ICD Independence Contract Drilling Inc

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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For the fiscal year ended December 31, 2022

or

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For the transition period from              to

Commission file number 001-36590

(Registrant’s telephone number, including area code)

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 and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post 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):

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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 $27,149,805 as of June 30, 2022, the last business day of the registrant’s most recently completed second fiscal quarter (based on a closing price of $3.13 per share as reported on the New York Stock Exchange and 8,674,059 shares held by non-affiliates).

There were 13,641,228 shares of the registrant’s common stock outstanding as of February 24, 2023.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the registrant’s 2023 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

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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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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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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 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.

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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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.

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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.

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, 2022, our backlog of term contracts with original terms of six months or more was $79.1 million, all of which is expected to be realized during 2023. 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 2022, our customers representing more than 10% of our revenues were Paloma Natural Gas, LLC, Endeavor Energy Resources and Diamondback Energy, Inc.

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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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. On January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. 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:

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 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 under the federal Water Pollution 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. On January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, effectively limiting hydraulic fracturing on federal lands and waters. Any such 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 the EPA rules issued in April 2012, which 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 GHG 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. However, in September 2020, the EPA issued a final rule that removed the transmission and storage segment from the 2016 new source performance standards, rescinded VOCs and methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. On January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent methane emission rulemaking. In addition, the Inflation Reduction Act of 2022

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(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. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs 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 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

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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.

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

Human Capital

As of February 28, 2023, we had approximately 600 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.

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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 operation on air and water quality, land usage, use of energy, and reducing waste materials. 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 recently 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.

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.

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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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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.

During 2020, OPEC and Russia (collectively “OPEC+”) instituted production cuts in order to support oil prices during the period of reduced demand caused by the COVID-19 pandemic. Recently, OPEC+ has announced modest production increases as global supply-demand fundamentals have become more normalized and oil prices have risen. Although oil prices have recovered from historic 2020 lows, 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 despite substantial improvements in commodity prices. If oil prices were to fall again and remain below $70 per barrel for an extended period, we believe demand for contract drilling services would again soften over current levels, which could have a material adverse effect on our operations and financial condition.

Recently, natural gas prices have fallen dramatically. Natural gas prices (Henry Hub) reached a high of $9.85 per mmcf in August 2022, but fell to $3.52 per mmcf as of December 31, 2022 and have fallen further to a low of $2.12 as of February 21, 2023. These commodity price declines, as well as take away capacity issues, have caused market conditions in the Haynesville Shale to weaken rapidly, which we believe will result in a reduction in the number of drilling rigs operating in the Haynesville Shale, including a reduction in our operating rigs. We intend to relocate any idle rigs to the Permian Basin where market conditions remain strong and where we believe we can recontract these rigs on attractive terms, with one relocation already occurring as of March 1, 2023. However, there can be no assurance that we will be successful in marketing all idle Haynesville Shale rigs in the Permian Basin or that they will be contracted on a timely basis or upon terms that are acceptable to us. Any failure to successfully remarket these rigs in the Permian Basin could have a material adverse effect on our operations and financial condition.

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, 2022, we had rigs operating or earning revenues from 13 different customers, including one customer who had contracted five rigs, or 25%, of our contracted rigs and three customers who had contracted two each, or 10%, 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. 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.

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All of our operating rigs are operating under contracts with terms expiring during 2023. 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 2023. 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 downturn in oil prices has decreased demand for drilling rigs and resulted in downward pricing pressure on operating drilling rigs.

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.

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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, 2022, 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 $79.1 million. All of this backlog expires in 2023, 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 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.

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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. Any limitations on our access to capital or increase in the cost of that capital could 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 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.

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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 believe we had an ownership change in April 2016, October 2018 in connection with the Sidewinder Merger, and in October 2021. In conjunction with the ownership change in October 2021, we expect to have approximately $94.8 million of NOLs 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 in the future 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 service, 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 in the production of oil and natural gas, including from the developing shale plays, incurred by our customers 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 operations, 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. However, in September 2020, the EPA issued a final rule that removed the transmission and storage segment from the 2016 new source performance standards, rescinded VOCs and methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. On January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent methane emission rulemaking. 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. While the U.S. withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris Agreement. On January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices and to consider whether to adjust royalties associated with oil and gas resources extracted from public lands and offshore waters to account for corresponding climate costs. 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 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. 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.

On March 18, 2022, we issued $157.5 million principal amount of Convertible Notes, and currently have $170.2 million of Convertible Notes outstanding as of December 31, 2022. 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, resulting in an additional $12.7 million principal amount of Convertible Notes being issued as of September 30, 2022 and have elected to pay in-kind outstanding interest that is payable on March 31, 2023. 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 a large percentage of our common stock as a result of the transactions relating to the issuance of the Convertible Notes, 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 approval, and the priorities of the Primary Noteholders for our business may be different from our other stockholders.

The Primary Noteholders collectively own approximately 17% 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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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. Any refinancing of indebtedness could be at higher interest rates 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:

Our Convertible Notes contain a covenant restricting capital expenditures to $15.0 million during 2023 and 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. During 2022, the holders of our Convertible Notes consented to capital expenditure adjustments under this covenant aggregating $10.6 million and have consented to $16.9 million of capital expenditures in February 2023. If were are unable to obtain consents in the future to 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.

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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 2023.

As of December 31, 2022, the borrowing base under our ABL Credit Facility was $33.1 million, and we had $21.3 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. During 2022, we did not maintain this minimum fixed charge coverage ratio but maintained minimum availability above $4.0 million at all times. 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. The borrowing base under our ABL Credit Facility was $33.1 million as of December 31, 2022, with lender commitments of $40.0 million.

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 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

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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, 2022 included $182.0 million of floating-rate debt attributed to borrowings at an average interest rate of 13.30%, and the impact on annual cash flow of a 10% change in the floating-rate (approximately 14.63%) would be approximately $2.4 million annually based on the floating-rate debt and other obligations outstanding as of December 31, 2022; 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.

As a result of improved U.S. land rig activity driven by improving market conditions, demand and competition for rig personnel in our operating regions has increased significantly, driven not only by competition between land drilling companies but also other industries where economic activity has improved. This has resulted in meaningful increases in field-level pay over the past twelve months and the costs to recruit and train new employees. Inflationary factors have also increased other costs to reactivate and 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, as worldwide economic activity has improved following emergence from the COVID-19 pandemic, supply chain pressures and bottlenecks have developed (including due to both COVID-19 and the war in the Ukraine) and could potentially develop 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:

We may issue preferred stock 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.

General Risk Factors

The COVID-19 pandemic and related economic repercussions had a significant impact on our business, results of operations and financial condition, and future outbreaks from COVID-19 or other pandemics could have a material adverse effect on our business, liquidity, results of operations and financial condition.

The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19 resulted in a decline in demand for oil and natural gas in 2020 and early 2021. This had a material negative impact on our business, causing our operating rig count to fall to as low as three rigs in August 2020 and resulting in our reporting negative cash flows from operations in the first quarter of 2021 through the first quarter of 2022. Since early 2021, the distribution of COVID-19 vaccines progressed, many government-imposed restrictions were relaxed or rescinded, and the global oil and gas market and our business have recovered and significantly improved. However, if future COVID-19 outbreaks or other 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.

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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.

Our business is subject to cybersecurity risks and threats.

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. It is possible that our business, financial and other systems could be compromised, which might not be noticed for some period of time. Risks associated with these threats include, among other things, loss of intellectual property, disruption of our customers’ business operations and safety procedures, loss or damage to our worksite data delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events. Furthermore, geopolitical tensions or conflicts, such as Russia’s invasion of Ukraine, may further heighten the risk of cybersecurity attacks.

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.

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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 at times of high demand we will be able to retain, recruit and train an adequate number of skilled workers. 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.

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ITEM 6.       [Reserved]

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Recently, natural gas prices have fallen dramatically. Natural gas prices (Henry Hub) reached a high of $9.85 per mmcf in August 2022, but fell to $3.52 per mmcf as of December 31, 2022 and have fallen further to a low of $2.12 per mmcf as of February 21, 2023. These commodity price declines, as well as take away capacity issues, have caused market conditions in the Haynesville Shale to weaken rapidly, which we believe will result in a reduction in the number of drilling rigs operating in the Haynesville Shale, including a reduction in our operating rigs. We intend to relocate these rigs to the Permian Basin where market conditions remain strong and where we believe we can recontract these rigs on attractive terms, with one relocation already occurring as of March 1, 2023. However, there can be no 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.

Convertible Notes

On March 18, 2022, we issued $157.5 million aggregate principal amount of convertible secured PIK toggle notes due 2026 (the “Convertible Notes”), and currently have $170.2 million of Convertible Notes outstanding as of December 31, 2022. 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 merger consideration payable with associated accrued interest to prior equity holders of Sidewinder Drilling LLC, and for working capital purposes. 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 had an initial payment in-kind, or “PIK,” interest rate of SOFR plus 14.0% through September 30, 2022. The PIK interest rate decreased to SOFR plus 9.5% as of September 30, 2022.

We have the right, at our option, to PIK Convertible Note interest for the entire term of the Convertible Notes. We elected to PIK outstanding interest as of September 30, 2022, resulting in an additional $12.7 million principal amount of Convertible Notes being issued as of that date. We have accrued $5.8 million of interest related to the Convertible Notes as of December 31, 2022. The next interest due date is March 31, 2023 and we have elected to pay this interest in-kind when due on March 31, 2023. As the PIK interest due as of March 31, 2023 will result in the issuance of additional Convertible Notes, we have classified the accrued interest as of December 31, 2022 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 our common stock 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. 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. See Note 8 “Long-term Debt” for additional information.

Derivatives

We do not use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. We evaluate all of our financial instruments to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to ASC 480, Distinguishing Liabilities from Equity, and ASC 815, Derivatives and Hedging (“ASC 815”). The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period. All derivative instruments are measured at fair value.

As described in Note 8, we determined that certain features under our Convertible Notes required bifurcation from the debt host agreement in accordance with ASC 815 as of March 18, 2022. Accordingly, we recognized a derivative liability at fair value for this instrument in our consolidated balance sheet and adjusted the carrying value of the liability to fair value at each reporting period until the features underlying the instrument were exercised, redeemed, cancelled or expired. The changes in fair value were assessed quarterly and recorded in our consolidated statement of operations. After the approval of certain matters by our stockholders at our 2022 Annual Meeting of Stockholders held

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June 8, 2022, certain features under our Convertible Notes were modified and no longer met the criteria to bifurcate from the host debt agreement. Accordingly, through June 8, 2022, we recognized a loss of $4.3 million for the change in fair value of the embedded derivative, and reclassified to stockholders’ equity $69.2 million representing the fair value of the conversion rate feature derivative liability on our balance sheet, as the conversion rate feature now met the criteria to be classified in equity, and recognized a gain on extinguishment of derivative liability of $10.8 million on our consolidated statement of operations associated with the PIK interest rate feature of the derivative liability. See Financial Instruments and Fair Value in Note 2 “Summary of Significant Accounting Policies” for additional information.

Asset Impairment, net and Assets Held for Sale

During the fourth quarter of 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.

During 2021, we impaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries. During the third quarter of 2021, we initiated a plan to sell miscellaneous drilling equipment. Accordingly, we impaired the drilling equipment to fair market value less cost to sell and recorded asset impairment expense of $0.5 million in our consolidated statements of operations and recorded assets held for sale of $50.0 thousand on our consolidated balance sheet. These assets were sold in the fourth quarter of 2021.

Amendment No. 5 to the Revolving ABL Credit Facility

On September 22, 2022, we amended our Revolving ABL Credit Facility Agreement, which included extending the maturity date by two years to September 30, 2025, replacing references to LIBOR interest rates with SOFR interest rates and amending the applicable margin for which interest is calculated.

Certificate of Amendment to the Restated Certificate of Incorporation

On June 8, 2022, we filed a certificate of amendment to our Restated Certificate of Incorporation (the “Charter Amendment”) with the Delaware Secretary of State. The Charter Amendment increased the number of authorized shares of our common stock, par value $0.01 per share from 50 million shares to 250 million shares. The Charter Amendment did not change the number of authorized shares of our preferred stock or the par value per share of any stock.

Amendment No. 1 to the 2019 Plan

On June 8, 2022, our stockholders approved an amendment to our 2019 Omnibus Incentive Plan (the “2019 Plan”) to increase the number of shares of our common stock authorized for issuance under the 2019 Plan by 4.3 million shares (from 275,000 shares to 4,575,000 shares).

ATM Offering

In conjunction with the ATM Distribution Agreement entered into on August 19, 2021, our board of directors authorized the sale of $5.9 million and $6.5 million in December 2021 and May 2022, respectively, of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” We sold shares under this program during the first quarter of 2022 and raised gross proceeds of $3.6 million. We did not participate in this program in the second, third or fourth quarter of 2022. As of December 31, 2022, we have $8.8 million remaining availability under this ATM program.

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

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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

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.

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:

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Comparison of the years ended December 31, 2022 and 2021

Revenues

Revenues for the year ended December 31, 2022 were $186.7 million, representing a 112.3% increase over revenues of $88.0 million for the year ended December 31, 2021. This increase was attributable to an increase in operating days resulting from the reactivation of rigs in late 2021 and 2022 (such increase in days noted below), as well as increases in contractual dayrates driven by improving demand for our contract drilling services. Revenue per day increased by 58.3% to $27,258 during 2022 compared to revenue per day of $17,224 during 2021 as a result of increases in contractual dayrates and improved demand in 2022.

Operating Costs

Operating costs for the year ended December 31, 2022 were $123.4 million, representing a 62.9% increase over operating costs for the year ended December 31, 2021 of $75.8 million. This increase was primarily attributable to an increase in operating days to 6,308 days as compared to 4,651 days in 2021 as well as higher per day operating expenses. Operating cost per day increased to $16,940 during 2022, representing a 21.5% increase compared to cost per day of $13,943 during 2021. This increase in cost per day was primarily attributable to higher personnel costs, driven by a much tighter labor market compared to 2021, higher incentive compensation expense as well as inflationary pressures.

Selling, General and Administrative Expenses

Selling, general and administrative expenses for the year ended December 31, 2022 were $24.8 million, representing a 58.0% increase over selling, general and administrative expenses for the year ended December 31, 2021 of $15.7 million. This increase was primarily related to the reinstatement of pre-COVID salaries and benefits, higher incentive compensation expense and higher stock-based compensation expense associated primarily with awards granted in the second quarter of 2022.

Depreciation and Amortization

Depreciation and amortization for the year ended December 31, 2022 was $40.4 million, representing a 3.9% increase compared to $38.9 million for the year ended December 31, 2021. This increase was primarily the result of asset additions related to reactivated rigs in 2021 and 2022.

Gain on Disposition of Assets, net

A gain on the disposition of assets totaling $0.2 million and $0.2 million was recorded for the years ended December 31, 2022 and 2021, respectively. 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 write-off of certain assets related to overhauls performed during the year. For the year ended December 31, 2021, the gain relates primarily to the sale of miscellaneous drilling equipment.

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Interest Expense

Interest expense was $29.6 million for the year ended December 31, 2022, compared to $15.2 million for the year ended December 31, 2021. 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) Gain on Extinguishment of Debt

Loss on extinguishment of debt was $46.3 million for the 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.

A gain on extinguishment of debt totaling $10.1 million was recorded for the year ended December 31, 2021 related to the forgiveness of our PPP Loan.

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 they were 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) Expense

Income tax benefit for the year ended December 31, 2022 amounted to $6.2 million compared to income tax expense of $18.5 million for the year ended December 31, 2021. The effective tax rate was 8.7% for the year ended 2022 compared to negative 38.5% for the year ended 2021. The tax benefit for 2022 primarily relates to non-cash charges related to the creation of deferred tax assets in 2022 (net operating losses and interest limitation carryforwards) with the ability to offset deferred tax liabilities. Tax expenses for 2021 primarily related to non-cash charges related to the inability to utilize net operating loss (“NOL”) deferred tax assets to offset deferred tax liabilities due to an IRC Section 382 ownership change that occurred in October 2021 and the limitations therefrom placed upon the NOLs. See Note 9 “Income Taxes” in the accompanying consolidated financial statements.

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interest payment due under our Convertible Notes. We have the right, at our option, to PIK interest under the Convertible Notes for the entire term of the Convertible Notes. We continued our “at-the-market” offering process, raising an additional $3.6 million of gross proceeds and issuing an additional 1,061,853 shares.

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 and periods subsequent to such.

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.

Our long-term debt as of December 31, 2022 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, 2022. Interest payment obligations on our Convertible Notes were estimated based on the 13.6% interest rate that was in effect December 31, 2022, and the principal balance of $170.2 million as of December 31, 2022, and assuming repayment of the outstanding balance occurs on March 18, 2026. Interest payment obligations on our ABL Credit Facility were estimated based on the 9.25% interest rate that was in effect as of December 31, 2022, and the principal balance of $11.8 million as of December 31, 2022, 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 $0.9 million that could be forfeited if we were to cancel these orders.

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Net Cash Provided By (Used In) Operating Activities

Cash provided by operating activities was $28.6 million for the year ended December 31, 2022 compared to cash used in operating activities of $9.6 million for the year ended December 31, 2021. 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 issuance costs and debt discount. 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 2022 were higher as a result of a decrease in net loss of $1.4 million, adjusted for non-cash items of $101.5 million, compared to $57.1 million in 2021. Additionally, working capital changes that decreased cash flows from operating activities were $7.6 million in 2022 compared to de minimis working capital changes that increased cash flows from operating activities in 2021.

Net Cash Used In Investing Activities

Cash used in investing activities was $38.3 million for the year ended December 31, 2022 compared to $14.4 million for the year ended December 31, 2021. Our primary investing activities in 2022 related to rig reactivations and maintenance capital expenditures. 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. Cash payments during 2022 included approximately $4.5 million associated with equipment purchased in 2021. During 2021, cash payments of $16.4 million for capital expenditures were offset by proceeds from the sale of property, plant and equipment of $2.0 million.

Net Cash Provided By Financing Activities

Cash provided by financing activities was $10.9 million for the year ended December 31, 2022 compared to cash provided by financing activities of $15.8 million for the year ended December 31, 2021. 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, 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, restricted stock units withheld for taxes paid of $10.0 thousand, the purchase of treasury stock of $10.0 thousand and payments for finance lease obligations of $5.8 million.

During 2021, we received proceeds from borrowings under our Revolving ABL Credit Facility of $6.3 million, proceeds from the issuance of common stock through our ATM transaction, net of issuance costs, of $9.0 million and proceeds from the issuance of common stock under our equity line of credit purchase agreement of $4.2 million offset by restricted stock units withheld for taxes paid of $14.0 thousand, the purchase of treasury stock of $10.0 thousand, financing costs paid of $64.0 thousand and payments for finance lease obligations of $3.6 million.

Long-term Debt

On March 18, 2022, we issued $157.5 million aggregate principal amount of convertible secured PIK toggle notes due 2026 (the “Convertible Notes”), and currently have $170.2 million of Convertible Notes outstanding as of December 31, 2022. 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

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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 had an initial payment in-kind, or “PIK,” interest rate of SOFR plus 14.0% through September 30, 2022. The PIK interest rate decreased to SOFR plus 9.5% as of September 30, 2022. We have the right at our option, to PIK interest under the Convertible Notes for the entire term of the Convertible Notes. We elected to PIK outstanding interest as of September 30, 2022, resulting in an additional $12.7 million principal amount of Convertible Notes being issued as of that date. We have accrued $5.8 million of interest related to the Convertible Notes as of December 31, 2022. The next interest due date is March 31, 2023 and we have elected to pay this interest in-kind when due on March 31, 2023. As the PIK interest due as of March 31, 2023 will result in the issuance of additional Convertible Notes, we have classified the accrued interest as of December 31, 2022 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.

The following changes to the terms of the Convertible Notes and Indenture, and to the shares issuable upon conversion of the Convertible Notes, became effective based on approvals of matters by our stockholders at our 2022 Annual Meeting of Stockholders held on June 8, 2022 (constituting “Shareholder Approval” as defined in the Indenture): (a) the Convertible Notes initial PIK interest rate of SOFR plus 14.0% decreased to SOFR plus 9.5% as of September 30, 2022; (b) our initial option to pay interest in additional PIK notes for a period of 18 months was increased to 48 months (the entire term of the Convertible Notes); (c) the effective conversion price of $5.07 per share (197.23866 shares of common stock per $1,000 principal amount of Convertible Notes) was decreased to $4.51 per share (221.72949 shares of Common Stock per $1,000 principal amount of Convertible Notes); (d) the issuance by us of up to $7.5 million of additional Convertible Notes, if and when issued by us; and (e) the issuance of additional shares of common stock upon conversion of Convertible Notes in connection with a Qualified Merger Conversion (as defined in the Indenture) 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 for shares of ICD common stock at any time after issuance through maturity. The conversion price is $4.51 per share. Interest on the Convertible Notes is due on March 31 and September 30 each year, beginning on September 30, 2022. 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.

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The Indenture includes a mandatory redemption offer requirement (the “Mandatory Offer Requirement”). Beginning June 30, 2023, we are 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. The Indenture also includes an optional redemption right (the “Company Redemption Right”) that permits us to redeem on one or more occasions during the period beginning September 19, 2022 and ending September 19, 2023, up to $25 million aggregate principal amount of notes at redemption price of 104% of par, plus accrued and unpaid interest. The Mandatory Offer Requirement is reduced by the amount of any Convertible Notes repurchased pursuant to our Redemption Right. 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.

The Indenture contains financial covenants, including a liquidity covenant of $10.0 million beginning September 30, 2022; 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 $25.0 million during 2022 and $15.0 million during 2023 and 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. During 2022, the holders of our Convertible Notes consented to capital expenditure adjustments under this covenant aggregating $10.6 million and have consented to $16.9 million of capital expenditures in February 2023. The Indenture also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments, 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, 2022.

On February 24, 2023, we entered into a Second Supplemental Indenture relating to our Convertible Notes. The Second Supplemental Indenture (i) amends the Indenture to permit notice communications to a noteholder to be provided electronically at the election of a noteholder, (ii) amends the definition of “Redemption Multiplier” with respect to any Redemption Date from 1.04 to 1.08 and (iii) amends Section 3.08 and Schedule 3.08 of the Indenture to clarify procedures and obligations with respect to the information sharing requirements under the Indenture. The Second Supplemental Indenture was entered into in connection with a consent from the Required Holders regarding an increase in the Capex Adjustment under the Indenture for fiscal year 2023 in an amount equal to $16.9 million. Such consent was given pursuant to Section 3.39 of the Indenture and relates to capital expenditures committed to during 2023 for (i) planned maintenance capital expenditures and other miscellaneous items, (ii) tubular purchases and modifications, and (iii) completion costs relating to reactivation of our 21st drilling rig.

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

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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 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, we recognized a loss on the extinguishment of debt of approximately $46.3 million. This is 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 a 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 are recorded as a direct deduction from the Convertible Notes in the consolidated balance sheet. The debt discount is 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, 2022 is 22.1%. For the year ended December 31, 2022, the contractual interest expense was $18.5 million; the amortization of the debt discount was $4.9 million; and the amortization of the issuance costs was $1.8 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

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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. Accordingly, through June 8, 2022, we recognized a loss of $4.3 million for the change in fair value of the embedded derivative, and reclassified to stockholders’ equity $69.2 million representing the fair value of the conversion rate feature derivative liability on our balance sheet, as the conversion rate feature now met the criteria to be classified in equity, and recognized a gain on extinguishment of derivative liability of $10.8 million on our consolidated statement of operations associated with the PIK interest rate feature of the derivative liability. 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 (b) 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 years ended December 31, 2022 and 2021, we elected to PIK interest of $3.2 million and $5.9 million, respectively, 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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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, 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, 2022.

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 Term Priority Collateral, and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries. As of December 31, 2022, the weighted-average interest rate on our borrowings was 13.30%. As of December 31, 2022, the borrowing base under our Revolving ABL Credit Facility was $33.1 million, and we had $21.3 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 Policies and 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

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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.

Asset impairment expense was $0.4 million and $0.8 million for the years ended December 31, 2022 and 2021, respectively.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal and state tax jurisdictions. 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. Estimates of future taxable income are used to determine the ability to utilize NOL carryforwards, which make up a significant amount of our deferred tax assets.

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.

The accruals for deferred tax assets and liabilities are often based on uncertain tax positions and assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. As of December 31, 2022, our uncertain tax positions were zero; however, material changes to our income tax accruals may occur in the future should we incur any audits or changes in legislation.

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

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 June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments, as additional guidance on the measurement of credit losses on financial instruments. The new guidance requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions and reasonable supportable forecasts. In addition, the guidance amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The new guidance is effective for all public companies for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. In October 2019, the FASB approved a proposal which grants smaller reporting companies additional time to implement FASB standards on current expected credit losses (CECL) to January 2023. As a smaller reporting company, we will defer adoption of ASU No. 2016-13 until January 2023. We do not expect the standard to have a material impact on our consolidated financial statements.

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In August 2020, the FASB issued ASU No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, to simplify the accounting for convertible instruments by removing certain separation models in Subtopic 470-20, Debt-Debt with Conversion and Other Options, for convertible instruments. The pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. For smaller reporting companies the pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2023. We early adopted this standard on January 1, 2022. See Note 8 “Long-term Debt” for additional information.

In May 2021, the FASB issued ASU No. 2021-04, Earnings Per Share (Topic 260), Debt – Modifications and Extinguishments (Subtopic 470-50), Compensation – Stock Compensation (Topic 718), and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options, which clarifies that issuers should account for modifications and exchanges of freestanding equity-classified written call options that remain equity-classified after these transactions as an exchange of the original instrument for a new instrument. The pronouncement is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We adopted this guidance on January 1, 2022 and there is no impact on our consolidated financial statements.

In September 2022, the FASB issued ASU 2022-04, Liabilities - Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations. This guidance requires a business entity operating as a buyer in a supplier finance agreement to disclose qualitative and quantitative information about its supplier finance programs. This ASU does not affect the recognition, measurement or financial statement presentation of obligations covered by supplier finance programs. This guidance is effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on rollforward information, which is effective for fiscal years beginning after December 15, 2023, with early adoption permitted. The adoption of this guidance will result in additional disclosures relating to our supplier financing programs and related obligations.

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derivatives and required bifurcation in accordance with Accounting Standards Codification 815, Derivatives and Hedging. The fair value of the embedded derivatives was approximately $75.7 million at the time of issuance and were recorded as a derivative liability on the Company’s consolidated balance sheet.

We identified the valuation of the Convertible Senior Notes and embedded derivatives as a critical audit matter because of the complexity of the valuation models and the judgements made by management in estimating the fair value of the Convertible Senior Notes and embedded derivatives. The valuation models used in determining the fair value of the Convertible Senior Notes and embedded derivatives include inputs subject to management's judgment. Specifically, management’s estimate of equity volatility and the credit adjusted spread. This required subjective auditor judgment and an increased level of effort when performing audit procedures, including the involvement of valuation professionals with specialized skills and knowledge.

The primary procedures we performed to address this critical audit matter included:

/s/ BDO USA, LLP

We have served as the Company’s auditor since 2015.

Houston, Texas

March 6, 2023

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

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

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

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

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Independence Contract Drilling, Inc.

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accrued interest to prior equity holders of Sidewinder Drilling LLC, and for working capital purposes. 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 an initial payment in-kind, or “PIK,” interest rate of SOFR plus 14.0% through September 30, 2022. The PIK interest rate decreased to SOFR plus 9.5% as of September 30, 2022.

We have the right at our option, to PIK Convertible Note interest for the entire term of the Convertible Notes. We elected to PIK outstanding interest as of September 30, 2022, resulting in an additional $12.7 million principal amount of Convertible Notes being issued as of that date. We have accrued $5.8 million of interest related to the Convertible Notes as of December 31, 2022. The next interest due date is March 31, 2023 and we have elected to pay this interest in-kind when due on March 31, 2023. As the PIK interest due as of March 31, 2023 will result in the issuance of additional Convertible Notes, we have classified the accrued interest as of December 31, 2022 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 our common stock 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. 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. See Note 8 “Long-term Debt” for additional information.

Derivatives

We do not use derivative instruments to hedge exposures to cash flow, market, or foreign currency risks. We evaluate all of our financial instruments to determine if such instruments are derivatives or contain features that qualify as embedded derivatives, pursuant to ASC 480, Distinguishing Liabilities from Equity, and ASC 815, Derivatives and Hedging (“ASC 815”). The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is re-assessed at the end of each reporting period. All derivative instruments are measured at fair value.

As described in Note 8, we determined that certain features under our Convertible Notes required bifurcation from the debt host agreement in accordance with ASC 815 as of March 18, 2022. Accordingly, we recognized a derivative liability at fair value for this instrument in our consolidated balance sheet and adjusted the carrying value of the liability to fair value at each reporting period until the features underlying the instrument were exercised, redeemed, cancelled or expired. The changes in fair value were assessed quarterly and recorded in our consolidated statement 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. Accordingly, through June 8, 2022, we recognized a loss of $4.3 million for the change in fair value of the embedded derivative, and reclassified to stockholders’ equity $69.2 million representing the fair value of the conversion rate feature derivative liability on our balance sheet, as the conversion rate feature now met the criteria to be classified in equity, and recognized a gain on extinguishment of derivative liability of $10.8 million on our consolidated statement of operations associated with the PIK interest rate feature of the derivative liability. See Financial Instruments and Fair Value in Note 2 “Summary of Significant Accounting Policies” for additional information.

Asset Impairment, net and Assets Held for Sale

During the fourth quarter of 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.

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During 2021, we impaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries. During the third quarter of 2021, we initiated a plan to sell miscellaneous drilling equipment. Accordingly, we impaired the drilling equipment to fair market value less cost to sell and recorded asset impairment expense of $0.5 million in our consolidated statements of operations and recorded assets held for sale of $50.0 thousand on our consolidated balance sheet. These assets were sold in the fourth quarter of 2021.

ATM Offering

In conjunction with the ATM Distribution Agreement entered into on August 19, 2021, our board of directors authorized the sale of $5.9 million and $6.5 million in December 2021 and May 2022, respectively, of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” We sold shares under this program during the first quarter of 2022 and raised gross proceeds of $3.6 million. We did not participate in this program in the second, third or fourth quarter of 2022. As of December 31, 2022, we have $8.8 million remaining availability under this ATM program.

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

Accounts receivable is comprised primarily of amounts due from our customers for contract drilling services. Accounts receivable are reduced to reflect estimated realizable values by an allowance for doubtful accounts based on historical collection experience and specific review of current individual accounts. Receivables are written off when they are deemed to be uncollectible. Allowance for doubtful accounts was zero as of December 31, 2022 and 2021, respectively.

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.

Property, Plant and Equipment, net

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 of property and equipment requires us to make various assumptions when the assets are acquired or placed into service about the expected usage, normal wear and tear and the extent and frequency of maintenance programs. Major overhauls and upgrades are capitalized and depreciated over their useful life. The cost of maintenance and repairs are expensed as incurred.

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

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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. We currently have six such field locations.

Additionally, we lease office space for our corporate headquarters in northwest Houston. 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.

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. 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. For further discussion, see Asset Impairments in Note 1 “Nature of Operations and Recent Developments.”

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:

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, 2022 and our Term Loan and our Revolving ABL Facility as of December 31, 2021. The fair value of cash and cash equivalents, accounts receivable, accounts payable and certain accrued liabilities, which are determined to be Level 1 measurements, approximate their carrying value because of the short-term nature of these instruments.

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The estimated fair value of our Revolving ABL Credit Facility, Term Loan Facility, and merger consideration payable to an affiliate are determined to be Level 3 measurements 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, we utilized a credit spread of 493 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. The following table sets forth the estimated fair value of our Revolving ABL Credit Facility, Term Loan Facility and merger consideration payable to an affiliate as of December 31, 2022 and 2021.

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The fair value of the Convertible Notes was estimated as $159.2 million as of December 31, 2022. The fair value of the Convertible Notes is also determined to be a Level 3 measurement and was estimated using a binomial lattice model. The factors used to determine fair value are subject to management's judgement and expertise and include, but are 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.

Recurring Fair Value Measurements

As described in Note 8, we determined that certain features under our Convertible Notes required bifurcation from the debt host agreement in accordance with ASC 815. Accordingly, we recognized a derivative liability at fair value for this instrument in our consolidated balance sheet and adjusted the carrying value of the liability to fair value at each reporting period until the features underlying the instrument were exercised, redeemed, cancelled or expired. The changes in fair value were assessed quarterly and recorded in our consolidated statement of operations.

In conjunction with the issuance of the Convertible Notes on March 18, 2022, we recorded an embedded derivative liability of $75.7 million.

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. Accordingly, through June 8, 2022, we recognized a loss of $4.3 million for the change in fair value of the embedded derivative, and reclassified to stockholders’ equity $69.2 million representing the fair value of the conversion rate feature derivative liability on our balance sheet, as the conversion rate feature now met the criteria to be classified in equity, and recognized a gain on extinguishment of derivative liability of $10.8 million on our consolidated statement of operations associated with the PIK interest rate feature of the derivative liability. As of December 31, 2022 and December 31, 2021, we had no embedded derivative liability recorded.

The loss associated with the change in the fair value of the embedded derivative as of June 8, 2022 is reported in our consolidated statement of operations within change in fair value of embedded derivative liability. The fair value of the embedded derivative liability as of June 8, 2022 was estimated using a “with and without” approach:

•“With” scenario: the fair value of the Convertible Notes as of the valuation date is estimated based on a binomial lattice model.

•“Without” scenario: the fair value of the Convertible Notes “without” the embedded features was estimated using a discounted cash flow model whereby the expected cash flows absent the embedded derivative (i.e., the coupon and principal payments) are discounted at a credit-adjusted rate.

The significant unobservable inputs that were used in the fair value measurement of our embedded derivative liability were a volatility rate of 58.9%, a credit spread of 3,570 basis points and a risk-free rate of 3.0%. The expected

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volatility was estimated based on the historical volatility of our common stock and the remaining term of the Convertible Notes of 3.7 years as of June 8, 2022.

There were no transfers between fair value measurement levels during the years ended December 31, 2022, or 2021.

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.

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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.

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

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments, as additional guidance on the measurement of credit losses on financial instruments. The new guidance requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions and reasonable supportable forecasts. In addition, the guidance amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The new guidance is effective for all public companies for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. In October 2019, the FASB approved a proposal which grants smaller reporting companies additional time to implement FASB standards on current expected credit losses (CECL) to January 2023. As a smaller reporting company, we will defer adoption of ASU No. 2016-13 until January 2023. We do not expect the standard to have a material impact on our consolidated financial statements.

In August 2020, the FASB issued ASU No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, to simplify the accounting for convertible instruments by removing certain separation models in Subtopic 470-20, Debt-Debt with Conversion and Other Options, for convertible instruments. The pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. For smaller reporting companies the pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2023. We early adopted this standard on January 1, 2022. See Note 8 “Long-term Debt” for additional information.

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In May 2021, the FASB issued ASU No. 2021-04, Earnings Per Share (Topic 260), Debt – Modifications and Extinguishments (Subtopic 470-50), Compensation – Stock Compensation (Topic 718), and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options, which clarifies that issuers should account for modifications and exchanges of freestanding equity-classified written call options that remain equity-classified after these transactions as an exchange of the original instrument for a new instrument. The pronouncement is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We adopted this guidance on January 1, 2022 and there is no impact on our consolidated financial statements.

In September 2022, the FASB issued ASU 2022-04, Liabilities - Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations. This guidance requires a business entity operating as a buyer in a supplier finance agreement to disclose qualitative and quantitative information about its supplier finance programs. This ASU does not affect the recognition, measurement or financial statement presentation of obligations covered by supplier finance programs. This guidance is effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on rollforward information, which is effective for fiscal years beginning after December 15, 2023, with early adoption permitted. The adoption of this guidance will result in additional disclosures relating to our supplier financing programs and related obligations.

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 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

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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.