained depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

Reimbursable Revenue. We receive reimbursements from our customers for the purchase of supplies, equipment and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer.

Capital Modification Revenue. From time to time, we may receive fees (on either a fixed lump-sum or variable dayrate basis) from our customers for capital improvements to our rigs to meet their requirements. Such revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract, as these activities are not considered to be distinct within the context of our contracts. We record a contract liability for such fees received up front and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.

Early Termination Revenue. Our contracts provide for early termination fees in the event our customers choose to cancel the contract prior to the specified contract term. We record a contract liability for such fees received up front and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract or until such time that all performance obligations are satisfied.

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Disaggregation of Revenue

The following table summarizes revenues from our contracts disaggregated by revenue generating activity contained therein for the years ended December 31, 2023 and 2022:


	Year Ended December 31,
(in thousands)	2023		2022
Dayrate drilling	$	189,315	$	172,284
Mobilization		5,122		4,719
Reimbursables		9,305		8,856
Early termination		5,864		—
Capital modification		387		810
Other		113		41
Total revenue	$	210,106	$	186,710

Contract Balances

Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Contract asset balances could consist of demobilization fee revenue that we expect to receive that is recognized ratably throughout the contract term but invoiced upon completion of the demobilization activities. Once the demobilization fee revenue is invoiced, the corresponding contract asset is transferred to accounts receivable. Contract liabilities include payments received for mobilization fees as well as upgrade activities, which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.

The following table provides information about receivables and contract liabilities related to contracts with customers as of December 31, 2023 and 2022, respectively. We had no contract assets in either year.


	December 31,		December 31,
(in thousands)	2023		2022
Receivables, which are included in “Accounts receivable”	$	31,380	$	39,732
Contract liabilities, which are included in “Accrued liabilities”	$	(578)	$	(1,158)

Significant changes in the contract liabilities balance during the years ended December 31, 2023 and 2022 are as follows:


	Year Ended December 31,
(in thousands)	2023		2022
Revenue recognized that was included in contract liabilities at beginning of period	$	1,158	$	542
Increase in contract liabilities due to cash received, excluding amounts recognized as revenue	$	(578)	$	(1,158)

Transaction Price Allocated to the Remaining Performance Obligations

The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) as of December 31, 2023. The estimated revenue does not include amounts of variable consideration that are constrained.


	Year Ending December 31,
(in thousands)	2024		2025		2026		Total
Revenue	$	578	$	—	$	—	$	578

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The amounts presented in the table above consist only of fixed consideration related to fees for rig mobilizations and demobilizations, if applicable, which are allocated to the drilling services performance obligation as such performance obligation is satisfied. We have elected the exemption from disclosure of remaining performance obligations for variable consideration. Therefore, dayrate revenue to be earned on a rate scale associated with drilling conditions and level of service provided for each fractional-hour time increment over the contract term and other variable consideration such as penalties and reimbursable revenues, have been excluded from the disclosure.

Contract Costs

We capitalize costs incurred to fulfill our contracts that (i) relate directly to the contract, (ii) are expected to generate resources that will be used to satisfy our performance obligations under the contract and (iii) are expected to be recovered through revenue generated under the contract. These costs, which principally relate to rig mobilization costs at the commencement of a new contract, are deferred as a current or noncurrent asset (depending on the length of the contract term) and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Such contract costs, recorded as “Prepaid expenses and other current assets”, amounted to $0.5 million and $0.3 million on our consolidated balance sheets as of December 31, 2023 and December 31, 2022, respectively. During the year ended December 31, 2023, contract costs increased by $2.3 million and we amortized $2.1 million of contract costs. During the year ended December 31, 2022, contract costs increased by $3.3 million and we amortized $3.6 million of contract costs. Additionally, in the fourth quarter of 2023, we recognized $0.6 million of costs to obtain a contract with a customer which is included in “Other expense” on our consolidated statement of operations.

Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement.

4. Leases

As a Lessor

Our daywork drilling contracts, under which the vast majority of our revenues are derived, contain both a lease component and a service component.

We account for these contracts using the practical expedient to not separate non-lease components from lease components and, instead, to account for those components as a single amount, if the non-lease components otherwise would be accounted for under Topic 606 and both of the following are met: (i) the timing and pattern of transfer of non-lease components and lease components are the same; (ii) the lease component, if accounted for separately, would be classified as an operating lease.

If the non-lease component is the predominant component of the combined amount, an entity is required to account for the combined amount in accordance with Topic 606. Otherwise, the entity must account for the combined amount as an operating lease in accordance with Topic 842.

Revenues from our daywork drilling contracts meet both of the criteria above and we have determined both quantitatively and qualitatively that the service component of our daywork drilling contracts is the predominant component. Accordingly, we combine the lease and service components of our daywork drilling contracts and account for the combined amount under Topic 606. See Note 3 “Revenue from Contracts with Customers.”

As a Lessee

We have multi-year operating and financing leases for corporate office space, field location facilities, land, vehicles and various other equipment used in our operations. We also have a significant number of rentals related to our drilling operations that are day-to-day or month-to-month arrangements. Our multi-year leases have remaining lease terms of greater than one year to three years.

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As a practical expedient, a lessee may elect not to apply the recognition requirements in ASC 842 to short-term leases. Instead, a lessee may recognize the lease payments in profit or loss on a straight-line basis over the lease term and variable lease payments in the period in which the obligation for those payments is incurred. We elected to utilize this practical expedient.

The components of lease expense were as follows:


	Year Ended		Year Ended
(in thousands)	December 31, 2023		December 31, 2022
Operating lease expense	$	1,086	$	747
Short-term lease expense		7,107		5,697
Variable lease expense		608		577

Finance lease expense:
Amortization of right-of-use assets	$	1,878	$	1,682
Interest expense on lease liabilities		278		387
Total finance lease expense		2,156		2,069
Total lease expense	$	10,957	$	9,090

Supplemental cash flow information related to leases is as follows:


	Year Ended		Year Ended
(in thousands)	December 31, 2023		December 31, 2022
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases	$	921	$	732
Operating cash flows from finance leases	$	278	$	373
Financing cash flows from finance leases	$	2,580	$	5,811

Right-of-use assets obtained or recorded in exchange for lease obligations:
Operating leases	$	2,106	$	153
Finance leases	$	2,161	$	4,440

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Supplemental balance sheet information related to leases is as follows:


(in thousands)	December 31, 2023			December 31, 2022
Operating leases:
Other long-term assets, net	$	2,205		$	976

Accrued liabilities	$	934		$	751
Other long-term liabilities		1,375			373
Total operating lease liabilities	$	2,309		$	1,124

Finance leases:
Property, plant and equipment	$	6,238		$	7,307
Accumulated depreciation		(1,829)			(1,994)
Property, plant and equipment, net	$	4,409		$	5,313

Current portion of long-term debt	$	1,226		$	2,485
Long-term debt		1,659			1,599
Total finance lease liabilities	$	2,885		$	4,084

Weighted-average remaining lease term
Operating leases		3.4 years			1.6 years
Finance leases		2.0 years			1.6 years

Weighted-average discount rate
Operating leases		8.75	%		10.86	%
Finance leases		8.25	%		8.12	%

Maturities of lease liabilities as of December 31, 2023 were as follows:


(in thousands)	Operating Leases		Finance Leases
2024	$	1,086		1,414
2025		516		1,138
2026		401		634
2027		370		—
2028		285		—
Total cash lease payment		2,658		3,186
Less: imputed interest		(349)		(301)
Total lease liabilities	$	2,309	$	2,885

5. Inventories

Inventories consisted of the following:


	December 31,
(in thousands)	2023		2022
Rig components and supplies	$	1,557	$	1,508

We determined that no reserve for obsolescence was needed as of December 31, 2023 or 2022. No inventory obsolescence expense was recognized during the years ended December 31, 2023 or 2022.

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6. Property, Plant and Equipment

Major classes of property, plant, and equipment, which include finance lease assets, consisted of the following (in millions):


	December 31,
(in thousands)	2023		2022
Land	$	300	$	300
Buildings		2,858		2,816
Drilling rigs and related equipment		611,382		611,972
Machinery, equipment and other		1,762		1,775
Finance leases		6,238		7,307
Leasehold improvements		25		25
Construction in progress		2,851		5,693
Total	$	625,416	$	629,888
Less: Accumulated depreciation		(277,223)		(253,804)
Total Property, plant and equipment, net	$	348,193	$	376,084

Repairs and maintenance expense included in operating costs in our statements of operations totaled $28.5 million and $23.3 million for the years ended December 31, 2023 and 2022, respectively.

Depreciation expense was $43.5 million and $40.4 million for the years ended December 31, 2023 and 2022, respectively.

7. Supplemental Consolidated Balance Sheet and Cash Flow Information

Prepaid expenses and other current assets consisted of the following:


(in thousands)	December 31, 2023		December 31, 2022
Prepaid insurance	$	3,502	$	3,796
Deferred mobilization costs		467		283
Prepaid and other current assets		790		657
	$	4,759	$	4,736

Accrued liabilities consisted of the following:


(in thousands)	December 31, 2023		December 31, 2022
Accrued salaries and other compensation	$	6,625	$	6,908
Insurance		2,996		3,002
Deferred mobilization revenues		578		1,003
Property and other taxes		2,124		3,621
Interest		25		101
Operating lease liability - current		934		751
Cash-settled SARs liability		2,054		1,826
Other		1,035		396
	$	16,371	$	17,608

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Supplemental consolidated cash flow information:


	Year Ended December 31,
(in thousands)	2023		2022
Supplemental disclosure of cash flow information
Cash paid during the year for interest	$	2,358	$	5,084
Cash paid during the year for taxes	$	804	$	—
Supplemental disclosure of non-cash investing and financing activities
Change in property, plant and equipment purchases in accounts payable	$	(8,093)	$	11,686
Additions to property, plant & equipment through finance leases	$	2,161	$	4,440
Extinguishment of finance lease obligations from sale of assets classified as finance leases	$	(513)	$	(281)
Transfer of assets from held and used to held for sale	$	—	$	(325)
Initial embedded derivative liability upon issuance of Convertible Notes	$	—	$	75,733
Extinguishment of embedded derivative liability	$	—	$	(69,232)
Shares issued for structuring fee	$	—	$	9,163

8. Long-term Debt

Our Long-term Debt consisted of the following:



(in thousands)	December 31, 2023		December 31, 2022
Convertible Notes due March 18, 2026	$	179,209	$	170,166
Revolving ABL Credit Facility due September 30, 2025		5,500		11,811
Finance lease obligations		2,885		4,084
		187,594		186,061
Less: Convertible Notes debt discount and issuance costs		(31,819)		(40,353)
Less: current portion of finance leases		(1,226)		(2,485)
Long-term debt, net	$	154,549	$	143,223

Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of December 31, 2023:


(in thousands)	2024		2025		2026		Total
Convertible Notes	$	14,000	$	3,500	$	161,709	$	179,209
Revolving ABL Credit Facility		—		5,500		—		5,500
Total	$	14,000	$	9,000	$	161,709	$	184,709

Future payments of finance leases are included in Note 4 “Leases.”

Convertible Notes

On March 18, 2022, we entered into a subscription agreement with affiliates of MSD Partners, L.P. and an affiliate of Glendon Capital Management L.P. (the “Subscription Agreement”) for the placement of $157.5 million aggregate principal amount of convertible secured PIK toggle notes due 2026 (the “Convertible Notes”), and currently have $179.2 million of Convertible Notes outstanding as of December 31, 2023. The Convertible Notes were issued pursuant to an Indenture, dated as of March 18, 2022 (the “Indenture”). The obligations under the Convertible Notes are secured by a first priority lien on collateral other than accounts receivable, deposit accounts and other related collateral pledged as first priority collateral (“Priority Collateral”) under the Revolving ABL Credit Facility (defined below). Proceeds from the private placement of the Convertible Notes were used to repay all of our outstanding indebtedness under our term loan credit agreement, to repay obligations to prior equity holders of Sidewinder Drilling LLC, and for

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working capital purposes. In connection with the placement of the Convertible Notes, we issued 2,268,000 shares of our common stock as a structuring fee. The structuring fee shares were issued on March 18, 2022, concurrent with the closing of the private placement of the Convertible Notes. The Convertible Notes mature on March 18, 2026.

The Convertible Notes have a cash interest rate of the Secured Overnight Financing Rate plus a 10-basis point credit spread, with a floor of 1% (collectively, “SOFR”) plus 12.5%. The Convertible Notes have a PIK interest rate of SOFR plus 9.5%. We have the right at our option, to PIK interest under the Convertible Notes for the entire term of the Convertible Notes. Interest on the Convertible Notes is due on March 31 and September 30 each year. We elected to PIK outstanding interest as of September 30, 2022, March 31, 2023 and September 30, 2023, resulting in the issuance of an additional $12.7 million, $11.6 million and $12.4 million principal amount of Convertible Notes, respectively. As of December 31, 2023, accrued PIK interest of $6.8 million, which is due March 31, 2024 and will result in the issuance of additional Convertible Notes, is classified as “Other Long-Term Liabilities” on our consolidated balance sheet. As of December 31, 2022, accrued PIK interest of $5.8 million, which was due March 31, 2023 and resulted in the issuance of additional Convertible Notes, was classified as “Other Long-Term Liabilities” on our consolidated balance sheet.

Each noteholder has a right to convert our Convertible Notes into shares of ICD common stock at any time after issuance through maturity. The conversion price is $4.51 per share. Under the Indenture, a holder is not entitled to receive shares of our common stock upon conversion of any Convertible Notes to the extent to which the aggregate number of shares of common stock that may be acquired by such beneficial owner upon conversion of Convertible Notes, when added to the aggregate number of shares of common stock deemed beneficially owned, directly or indirectly, by such beneficial owner and each person subject to aggregation of Common Stock with such beneficial owner under Section 13 or Section 16 of the Securities Exchange Act of 1934 (the “Exchange Act”) and the rules promulgated thereunder at such time (an “Aggregated Person”) (other than by virtue of the ownership of securities or rights to acquire securities that have limitations on such beneficial owner’s or such person’s right to convert, exercise or purchase similar to this limitation), as determined pursuant to the rules and regulations promulgated under Section 13(d) of the Exchange Act, would exceed 9.9% (the “Restricted Ownership Percentage”) of the total issued and outstanding shares of Common Stock (the “Section 16 Conversion Blocker”); provided that any holder has the right to elect for the Restricted Ownership Percentage to be 19.9% with respect to such Holder, (x) at any time, in which case, such election will become effective sixty-one days following written notice thereof to us or (y) in the case of a holder acquiring Convertible Notes on the Issue Date, in such Holder’s Subscription Agreement. In lieu of any shares of common stock not delivered to a converting holder by operation of the Restricted Ownership Percentage limitation, we will deliver to such Holder Pre-Funded Warrants in respect of any equal number of shares of common stock. Such Pre-Funded Warrants will contain substantially similar Restricted Ownership Percentage terms.

The Indenture includes a mandatory redemption offer requirement (the “Mandatory Offer Requirement”). Beginning June 30, 2023, we were obligated to offer to redeem $5.0 million of Convertible Notes on a quarterly basis through December 31, 2023, and $3.5 million of Convertible Notes on a quarterly basis through March 31, 2025. The mandatory offer price is an amount in cash equal to the principal amount of such Note plus accrued and unpaid interest on such Note. During 2023, our noteholders accepted our offers to redeem $5.0 million of Convertible Notes on each of June 30, 2023, September 30, 2023 and December 31, 2023. As such, on June 30, 2023, we redeemed and paid cash for $5.0 million of principal of Convertible Notes and $0.2 million of accrued interest on such Notes; on September 30, 2023, we redeemed and paid cash for $5.0 million of principal of Convertible Notes and $0.4 million of accrued interest on such Notes; and on December 31, 2023, we redeemed and paid cash for $5.0 million of principal of Convertible Notes and $0.2 million of accrued interest on such Notes. We have the ability and intent to refinance the mandatory redemption offers that occur within the next twelve months under our Revolving ABL Credit Facility and as a result such amounts have been classified as long-term debt. On June 30, 2023, September 30, 2023 and December 31, 2023,

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we borrowed $5.0 million, $5.0 million and $5.0 million, respectively, under our Revolving ABL Credit Facility to refinance the accepted mandatory offerings.

The Indenture contains financial covenants, including a liquidity covenant of $10.0 million; a springing fixed charge coverage ratio covenant of 1.00 to 1.00 that is tested when availability under the Revolving ABL Credit Facility (defined below) is below $5.0 million at any time that the Convertible Notes are outstanding; and capital expenditure limits of $14.8 million during the nine months ended September 30, 2024 and $11.25 million during the nine months ended June 30, 2024, subject to adjustment upward by $500,000 per year for each rig above 17 that operates during each year. In addition, capital expenditures are excluded from this covenant (a) if funded from equity proceeds, (b) if relating to the reactivation of a rig so long as (i) we have a signed contract with a customer with respect to each such rig of at least one (1) year duration providing for early termination payments consistent with past practice equal to at least the expected margin on the contract, (ii) the expected margin on such rig contract will be equal to or exceed such reactivation capital expenditures, and (iii) the reactivation capital expenditures, rig contract and the expected margin calculation are approved by our board of directors or (c) relate to other capital expenditures specifically approved by written or electronic consent by both (i) the required holders (which approval may, for the avoidance of doubt, be provided by the required holders in their sole discretion for an amount of capital expenditures to be committed or made by the Company or a subsidiary of the Company within ninety (90) days after the date of such consent) and (ii) the Board of Directors of the Company. The holders of our Convertible Notes consented to capital expenditure adjustments under this covenant aggregating $10.6 million in 2022 and $16.9 million in 2023. The Indenture also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments (including the payment of dividends), investments and transactions with affiliates. The Indenture also provides for customary events of default, including breaches of material covenants, defaults under the Revolving ABL Credit Facility or other material agreements for indebtedness, and a change of control. Beginning 18 months prior to maturity, we may elect to suspend the Convertible Debt covenant requirements by depositing cash and short-term treasuries with the Trustee in an amount equal to all amounts due to the noteholders including principal, premium (if any) and interest. We are in compliance with our covenants as of December 31, 2023.

Upon a Qualified Merger (defined below), we may elect to convert all, but not less than all, of the Convertible Notes at a Conversion Rate equal to our Conversion Rate on the date on which the relevant “Qualified Merger” is consummated (a “Qualified Merger Conversion”), so long as the “MOIC Condition” is satisfied with respect to such potential Qualified Merger Conversion. A “Qualified Merger” means a Common Stock Change Event consolidation, merger, combination or binding or statutory share exchange of the Company with a Qualified Acquirer. A “Qualified Merger Conversion Date” means the date on which the relevant Qualified Merger is consummated. A “Qualified Acquirer” means any entity that (i) has its common equity listed on the New York Stock Exchange, the NYSE American, Nasdaq Global Market or Nasdaq Global Select Market, or Toronto Stock Exchange, (ii) has an aggregate equity market capitalization of at least $350 million, and (iii) has a “public float” (as defined in Rule 12b-2 under the Securities Act of 1933) of at least $250 million in each case, as determined by the calculation agent based on the last reported sale price of such common equity on date of the signing of the definitive agreement in respect of the relevant Common Stock Change Event. A “Common Stock Change Event” means the occurrence of any: (i) recapitalization, reclassification or change of our common stock (other than (x) changes solely resulting from a subdivision or combination of the common stock, (y) a change only in par value or from par value to no par value or no par value to par value and (z) stock splits and stock combinations that do not involve the issuance of any other series or class of securities); (ii) consolidation, merger, combination or binding or statutory share exchange involving us; (iii) sale, lease or other transfer of all or substantially all of the assets of ours and our Subsidiaries, taken as a whole, to any person; or (iv) other similar event, and, as a result of which, the common stock is converted into, or is exchanged for, or represents solely the right to receive, other securities, cash or other property, or any combination of the foregoing. A “Company Conversion Rate” means, in respect of any Qualified Merger, the greater of (a) the relevant Conversion Rate, (b) $1,000 divided by our Conversion VWAP, and (c) the lowest rate that would cause the MOIC Condition to be satisfied with respect to the related Qualified Merger Conversion. A “Company Conversion VWAP” means, in respect of any Qualified Merger, the average of daily VWAP over the five (5) VWAP Trading Days prior to the earlier of signing or public announcement (by any party, and whether formal or informal, including for the avoidance of doubt any media reports thereof) of a definitive agreement in respect of such Qualified Merger as calculated by the Calculation Agent. The “MOIC Condition” means, with respect to any potential Qualified Merger Conversion, MOIC is greater than or equal to the MOIC Required Level. The “MOIC Required Level” means $1,350. “MOIC” means, with respect to any

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potential Qualified Merger Conversion, an amount determined by the Calculation Agent equal to the aggregate return on a hypothetical Note with $1,000 face amount, issued on the Issue Date, from the Issue Date through the potential Qualified Merger Conversion Date, including (x) the aggregate amount of any cash interest paid on such hypothetical Note from the Issue Date through the potential Qualified Merger Conversion Date, (y) the aggregate fair market value of any Conversion Consideration that would be received by the Holder of such hypothetical Note on the relevant Qualified Merger Conversion Date and (z) the aggregate fair market value of any Conversion Consideration that would be received on the relevant Qualified Merger Conversion Date by the Holder of any PIK Notes issued in respect of (or the relevant increase in value of) such hypothetical Note.

We early adopted ASU 2020-06 as of January 1, 2022 and concluded the Convertible Notes are accounted for as debt, with embedded features. As a consequence of the embedded features, the Convertible Notes gave rise to a derivative liability. See Embedded Derivative Liability. The debt terms of the Convertible Notes, of which affiliates of our prior Term Loan Facility are 50.1% noteholders, were determined to be substantially different terms from the Term Loan Facility and therefore required to be accounted for as an extinguishment of the Term Loan Facility. Accordingly, in the second quarter of 2022 we recognized a loss on the extinguishment of debt of approximately $46.3 million. This was a non-cash expense primarily associated with the recognition of unamortized debt issuance costs, non-cash fees settled in shares to the affiliates of our prior Term Loan Facility and the fair value of the embedded derivatives. We recorded an embedded derivative liability of $75.7 million at the time of the issuance and a debt discount of $37.8 million. Issuance costs consisting of cash fees of $7.4 million and a non-cash structuring fee settled in shares of $2.3 million along with the debt discount were recorded as a direct deduction from the Convertible Notes in the consolidated balance sheet. The debt discount and issuance costs are amortized to interest expense using the effective interest rate method over the term of the Convertible Notes. The effective interest rate for the Convertible Notes as of December 31, 2023 is 25.4%. For the year ended December 31, 2023, the contractual interest expense was $25.9 million and the debt discount and issuance cost amortization was $8.5 million. For the year ended December 31, 2022, the contractual interest expense was $18.5 million and the debt discount and issuance cost amortization was $6.7 million.

Embedded Derivative Liability

The Convertible Notes contained the following embedded features upon issuance (i) an increase of the noteholder’s optional conversion rate for the Convertible Notes from 197.23866 shares of common stock per $1,000 principal amount of Convertible Notes ($5.07 per share) to 221.72949 shares of Common Stock per $1,000 principal amount of Convertible Notes ($4.51 per share) following the receipt of the Shareholder Approval, (ii) a decrease in the PIK interest rate from SOFR plus 14.0% to SOFR plus 9.5% following receipt of the Shareholder Approval, (iii) a conversion feature associated with the MOIC condition in the event of a Qualified Merger and (iv) a contingent interest feature as a result of violations of credit-risk related covenants. We evaluated these embedded features under the guidance of ASC 815 and determined that they required bifurcation at fair value. However, management determined the probability of a Qualified Merger to be remote and as such the fair value of the embedded conversion feature has been estimated to be zero. Management also evaluated the contingent interest feature and determined the likelihood of payment to be remote. Accordingly, the fair value of the contingent interest feature was also estimated to be zero. Lastly, management evaluated the conversion rate feature and the decrease in PIK interest feature and determined that these embedded features met all three criteria in ASC 815-15-25-1 and therefore required bifurcation. Accordingly, as of the Convertible Notes issuance date, we recorded a derivative liability representing the increase in the conversion rate feature and the decrease in PIK interest feature. The derivative liability was presented as a non-current liability in our consolidated balance sheet and was adjusted to reflect fair value at each period end with changes in fair value recorded in the “Change in fair value of embedded derivative liability” financial statement line item of our consolidated statements of operations.

After the approval of our stockholders on June 8, 2022, certain features under our Convertible Notes were modified and no longer met the criteria to bifurcate from the host debt agreement. As of December 31, 2023 and 2022,

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we had no embedded derivative liability recorded. See Financial Instruments and Fair Value in Note 2 “Summary of Significant Accounting Policies” for additional information.

Term Loan Facility

Revolving ABL Credit Facility

The Revolving ABL Credit Facility contains a springing fixed charge coverage ratio covenant of 1.00 to 1.00 that is tested when availability is less than 10% of the maximum credit. The Revolving ABL Credit Facility also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments (including the payment of dividends), investments and transactions with affiliates. The Revolving ABL Credit Facility also provides for customary events of default, including breaches of material covenants, defaults under the Indenture or other material agreements for indebtedness, and a change of control. We are in compliance with our financial covenants as of December 31, 2023.

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9. Income Taxes

The components of the income tax expense are as follows:


	Year Ended December 31,
(in thousands)	2023		2022
Current:
Federal	$	—	$	—
State		530		575
	$	530	$	575
Deferred:
Federal	$	(3,285)	$	(7,480)
State		780		709
	$	(2,505)	$	(6,771)

Income tax benefit	$	(1,975)	$	(6,196)

The effective tax rate (as a percentage of net loss before income taxes) is reconciled to the U.S. federal statutory rate as follows:


	Year Ended December 31,
(in thousands)	2023			2022
Income tax benefit at the statutory federal rate (21%)	$	(8,331)		$	(15,019)
Nondeductible expenses		232			3
Valuation allowance		3,140			(1,200)
Debt discount		1,408			7,629
State taxes, net of federal benefit		435			1,518
Stock-based compensation and other		1,141			873
Income tax benefit	$	(1,975)		$	(6,196)
Effective tax rate		5.0	%		8.7	%

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Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities are as follows:


	December 31,
(in thousands)	2023		2022
Deferred income tax assets
Merger-related expenses	$	808	$	894
Stock-based compensation		1,328		1,349
Accrued liabilities and other		128		613
Deferred revenue		133		228
Interest limitation		14,855		8,024
ROU Asset		533		255
Debt Instruments		1,666		2,026
Net operating losses		97,112		96,142
Total net deferred tax assets	$	116,563	$	109,531
Deferred income tax liabilities
Prepaids	$	(794)	$	(845)
Property, plant and equipment		(43,088)		(41,937)
ROU Liability		(509)		(222)
Total net deferred tax liabilities	$	(44,391)	$	(43,004)
Valuation allowance	$	(81,933)	$	(78,793)
Net deferred tax liability	$	(9,761)	$	(12,266)

As of December 31, 2023, we had a total of $448.6 million of net operating loss carryforwards, of which $134.1 million will begin to expire in 2031 and $314.5 million will be carried forward indefinitely.

Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an ownership change. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in April 2016, October 2018 in connection with the Sidewinder Merger, and in October 2021. We are subject to an annual limitation on the usage of our NOL and as a result of our limitation from the ownership change in October 2021, we expect to have approximately $94.2 million of NOLs expire before becoming available to be utilized by us. Management will continue to monitor the potential impact of Section 382 with respect to our NOL carryforward.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2023, we had no unrecognized tax benefits. We file income tax returns in the United States and in various state jurisdictions. With few exceptions, we are subject to United States federal, state and local income tax examinations by tax authorities for tax periods 2012 and forward. Our federal and state tax returns for 2012 and subsequent years remain subject to examination by tax authorities due to the existence of NOLs in each jurisdiction. Although we cannot predict the outcome of future tax examinations, we do not anticipate that the ultimate resolution of these examinations will have a material impact on our financial position, results of operations, or cash flows.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the consolidated statement of operations. We have not recorded any interest or penalties associated with unrecognized tax benefits.

In assessing the realizability of the deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. In prior years, we determined

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that the deferred tax assets did not meet the more likely than not threshold of being utilized and thus recorded a valuation allowance. However, due to IRC Section 382 ownership changes in earlier years and the resulting annual limitation on our pre-change NOLs, we do not anticipate having enough NOL available to offset our deferred tax liabilities in the appropriate years. Therefore, we have adjusted our valuation allowance to reflect such.

On August 16, 2022, the Inflation Reduction Act of 2022 was enacted and signed into law and includes targeted tax provisions. We do not anticipate these tax provisions will have a material impact on our financial statements.

10. Stock-Based Compensation

Prior to June 2019, we issued common stock-based awards to employees and non-employee directors under our 2012 Long-Term Incentive Plan adopted in March 2012 (the “2012 Plan”). In June 2019, we adopted the 2019 Omnibus Incentive Plan (the “2019 Plan”) providing for common stock-based awards to employees and non-employee directors. The 2019 Plan permits the granting of various types of awards, including stock options, restricted stock, restricted stock unit awards, and stock appreciation rights (“SARs”), and up to 4.6 million shares were authorized for issuance. Restricted stock and restricted stock units may be granted for no consideration other than prior and future services. The purchase price per share for stock options and SARs may not be less than the market price of the underlying stock on the date of grant. As of December 31, 2023, approximately 891,790 shares were available for future awards under the 2019 Plan. In connection with the adoption of the 2019 Plan, no further awards will be made under the 2012 Plan. Our policy is to account for forfeitures of share-based compensation awards as they occur.

A summary of compensation cost recognized for stock-based payment arrangements is as follows:


	Year Ended December 31,
(in thousands)	2023		2022
Compensation cost recognized:
Restricted stock, restricted stock units and stock-settled stock appreciation rights	$	5,239	$	3,390
Cash-settled stock appreciation rights and performance-based phantom units		432		1,254
Total stock-based compensation	$	5,671	$	4,644

Time-Based Restricted Stock and Restricted Stock Units

We have granted time-based restricted stock and restricted stock units to key employees under the 2012 plan and the 2019 plan.

Time-Based Restricted Stock

Time-based restricted stock awards consist of grants of our common stock that vest over three to five years. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of time-based restricted stock awards is determined based on the estimated fair market value of our shares on the grant date. As of December 31, 2023, there was no unrecognized compensation cost related to unvested time-based restricted stock awards.

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A summary of the status of our time-based restricted stock awards and of changes in our time-based restricted stock awards outstanding for the year ended December 31, 2023 and 2022 is as follows:


		Weighted
		Average
		Grant-Date
		Fair Value
	Shares	Per Share
Outstanding at January 1, 2022	26,890	$	64.40
Granted	—		—
Vested	(10,198)		64.40
Forfeited/expired	(3,246)		64.40
Outstanding at January 1, 2023	13,446	$	64.40
Granted	—		—
Vested	(10,170)		64.40
Forfeited	(3,276)		64.40
Outstanding at December 31, 2023	—	$	—

Time-Based Restricted Stock Units

We have granted three-year time-based vested restricted stock unit awards where each unit represents the right to receive, at the end of a vesting period, one share of ICD common stock with no exercise price. The fair value of time-based restricted stock unit awards is determined based on the estimated fair market value of our shares on the grant date. As of December 31, 2023, there was $2.6 million of total unrecognized compensation cost related to unvested time-based restricted stock unit awards. This cost is expected to be recognized over a weighted-average period of 0.7 years.

A summary of the status of our time-based restricted stock unit awards and of changes in our time-based restricted stock unit awards outstanding for the year ended December 31, 2023 and 2022 is as follows:


		Weighted
		Average
		Grant-Date
		Fair Value
	RSUs	Per Share
Outstanding at January 1, 2022	109,911	$	8.50
Granted	1,526,385		4.16
Vested and converted	(78,011)		7.78
Forfeited/expired	(2,743)		38.80
Outstanding at January 1, 2023	1,555,542	$	4.22
Granted	272,736		4.00
Vested and converted	(817,831)		4.28
Forfeited	(257,267)		4.17
Outstanding at December 31, 2023	753,180	$	4.10

Performance-Based and Market-Based Restricted Stock Units

In the first quarter of 2020, we granted three-year market-based restricted stock unit awards, where each unit represents the right to receive, at the end of a vesting period, up to two shares of ICD common stock with no exercise price. Exercisability of the market-based restricted stock unit awards is based on our total shareholder return (“TSR”) as measured against the TSR of a defined peer group over a three-year period. We used a Monte Carlo simulation model to value the TSR market-based restricted stock unit awards. The fair value of the performance-based restricted stock unit awards is based on the market price of our common stock on the date of grant. In the first quarter of 2023, 6,442 shares

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were vested and issued under these awards. The remaining shares were unearned and forfeited. There are no further vestings under this grant.

In the first quarter of 2023, we granted certain employees 299,411 three-year performance-based restricted stock unit awards with a market condition. Based on target shares of 173,570, a minimum of 0% and a maximum of 150% of the units could be awarded based upon the measurement of free cash flow (“FCF”) as measured against FCF performance goals determined by the compensation committee of our Board of Directors, during the three-year performance period of January 1, 2023 to December 31, 2025 and vest fully on December 31, 2025 subject to continued employment. The payout of the awards will be further adjusted by a TSR multiplier that may adjust the payout between 85% and 115% based upon our relative total shareholder return for the three-year period ending on third anniversary of the date of grant compared to the relative total shareholder return of an eight-company peer group of oilfield service companies for the same period. As these awards are performance-based with a market condition, we utilized a Monte Carlo simulation model to determine grant date fair value per share.

During the restriction period, the performance-based and market-based restricted stock unit awards may not be transferred or encumbered, and the recipient does not receive dividend equivalents or have voting rights until the units vest. As of December 31, 2023, there was $0.3 million of unrecognized compensation cost related to unvested performance-based and market-based restricted stock unit awards, which is expected to be recognized over a weighted-average period of 2.1 years.

The assumptions used to value our FCF restricted stock unit awards on the grant date in the first quarter of 2023 were a risk-free interest rate of 4.15%, an expected volatility of 135.3% and an expected dividend yield of 0.0%. Based on the Monte Carlo simulation, these restricted stock unit awards were valued at $4.47.

A summary of the status of our performance-based and market-based restricted stock unit awards and of changes in our restricted stock unit awards outstanding for the year ended December 31, 2023 and 2022 is as follows:


		Weighted
		Average
		Grant-Date
		Fair Value
	RSUs	Per Share
Outstanding at January 1, 2022	27,285	$	24.50
Granted	—		—
Vested and converted	(3,056)		29.00
Forfeited/expired	(13,486)		33.10
Outstanding at January 1, 2023	10,743	$	12.42
Granted	299,411		4.47
Vested and converted	(6,442)		12.42
Forfeited	(4,301)		12.42
Outstanding at December 31, 2023	299,411	$	4.47

Phantom Units

In the first quarter of 2023, we granted certain employees 149,709 three-year performance-based phantom units with a market condition. Based on target shares of 86,789, a minimum of 0% and a maximum of 150% of the units could be awarded based upon the measurement of free cash flow (“FCF”) as measured against FCF performance goals determined by the compensation committee of our Board of Directors, during the three-year performance period of January 1, 2023 to December 31, 2025 and vest fully on December 31, 2025 subject to continued employment. The payout of the awards will be further adjusted by a TSR multiplier that may adjust the payout between 85% and 115% based upon our relative total shareholder return for the three-year period ending on third anniversary of the date of grant compared to the relative total shareholder return of an eight-company peer group of oilfield service companies for the same period. The phantom units are cash-settled awards and are accounted for as a liability classified award. The grant date fair value of the phantom units was $0.3 million. Compensation expense is recognized on a straight-line basis over

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the performance period, with the amount recognized fluctuating as a result of the phantom units being remeasured to fair value at the end of each reporting period due to their liability-award classification. We recognized $31.0 thousand of compensation expense in the year ended December 31, 2023.

In the first quarter of 2023, we granted 94,708 three-year time-vested phantom unit awards where each unit represents the right to receive, at the end of a vesting period, one share of ICD common stock. In the third quarter of 2023, 1,250 shares were forfeited. As of December 31, 2023, there were 93,458 unvested shares outstanding. The phantom units are cash-settled awards and are accounted for as a liability classified award. The grant date fair value of the phantom units was $0.4 million. Compensation expense is recognized on a straight-line basis over the performance period, with the amount recognized fluctuating as a result of the phantom units being remeasured to fair value at the end of each reporting period due to their liability-award classification. We recognized $68.0 thousand of compensation expense in the year ended December 31, 2023.

In the first quarter of 2023, we granted independent directors 41,665 one-year time-vested phantom unit awards where each unit represents the right to receive, at the end of a vesting period, one share of ICD common stock. In the second quarter of 2023, 8,333 shares were forfeited due to the resignation of a director. As of December 31, 2023, there were 33,332 unvested shares outstanding. The phantom units are cash-settled awards and are accounted for as a liability classified award. The grant date fair value of the phantom units was $0.2 million. Compensation expense is recognized on a straight-line basis over the performance period, with the amount recognized fluctuating as a result of the phantom units being remeasured to fair value at the end of each reporting period due to their liability-award classification. We recognized $73.0 thousand of compensation expense in the year ended December 31, 2023.

Time-Based Stock-Settled Stock Appreciation Rights

We have granted time-based, stock-settled stock appreciation rights (“SARs”) to certain employees. The SARs have a term of seven years, an exercise price of $5.19 per share, and vest one-third on March 18, 2023 and in equal quarterly increments thereafter, until fully vested on March 18, 2025. Because these SARs are stock-settled, they are classified as an “equity award” which are measured at their fair value at the grant date and are fixed and not revalued unless the award is modified.

The assumptions used in calculating the fair value of time-based stock-settled SARs as of the grant date were a risk-free interest rate of 3.03%, an expected volatility factor of 103.3% and an expected dividend yield of 0.0%.

Changes to our time-based stock-settled SARs for the year ended December 31, 2023 and 2022 are as follows:


		Weighted Average
		Grant Date
		Fair Value
	Stock-settled SARs	Per Share
Outstanding at January 1, 2022	—	$	—
Granted	1,421,740		2.83
Exercised	—		—
Forfeited/Expired	—		—
Outstanding at January 1, 2023	1,421,740	$	2.83
Granted	—		—
Exercised	—		—
Forfeited/Expired	—		—
Outstanding at December 31, 2023	1,421,740	$	2.83
Exercisable at December 31, 2023	829,349	$	2.83
Non-vested at January 1, 2023	1,421,740	$	2.83
Vested	829,349		2.83
Non-vested at December 31, 2023	592,391	$	2.83

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The number of stock-settled SARs exercisable at December 31, 2023 was 0.8 million with a weighted average remaining contractual life of 5.2 years. As of December 31, 2023, there was $1.8 million of unrecognized compensation cost related to time-based stock-settled SARs that is expected to be recognized over a weighted-average period of 0.7 years.

Time-Based Cash-Settled Stock Appreciation Rights

We have granted time-based, cash-settled stock appreciation rights (“SARs”) to certain employees. The SARs have a term of seven years, an exercise price of $5.73 per share, with the market price upon exercise capped at $10.00 per share, and vest ratably on the first, second and third anniversaries of the date of grant. Because these SARs are cash-settled, they are classified as “liability-classified awards” which are remeasured at their fair value at the end of each reporting period until settlement. As of December 31, 2023 and December 31, 2022, we have recorded a liability, classified as “Accrued Liabilities” on our consolidated balance sheets, of $2.1 million and $1.8 million, respectively.

Time-based, cash-settled SARs have no effect on dilutive shares or shares outstanding as any appreciation of our common stock over the exercise price is paid in cash and not in common stock.

The fair value of time-based cash-settled SARs is revalued (mark-to-market) each reporting period using a Monte Carlo simulation model based on period-end stock price. The expected term of the SARs is calculated as the average of each vesting tranche’s midpoint between vesting date and expiration date plus the vesting period. Expected volatility is based on the historical volatility of our stock for the length of time corresponding to the expected term of the SARs. The risk-free interest rate is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the SARs.

The following weighted-average assumptions were used in calculating the fair value of time-based cash-settled SARs outstanding during the year ended December 31, 2023 using the Monte Carlo simulation model:


	Year Ended		Year Ended
	December 31, 2023		December 31, 2022
Remaining term to maturity	4.1 years		5.1 years
Expected volatility factor	119.5	%	113.0	%
Expected dividend yield	—	%	—	%
Risk-free interest rate	3.88	%	3.95	%

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Changes to our non-vested time-based cash-settled SARs during the year ended December 31, 2023 and 2022 are as follows:


		Weighted Average
		Exercise Price
	Cash-settled SARs	Per Share
Outstanding at January 1, 2022	2,912,867	$	5.73
Granted	—		—
Exercised	—		—
Forfeited/Expired	(27,145)		5.73
Outstanding at January 1, 2023	2,885,722	$	5.73
Granted	—		—
Exercised	—		—
Forfeited/Expired	—		—
Outstanding at December 31, 2023	2,885,722	$	5.73
Exercisable at December 31, 2023	1,426,964	$	5.73

As of December 31, 2023, there was $0.1 million of unrecognized compensation cost related to time-based cash-settled SARs that is expected to be recognized over a weighted-average period of 0.1 years.

11. Stockholders’ Equity and Loss per Share

As of December 31, 2023, we had a total of 14,425,864 shares of common stock, $0.01 par value, outstanding. We also had 97,260 shares held as treasury stock. Total authorized common stock is 250,000,000 shares.

Basic earnings (loss) per common share (“EPS”) are computed by dividing net income (loss) available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted EPS are computed by dividing net income (loss) available to common stockholders by the weighted-average number of common shares outstanding during the period, including potential dilutive securities. When the Convertible Notes are dilutive, interest expense, net of tax, is added back to net income to calculate diluted EPS. A reconciliation of the numerators and denominators of the basic and diluted losses per share computations is as follows:


	For the Years Ended December 31,
(in thousands, except per share data)	2023		2022
Net loss (numerator):	$	(37,697)	$	(65,321)
Loss per share:
Basic and diluted		(2.69)		(5.01)
Shares (denominator):
Weighted average common shares outstanding - basic		14,012		13,026
Weighted average common shares outstanding - diluted		14,012		13,026

The following number of potential common shares at the end of each year presented were excluded from the calculation of diluted EPS because their effect would have been anti-dilutive.

12. Segment and Geographical Information

We report one segment because all of our drilling operations are all located in the United States and have similar economic characteristics. We build rigs and engage in land contract drilling for oil and natural gas in the United

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States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by rig; however, financial performance is measured as a single enterprise and not on a rig-by-rig basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.

13. Commitments and Contingencies

Purchase Commitments

As of December 31, 2023, we had outstanding purchase commitments to a number of suppliers totaling $3.4 million related primarily to rig equipment or components ordered but not received. We have paid deposits of $0.1 million related to these commitments.

Employment Agreements

We have entered into employment agreements with six key executives, with original terms of three years, that automatically extend a year prior to expiration, provided that neither party has provided a written notice of termination before that date. As of December 31, 2023, these agreements in aggregate provide for minimum annual cash compensation of $2.1 million and cash severance payments totaling $5.4 million for termination by ICD without cause, or termination by the employee for good reason, both as defined in the agreements, or $7.7 million in the event of a change in control, as defined in the agreements.

Contingencies

Our operations inherently expose us to various liabilities and exposures that could result in third party lawsuits, claims and other causes of action. While we insure against the risk of these proceedings to the extent deemed prudent by our management, we can offer no assurance that the type or value of this insurance will meet the liabilities that may arise from any pending or future legal proceedings related to our business activities. There are no current legal proceedings that we expect will have a material adverse impact on our consolidated financial statements.

14. Defined Contribution Plan

Substantially all employees may elect to participate in our 401(k) plan by contributing a portion of their earnings. We contribute an amount equal to 100 percent of the first six percent of the participant’s compensation subject to certain limitations. The annual expense incurred for this defined contribution plan was $1.5 million and $1.4 million for the years ended December 31, 2023 and 2022, respectively.

15. Concentration of Market and Credit Risk

We derive all our revenues from drilling services contracts with companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility in oil and natural gas prices. We have a number of customers that account for 10% or more of our revenues. For 2023, this customer included Endeavor Energy Resources (23%). For 2022, these customers included Paloma Natural Gas, LLC (20%), Endeavor Energy Resources (13%), and Diamondback Energy, Inc. (12%).

Our trade receivables are with a variety of E&P and other oilfield service companies. We perform ongoing credit evaluations of our customers, and we generally do not require collateral. We do occasionally require deposits from customers whose creditworthiness is in question prior to providing services to them. As of December 31, 2023, Endeavor Energy Resources (24%), Diamondback Energy, Inc. (13%) and Petro-Hunt Permian, LLC (12%) accounted for 10% or more of our accounts receivable. As of December 31, 2022, Paloma Natural Gas, LLC (19%) and Diamondback Energy, Inc. (15%) accounted for 10% or more of our accounts receivable.

We have concentrated credit risk for cash by maintaining deposits in major banks, which may at times exceed amounts covered by insurance provided by the United States Federal Deposit Insurance Corporation (“FDIC”). We

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monitor the financial health of the banks and have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk. As of December 31, 2023, we had approximately $5.3 million in cash and cash equivalents in excess of FDIC limits.

16. Related Parties and Other Matters

In connection with the issuance of the Convertible Notes on March 18, 2022, we issued to affiliates of MSD Partners, L.P. (the “MSD Investors”) $78.9 million principal amount of Convertible Notes and entered into an Investor’s Rights Agreement permitting MSD Partners to nominate one director to our Board so long as MSD Partners and its affiliates continue to own $25.0 million principal amount of Convertible Notes (the “Sunset Date”). We also entered into an Investor’s Rights Agreement with Glendon Capital Management L.P. (“GCM”) that permits GCM to designate one director on the same terms. In addition, as long as each of such parties continues to have the right to appoint such holder representatives, the two holder representatives will have the right to nominate one additional representative as a director, provided that the third representative must be an independent director unless one of the MSD Partners and the GCM representatives is independent for New York Stock Exchange purposes. The proposed representatives are subject to review by our Nominating and Corporate Governance Committee. Following the Sunset Date for the applicable party, MSD Partners and/or GCM, as applicable, will cause its designee to offer to tender his or her resignation, unless otherwise requested by the Board, and the third representative may be removed by the Board. Two holders representatives of the MSD Investors and GCM were initially nominated and appointed to the Board pursuant to the Investor’s Rights Agreement, and the third representative was appointed in connection with an increase in the number of directors from six to seven members effective July 1, 2022. As of December 31, 2023, accrued interest payable on the Convertible Notes was $6.8 million.

SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS


	Balance at		Charged to
	Beginning of		Costs and				Balance at
(in thousands)	Period		Expenses		Deductions ⁽¹⁾		End of Period
Year Ended December 31, 2023:
Credit loss allowance	$	—	$	1,177	$	(1,177)	$	—
Valuation allowance for deferred tax assets	$	78,793	$	3,140	$	—	$	81,933
Year Ended December 31, 2022:
Credit loss allowance	$	—	$	—	$	—	$	—
Valuation allowance for deferred tax assets	$	79,993	$	(1,200)	$	—	$	78,793

(1)

Includes accounts determined to be uncollectible and charged against allowance.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file 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 and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of December 31, 2023 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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.

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of our internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the 2013 framework). Based on this assessment, using this criteria, our management determined that our internal control over financial reporting was effective as of December 31, 2023.

Attestation Report of the Independent Registered Public Accounting Firm

Not applicable.

ITEM 9B. OTHER INFORMATION

None.

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ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2024 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of December 31, 2023.

Our Board of Directors has adopted a Code of Business Conduct and Ethics, which applies to all our officers and employees, a Code of Ethics for Senior Officers of the Company, and a Code of Business Conduct and Ethics for Directors, which applies to all our directors. A copy of each of these codes of business conduct and ethics is available on our website at http://icdrilling.investorroom.com. Stockholders may also request a printed copy of either code of business conduct and ethics, free of charge, by contacting us at Independence Contract Drilling, Inc., 20475 State Highway 249, Suite 300, Houston, TX 77070 or by telephone at (281) 598-1230 or by emailing Investor.relations@icdrilling.com. Any waiver of any of the codes of business conduct and ethics for executive officers or directors may be made only by our Board of Directors or a committee of the Board of Directors committee to which the Board of Directors has delegated that authority and will be promptly disclosed to our stockholders as required by applicable United States federal securities laws and the corporate governance rules of the NYSE. Amendments to either code of business conduct and ethics must be approved by our Board of Directors and will be promptly disclosed (other than technical, administrative or non-substantive changes) on our website.

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

List of filed documents:

(1)

Financial Statements

Our Consolidated Financial Statements and accompanying footnotes are included under Part II, “Item 8. Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

(2)

Financial Statement Schedules

Schedule II - Valuation and Qualifying Accounts is included under Part II, “Item 8. Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

(3)

Exhibits

The exhibits required by Item 601 of Regulation S-K are listed in subparagraph (b) below.

(b)

Exhibits

The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K and are incorporated herein by reference.

ITEM 16. FORM 10-K SUMMARY

None.

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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 Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.


		INDEPENDENCE CONTRACT DRILLING, INC.
Date:	February 28, 2024	By:	/s/ J. Anthony Gallegos, Jr.
			Name:	J. Anthony Gallegos, Jr.
			Title:	President, Chief Executive Officer and Director
				(Principal Executive Officer)

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints J. Anthony Gallegos, Jr. and Philip A. Choyce, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, 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 unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite or necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

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Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date:
February 28, 2024	By:	/s/ J. Anthony Gallegos, Jr.
		Name:	J. Anthony Gallegos, Jr.
		Title:	President, Chief Executive Officer and Director (Principal Executive Officer)

February 28, 2024	By:	/s/ Philip A. Choyce
		Name:	Philip A. Choyce
		Title:	Executive Vice President, Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer)

February 28, 2024	By:	/s/ Katherine Kokenes
		Name:	Katherine Kokenes
		Title:	Vice President and Chief Accounting Officer (Principal Accounting Officer)

February 28, 2024	By:	/s/ Robert J. Barrett, IV
		Name:	Robert J. Barrett, IV
		Title:	Director

February 28, 2024	By:	/s/ Brian D. Berman
		Name:	Brian D. Berman
		Title:	Director

February 28, 2024	By:	/s/ Vincent J. Cebula
		Name:	Vincent J. Cebula
		Title:	Director

February 28, 2024	By:	/s/ Christopher M. Gleysteen
		Name:	Christopher M. Gleysteen
		Title:	Director

February 28, 2024	By:	/s/ James G. Minmier
		Name:	James G. Minmier
		Title:	Director

February 28, 2024	By:	/s/ Stacy D. Nieuwoudt
		Name:	Stacy D. Nieuwoudt
		Title:	Director

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EXHIBIT INDEX

Exhibit Number	Document Description	Incorporated by Reference Herein

3.1	Amended and Restated Certificate of Incorporation of Independence Contract Drilling, Inc.	Incorporated herein by reference to Exhibit 3.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on August 13, 2014 (File No. 001-36590)
3.2	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Independence Contract Drilling, Inc.	Incorporated herein by reference to Exhibit 3.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on October 2, 2018 (File No. 001-36590)
3.3	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of the Company, dated as of March 11, 2020.	Incorporated herein by reference to Exhibit 3.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on March 11, 2020 (File No. 001-36590)
3.4	Certificate of Amendment of the Amended and Restated Certificate of Incorporation of Independence Contract Drilling, Inc., dated as of June 8, 2022.	Incorporated herein by reference to Exhibit 3.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on June 8, 2022 (File No. 001-36590)
3.5	Third Amended and Restated Bylaws of Independence Contract Drilling, Inc. (adopted as of February 28, 2023).	Incorporated herein by reference to Exhibit 3.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on March 2, 2023 (File No. 001-36590)
4.1	Form of Common Stock Certificate.	Incorporated herein by reference to Exhibit 4.1 of the Registration Statement on Form S-1 filed by Independence Contract Drilling, Inc. on July 18, 2014 (Registration No. 333-196914)
4.2	Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities and Exchange Act of 1934.	Incorporated herein by reference to Exhibit 4.4 of the Annual Report on Form 10-K filed by Independence Contract Drilling, Inc. on March 2, 2020 (File No. 001-36590)
10.1	Credit Agreement, dated as of October 1, 2018, by and among Wells Fargo Bank, National Association, as Agent, the Lenders party thereto, Independence Contract Drilling, Inc., Patriot Saratoga Merger Sub, LLC, and ICD Operating LLC, as Borrowers.	Incorporated herein by reference to Exhibit 10.2 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on October 2, 2018 (File No. 001-36590)
10.2	Second Amendment dated effective January 21, 2022 to Credit Agreement, dated as of October 1, 2018, by and among Wells Fargo Bank, National Association, as Agent, the Lenders party thereto, Independence Contract Drilling, Inc., Patriot Saratoga Merger Sub, LLC, and ICD Operating LLC, as Borrowers.	Incorporated herein by reference to Exhibit 10.3 of the Annual Report on Form 10-K filed by Independence Contract Drilling, Inc. on March 15, 2022 (File No. 001-36590)
10.3	Amendment No. 3 to Credit Agreement, dated as of March 18, 2022, to Credit Agreement, dated as of October 1, 2018, by and among Wells Fargo Bank, National Association, as Agent, the Lenders party thereto, Independence Contract Drilling, Inc., Patriot Saratoga Merger Sub, LLC, and ICD Operating LLC, as Borrowers.	Incorporated herein by reference to Exhibit 10.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on March 24, 2022 (File No. 001-36590)

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Exhibit Number	Document Description	Incorporated by Reference Herein

10.4	Amendment No. 5 to Credit Agreement, dated as of September 22, 2022, to Credit Agreement, dated as of October 1, 2018, by and among Wells Fargo Bank, National Association, as Agent, the Lenders party thereto, Independence Contract Drilling, Inc., Patriot Saratoga Merger Sub, LLC, and ICD Operating LLC, as Borrowers.	Incorporated herein by reference to Exhibit 10.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on September 26, 2022 (File No. 001-36590)
10.5	Convertible Note Subscription Agreement, dated as of March 18, 2022, by and among Independence Contract Drilling, Inc., and the subscribers named therein.	Incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.6	Indenture, dated as of March 18, 2022, by and among Independence Contract Drilling, Inc., U.S. Bank Trust Company, National Association, as trustee and collateral agent, and Sidewinder Drilling LLC, as guarantor.	Incorporated herein by reference to Exhibit 10.2 of the Company’s Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.7	First Supplemental Indenture dated July 21, 2022, by and among the Company, the Guarantor thereto, and U.S. Bank Trust Company National Association.	Incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K dated July 21, 2022 filed by Independence Contract Drilling, Inc. on July 27, 2022 (File No. 001-36590)
10.8	Second Supplemental Indenture dated February 24, 2023, by and amongst the Company, the Guarantor thereto, and U.S. Bank Trust Company National Association.	Incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K dated February 24, 2023 filed by Independence Contract Drilling, Inc. on February 27, 2023 (File No. 001-36590)
10.9	Third Supplemental Indenture dated February 27, 2024, by and amongst the Company, the Guarantor thereto, and U.S. Bank Trust Company National Association.	Incorporated herein by reference to Exhibit 10.1 of the Company’s Form 8-K dated February 27, 2024 filed by Independence Contract Drilling, Inc. on February 28, 2024 (File No. 001-36590)
10.10	Intercreditor Agreement, dated as of March 18, 2022, by and among U.S. Bank National Association, as Note Agent and Note Control Agent, and Wells Fargo Bank, National Association, as ABL Agent and ABL Control Agent.	Incorporated herein by reference to Exhibit 10.2 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on March 24, 2022 (File No. 001-36590)
10.11	Security Agreement, dated as of March 18, 2022, by and among U.S. Bank National Association, as Agent, and the Grantors named therein.	Incorporated herein by reference to Exhibit 10.3 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on March 24, 2022 (File No. 001-36590)
10.12	Investor Rights Agreement, dated as of March 18, 2022, by and between Independence Contract Drilling, Inc. and MSD Partners, L.P..	Incorporated herein by reference to Exhibit 10.4 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.13	Investor Rights Agreement, dated as of March 18, 2022, by and between Independence Contract Drilling, Inc. and Glendon Capital Management LP.	Incorporated herein by reference to Exhibit 10.5 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.14	Voting Support Agreement, dated as of March 18, 2022, by and among Independence Contract Drilling, Inc. and the stockholders named therein.	Incorporated herein by reference to Exhibit 10.6 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)

Table of Contents

Exhibit Number	Document Description	Incorporated by Reference Herein

10.15†	Amended and Restated Executive Employment Agreement, dated as of March 18, 2022, by and between Independence Contract Drilling, Inc., and J. Anthony Gallegos, Jr.	Incorporated herein by reference to Exhibit 10.8 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.16†	Amended and Restated Executive Employment Agreement, dated as of March 18, 2022, by and between Independence Contract Drilling, Inc. and Philip A. Choyce.	Incorporated herein by reference to Exhibit 10.9 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.17†	Amended and Restated Executive Employment Agreement, dated as of March 18, 2022, by and between Independence Contract Drilling, Inc. and Philip A. Dalrymple.	Incorporated herein by reference to Exhibit 10.10 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.18†	Amended and Restated Executive Employment Agreement, dated as of March 18, 2022, by and between Independence Contract Drilling, Inc. and Scott A. Keller.	Incorporated herein by reference to Exhibit 10.11 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.19†	Amended and Restated Executive Employment Agreement, dated as of March 18, 2022, by and between Independence Contract Drilling, Inc. and Katherine Kokenes.	Incorporated herein by reference to Exhibit 10.12 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.20†	Amendment No. 1 dated February 19, 2023 to Amended and Restated Employment Agreement dated March 18, 2022 with J. Anthony Gallegos, Jr.	Incorporated herein by reference to Exhibit 10.2 of the Quarterly Report on Form 10-Q filed by Independence Contract Drilling, Inc. on May 9, 2023 (File No. 001-36590)
10.21†	Amendment No. 1 dated February 19, 2023 to Amended and Restated Employment Agreement dated March 18, 2022 with Scott A. Keller.	Incorporated herein by reference to Exhibit 10.3 of the Quarterly Report on Form 10-Q filed by Independence Contract Drilling, Inc. on May 9, 2023 (File No. 001-36590)
10.22†	Amendment No. 1 dated February 19, 2023 to Amended and Restated Employment Agreement dated March 18, 2022 with Philip A. Dalrymple.	Incorporated herein by reference to Exhibit 10.4 of the Quarterly Report on Form 10-Q filed by Independence Contract Drilling, Inc. on May 9, 2023 (File No. 001-36590)
10.23†	Amendment No. 1 dated February 19, 2023 to Amended and Restated Employment Agreement dated March 18, 2022 with Katherine Kokenes.	Incorporated herein by reference to Exhibit 10.5 of the Quarterly Report on Form 10-Q filed by Independence Contract Drilling, Inc. on May 9, 2023 (File No. 001-36590)
10.24†	Independence Contract Drilling 2019 Omnibus Incentive Plan, effective as of February 27, 2019.	Incorporated herein by reference to Exhibit 10.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on March 5, 2019 (File No. 001-36590)
10.25†	Amendment No. 1 to Independence Contract Drilling 2019 Omnibus Incentive Plan, effective as of June 8, 2022.	Incorporated herein by reference to Exhibit 10.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on June 8, 2022 (File No. 001-36590)

Table of Contents

Exhibit Number	Document Description	Incorporated by Reference Herein

10.26†	Form of 2019 Performance-Based Unit Award Agreement (Total Shareholder Return).	Incorporated herein by reference to Exhibit 10.5 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on March 5, 2019 (File No. 001-36590)
10.27†	Form of Time-Based Restricted Stock Unit Agreement.	Incorporated herein by reference to Exhibit 10.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on February 13, 2020 (File No. 001-36590)
10.28†	Form of TSR Cash Settlement Award Agreement.	Incorporated herein by reference to Exhibit 10.2 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on February 13,2020 (File No. 001-36590)
10.29†	Form of Director RSU Award Agreement - Partial Cash Settlement.	Incorporated herein by reference to Exhibit 10.4 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on February 13, 2020 (File No. 001-36590)
10.30†	Form of Cash Settled SAR Award Agreement.	Incorporated herein by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q filed by Independence Contract Drilling, Inc. on May 4, 2021 (File No. 001-36590)
10.31†	Form of 2021 Retention Agreement.	Incorporated herein by reference to Exhibit 10.3 of the Quarterly Report on Form 10-Q filed by Independence Contract Drilling, Inc. on May 4, 2021 (File No. 001-36590)
10.32†	Form of Restricted Stock Unit Award Agreement (Time Vesting).	Incorporated herein by reference to Exhibit 10.13 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.33†	Form of Stock Appreciation Rights Award Agreement (Share Settled).	Incorporated herein by reference to Exhibit 10.14 of the Current Report on Form 8-K dated March 18, 2022 filed by Independence Contract Drilling, Inc. on March 21, 2022 (File No. 001-36590)
10.34†	Form of FCF/TSR Restricted Stock Unit Performance Award.	Incorporated herein by reference to Exhibit 10.1 of the Quarterly Report on Form 10-Q filed by Independence Contract Drilling, Inc. on May 9, 2023 (File No. 001-36590)
10.35	Form of Indemnification Agreement.	Incorporated by reference herein to Exhibit 10.1 of the Current Report on Form 8-K filed by Independence Contract Drilling, Inc. on May 20, 2020 (File No. 001-36590)
23.1*	Consent of MossAdams, LLP.
23.2*	Consent of BDO USA, P.C.
24.1	Power of Attorney.	Included on the signatures page of this Annual Report on Form 10-K
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Table of Contents

Exhibit Number		Document Description		Incorporated by Reference Herein

32.1**		Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
97.1*		Independence Contract Drilling, Inc. Policy on Recoupment of Incentive Compensation Applicable to Executive Officers.
101.INS*		XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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 Labels Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.
104		Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

*	Filed herewith.

**	Furnished, not filed.

†	Indicates a management contract or compensatory plan or arrangement filed pursuant to Item 601(b)(10)(iii) of Regulation S-K.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Year Ended December 31,

(in thousands)

Potentially dilutive securities excluded as anti-dilutive