ICD Independence Contract Drilling, Inc. - 10-K

ITEM 1A.      RISK FACTORS

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

Key Risks Related to Our Business and Operations

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

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

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

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

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

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

available pipeline and other oil and natural gas transportation capacity;

the levels of oil and natural gas storage;

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

economic conditions in the United States and elsewhere;

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

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

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

domestic and foreign tax policy;

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

weather conditions in the United States;

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

the price of foreign imports of oil and natural gas;

the strength or weakness of the United States dollar;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Legal and Regulatory Risks

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

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

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

Legal proceedings could have a negative impact on our business.

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

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

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

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

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

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

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

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

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

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

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

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

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Risks Related to Our Liquidity

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

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

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

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

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

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

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

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

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

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

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

incur or guarantee additional indebtedness;

make loans to others;

make investments;

merge or consolidate with another entity;

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

make certain payments and capital expenditures;

create or incur liens;

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

pay cash dividends;

enter into certain transactions with affiliates; and

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Increases in interest rates could adversely affect our business.

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

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

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

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

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Risks Related to our Common Stock

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

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

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

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

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

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

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

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

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

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

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

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

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

General Risk Factors

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

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

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

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

The effects of severe weather could adversely affect our operations.

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

Information technology failures and cybersecurity breaches could harm our business.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Management Overview

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

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

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

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

Significant Developments

Market Conditions

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

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

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Asset Impairment, net

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

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

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

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

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

Our Revenues

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

Our Operating Costs

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

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

How We Evaluate our Operations

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

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

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

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

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

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

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Results of Operations

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

Year Ended

(In thousands, except per share data)

Revenues

Costs and expenses

Operating costs

Selling, general and administrative

Depreciation and amortization

Asset impairment, net

Loss (gain) on disposition of assets, net

Other expense

Total cost and expenses

Operating loss

Interest expense

Loss on extinguishment of debt

Change in fair value of embedded derivative liability

Realized gain on extinguishment of derivative

Loss before income taxes

Income tax benefit

Net loss

Other financial and operating data

Number of marketed rigs (end of period)

Rig operating days (1)

Average number of operating rigs (2)

Rig utilization (3)

Average revenue per operating day (4)

Average cost per operating day (5)

Average rig margin per operating day

Oil price per Bbl (6) (end of year)

Natural gas price per Mcf (7) (end of year)

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

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

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

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

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

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

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

Comparison of the years ended December 31, 2023 and 2022

Revenues

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

Operating Costs

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

Selling, General and Administrative Expenses

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

Depreciation and Amortization

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

Asset Impairment, net

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

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Loss (Gain) on Disposition of Assets, net

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

Interest Expense

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

Loss on Extinguishment of Debt

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

Change in Fair Value of Embedded Derivative Liability

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

Realized Gain on Extinguishment of Derivative

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

Income Tax Benefit

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

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

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

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

Liquidity and Capital Resources

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

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

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

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

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

Contractual Obligations

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

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

(in thousands)

Total

Convertible Notes

Mandatory Offering on Convertible Notes

Interest on Convertible Notes

ABL Credit Facility

Interest on ABL Credit Facility

Finance leases

Purchase obligations

Total contractual obligations

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

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

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

Cash Flows

Year Ended December 31,

(in thousands)

Net cash provided by operating activities

Net cash used in investing activities

Net cash (used in) provided by financing activities

Net increase in cash and cash equivalents

Net Cash Provided By Operating Activities

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

Net Cash Used In Investing Activities

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

Net Cash (Used In) Provided By Financing Activities

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

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

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

Long-term Debt

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

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

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

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

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

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

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

Upon a Qualified Merger (defined below), we may elect to convert all, but not less than all, of the Convertible Notes at a Conversion Rate equal to our Conversion Rate on the date on which the relevant “Qualified Merger” is consummated (a “Qualified Merger Conversion”), so long as the “MOIC Condition” is satisfied with respect to such potential Qualified Merger Conversion. A “Qualified Merger” means a Common Stock Change Event consolidation, merger, combination or binding or statutory share exchange of the Company with a Qualified Acquirer. A “Qualified Merger Conversion Date” means the date on which the relevant Qualified Merger is consummated. A “Qualified Acquirer” means any entity that (i) has its common equity listed on the New York Stock Exchange, the NYSE American, Nasdaq Global Market or Nasdaq Global Select Market, or Toronto Stock Exchange, (ii) has an aggregate equity market capitalization of at least $350 million, and (iii) has a “public float” (as defined in Rule 12b-2 under the Securities Act of 1933) of at least $250 million in each case, as determined by the calculation agent based on the last reported sale price of such common equity on date of the signing of the definitive agreement in respect of the relevant Common Stock Change Event. A “Common Stock Change Event” means the occurrence of any: (i) recapitalization,

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

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

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

Embedded Derivative Liability

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

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

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

Term Loan Facility

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

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

Revolving ABL Credit Facility

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

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

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,

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

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

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

Critical Accounting Estimates

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

Property, Plant and Equipment

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

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

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

Other Matters

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

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

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

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