EDGAR 10-K Filing

Company CIK: 1537028
Filing Year: 2022
Filename: 1537028_10-K_2022_0001537028-22-000007.json

---

ITEM 1. BUSINESS
ITEM 1. BUSINESS
Overview
Except as expressly stated or the context otherwise requires, the terms “we,” “us,” “our,” the “Company” and “ICD” refer to Independence Contract Drilling, Inc. and its subsidiary.
We were incorporated in Delaware on November 4, 2011. We provide land-based contract drilling services for oil and natural gas producers targeting unconventional resource plays in the United States. We own and operate a premium fleet comprised of modern, technologically advanced drilling rigs.
Our rig fleet includes 24 marketed pad-optimal, superspec AC powered (“AC”) rigs plus additional AC rigs that require significant capital expenditures in order to meet our AC pad-optimal specifications that we do not plan to market absent material improvement in market conditions. 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, the Haynesville Shale and the Eagle Ford Shale; however, our rigs have previously operated in the Mid-Continent and Eaglebine regions as well.
Our business depends on the level of exploration and production activity by oil and natural gas companies operating in the United States, and in particular, the regions where we actively market our contract drilling services. The oil and natural gas exploration and production industry is historically cyclical and characterized by significant changes in the levels of exploration and development activities. Oil and natural gas prices and market expectations of potential changes in those prices significantly affect the levels of those activities. Worldwide political, regulatory, economic and military events, as well as natural disasters have contributed to oil and natural gas price volatility historically, and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities in the United States and the regions where we market our contract drilling services, whether resulting from changes in oil and natural gas prices or otherwise, could materially and adversely affect our business.
Our principal executive offices are located at 20475 Hwy 249, Houston, Texas 77070. Our common stock is traded on the NYSE under the symbol “ICD.”
Industry Trends
Land Rig Replacement Cycle
The increase in horizontal drilling in the United States over the past fifteen years has resulted in an ongoing land-rig replacement cycle in which the contract drilling industry is systematically upgrading its legacy fleets of electrical silicon-controlled rectifier (“SCR”) rigs and mechanical rigs with modern AC rigs that are specifically designed to optimize this type of drilling activity. Additionally, a growing focus on horizontal drilling of longer-reach lateral wells from multi-well pads is driving a further delineation in the United States land rig fleet between pad-optimal rigs specifically designed and engineered for such applications and AC and legacy rigs not specifically engineered for such applications.
The following describes the three different types of rig drives:
Mechanical Rigs. Mechanical rigs were not designed and are not well suited for the demanding requirements of drilling horizontal wells. A mechanical rig powers its systems through a combination of belts, chains and transmissions. This arrangement requires the rig to be rigged up with precise alignment of the belts and chains, which requires substantial time during a rig move. In addition, mechanical power loading of key rig systems, including drawworks, pumps and rotating equipment results in very imprecise control of system parameters, causing lower drill bit life, lower rate of penetration and difficulty maintaining wellbore trajectory.
SCR Rigs. In contrast to mechanical rigs, SCR rigs rely on direct current, or DC, to power the key rig systems. Load is changed by adjusting the amperage supplied to electric motors powering key rig systems. While a substantial improvement over mechanical belts and chains, SCR control is imprecise, and DC power levels normally drift resulting in fluctuations in pump speed and pressure, bit rotation speed, and weight on bit. These fluctuations can cause wellbore deviation, shorter bit life and less optimal rates of penetration. In addition, SCR equipment is heavy and energy inefficient.
AC Rigs. Compared to SCR and mechanical rigs, AC rigs are ideally suited for drilling horizontal wells. The first AC rigs were introduced into the United States land market in the early 2000s, and since that time their use has grown significantly as the use of horizontal drilling has increased. AC rigs use a computer-controlled variable frequency drive ("VFD") to precisely adjust key rig operating parameters and systems allowing for optimization of the rate of penetration, extended bit life and improved control of wellbore trajectory. These factors reduce the amount of time a wellbore is “open hole,” or uncased. Shorter open hole times dramatically reduce adjacent formation damage that can be caused by shale hydration or drilling fluid invasion and enhance the operator’s ability to optimally run and cement casing to complete the drilled well. In addition, when compared to SCR and mechanical rigs, AC rigs are electrically more efficient, produce more torque, utilize regenerative braking, and have digital controls. AC motors are also smaller, lighter and require less maintenance than DC motors.
Shift to Manufacturing Wellbore Model
As a result of significant investments made in unconventional resource plays, exploration and production ("E&P") companies are now focused on developing these investments in a systematic manner. Efficient development of these resource plays involves drilling programs requiring large numbers of wells to be drilled in succession, as opposed to a single or a few wells designed to delineate a field or hold a lease. We view this as analogous to a manufacturing process that requires an engineered program and is focused on economies of scale to reduce overall field development costs. Cost-effective development drilling requires more complex well designs, shorter cycle times, and the use of innovative technology in order to reduce an E&P company’s overall field development costs.
One method in which an E&P operator may reduce overall field development costs is through the use of a multi-well pad development program. Pad drilling involves the drilling of multiple wells from a single location, which provides benefits to the E&P company in the form of per well cost savings and accelerated cash flows as compared to non-pad developments. These cost savings result from reduced time required to move the rig between wells, centralized hydraulic fracturing operations and the efficient installation of central production facilities and pipelines. In addition, by performing drilling operations on one well with simultaneous completion operations on a second well, operators do not have to wait until the entire pad is complete to begin earning a return on their investment. Pad drilling promotes “manufacturing” efficiencies by enabling “batch” drilling, whereby an operator drills all of the wells’ surface holes as the first batch, then drills all of the intermediate sections as the second batch, and concludes with the drilling of all of the laterals as the final batch. Efficiencies are created because hole sizes change less frequently, and operators use the same mud system and tools repeatedly. We believe as operators have shifted over time to horizontal drilling, they have implemented pad drilling in order to maximize economics and optimize development plans. In order to maximize the efficiencies gained from pad drilling, a rig must be capable of moving quickly from one well to another and be able to address the complexities associated with the growing number of wells per pad. In addition to quickly moving from well to well, omni-directional walking systems are ideally suited for pad drilling because they are capable of efficiently addressing situations on a pad in which wellbores are not precisely aligned or when level variations exist on the pad, which becomes increasingly likely as pads become larger and more complex.
Another method utilized by operators to increase efficiencies and maximize well economics is the drilling of longer lateral horizontal wells. Operators in our target areas have continued to increase the lateral length of their horizontal wells. Longer laterals provide greater production zones as the portion of the wellbore that passes through the target formation increases, optimizing the impact of hydraulic fracturing and stimulation. The drilling of longer laterals necessitates the use of increased horsepower drawworks and top drive systems, which provide maximum torque and rotational control and allows the operator to maintain the integrity of its drilling plan throughout the wellbore. Additionally, higher pressure mud pumps are required to pump fluids through significantly longer wellbores. The competitive advantage of higher pressure mud pumps grows as the lateral length increases, as only high pressure pumps
can effectively address the severe pressure drop, while providing the required hydraulic horsepower at the bit face and sufficient flow to remove drill cuttings and keep the hole clean.
Super-Spec, Pad Optimal Equipment
Cost-effective development drilling in a manufacturing wellbore model requires more complex well designs, shorter cycle times, and the use of innovative technology in order to reduce an E&P company’s overall field development costs. Drilling rigs that are designed to maximize drilling efficiency, reduce cycle times, maximize energy efficiency, increase penetration rates while drilling, and drill longer-reach horizontal wells will reduce an E&P company’s overall field development costs and provide them with greater optionality when designing their field development program.
We believe that E&P companies drilling horizontal wells increasingly demand not only AC rigs that are optimal for horizontal drilling, but premium Super-Spec, Pad Optimal AC rigs such as our ShaleDriller rigs. All of our marketed drilling fleet is comprised of Super-Spec, Pad Optimal rigs. The following describes the minimum characteristics of a super-spec, pad optimal rig:
● AC Programmable. AC rigs use a variable frequency drive that allows precise computer control of motor speed during operations. This greater control of motor speed provides more precise drilling of the wellbore. Among other attributes, when compared to electrical SCR rigs and mechanical rigs, AC rigs are electrically more efficient, produce consistent torque, utilize regenerative braking, and have digital controls and AC motors that require less maintenance. AC rigs allow our customers to drill faster, which, in general, eliminates reservoir permeability damage, and to drill wellbores that more precisely track planned trajectories without doglegs. This, in turn, minimizes open hole time and enables our customers to more effectively and efficiently run casing, cement and successfully complete their wells.
● Pad Optimized, Omni-Directional Walking System. Omni-directional walking systems are designed to optimize pad drilling economics for our customers. Pad drilling involves the drilling of multiple wells from a single location, which provides benefits to the E&P company in the form of cost savings and accelerated cash flows. Our walking rigs move in any direction quickly between wellheads, rapidly and efficiently adjust to misaligned wellbores, walk over raised wellheads, and increase operational safety due to fewer required rig up and rig down movements.
● Efficient Mobilization Between Drilling Sites. A rig that can rapidly move between drilling sites has become increasingly desired by, and impactful to, E&P companies because it reduces cycle times allowing them to drill more wells in the same period of time. Our ShaleDriller rigs move rapidly on conventional rig moves between drilling sites.
● 1500-HP Drawworks. 1500-HP drawworks are well suited for the development of the vast majority of our customers’ unconventional resource assets. Compared to a 1000-HP or smaller rig, a 1500-HP rig has superior capability to handle extended drill string lengths required to drill long horizontal wells, which are becoming more common in the markets we serve.
● 7500psi Mud Systems. The drilling of longer laterals necessitates the use of higher-pressure mud pumps to pump fluids through significantly longer wellbores. The competitive advantage of higher-pressure mud pumps grows as the lateral length gets longer, as only high pressure pumps can effectively address the severe pressure drop while providing the required hydraulic horsepower at the bit face and sufficient flow to remove drill cuttings and keep the hole clean. All of our ShaleDriller rigs are equipped with 7500psi mud systems.
● Other. 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 three simultaneously operating mud pumps powered by a fourth engine when greater hydraulic flow and pressure is required, greater setback capacity allowing efficient drilling of ultra-long horizontal laterals, or increased hookload when utilizing larger casing strings in combination with
deeper wells. Our ShaleDriller fleet is capable of providing all of these varying equipment packages depending upon our customer’s requirements.
Customer Contracts and Backlog
Drilling contracts are obtained through competitive bidding or as a result of negotiations with customers, and may cover multi-well and multi-year projects. Each of our rigs operates under a separate drilling contract or drilling order subject to a master drilling contract. We perform drilling services on a “daywork” contract basis, under which we charge a specified rate per day. The dayrate under each of our contracts is a negotiated price determined by the location, depth and complexity of the wells to be drilled, operating conditions, the duration of the contract, and market conditions. We have not accepted, and do not anticipate entering into, any “turn-key” (fixed sum to deliver a hole to a stated depth) or “footage” (fixed rate per foot of hole drilled) contracts. The duration of land drilling contracts can vary from “well-to-well” or to a fixed term ranging from a few months to several years. The revenue generated by a rig in a given year is the product of the dayrate fee and the number of days the rig is earning this fee based on activity and the terms of the contract, referred to as utilization. “Well-to-well” contracts are typically cancelable at the option of either party upon the completion of drilling at a particular site. Fixed-term contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to the drilling contractor if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, the drilling contractor’s bankruptcy, sustained unacceptable performance by the drilling contractor or delivery of a rig beyond certain grace and/or liquidated damage periods, no early termination payment would be paid to the drilling contractor. Drilling contracts also contain provisions regarding indemnification against certain types of claims involving injury to persons, property and for acts of pollution, which are subject to negotiation on a contract-by-contract basis.
Under a typical daywork contract, we earn a dayrate fee while the rig is operating, and we earn a moving rate fee while the rig is moving between wells or drilling locations under the contract. If the rig is on standby or is not drilling due to a force majeure event unrelated to damage to the rig, contracts typically provide that we earn a rate during this period of time, which rate may be equal to or less than the operating rate.
Mobilization rates are determined by market conditions and are generally reimbursed by the customer. In most instances, contracts typically provide for additional payments associated with the initial mobilization of a drilling rig and, in certain circumstances, we receive a demobilization fee at the end of the contract term equal to the estimated cost to transport the rig from the final drilling location and to compensate us for the estimated demobilization time.
Drilling contracts typically provide that the contractor continues to earn the operating dayrate while a rig is not operating but under repair or maintenance, so long as the non-operating time due to repair and maintenance does not exceed a specified number of hours in a given day or calendar month.
Currently, most of our drilling rigs are operating on pad-to-pad contracts. This strategy allows us to more rapidly increase contracted dayrates in an improving dayrate market, but has resulted in a reduction of our reported contract backlog of term contracts compared to historical levels prior to the beginning of the COVID-19 pandemic in early 2020. As of December 31, 2021, our backlog of term contracts with original terms of six months or more was $16.1 million, all of which is expected to be realized during 2022. Our backlog does not include potential reductions in rates for unscheduled standby during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of contractually allowed downtime. It also does not include increases in rates for the billing of ancillary “adders” under the contract. In addition, rigs under term contracts may realize revenue on a standby-without-crew basis, which allows us to preserve our expected cash margins from the contract but reduces our overall top line revenue. To the extent that we have rigs under term contracts operating on a standby or standby-without-crew basis, our top line revenues will be less than our reported backlog from term contracts.
Our Customers
Customers for contract drilling services in the United States include major oil and natural gas companies, independent oil and natural gas companies, as well as numerous small to mid-sized publicly-traded and privately held oil and natural gas companies. We market our contract drilling services to all such customers. During 2021, our customers
representing more than 10% of our revenues were Indigo Minerals, LLC, a subsidiary of Southwestern Energy Company, and Endeavor Energy Resources.
Industry/Competition
To a large degree, our business depends on the level of capital spending by oil and natural gas companies for exploration, development and production activities. A sustained increase or decrease in the price of oil and natural gas could have a material impact on the exploration, development and production activities of our customers and could materially affect our financial position, results of operations and cash flows.
The contract drilling industry is highly competitive and has become even more so under current market conditions. The price for contract drilling services is a key competitive factor in the United States land contract drilling markets, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe the principal competitive factors in our markets are availability and condition of equipment, efficiency of equipment, quality of personnel, service quality, experience and safety record.
Many of our competitors are larger, publicly-held corporations with significantly greater resources and longer operating histories than us. Our largest competitors for high-end AC land drilling contract services are Helmerich & Payne, Inc., Patterson-UTI Energy, Inc., Nabors Industries, Ltd. and Precision Drilling Corporation.
Many of our larger competitors are able to offer ancillary products and services with their contract drilling services, and recently, some of our larger competitors have begun integrating and offering contract drilling services in connection with directional drilling and other services that we do not offer.
Government and Environmental Regulation
All of our operations and facilities are subject to numerous federal, state and local laws, rules and regulations related to various aspects of our business, including:
● drilling of oil and natural gas wells;
● the relationships with our employees;
● containment and disposal of hazardous materials, oilfield waste, other waste materials and acids; and
● use of underground storage tanks.
To date, we do not believe such rules and regulations, including applicable environmental laws and regulations, in the United States have required the expenditure by the contract drilling industry of significant resources outside the ordinary course of business. However, compliance costs under existing laws or under any new requirements could become material, and we could incur liability in any instance of noncompliance.
Our business is generally affected by political developments and by federal, state and local laws and regulations that relate to the oil and natural gas industry. The adoption of laws and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling and production, and otherwise have an adverse effect on our operations. Federal, state and local environmental laws and regulations currently apply to our operations and may become more stringent in the future. On January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. Any suspension or moratorium of the services we provide, whether or not short-term in nature, by a federal, state or local governmental authority, could have a material adverse effect on our business, financial condition and results of operation.
In the United States, the federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended (“CERCLA”), and comparable state statutes impose liability, without regard to fault or legality of
conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment. These persons include:
● current and past owners and operators of the site where the release occurred, and
● persons who disposed of or arranged for the disposal of “hazardous substances” released at the site.
Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA excludes certain classes of exploration and production wastes from regulation as hazardous waste under Subtitle C of RCRA, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.
The federal Water Pollution Control Act, as amended, also known as the Clean Water Act, and the Oil Pollution Act of 1990, as amended (the “Oil Pollution Act”), and analogous state laws and their respective implementing regulations govern:
● the prevention of discharges of pollutants, including oil and produced water spills, into waters of the United States; and
● liability for drainage into waters of the United States.
The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Administrative, civil or criminal penalties may also be imposed for violation of federal safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.
The Oil Pollution Act also expands the authority and capability of the federal government to direct and manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or into navigable waters. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to administrative, civil or criminal actions. Although the liability for owners and operators is the same under the federal Water Pollution Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.
Our contract drilling services will be marketed in oil and natural gas producing regions that utilize hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shales. Due to concerns raised relating to potential impacts of hydraulic fracturing on ground water quality and the increased occurrence of seismic activity, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. On January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, effectively limiting hydraulic fracturing on federal lands and waters. Any such efforts to limit or ban hydraulic fracturing could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the contract drilling services that we render for our exploration and production customers.
Our operations are also subject to federal, state and local laws, rules and regulations for the control of air emissions, including the federal Clean Air Act. The federal Clean Air Act, and comparable state laws, regulates emissions of various air pollutants through, for example, air emissions permitting programs. In addition, the Environmental Protection Agency (the "EPA") has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources including the energy extraction sector. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Finally, more stringent federal, state and local regulations, such as the EPA rules issued in April 2012, which add new requirements for the oil and natural gas sector under the New Source Review Program and the National Emission Standards for Hazardous Air Pollutants program, could result in increased costs and the need for operational changes. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.
On December 7, 2009, the EPA announced its findings that emissions of GHG present an “endangerment to human health and the environment.” The EPA based this finding on a conclusion that greenhouse gases are contributing to the warming of the Earth’s atmosphere and other climate changes. The EPA began to adopt regulations that would require a reduction in emissions of greenhouse gases from certain stationary sources and has required monitoring and reporting for other stationary sources. Mandatory reporting requirements for additional regional, federal or state requirements have been imposed and additional requirements may be imposed in the future. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our services. For example, during 2012, the EPA published rules that include standards to reduce methane emissions associated with oil and natural gas production. In May 2016, the EPA finalized regulations that set methane emission standards for new and modified oil and natural gas facilities, including production facilities. However, in September 2020, the EPA issued a final rule that removed the transmission and storage segment from the 2016 new source performance standards, rescinded VOCs and methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. Notwithstanding the current court challenges, on January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent methane emission rulemaking. Currently, our operations are not adversely impacted by existing state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in compliance with these applicable requirements and with other OSHA and comparable requirements.
Additionally, environmental laws such as the federal Endangered Species Act (“ESA”) and the Migratory Bird Treaty Act, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered species. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our customers’ properties may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species or the designation of previously unprotected areas as a critical habitat could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Risks and Insurance
Our operations are subject to the many hazards inherent in the drilling business, including: accidents at the work location; blow-outs; cratering; fires; and explosions. These and other hazards could cause personal injury or death, suspension of drilling operations, damage or destruction of our equipment and that of others, damage to producing formations and surrounding areas, or environmental damage.
Damage to the environment, including property contamination in the form of soil or ground water contamination, could also result from our operations, including through oil or produced water spillage, natural gas leaks, and fires.
We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we may not be fully insured against all risks, either because insurance is not available or because of the high premium costs. Such risks include personal injury, well disasters, extensive fire damage, damage to the environment, and other hazards. The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our rigs and other assets, employer’s liability, automobile liability, commercial general liability insurance and workers compensation insurance. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and other assets, such insurance does not cover the full replacement cost of the rigs or other assets, and we do not carry insurance against loss of earnings resulting from such damage. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on our financial condition and results of operations. Further, we may experience difficulties in collecting from insurers, or such insurers may deny all or a portion of our claims for insurance coverage.
In addition to insurance coverage, we also attempt to obtain indemnification from our customers for certain risks. These indemnities typically require our customers to hold us harmless in the event of loss of production or reservoir damage. There is no assurance that we will obtain such contractual indemnity, and if obtained, whether such indemnity will be enforceable, whether the customer will be able to satisfy such indemnity or whether such indemnity will be supported by adequate insurance maintained by the customer.
If a significant accident or other event occurs and is not fully covered by insurance or is not an enforceable or recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations. See “Risk Factors - Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.”
Human Capital and Sustainability
We work to provide the safest and most efficient contract drilling services in our industry in a manner which protects, develops and rewards people, while striving to protect the environment, providing positive impacts to the communities where we operate, while recognizing the needs of all our stakeholders.
The foundation for our commitment to human capital and sustainability is illustrated in our corporate vision and values and mission statements:
● Vision: Our Vision is to be the leader in Health, Safety & Environment and Operational Excellence while providing services to support North American energy development.
● Mission: Our Mission is to provide the safest and most efficient contract drilling services in our industry.
● Core Values: Our Core Values provide the directions in achieving these objectives: (i) focus on safety, people and the environment; (ii) lead our industry with integrity and pursuit of performance excellence in everything we do; (iii) accountability to all stakeholders including employees, customers, vendors and investors; and (iv) our greatest resource is people.
Human Capital
As of February 28, 2022, we had approximately 500 employees. We believe people are our greatest resource. We are committed to fostering a work environment where all people feel valued and respected. We are committed to recruiting, hiring, training and retaining the highest caliber human talent for our business by utilizing various means including outreach initiatives and partnerships with a diverse group of organizations, industry associations and networks. We require our employees to complete training annually including our commitment to a respectful workplace.
Training and mentoring of our team members are essential to the development of our employees and providing industry leading contract drilling services. Our mentoring programs are designed to assist short-service employees, especially at the floorhand level at the rig site, with adjusting to their new careers with our company and within our industry. Our training programs are designed to create core-competencies and equip our employees for advancement and promotion opportunities. Training is provided through various means including classroom, online and on-the-job training, and competencies must be demonstrated. Adherence to our training requirements and protocols is monitored for each of our field and office employees and is a component of our field-based annual incentive programs. We consider our employee relations to be good. None of our employees are represented by a union.
Safety. The safety of our employees and others is our highest priority at the worksite, and also at home. Our safety programs were built and are maintained by Company employees. The programs undergo annual revalidation. Our safety programs are designed to comply with applicable laws and industry standards and the requirements of our customers. We maintain a robust safety management system whereby all incidents and potential incidents are reported, monitored and root cause analysis and corrective actions are documented and performed when appropriate. All field-based employees are required to follow a structured safety training regimen, including safety orientations, behavior-based safety programs, and programs regarding hazard awareness, 12 ICD life-saving skills, safe systems of work, permission to work, time out for safety, energy isolation, hazard communication and material handling. Safety is a material component of our executive, corporate, and field-based annual incentive compensation programs.
Health and Benefits. For our field employees, we provide third party medical consultation services on a 24-hour / 7-day a week basis in the event of any personal illness, first aid or injury on our work sites. We provide robust health and benefit programs for all of our employees that include an emphasis on preventative care programs.
Environment
We evaluate, pursue and implement efforts to reduce impacts from our operation on air and water quality, land usage, use of energy, and reducing waste materials. For example, our drilling rigs are equipped with dual fuel engines that reduce carbon and greenhouse emissions. Our rigs also are capable of operating on utility electrical power where feasible and we have recently partnered with several operators to equip our drilling rigs to this power source. All of our drilling rigs are designed to be pad optimal, which enables multi-well pad drilling which reduces the number of drilling locations required and thus the environmental impact of the operations. We track spills and employ spill prevention plans and use additional protective measures in our efforts to minimize impacts to the environment.
Social Community Engagement
By focusing on increasing employee engagement, we seek to imprint the feel of community within the Company’s employee base including their families. We utilize social media tools to help increase engagement and also promote a positive image of the Company and our industry. Annually, the Company participates in toy drives and other volunteer efforts to “give back” to the communities where we operate.
Governance
Overall corporate governance oversight is provided by our Board of Directors. All of our employees are required to complete annual training on our Code of Business Conduct and Ethics, which addresses conflicts of interest, confidentiality, fair dealing with others, proper use of company assets, compliance with laws, insider trading, keeping of books and records, zero tolerance for discrimination and harassment in the work environment, as well as reporting of
violations. We maintain reporting mechanisms, including anonymous hotlines, for potential violations of our Code of Business Conduct and Ethics to be reported to our Board of Directors and senior management.
Seasonality
Seasonality has not significantly affected our overall operations. However, our drilling operations can be affected by severe winter storms or other weather-related events. Additionally, toward the end of some years, we experience slower contracting activity as customers’ capital expenditure budgets are depleted.
Drilling Equipment, Suppliers and Subcontractors
We use many suppliers of drilling equipment and services. Although these suppliers, drilling equipment and services have historically been available, there is no assurance that such drilling equipment and services will continue to be available on favorable terms or at all. We also utilize numerous manufacturers and independent subcontractors from various trades to supply key components for our use. These key components include masts and substructures, top drives, high pressure mud pumps, pressure control equipment, engines, and VFD control systems. We believe that we have alternative sources for each of these components.
Website Access to Our Periodic SEC Reports
Our internet address is http://www.icdrilling.com. We file and furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and amendments to these reports, with the Securities and Exchange Commission (the “SEC”), which are available free of charge through our website as soon as reasonably practicable after such reports are filed with or furnished to the SEC. The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding our company that we file and furnish electronically with the SEC.
We may from time to time provide important disclosures to investors by posting them in the investor relations section of our website, as allowed by SEC rules. Information on our website is not incorporated by reference into this Annual Report on Form 10-K and you should not consider information on our website as part of this Annual Report on Form 10-K.

---

ITEM 1A. RISK FACTORS
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
Due to the adverse effects of the COVID-19 pandemic on the oil and gas industry, our operating rig count dropped rapidly, and as a result, we reported negative cash flow from operations during the third and fourth quarters of 2020 and during fiscal 2021. We cannot assure you when we will again generate positive cash flow from operations or that our operating rig count will not decline again. Depending upon the length of time it takes for our operating rig count to improve to pre-COVID levels, this could have a material adverse effect on our business, liquidity, results of operations and financial condition.
During the first quarter of 2020, our operating rig count reached a peak of 22 rigs. It previously had reached a peak of 32 rigs during the fourth quarter of 2018. Market deterioration largely caused by COVID-19 subsequently caused our customers to reduce drilling activity from peak 2020 levels, which resulted in a rapid decline in our operating rig count, reaching a low of three rigs during the third quarter of 2020. We were able to reactivate rigs in late 2020 and throughout 2021 and had 16 rigs operating and 17 rigs under contract as of December 31, 2021. Our 17th operating rig recommenced drilling operations in January 2022. However, even with these improvements, we reported negative cash flow from operations throughout 2021. Due to the lack of visibility and confidence towards customer intentions, we cannot assure you that our rig count will not decline from these year-end levels. We also cannot assure you that market conditions will improve and if or when our operating rig count will improve further or reach pre-COVID-19 levels or if we will report positive cash flow from operations in 2022.
Current sources of liquidity at December 31, 2021 included $4.1 million of cash, $11.3 million of availability under our revolving credit facility, and $11.9 million available under our term loan accordion. We currently believe that these sources of liquidity are sufficient to fund our operations for the next twelve months from the date of filing of this Form 10-K, but this assumes that both our operating rig count and dayrates continue to increase steadily during the first half of 2022 in response to recently improving market conditions. Due to the uncertainty regarding the duration of the COVID-19 pandemic and its effects on the oil and gas industry, we cannot predict if market conditions will continue to improve or when, or if, oil and gas prices and demand for our contract drilling services will return to pre-COVID-19 levels. As a result, we cannot assure that our current sources of financial liquidity will be sufficient to fund our operations, and any failure to do so could have a material adverse effect on our business, liquidity, results of operations and financial condition.
We could lose our listing on the New York Stock Exchange, which could have a material adverse effect on the market value of our common stock.
Under New York Stock Exchange listing requirements, in order to maintain our listing status we are required to maintain at all times a minimum 30-day trading average public 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 December 31, 2021, we estimated that our 30-day average market capitalization was approximately $30.2 million, and has increased to $39.0 million as of March 2, 2022. Because we cannot predict when, or if, demand for our contract drilling services will return to pre-COVID-19 levels, or when, or if, a general decline in the stock market could occur, we cannot assure you that our common stock will remain listed on the New York Stock Exchange, 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.
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 the Organization of Petroleum Exporting Countries;
● political instability in the Middle East and other major oil and natural gas producing regions;
● governmental regulations, sanctions and trade restrictions, both domestic and foreign;
● domestic and foreign tax policy;
● 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;
● 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.
During 2020, the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively “OPEC+”) instituted production cuts in order to support oil prices during the period of reduced demand caused by the COVID-19 pandemic. Recently, OPEC+ has announced modest production increases as global supply-demand fundamentals have become more normalized and oil prices have risen. Although oil prices have recovered from historic 2020 lows, the sustainability of these price levels and adherence by OPEC+ to agreed allocations remains uncertain. Because of this uncertainty, most of our exploration and production (“E&P”) customers have not significantly increased capital expenditure budgets despite substantial improvements in commodity prices. If oil prices were to fall again as a result of prolonged demand destruction caused by the COVID-19 pandemic or increased supply from OPEC+, and remain below $75 per barrel for an extended period, we believe demand for contract drilling services would again soften over current levels, which could have a material adverse effect on our operations and financial condition.
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, 2021, we had rigs operating or earning revenues from nine different customers, including two customers who had contracted four each, or 25%, of our contracted rigs. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a customer decided not to continue to use our services or to terminate an existing contract, or if there is a change of management or ownership of a customer or a material adverse change in the financial condition of one of our customers, 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 2022. 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 2022. We cannot assure that a customer will continue to renew contracts as they expire or that any replacement contract can be obtained for any of our rigs operating in the spot-market or with terms expiring, and if obtained, that it would be on terms as favorable as those of our existing drilling contracts or at profitable levels. The failure to renew or timely replace one or more of our expiring contracts could have a material adverse effect on our results of operations and financial condition.
Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.
Our operations are subject to the many hazards inherent in the drilling and well services industries, including the risks of personal injury and loss of life, blowouts, cratering, fires and explosions, loss of well control, collapse of the borehole, damaged or lost drilling equipment, and damage or loss from extreme weather and natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things, suspension of operations, damage to, or destruction of, our property and equipment and that of others, damage to producing or potentially productive oil and natural gas formations through which we drill, and environmental damage.
Although, we seek to protect ourselves from some but not all operating hazards through insurance coverage, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks
from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance or otherwise have the financial resources necessary to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. We do not carry loss of business insurance for a rig being out of service.
We maintain insurance against some, but not all, of the potential risks affecting our operations and only in coverage amounts and deductible levels that we believe to be economical. Our insurance coverage includes deductibles which must be met prior to recovery. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable. Incurring a liability for which we are not fully insured or indemnified could have a material adverse effect on our financial condition and results of operations.
We operate in a highly competitive industry in which price competition could reduce our profitability.
We encounter substantial competition from other drilling contractors. The competition in the markets in which we operate has intensified as recent mergers among E&P companies have reduced the number of available customers and the downturn in oil prices has decreased demand for drilling rigs and resulted in downward pricing pressure on operating drilling rigs.
As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, results of operations and financial condition. In addition, the failure to maintain an adequate safety record could harm our ability to secure new drilling contracts.
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, 2021, 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 $16.1 million. All of this backlog expires in 2022, which requires us to renew these expiring contracts as well as short term contracts under which a large number of our rigs operate. Although we historically have been successful in obtaining extensions or follow on work for drilling rigs with expiring contracts, in periods of market decline or uncertainty such as the U.S. land contract drilling industry is experiencing, we cannot assure that we will obtain such renewals, or that such renewals will be on terms acceptable to us. Any failure to renew or find follow-on work for our drilling rigs with expiring contracts, could have a material adverse effect on our operations and financial condition.
Fixed-term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to us if a contract is terminated prior to the expiration of the fixed term. Additionally, in certain circumstances, for example, destruction of a drilling rig that is not replaced within a specified period of time, our bankruptcy, or a breach of our contract obligations, the customer may not be obligated to make an early termination payment to us. Additionally, during depressed market conditions, such as those we are currently experiencing, or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate, renegotiate or fail to honor their contractual obligations. In addition, we may not be able to perform under these contracts due to events beyond our control, and our customers may seek to cancel or negotiate our contracts for various reasons, including those described above. As a result, we may be unable to realize all of our current contract drilling backlog. In addition, the renegotiation or termination of fixed-term contracts without the receipt of early termination payments could have a material adverse effect on our business, financial condition, cash flows and results of operations.
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. Based upon the significant downturn in market conditions, any new sources of debt capital would require substantially higher interest requirements, and any new sources of equity capital could be substantially dilutive to existing shareholders. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. Our ability to maintain our targeted credit profile could affect our cost of capital as well as our ability to execute our growth strategy. In addition, a variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets. If we are at any time not able to obtain the necessary capital resources, our financial condition and results of operations could be materially adversely affected.
We depend on a limited number of vendors, some of which are thinly capitalized and the loss of any of which could disrupt our operations.
Our contract drilling operations depend upon the availability of various rig equipment, including VFD drives and drillers cabins, top drives, mud pumps, engines and drill pipe, as well as replacement parts, related rig equipment and fuel. Some of these have been in short supply from time to time. In addition, key rig components critical to the operation, construction or upgrade of our rigs are either purchased from or fabricated by a limited number of vendors, including vendors that may compete against us from time to time. For many of these products and services, there are only a limited number of vendors and suppliers available to us.
We do not currently have any long-term supply contracts with any of our suppliers or subcontractors and may be at a competitive disadvantage compared to our larger competitors when purchasing from these suppliers and subcontractors. Shortages could occur in these essential components due to an interruption of supply or increased demands in the industry. If we are unable to procure certain of such rig components or services from our subcontractors we would be required to reduce or delay our rig construction and other operations, which could have a material adverse effect on our business, results of operations, financial condition and growth strategy.
We could be adversely affected if shortages of equipment or supplies occur.
Increased or decreased demand among drilling contractors and our customers for consumable supplies, including fuel, water and ancillary rig equipment, such as pumps, valves, drill pipe and engines, may lead to delays in obtaining these materials and our inability to operate our rigs in an efficient manner. We have periodically experienced increased lead times in purchasing ancillary equipment for our drilling rigs. To the extent there are significant delays in being able to purchase important components for our rigs, certain of our rigs may not be available for operation or may not be able to operate as efficiently as expected, which could adversely affect our results of operations and financial condition.
In addition, our customers typically purchase the fuel and water for their operations, including fuel that runs our drilling rigs, and thus bear the financial impact of increased prices. However, prolonged shortages in the availability of fuel or water to conduct drilling and completion activities could result in the suspension of our contracts or reduce demand for our contract drilling services and have a material adverse effect on our financial condition and results of operations.
Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited.
Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code of 1986, as amended) at any time during a rolling three-year period. In addition, future ownership changes or future regulatory changes could further limit our ability to utilize our NOLs. If all or a substantial part of our NOLs is lost or limited, it will result in our recognizing a net deferred tax liability and associated expense during the period of limitation.
We believe we had an ownership change in April 2016, October 2018 in connection with the Sidewinder Merger, and in October 2021. In conjunction with the ownership change in October 2021, we expect to have approximately $81.2 million of NOLs expire before becoming available to be utilized by the Company. 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. As a result of the ownership change, and the limitation of our NOL, we recognized a net deferred tax liability and associated expense in the fourth quarter of 2021. Subsequent ownership changes under Section 382 in the future could cause further limitations in our existing NOLs as well as NOLs generated during future periods.
Legal and Regulatory Risks
Federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and natural gas wells that may reduce demand for our activities and could adversely affect our financial position, results of operations and cash flows.
Hydraulic fracturing is a commonly used process that involves injection of water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The adoption of any
federal, state or local laws or the implementation of regulations or ordinances restricting or increasing the costs of hydraulic fracturing could potentially increase our costs of operations and cause a decrease in drilling activity levels in the Permian Basin and other unconventional resource plays and an associated decrease in demand for our rigs and service, any or all of which could adversely affect our financial position, results of operations and cash flows.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our customers or could make it more difficult to perform hydraulic fracturing in the unconventional resource plays where we focus our operations. Any such regulation that adversely affects our customers’ operations could materially impact demand for our contract drilling services which could adversely affect our financial position, results of operations and cash flows.
Legal proceedings could have a negative impact on our business.
The nature of our business makes us susceptible to legal proceedings and governmental investigations from time to time. Lawsuits or claims against us could have a material adverse effect on our business, financial condition and results of operations. Any litigation or claims, even if fully indemnified or insured, could negatively affect our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future.
Regulatory compliance costs and restrictions, as well as any delays in obtaining permits by our customers for their operations, could impair our business.
The operations of our customers are subject to or impacted by a wide array of regulations in the jurisdictions in which they operate. As a result of changes in regulations and laws relating to the oil and natural gas industry, including land drilling, our customers’ operations could be disrupted or curtailed by governmental authorities. In most states, our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and completion activities. Such permits are typically required by state agencies, but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued, and the conditions which may be imposed in connection with the granting of the permit. Additionally, the high cost of compliance with applicable regulations may cause customers to discontinue or limit their operations or defer planned drilling, and may discourage companies from continuing development activities. As a result, demand for our services could be substantially affected by regulations adversely impacting the oil and natural gas industry.
We are subject to environmental, health and safety laws and regulations that may expose us to significant liabilities for penalties, damages or costs of remediation or compliance.
Our operations are subject to federal, regional, state and local laws and regulations relating to protection of natural resources and the environment, health and safety aspects of our operations and waste management, including the transportation and disposal of waste and other materials. These laws and regulations may impose numerous obligations on our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to mitigate or prevent releases of materials from our facilities, the imposition of substantial liabilities for pollution resulting from our operations and the application of specific health and safety criteria addressing worker protection. Failure to comply with these laws and regulations could result in investigations, restrictions or orders suspending well operations, the assessment of administrative, civil and criminal penalties, the revocation of permits and the issuance of corrective action orders, any of which could have a material adverse effect on our business, results of operations and financial condition.
There is inherent risk of environmental costs and liabilities in our business as a result of our handling of petroleum hydrocarbons and oilfield and industrial wastes, air emissions and wastewater discharges related to our operations, and historical industry operations and waste disposal practices. Some environmental laws and regulations
may impose strict, joint and several liability, which means that in some situations, we could be exposed to liability as a result of our conduct that was without fault or lawful at the time it occurred or as a result of the conduct of, or conditions caused by, prior operators or other third parties. Clean-up costs and other damages arising as a result of environmental laws and costs associated with changes in environmental laws and regulations could be substantial and could have a material adverse effect on our financial condition and results of operations.
Laws protecting the environment generally have become more stringent over time and are expected to continue to do so, which could lead to material increases in costs for future environmental compliance and remediation. The modification or interpretation of existing laws or regulations, or the adoption of new laws or regulations, could curtail exploratory or developmental drilling for oil and natural gas, could limit well servicing opportunities or impose unforeseen liabilities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance.
Potential listing of species as “endangered” under the federal ESA could result in increased costs and new operating restrictions or delays on our oil and natural gas exploration and production customers, which could adversely reduce the amount of contract drilling services that we provide to such customers.
The federal ESA and analogous state laws regulate a variety of activities, including oil and natural gas development, which could have an adverse effect on species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species or the designation of previously unprotected areas as a critical habitat could cause oil and natural gas exploration and production operators to incur additional costs or become subject to operating delays, restrictions or bans in affected areas, which impacts could adversely reduce the amount of drilling activities in affected areas, including support services that we provide to such operators under our contract drilling services segment. Numerous species have been listed or proposed for protected status in areas in which we provide or could in the future provide field services. For instance, the sage grouse, the lesser prairie-chicken and certain wildflower species, among others, are species that have been or are being considered for protected status under the ESA and whose range can coincide with our oil and natural gas production activities. The presence of protected species in areas where operators for whom we provide contract drilling services conduct exploration and production operations could impair such operators’ ability to timely complete well drilling and development and, consequently, adversely affect the amount of contract drilling or other field services that we provide to such operators, which reduction of services could have a significant adverse effect on our results of operations and financial position.
Climate change legislation or regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for our field services.
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases from industrial and energy sources contribute to increases of carbon dioxide levels in the Earth’s atmosphere and oceans and contribute to global warming and other environmental effects, the EPA has adopted various regulations under the federal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and natural gas industry. During 2012, the EPA published rules that include standards to reduce methane emissions associated with oil and natural gas production. In May 2016, the EPA finalized regulations that set methane emission standards for new and modified oil and natural gas facilities, including production facilities. However, in September 2020, the EPA issued a final rule that removed the transmission and storage segment from the 2016 new source performance standards, rescinded VOCs and methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. Notwithstanding the current court challenges, on January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent methane emission rulemaking. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change and was among the 195 nations that signed an international accord in December 2015 with the objective of limiting greenhouse gas emissions. The Paris Agreement (adopted at the conference) went into effect on November 4, 2016. While the U.S. withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20,
2021 recommitting the United States to the Paris Agreement. And, on January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on federal lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices and to consider whether to adjust royalties associated with oil and gas resources extracted from public lands and offshore waters to account for corresponding climate costs. Additionally, certain U.S. states and regional coalitions of states have adopted measures regulating or limiting greenhouse gases from certain sources or have adopted policies seeking to reduce overall emissions of greenhouse gases. The adoption and implementation of any international treaty or of any federal or state legislation or regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with our operations and other sources within the industrial or energy sectors. Such legislation or regulations could adversely affect demand for the production of oil and natural gas and thus reduce demand for the services we provide to oil and natural gas producers as well as increase our operating costs by requiring additional costs to operate and maintain equipment and facilities, install emissions controls, acquire allowances or pay taxes and fees relating to emissions, which could adversely affect our results of operations and financial condition. 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.
Risks Related to Our Liquidity
We may not be successful in refinancing our existing term loan indebtedness on terms that are acceptable to us. In addition, any refinancing of the term loan could result in substantial dilution to our existing stockholders.
On December 31, 2021, our outstanding term loan had a balance of $135.9 million, and on January 1, 2022, we increased the outstanding balance by an additional $3.2 million under the facility in connection with the payment of interest due on such date. Although our Term Loan Credit Agreement does not mature until October 2023, we expect it to be classified as a current liability on our balance sheet when we report our results of operations and financial condition on our Quarterly Report on Form 10-Q for the nine months ended September 30, 2022. We have begun the process of evaluating alternatives to refinance this Term Loan Facility. We cannot predict at this time the form of any such refinancing; however, such alternatives could include an extension of the term of the Term Loan Facility, the conversion or refinancing of all or part of the debt to equity or equity-linked instruments, and adjustments to interest rates and covenants, the issuance of debt or equity securities to third parties, or a combination of conversions or exchanges and issuances of debt or equity securities to third parties. We believe it is likely that any refinancing of the Term Loan Credit Agreement will involve the issuance of equity or equity linked instruments that will result in dilution to our existing stockholders. Although market conditions for our business have been strengthening, we cannot predict whether suitable refinancing alternatives will be available to us, or the timing of when such refinancing could occur. Any failure to refinance outstanding amounts under the Term Loan Credit Agreement would have a material adverse effect on our financial condition.
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.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future
debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition 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;
● 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.
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 2022.
At December 31, 2021, the borrowing base under our ABL Credit Facility was $17.8 million, and we had $11.3 million of availability remaining of our $40.0 million commitment on that date. Unless we maintain a minimum fixed charge coverage ratio (“FCCR”) of 1:1, we are required to maintain minimum availability under the ABL Credit Facility of $4.0 million. During 2021, we did not maintain this minimum fixed charge coverage ratio. The borrowing base under the ABL Credit Facility is calculated based upon 85% of the sum of our eligible accounts receivable. In most circumstances, all of accounts receivable are considered eligible unless they are more than 90 days past due. If at any time our borrowing base falls below our outstanding balance under our ABL Credit Facility, and we were not able to promptly repay such deficiency, we would be required to repay to the banks any deficiency amount. In such event, if our available cash balances were not sufficient to repay such amounts, we would be required to obtain other debt or equity financing necessary to cure such deficiency, and there can be no assurance that such additional financing sources would be available to us, or available on terms acceptable to us. Any inability to timely cure any deficiency between our borrowing base and credit facility balance may have a material adverse effect on our liquidity and financial condition.
A failure of any of our lenders to honor commitments or advance funds under our existing debt instruments would have a material adverse effect on our ability to fund our operations and business strategy.
Our ABL Credit Facility limits the amounts we can borrow up to a borrowing base amount which is calculated monthly and is based on a percentage of our eligible accounts receivable. The borrowing base under our ABL Credit Facility was $17.8 million as of December 31, 2021, with lender commitments of $40.0 million. Our Term Loan Facility also contains a committed accordion feature that allows us to borrow up to an additional $15 million during the term of that facility, of which $11.9 million is available. Subsequent to December 31, 2021, we elected to pay in-kind $3.2 million of interest due on January 1, 2022, reducing the available committed accordion to $8.7 million.
If our lenders fail to honor their commitments or advance funds pursuant to such commitments, we may be unable to implement our strategic plans, make acquisitions or capital expenditures or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations.
Our ability to comply with the financial covenants contained in our debt instruments is based upon our future cash flows and debt levels.
Both our existing ABL Credit Facility and Term Loan Facility 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 Term Loan Facility 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 availability under our ABL Credit Facility and Term Loan Accordion.
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. 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 LIBOR. A change in indices, including the announced discontinuation of LIBOR, 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 at December 31, 2021 included $142.2 million of floating-rate debt attributed to borrowings at an average interest rate of 8.81%, and the impact on annual cash flow of a 10% change in the floating-rate (approximately 9.69%) would be approximately $1.3 million annually based on the floating-rate debt and other obligations outstanding at December 31, 2021; 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.
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.
Future offerings of debt securities, which would rank senior to our common stock in the event of our liquidation, and future offerings of equity and equity-linked securities, which would dilute our existing stockholders or rank senior to our common stock, may adversely affect the market value of our common stock.
We intend to evaluate and may attempt to increase our capital resources by offering debt or equity securities, including commercial paper, medium-term notes, senior or subordinated notes, convertible notes and classes of preferred stock. In the event of our liquidation, holders of our debt securities and preferred stock and lenders with respect to other borrowings will receive a distribution of our available assets prior to the holders of our common stock. On November 11, 2020, we entered into a Common Stock Purchase Agreement (the “Commitment Purchase Agreement”) and a Registration Rights Agreement (the “Registration Rights Agreement”) with Tumim Stone Capital LLC (“Tumim”). Pursuant to the Commitment Purchase Agreement, the Company had the right to sell to Tumim up to $5.0 million (the “Total Commitment”) in shares of its common stock, par value $0.01 per share (the “Shares”) (subject to certain conditions and limitations) from time to time during the term of the Commitment Purchase Agreement. This agreement was terminated on December 14, 2021. As of December 31, 2021, we had sold 1,144,000 shares for a total of $4.2 million in proceeds at an average sales price of $3.71 per share. In addition, during 2021 we issued 2,860,924 shares for a total of $9.7 million in proceeds pursuant to our at-the-market (“ATM”) offerings. At the end of 2021, our Board approved additional ATM offerings aggregating up to $5.9 million in proceeds, and during January and February 2022, we sold an additional 1,061,853 shares for a total of $3.6 million in proceeds pursuant to this most recent authorization. Additional equity offerings may dilute the holdings of our existing stockholders or reduce the market value of our common stock, or both. Our preferred stock, if issued, could have a preference on liquidating distributions or a preference on dividend payments that would limit amounts available for distribution to holders of our common stock. Because our decision to issue securities in any future offering will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing or nature of our future offerings. Thus, holders of our common stock bear the risk of our future offerings reducing the market value of our common stock and diluting their shareholdings in us.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our amended and restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
General Risk Factors
The COVID-19 pandemic and related economic repercussions had a significant impact on our business, results of operations and financial condition, and depending on the duration of the pandemic and its effect on the oil and gas industry, could continue to have a material adverse effect on our business, liquidity, results of operations and financial condition.
The worldwide outbreak of COVID-19, the uncertainty regarding the impact of COVID-19 and various governmental actions taken to mitigate the impact of COVID-19 resulted in a decline in demand for oil and natural gas. To the extent that the outbreak of COVID-19 continues to negatively impact demand and OPEC+ members and other oil exporting nations fail to maintain compliance with production quotas or other actions that support and stabilize commodity prices, we expect our business, operating results and financial condition to remain depressed with further declines in activity levels possible.
Given the nature and significance of the COVID-19 pandemic on demand for oil, and the uncertainty regarding the length of this impact, our business is subject to substantial risks outside of our control, which include, but are not limited to:
● disruption to our supply chain for equipment, supplies and materials essential to our business;
● notices from customers or suppliers arguing that their non-performance under our contracts with them is permitted as a result of force majeure or other reasons;
● reductions in our borrowing base under our revolving line of credit related to delayed customer payments and payment defaults associated with customer liquidity issues and bankruptcies;
● a need to preserve liquidity, which could result in reductions or delays to planned maintenance capital expenditures or failure to pursue other business opportunities;
● failure of our lenders under our revolving credit facility or term loan to honor commitments to provide additional funding in accordance with the terms of such agreements;
● actions by the lenders under our term loan or revolving line of credit that additional borrowings permitted under such arrangements will not be permitted as a result of the occurrence of a material adverse effect caused by the COVID-19 pandemic;
● our ability to comply with minimum liquidity and springing fixed charge coverage ratio covenants contained in our credit facilities;
● cybersecurity issues, as digital technologies may become more vulnerable and experience a higher rate of cyberattacks in the current environment of remote connectivity;
● litigation risk and possible loss contingencies related to COVID-19 and its impact, including with respect to commercial contracts, employee matters and insurance arrangements;
● additional reductions to our workforce to adjust to market conditions, including severance payments, retention issues, and an inability to hire employees when market conditions improve;
● additional asset impairments, including an impairment of the carrying value of our assets as demand for our contract drilling services decreases;
● infections and quarantining of our employees and the personnel of our customers, suppliers and other third parties in areas in which we operate; and
● changes in the regulation of the production of hydrocarbons, such as the imposition of limitations on the production of oil and gas by states in our target markets or other jurisdictions, that may result in additional limits on demand for our contract drilling services.
If any of these risk factors were to come to fruition, they could have a material adverse effect on our business, 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.
Our business is subject to cybersecurity risks and threats.
Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. It is possible that our business, financial and other systems could be compromised, which might not be noticed for some period of time. Risks associated with these threats include, among other things, loss of intellectual property, disruption of our customers’ business operations and safety procedures, loss or damage to our worksite data delivery systems, and increased costs to prevent, respond to or mitigate cybersecurity events.
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 maters.
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 at times of high demand we will be able to retain, recruit and train an adequate number of skilled workers. In addition, our ability to expand our operations will depend in part on our ability to increase the size of our skilled labor force. 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. If either or both of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired. Our inability to attract and retain skilled workers in sufficient numbers to satisfy our existing service contracts and enter into new contracts could materially adversely affect our business, financial condition, results of operations and growth strategy.

---

ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

---

ITEM 2. PROPERTIES
ITEM 2. PROPERTIES
We lease an approximate 14.4 acre rig assembly yard complex located at 11601 North Galayda Street, Houston, Texas 77086. The complex includes approximately 18,000 square feet of office space and 76,000 square feet of warehouse space.
Our operations are managed from field locations that we own or lease, that contain office, shop and yard space to support day-to-day operations, including repair and maintenance of equipment, as well as storage of equipment, materials and supplies. Including the Galayda facility, we currently have five such field locations.
Additionally, we lease office space for our corporate headquarters in northwest Houston located at 20475 State Highway 249, Suite 300, Houston, Texas 77070.
We believe that all of our existing properties are suitable for their intended uses and are sufficient to support our operations. We do not believe that any single property is material to our operations and, if necessary, we could obtain a replacement facility. We continuously evaluate the needs of our business, and we will purchase or lease additional properties or reduce our properties, as our business requires.

---

ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
We are the subject of certain legal proceedings and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such legal proceedings and claims. While the legal proceedings and claims may be asserted for amounts that may be material should an unfavorable outcome be the result, management does not currently expect that the resolution of these matters will have a material adverse effect on our financial position or results of operations. In addition, management monitors our legal proceedings and claims on a quarterly basis and establishes and adjusts any reserves as appropriate to reflect our assessment of the then-current status of such matters.

---

ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information for Common Stock
Our common stock is traded on the New York Stock Exchange under the symbol “ICD”.
Holders of Record
As of February 28, 2022, there were approximately 20 record holders of our common stock as listed by our transfer agent’s records. This number includes registered stockholders and does not include stockholders who hold their shares institutionally.
Dividend Policy
We have not declared or paid any cash dividends on our common stock. Our ABL Credit Facility prohibits us from paying cash dividends on our common stock, and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our Board of Directors and will depend on funds legally available, our results of operations, financial condition, capital requirements, the ability to pay cash dividends under our then existing revolving credit facility and other factors deemed relevant by our Board of Directors.
Stock Performance Graph
The following stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
The following graph compares our cumulative five-year total stockholder return with total stockholder return during the same period for the Standard & Poors 500 Index, the Standard & Poor’s Oil and Gas Equipment Service Index, the Philadelphia Stock Exchange Oil Service Sector Index and an index of peer companies. The graph assumes that (i) $100 was invested in our common stock on December 31, 2016, (ii) $100 was invested in each index on December 31, 2016, and (iii) all dividends, if any, were reinvested.
12/31/2016
12/31/2017
12/31/2018
12/31/2019
12/31/2020
12/31/2021
Independence Contract Drilling, Inc.
$
100.00
$
59.40
$
46.57
$
14.88
$
2.19
$
2.24
S&P 500 Index
$
100.00
$
121.82
$
116.46
$
153.12
$
181.28
$
233.26
Peer Index
$
100.00
$
83.85
$
46.85
$
42.72
$
22.95
$
29.65
S&P Oil & Gas Equipment Service Index
$
100.00
$
78.18
$
41.42
$
37.84
$
21.42
$
24.04
Philadelphia Stock Exchange Oil Service Sector Index
$
100.00
$
82.80
$
45.38
$
45.12
$
26.14
$
31.56
The Peer Index companies consist of: Akita Drilling, Ltd., Ensign Energy Services, Inc., Helmerich & Payne, Inc., Nabors Industries, Ltd., Patterson-UTI Energy, Inc., Precision Drilling Corporation, and RPC, Inc.
Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities
None.
Issuer Purchases of Equity Securities
During the fourth quarter of 2021, we withheld shares of our common stock to satisfy tax withholding obligations in connection with the vesting of certain stock awards. These shares are deemed to be “issuer purchases” of shares that are required to be disclosed pursuant to this Item but were not purchased as part of a publicly announced program to repurchase common shares. The following table provides information relating to our repurchase of shares of common stock during the three months ended December 31, 2021.
In the second quarter of 2019, our Board of Directors authorized a stock repurchase program of up to $10.0 million beginning on August 2, 2019 and ending on August 1, 2022. During the second quarter of 2020, this program was suspended until market conditions and our financial liquidity substantially improve. As of December 31, 2021, the Company has repurchased approximately $0.9 million of its common stock over the life of the program.
Issuer Purchases of Equity Securities
Total Number of
Approximate Dollar
Shares Purchased as
Value of Shares That
Total Number of
Average Price Paid
Part of Publicly
May Yet be Purchased
Period
Shares Purchased
Per Share
Announced Program
Under the Program
October 1 - October 31
-
$
-
-
$
9,124,711
November 1 - November 30
-
$
-
-
$
9,124,711
December 1 - December 31
3,268
$
2.94
-
$
9,124,711
Total
3,268
$
2.94
-
$
9,124,711

---

ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [Reserved]

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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, 2019 and year-to-year comparisons between the years ended December 31, 2020 and 2019 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, 2020 that was filed on March 1, 2021.
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 24 marketed AC powered (“AC”) rigs plus additional AC rigs that require significant capital expenditures in order to meet our AC pad-optimal specifications that we do not plan to market absent a material improvement in market conditions. 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, the Haynesville Shale and the Eagle Ford Shale; however, our rigs have previously operated in the 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
COVID-19 Pandemic and Market Conditions Update
During 2020, reduced demand for crude oil related to the COVID-19 pandemic, combined with production increases from OPEC+ early in the year, led to a significant reduction in oil prices and demand for drilling services in the United States. In response to these adverse conditions and uncertainty, our customers reduced planned capital expenditures and drilling activity throughout 2020. During the first quarter of 2020, our operating rig count reached a peak of 22 rigs and temporarily reached a low of three rigs during the third quarter of 2020. During the third quarter of 2020, oil and natural gas prices began to stabilize and steadily improve, and demand for our products began to modestly improve from their historic lows, which allowed us to reactivate additional rigs during the back half of 2020 and throughout 2021. As market conditions improved, dayrates and our revenue per day also began to steadily improve for our contract drilling services, in particular during the second half of 2021. Recently, oil prices (WTI-Cushing) reached a high of $96.13 per barrel on February 28, 2022, and natural gas prices (Henry Hub) reached a high of $6.70 per mmcf on February 2, 2022. Although our customers have increased drilling activity in response to these improvements, capital
discipline and adherence to 2021 capital budgets, reduced access to capital markets and hedges in place based on lower commodity prices, have caused such increases to be less dramatic compared to prior industry cycles. As of December 31, 2021, we had 16 rigs operating and 17 contracted, with our 17th rig reactivating in January 2022.
Due to rapidly declining market conditions at the end of the first quarter of 2020, we took actions in order to reduce our cost structure including: salary or compensation reductions, suspension of all cash-based incentive compensation, reduction of the number of executive management and directors, reduction of annual director compensation and reduction of non-field-based personnel headcount. As market conditions improved in 2021, we reinstated our incentive compensation accruals and increased field pay in response to tighter labor markets. As of January 1, 2022, we have fully reinstitued pre-COVID compensation levels and in many cases increased compensation above pre-COVID levels in response to a tightening labor market.
On March 27, 2020, President Trump signed into law the “Coronavirus Aid, Relief, and Economic Security (CARES) Act.” The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable contributions, and technical corrections to tax depreciation methods for qualified improvement property. We deferred $0.8 million of employer social security payments during the year ended December 31, 2020. We made the first required payment of $0.4 million on January 3, 2022.
The CARES Act did not have a material impact on our income taxes. Management will continue to monitor future developments and interpretations for any further impacts on our financial condition, results of operations, or liquidity.
PPP Loan
During the second quarter of 2020, we entered into an unsecured loan in the aggregate principal amount of $10.0 million (the “PPP Loan”) pursuant to the Paycheck Protection Program (the “PPP”), sponsored by the Small Business Administration (the “SBA”) as guarantor of loans under the PPP. The PPP was part of the CARES Act, and it provided loans to qualifying businesses in a maximum amount equal to the lesser of $10.0 million and 2.5 times the average monthly payroll expenses of the qualifying business. The proceeds of the loan could only be used for payroll costs, rent, utilities, mortgage interests, and interest on other pre-existing indebtedness (the “permissible purposes”) during the covered period that ended on or about October 13, 2020. Interest on the PPP loan was equal to 1.0% per annum. All or part of the loan was forgivable based upon the level of permissible expenses incurred during the covered period and changes to the Company’s headcount during the covered period to headcount during the period from January 1, 2020 to February 15, 2020. In the third quarter of 2021, we received notice from the SBA that our loan was forgiven and paid in full. The loan is considered an extinguishment of debt and is recorded as “Gain on extinguishment of debt” in our 2021 Statements of Operations. We have not accrued any liability associated with the risk of an adverse SBA review.
Common Stock Purchase Agreement
On November 11, 2020, we entered into a Common Stock Purchase Agreement (the “Commitment Purchase Agreement”) and a Registration Rights Agreement (the “Registration Rights Agreement”) with Tumim Stone Capital LLC (“Tumim”). Pursuant to the Commitment Purchase Agreement, the Company had the right to sell to Tumim up to $5.0 million (the “Total Commitment”) in shares of its common stock, par value $0.01 per share (the “Shares”) (subject to certain conditions and limitations) from time to time during the term of the Commitment Purchase Agreement. Sales of common stock pursuant to the Commitment Purchase Agreement, and the timing of any sales, were solely at our option and we were under no obligation to sell securities pursuant to this arrangement. Shares could be sold by the Company pursuant to this arrangement over a period of up to 24 months, commencing on December 1, 2020.
We determined that the right to sell additional shares represented a freestanding put option under ASC 815 Derivatives and Hedging, but had a fair value of zero, and therefore no additional accounting was required. Transaction costs, of $0.5 million, incurred in connection with entering into the Purchase Agreement were expensed as selling,
general and administrative expense during the fourth quarter of 2020. As of December 31, 2021, we had sold 1,144,000 shares for a total of $4.2 million in proceeds at an average sales price of $3.71 per share. On December 14, 2021, the agreement was terminated and no further shares were sold.
Amendments to Term Loan Credit Agreement
On June 4, 2020, we revised our Term Loan Credit Agreement to elect to pay accrued and unpaid interest, solely during one three-consecutive-month period immediately following such notice, in-kind (the “PIK Amount”). We agreed to pay an additional amount equal to 0.75% of the aggregate principal amount of the loans under the Term Loan Credit Agreement plus all PIK Amounts, if any, that are added to such principal amount being repaid or prepaid on either the maturity date or upon the occurrence of an acceleration of obligations under the Term Loan Credit Agreement. On April 1, 2021, we elected to pay in-kind the $2.8 million interest payment due under our Term Loan, which increased our Term Loan balance accordingly.
On September 28, 2021, we executed a Fourth Amendment (the “Fourth Amendment”) to the Term Loan Credit Agreement, dated as of October 1, 2018 (the “Term Loan Credit Agreement”), which amended the Term Loan Credit Agreement to permit us, at our option, subject to required prior notice, to elect to pay accrued and unpaid interest due October 1, 2021, in-kind. The payment-in-kind was in lieu of exercising a drawdown under the Accordion under the Term Loan Credit Agreement, thus, the amount of the Term Loan Accordion commitment of $15 million was reduced by the PIK Amount. On September 29, 2021, we elected to pay in-kind the $3.1 million October 1, 2021 interest payment.
On December 30, 2021 we executed a Fifth Amendment (the “Fifth Amendment”) to the Term Loan Credit Agreement, dated as of October 1, 2018, to permit us, at our option, subject to prior notice, to elect to pay accrued and unpaid interest due January 1, 2022 in-kind. The payment-in-kind was in lieu of exercising a drawdown under the Accordion under the Term Loan Credit Agreement, thus the amount of the Term Loan Accordion commitment was further reduced by the PIK Amount. On December 30, 2021, we elected to pay in-kind the $3.2 million January 3, 2022 interest payment. Following this payment-in-kind on January 1, 2022, the Term Loan Accordion commitment was $8.7 million.
ATM Offering
On June 5, 2020, we entered into an equity distribution agreement (the “Agreement”) with Piper Sandler & Co. (the “Agent”), through its Simmons Energy division. Pursuant to the Agreement, we were able to offer and sell through the Agent shares of our common stock, par value $0.01 per share, having an aggregate offering price of up to $11.0 million. We issued and sold approximately $11.0 million of common stock in the second and third quarters of 2020.
On March 8, 2021, in conjunction with the ATM Distribution Agreement entered into on June 5, 2020, our board of directors authorized an additional $2.2 million of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” We began offering shares under this program during the first quarter of 2021 and completed this offering process during the second quarter of 2021, raising $2.2 million of gross proceeds and issuing an aggregate of 585,934 shares at an average gross offering price of $3.75 per share.
On August 19, 2021, we entered into a new ATM Distribution Agreement relating to the offer and sale of an additional $7.5 million of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” During the fourth quarter of 2021, we completed this offering process, raising $7.5 million of gross proceeds and issuing an aggregate of 2,274,990 shares at an average gross offering price of $3.30.
On December 16, 2021, in conjunction with the ATM Distribution Agreement entered into on August 19, 2021, our board of directors authorized the sale of an additional $5.9 million of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” We began offering shares under this program during the first quarter of 2022. As of March 4, 2022, we raised gross proceeds of $3.6 million from the sale of shares in the offering.
Reverse Stock Split
Following approval by our stockholders on February 6, 2020, our Board of Directors approved a 1-for-20 reverse stock split of our common stock. The reverse stock split reduced the number of shares of common stock issued and outstanding from 77,523,973 and 76,241,045 shares, respectively, to 3,876,196 and 3,812,050 shares, respectively, and reduced the number of authorized shares of our common stock from 200,000,000 shares to 50,000,000 shares.
Sidewinder Merger Effects and Merger Consideration Amendment
We completed the merger with Sidewinder Drilling LLC on October 1, 2018. At the time of consummation of the Sidewinder Merger, Sidewinder owned various mechanical rig assets and related equipment (the "Mechanical Rigs") located principally in the Utica and Marcellus plays. As these assets were not consistent with ICD’s core strategy or geographic focus, ICD agreed that these assets could be disposed of, with the Sidewinder unitholders receiving the net proceeds. As a result of this arrangement, on the merger date, we recorded the fair value of the Mechanical Rigs less costs to sell, as assets held for sale, with a related liability in contingent consideration. Subsequently, these assets were sold at auction for substantially less than the appraised fair values on the merger date. As a result, in the second quarter of 2020, the contingent consideration liability was reduced by the appraised fair values on the merger date and the proceeds were recorded as merger consideration payable to an affiliate on our consolidated balance sheets.
On June 4, 2020, we entered into a letter agreement (the “Merger Consideration Amendment”) with MSD Credit Opportunity Master Fund, L.P. to allow for the deferral of payment of the Mechanical Rig net proceeds of $2.9 million, to the earlier of (i) June 30, 2022 and (ii) a change of control transaction (as defined therein) (such applicable date, the “Payment Date”), and requires us to pay an additional amount in connection with such deferred payment equal to interest accrued on the amount of Mechanical Rig net proceeds during the period between May 1, 2020 and the Payment Date, which interest shall accrue at a rate of 15% per annum, compounded quarterly, during the period beginning on May 1, 2020 and ending on December 31, 2020 and at a rate of 25% per annum, compounded quarterly, during any period following December 31, 2020. The Mechanical Rig net proceeds were previously payable in the second quarter of 2020. Accrued interest as of December 31, 2021 was $1.2 million.
Asset Impairment, net
During 2021, we impaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries. We also sold miscellaneous drilling equipment. Accordingly, we impaired the drilling equipment to fair market value less cost to sell and recorded asset impairment expense of $0.5 million in our consolidated statements of operations.
During the first quarter of 2020, as a result of the rapidly deteriorating market conditions described in "COVID-19 Pandemic and Market Conditions Update," we concluded that a triggering event had occurred and, accordingly, an interim asset impairment test was performed. As a result, we recognized impairment of $3.3 million associated with the decline in the market value of our assets held for sale based upon the market approach method and $13.3 million related to the remaining assets on rigs removed from our marketed fleet, as well as certain other component equipment and inventory; all of which was deemed to be unsaleable and of zero value based upon the macroeconomic conditions at the time and uncertainties surrounding COVID-19.
During the fourth quarter of 2020, due to the highly competitive market and in an effort to minimize capital spending, management drafted and approved a plan to upgrade our existing fleet by utilizing the primary components needed to complete the upgrades from five of our existing rigs and these five rigs were removed from our marketed fleet. We recorded an impairment charge of $21.9 million related to the remaining assets on these non-marketed rigs. Additionally, we recorded a $2.4 million asset impairment based upon the market approach method on certain capital spare parts, all of which were deemed to be incompatible with our upgraded fleet.
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 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.
Our operating costs also include costs and expenses associated with construction activities at our Galayda yard location to the extent that construction activities cease or are not continuous. During 2021, our operating costs also included approximately $1.4 million of costs associated with the reactivation of idle rigs. Reactivation costs include costs associated with recommissioning the rig, the hiring and training of new crews and the purchase of supplies and other consumables required for the operation of the rigs.
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 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.
Results of Operations
The following summarizes our financial and operating data for the years ended December 31, 2021 and 2020:
Year Ended
December 31,
December 31,
(In thousands, except per share data)
Revenues
$
87,955
$
83,418
Costs and expenses
Operating costs
75,751
65,367
Selling, general and administrative
15,699
13,484
Severance expense
-
1,076
Depreciation and amortization
38,915
43,919
Asset impairment, net
41,007
(Gain) loss on disposition of assets, net
(245)
Other expense
-
Total cost and expenses
131,070
165,576
Operating loss
(43,115)
(82,158)
Interest expense
(15,193)
(14,627)
Gain on extinguishment of debt
10,128
-
Loss before income taxes
(48,180)
(96,785)
Income tax expense (benefit)
18,532
(147)
Net loss
$
(66,712)
$
(96,638)
Other financial and operating data
Number of marketed rigs (end of period) (1)
Rig operating days (2)
4,651
3,739
Average number of operating rigs (3)
12.7
10.2
Rig utilization (4)
%
%
Average revenue per operating day (5)
$
17,224
$
19,000
Average cost per operating day (6)
$
13,943
$
13,984
Average rig margin per operating day
$
3,281
$
5,016
Oil price per Bbl (7) (end of year)
$
75.33
$
48.35
Natural gas price per Mcf (8) (end of year)
$
3.82
$
2.36
(1) Marketed rigs exclude idle rigs that will not be reactivated until upgrades or conversions are complete or market conditions substantially improve.
(2) 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.
(3) 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.
(4) Rig utilization is calculated as rig operating days divided by the total number of days our drilling rigs are available during the applicable period.
(5) 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 $7.8 million and $9.0 million during the years ended December 31, 2021 and 2020, respectively, and (ii) early termination revenues of zero and $3.3 million during the years ended December 31, 2021 and 2020, respectively.
(6) 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 $7.8 million and $9.0 million during the years ended December 31, 2021 and 2020, respectively, (ii) overhead costs expensed due to reduced rig upgrade activity of $1.6 million and $1.9 million during the years ended years ended December 31, 2021 and 2020, respectively, (iii) rig reactivation costs, inclusive of new crew training costs, of $1.4 million and $1.6 million during the years ended December 31, 2021 and 2020, respectively, and (iv) rig decommissioning costs associated with stacking deactivated rigs of $0.1 million and $0.6 million during the years ended December 31, 2021 and 2020, respectively.
(7) WTI spot price as reported by the United States Energy Information Administration.
(8) Henry Hub spot price as reported by the United States Energy Information Administration.
Comparison of the years ended December 31, 2021 and 2020
Revenues
Revenues for the year ended December 31, 2021 were $88.0 million, representing a 5.4% increase over revenues of $83.4 million for the year ended December 31, 2020. This increase was attributable to an increase in operating days to 4,651 days as compared to 3,739 days in 2020. The increase in operating days was primarily attributable to the reactivation of rigs in 2021 after the drastic downturn in market conditions in 2020 as a result of the COVID-19 pandemic and the concurrent initiation of a crude oil price war between members of the “OPEC+” group. On a revenue per operating day basis, which excludes the impact of early termination, our revenue per operating day decreased to $17,224 during 2021 compared to revenue per operating day of $19,000 during 2020. This decrease in average revenue per day resulted from the expiration of various higher dayrate legacy term contracts prior to 2021.
Operating Costs
Operating costs for the year ended December 31, 2021 were $75.8 million, representing a 15.9% increase over operating costs for the year ended December 31, 2020 of $65.4 million. This increase was attributable to an increase in operating days to 4,651 days as compared to 3,739 days in 2020. On a cost per operating day basis, our cost per day decreased to $13,943 during 2021, compared to cost per day of $13,984 during 2020. This decrease was primarily attributable to inefficiencies during the downturn in 2020, offset by higher personnel costs associated with staffing for planned rig reactivations and tighter labor markets in 2021.
Selling, General and Administrative Expenses
Selling, general and administrative expenses for the year ended December 31, 2021 were $15.7 million, representing a 16.4% increase over selling, general and administrative expenses for the year ended December 31, 2020 of $13.5 million. This increase was primarily related to higher incentive compensation accruals in 2021. We suspended our incentive compensation plan for 2020 as a result of the COVID-19 pandemic.
Severance Expense
Severance expense of $1.1 million was recorded during 2020 in connection with our cost reduction measures instituted in response to the COVID-19 pandemic and deteriorating market conditions. We did not record any severance expense in 2021.
Depreciation and Amortization
Depreciation and amortization for the year ended December 31, 2021 was $38.9 million, representing a 11.4% decrease compared to $43.9 million for the year ended December 31, 2020. This decrease was primarily the result of the asset impairments incurred in 2020 and 2021, offset by increases related to the introduction of reactivated drilling rigs upgraded by us in 2021. We begin depreciating our rigs on a straight-line basis when they commence drilling operations.
Asset Impairment, net
Asset impairment expense of $0.8 million was recorded for the year ended December 31, 2021, as compared to $41.0 million for the year ended December 31, 2020. For further discussion, see “Significant Developments - Asset Impairments” in this Management’s Discussion and Analysis of Financial Condition and Results of Operations.
(Gain) Loss on Disposition of Assets, net
A gain on the disposition of assets totaling $0.2 million and a loss of $0.7 million was recorded for the years ended December 31, 2021 and 2020, respectively. In the current and prior year period the gain and loss relate primarily to the sale of miscellaneous drilling equipment.
Other Expense
Other expense of $0.2 million was recorded during 2021 in connection with the termination of our Commitment Purchase Agreement. We did not record any other expense in 2020.
Interest Expense
Interest expense was $15.2 million for the year ended December 31, 2021, compared to $14.6 million for the year ended December 31, 2020. The increase in the current year primarily relates to the compounding interest on the merger consideration payable in June 2022.
Gain on Extinguishment of Debt
A gain on extinguishment of debt totaling $10.1 million was recorded for the year ended December 31, 2021 related to the forgiveness of our PPP Loan. See Note 8 “Long-term Debt” for additional information.
Income Tax Expense (Benefit)
Income tax expense for the year ended December 31, 2021 amounted to $18.5 million compared to income tax benefit of $0.1 million for the year ended December 31, 2020. The effective tax rate was negative 38.5% for the year ended 2021 compared to 0.2% for the year ended 2020. Tax expenses for 2021 primarily related to non-cash charges related to the inability to utilize net operating loss (“NOL”) deferred tax assets to offset deferred tax liabilities due to an IRC Section 382 ownership change occurring in October 2021 and the limitations therefrom placed upon the NOLs. Taxes for 2020 primarily relate to Louisiana state income tax and Texas margin tax. See Note 9 “Income Taxes” for additional information.
Liquidity and Capital Resources
Our liquidity as of December 31, 2021 included cash on hand of $4.1 million, $11.3 million of availability under our $40.0 million ABL Credit Facility, based on a borrowing base of $17.8 million, and an $11.9 million committed accordion under our existing term loan facility. Subsequent to December 31, 2021, we raised an additional $3.6 million of gross proceeds through “at-the-market” equity offerings issuing an additional 1,061,853 shares which is not included in our liquidity or our outstanding share count as of December 31, 2021.
We expect our future capital and liquidity needs to be related to operating expenses, maintenance capital expenditures, rig reactivations, working capital and general corporate purposes.
Cash flow from operations, ignoring working capital fluctuations, was negative during 2021. Subsequent to December 31, 2021, we elected to pay in-kind $3.2 million of interest due on January 1, 2022, which reduced our remaining Term Loan Accordion commitment and increased our Term Loan Facility balance accordingly. Looking forward past December 31, 2021, we currently estimate that required non-operating cash payments for interest under our credit facilities and finance lease payments will approximate $18.1 million for the 12 months ending December 31,
2022. In addition, the final merger consideration payment due pursuant to our merger agreement executed in connection with our merger with Sidewinder Drilling matures on June 30, 2022. Payments for capital expenditures and financing leases and to fund operations will be in addition to these amounts.
Because our cash flows from operations have been and could continue to be impacted by depressed market conditions caused by the COVID-19 pandemic, we may be required to continue to draw down under our ABL Credit Facility and to draw down funds pursuant to the DDTL Facility under our term loan facility to meet required non-operating expenditures and if necessary to fund operations. We currently believe that the actions we have taken to date and our existing sources of liquidity are sufficient to fund our operations for the next twelve months. However, due to the uncertainty regarding the duration of the COVID-19 pandemic and its effects on the oil and gas industry and our business and operations, there can be no assurance in this regard.
Although our Term Loan Credit Agreement does not mature until October 2023, we also have begun the process of evaluating alternatives to refinance this Term Loan Facility. We cannot predict at this time the form of any such refinancing; however, such alternatives could include an extension of the term of the Term Loan Facility, the conversion or refinancing of all or part of the debt to equity or equity-linked instruments, and adjustments to interest rates and covenants, the issuance of debt or equity securities to third parties, or a combination of conversions or exchanges and issuances of debt or equity securities to third parties. Although market conditions for our business have been strengthening, we cannot predict whether suitable refinancing alternatives will be available to us, or the timing of when such refinancing could occur.
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, 2021, 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)
Thereafter
Total
Term Loan Facility
$
-
$
135,883
$
-
$
-
$
135,883
ABL Credit Facility
-
6,300
-
-
6,300
Interest on Term Loan Facility
12,467
12,399
-
-
24,866
Interest on ABL Credit Facility
-
-
Deferred amendment fee
-
-
-
Merger consideration payable to an affiliate, including interest
4,606
-
-
-
4,606
Finance leases
4,868
1,068
-
6,136
Purchase obligations
2,927
-
-
-
2,927
Total contractual obligations
$
25,171
$
156,928
$
$
-
$
182,299
Our long-term debt as of December 31, 2021 consisted of amounts due under our Term Loan Facility (as defined and further described below). Interest on long-term debt is related to our estimated future contractual interest obligations on long-term indebtedness outstanding as of December 31, 2021 under our Term Loan Facility. Interest payment obligations on our Term Loan Facility were estimated based on the 9.0% interest rate that was in effect at December 31, 2021, and the principal balance of $135.9 million at December 31, 2021, and assuming repayment of the outstanding balance occurs at October 1, 2023. Interest payment obligation on our ABL Credit Facility were estimated based on the 4.75% interest rate that was in effect at December 31, 2021, and the principal balance of $6.3 million at December 31, 2021, and assuming repayment of the outstanding balance occurs at October 1, 2023. 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 $0.2 million that could be forfeited if we were to cancel these orders.
Cash Flows
Year Ended December 31,
(in thousands)
Net cash (used in) provided by operating activities
$
(9,579)
$
Net cash used in investing activities
(14,378)
(8,977)
Net cash provided by financing activities
15,818
15,763
Net (decrease) increase in cash and cash equivalents
$
(8,139)
$
7,073
Net Cash (Used In) Provided By Operating Activities
Cash used in operating activities was $9.6 million for the year ended December 31, 2021 compared to cash provided by operating activities of $0.3 million for the year ended December 31, 2020. 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, stock-based compensation, deferred taxes and amortization of deferred financing 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 2021 were lower as a result of a decrease in net loss of $29.9 million, adjusted for non-cash items of $57.1 million, compared to $88.5 million in 2020. Additionally, working capital changes that increased cash flows from operating activities were de minimis in 2021 compared to working capital changes that increased cash flows from operating activities of $8.4 million in 2020.
Net Cash Used In Investing Activities
Cash used in investing activities was $14.4 million for the year ended December 31, 2021 compared to $9.0 million for the year ended December 31, 2020. Our primary investing activities in 2021 related to rig upgrades and maintenance capital expenditures. Cash payments of $16.4 million for capital expenditures were offset by proceeds from the sale of property, plant and equipment of $2.0 million. Cash payments during 2021 included approximately $1.0 million associated with equipment purchased in 2020. During 2020, cash payments of $14.2 million for capital expenditures were offset by proceeds from the sale of property, plant and equipment of $5.1 million and the collection of principal on note receivable of $0.1 million.
Net Cash Provided By Financing Activities
Cash provided by financing activities was $15.8 million for the year ended December 31, 2021 compared to cash provided by financing activities of $15.8 million for the year ended December 31, 2020. During 2021, we received proceeds from borrowings under our Revolving Credit Facility of $6.3 million, proceeds from the issuance of common stock through our ATM transaction, net of issuance costs of $9.0 million and proceeds from the issuance of common stock under our equity line of credit purchase agreement of $4.2 million offset by restricted stock units withheld for taxes paid of $14.0 thousand, the purchase of treasury stock of $10.0 thousand, financing cost paid of $64 thousand, and made payments for finance lease obligations of $3.6 million. During 2020, we made borrowings under our Revolving Credit Facility of $11.0 million and under the PPP Loan of $10.0 million, offset by repayments under our Revolving Credit Facility of $11.0 million, common stock issuance costs of $0.8 million, received proceeds from issuance of common stock of $11.0 million, had restricted stock units withheld for taxes paid of $44.0 thousand, purchased $0.1 million of treasury stock and made payments for finance lease obligations of $4.3 million.
Long-term Debt
On October 1, 2018, we entered into a Term Loan Credit Agreement (the “Term Loan Credit Agreement”) for an initial term loan in an aggregate principal amount of $130.0 million, (the “Term Loan Facility”) and (b) a delayed
draw term loan facility in an aggregate principal amount of up to $15.0 million (the “DDTL Facility”, and together with the Term Loan Facility, the “Term Facilities”). The Term Facilities have a maturity date of October 1, 2023, at which time all outstanding principal under the Term Facilities and other obligations become due and payable in full. The outstanding balance under this Term Loan Credit Agreement at December 31, 2021 was $135.9 million, and increased to $139.1 million in January 2022 as a result of the payment-in-kind of interest due on January 1, 2022.
At our election, interest under the Term Loan Facility is 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%.
The Term Loan Credit Agreement contains financial covenants, including a liquidity covenant of $10.0 million and a springing fixed charge coverage ratio covenant of 1:1 that is tested when availability under the ABL Credit Facility (defined below) and the DDTL Facility is below $5.0 million at any time that a DDTL Facility loan is outstanding. The Term Loan Credit Agreement also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments, investments and transactions with affiliates. The Term Loan Credit Agreement also provides for customary events of default, including breaches of material covenants, defaults under the ABL Credit Facility or other material agreements for indebtedness, and a change of control.
The obligations under the Term Loan Credit Agreement are secured by a first priority lien on collateral (the “Term Priority Collateral”) other than accounts receivable, deposit accounts and other related collateral pledged as first priority collateral (“Priority Collateral”) under the ABL Credit Facility (defined below) and a second priority lien on such Priority Collateral, and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries. MSD PCOF Partners IV, LLC (an affiliate of MSD Partners) is the lender of our $130.0 million Term Loan Facility. MSD Partners, together with MSD Capital, owned approximately 6.1% of the outstanding shares of our common stock as of June 30, 2021. Their ownership percentage dropped below the 5% beneficial ownership percentage as of September 30, 2021, and remains as such at December 31, 2021.
In June 2020, we revised our Term Loan Credit Agreement to elect to pay accrued and unpaid interest, solely during one three-consecutive-month period immediately following such notice, in-kind (the “PIK Amount”). We agreed to pay an additional amount equal to 0.75% of the aggregate principal amount of the loans under the Term Loan Credit Agreement plus all PIK Amounts, if any, that are added to such principal amount being repaid or prepaid on either the maturity date or upon the occurrence of an acceleration of obligations under the Term Loan Credit Agreement. As such, the additional amount, approximately $1.0 million, was recorded as a direct deduction from the face amount of the Term Loan Facility and as a long-term payable on our consolidated balance sheets. The additional amount is amortized as interest expense over the term of the Term Loan Facility. During the second quarter of 2021, we utilized this PIK option to pay interest due during the quarter. In September 2021, we amended our Term Loan Credit Agreement to permit us, subject to required prior notice, to elect to pay accrued and unpaid interest due October 1, 2021, in-kind. The payment-in-kind is in lieu of exercising a drawdown under the DDTL Facility under the Term Loan Credit Agreement, reducing the amount of the DDTL Facility commitment of $15 million by the amount of the accrued and unpaid interest due October 1, 2021. On October 1, 2021, we elected to pay in-kind the $3.1 million interest payment due under our Term Loan Credit Agreement. Subsequent to December 31, 2021, we elected to pay in- kind $3.2 million of interest due on January 1, 2022, which will draw down our remaining $11.9 million DDTL Facility and increase our Term Loan Facility balance accordingly.
Additionally on October 1, 2018, we entered into a $40.0 million revolving Credit Agreement (the “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 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 ABL Credit Facility has a maturity date of the earlier of October 1, 2023 or the maturity date of the Term Loan Credit Agreement.
At our election, interest under the ABL Credit Facility is 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) LIBOR with an interest period of one month, plus 1.0%, and (c) 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 LIBOR for the applicable interest period plus an applicable LIBOR margin ranging from 2.0% to 2.5% 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 ABL Credit Facility commitment.
The ABL Credit Facility contains a springing fixed charge coverage ratio covenant of 1:1 that is tested when availability is less than 10% of the maximum credit. The ABL Credit Facility also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments, investments and transactions with affiliates. The ABL Credit Facility also provides for customary events of default, including breaches of material covenants, defaults under the Term Loan Credit Agreement or other material agreements for indebtedness, and a change of control. We are in compliance with our financial covenants as of December 31, 2021.
The obligations under the ABL Credit Facility are secured by a first priority lien on Priority Collateral, which includes all accounts receivable and deposit accounts, and a second priority lien on the Term Priority Collateral, and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries. As of December 31, 2021, the weighted-average interest rate on our borrowings was 8.81%. At December 31, 2021, the borrowing base under our ABL Credit Facility was $17.8 million, and we had $11.3 million of availability remaining of our $40.0 million commitment on that date.
In addition, on April 27, 2020, we entered into an unsecured loan in the aggregate principal amount of $10.0 million (the “PPP Loan”) pursuant to the PPP, sponsored by the SBA as guarantor of loans under the PPP. The PPP was part of the CARES Act, and it provided loans to qualifying businesses in a maximum amount equal to the lesser of $10.0 million and 2.5 times the average monthly payroll expenses of the qualifying business. The proceeds of the loan could only be used for payroll costs, rent, utilities, mortgage interests, and interest on other pre-existing indebtedness (the “permissible purposes”) during the covered period ending October 13, 2020. Interest on the PPP Loan was equal to 1.0% per annum. All or part of the loan was forgivable based upon the level of permissible expenses incurred during the covered period and changes to the Company’s headcount during the period from January 1, 2020 to February 15, 2020. In the third quarter of 2021, we received notice from the SBA that our loan was forgiven and paid in full. We have not accrued any liability associated with the risk of an adverse SBA review.
Additionally, included in our long-term debt are finance leases. These leases generally have initial terms of 36 months and are paid monthly.
Critical Accounting Policies and Accounting Estimates
The consolidated financial statements are impacted by the accounting policies and estimates and assumptions used by management during their preparation. These estimates and assumptions are evaluated on an on-going basis. Estimates are based on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities if not readily available from other sources. Actual results may differ from these estimates under different assumptions or conditions. The following is a discussion of the critical accounting policies and estimates used in our consolidated financial statements. Other significant accounting policies are summarized in Note 2 “Summary of Significant Accounting Policies” to the consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."
Revenue and Cost Recognition
We earn contract drilling revenues pursuant to drilling contracts entered into with our customers. We perform drilling services on a “daywork” basis, under which we charge a specified rate per day, or “dayrate.” The dayrate associated with each of our contracts is a negotiated price determined by the capabilities of the rig, location, depth and
complexity of the wells to be drilled, operating conditions, duration of the contract and market conditions. The term of land drilling contracts may be for a defined number of wells or for a fixed time period. We generally receive lump-sum payments for the mobilization of rigs and other drilling equipment at the commencement of a new drilling contract. Revenue and costs associated with the initial mobilization are deferred and recognized ratably over the term of the related drilling contract once the rig spuds. Costs incurred to relocate rigs and other equipment to an area in which a contract has not been secured are expensed as incurred. Our contracts provide for early termination fees in the event our customers choose to cancel the contract prior to the specified contract term. We record a contract liability for such fees received up front, and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract or until such time that all performance obligations are satisfied. While under contract, our rigs generally earn a reduced rate while the rig is moving between wells or drilling locations, or on standby waiting for the customer. Reimbursements for the purchase of supplies, equipment, trucking and other services that are provided at the request of our customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred. Revenue is presented net of any sales tax charged to the customer that we are required to remit to local or state governmental taxing authorities.
Our operating costs include all expenses associated with operating and maintaining our drilling rigs. Operating costs include all “rig level” expenses such as labor and related payroll costs, repair and maintenance expenses, supplies, workers’ compensation and other insurance, ad valorem taxes and equipment rental costs. Also included in our operating costs are certain costs that are not incurred at the rig level. These costs include expenses directly associated with our operations management team as well as our safety and maintenance personnel who are not directly assigned to our rigs but are responsible for the oversight and support of our operations and safety and maintenance programs across our fleet.
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 of property and equipment requires us to make various assumptions when the assets are acquired or placed into service about the expected usage, normal wear and tear and the extent and frequency of maintenance programs. 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. 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.
Asset impairment expense of $0.8 million was recorded for 2021, as compared to $41.0 million for 2020. For further discussion, see “Significant Developments - Asset Impairments” in this Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Income Taxes
We use the asset and liability method of accounting for income taxes. Under this method, we record deferred income taxes based upon differences between the financial reporting basis and tax basis of assets and liabilities, and use enacted tax rates and laws that we expect will be in effect when we realize those assets or settle those liabilities. We review deferred tax assets for a valuation allowance based upon management’s estimates of whether it is more likely than not that a portion of the deferred tax asset will be fully realized in a future period.
We recognize the financial statement benefit of a tax position only after determining that the relevant taxing authority would more-likely-than-not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
Our policy is to include interest and penalties related to the unrecognized tax benefits within the income tax expense (benefit) line item in our consolidated statement of operations.
Stock-Based Compensation
We record compensation expense over the requisite service period for all stock-based compensation based on the grant date fair value of the award. The expense is included in selling, general and administrative expense in our consolidated statement of operations or capitalized in connection with rig construction activity.
Other Matters
Off-Balance Sheet Arrangements
We are party to certain arrangements defined as “off-balance sheet arrangements” that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors. These arrangements relate to non-cancelable operating leases with terms of less than twelve months and unconditional purchase obligations not fully reflected on our consolidated balance sheets. See Note 13 “Commitments and Contingencies” to our consolidated financial statements for additional information.
Recent Accounting Pronouncements
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments, as additional guidance on the measurement of credit losses on financial instruments. The new guidance requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions and reasonable supportable forecasts. In addition, the guidance amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The new guidance is effective for all public companies for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. In October 2019, the FASB approved a proposal which grants smaller reporting companies additional time to implement FASB standards on current expected credit losses (CECL) to January 2023. As a smaller reporting company, we will defer adoption of ASU No. 2016-13 until January 2023. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
On April 1, 2020, we adopted the new standard, ASU 2020-04, Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying generally accepted accounting principles to contracts, hedging relationships, and other transactions affected by reference rate reform (e.g. discontinuation of LIBOR) if certain criteria are met. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform, to provide clarifying guidance regarding the scope of Topic 848, effective immediately. As of December 31, 2021, we have not yet elected any optional expedients provided in the standard. We will apply the accounting relief as relevant contract and hedge accounting relationship modifications are made during the reference rate reform transition period. We do not expect the standard to have a material impact on our consolidated financial statements.
In August 2020, the FASB issued ASU No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, to simplify the accounting for convertible instruments by removing certain separation models in Subtopic 470-20, Debt-Debt with Conversion and Other Options, for convertible instruments. The pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We do not expect the standard to have a material impact on our consolidated financial statements.
In May 2021, the FASB issued ASU No. 2021-04, Earnings Per Share (Topic 260), Debt - Modifications and Extinguishments (Subtopic 470-50), Compensation - Stock Compensation (Topic 718), and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options, which clarifies that issuers should account for modifications and exchanges of freestanding equity-classified written call options that remain equity-classified after these transactions as an exchange of the original instrument for a new instrument. The pronouncement is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We adopted this guidance on January 1, 2022 and there is no impact on our consolidated financial statements.

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to a variety of market risks including risks related to potential adverse changes in interest rates and commodity prices. We actively monitor exposure to market risk and continue to develop and utilize appropriate risk management techniques. We do not use derivative financial instruments for trading or to speculate on changes in commodity prices.
Interest Rate Risk
Total long-term debt at December 31, 2021 included $142.2 million of floating-rate debt attributed to borrowings at an average interest rate of 8.81%. As a result, our annual interest cost in 2021 will fluctuate based on short-term interest rates. The impact on annual cash flow of a 10% change in the floating-rate (approximately 9.69%) would be approximately $1.3 million annually based on the floating-rate debt and other obligations outstanding at December 31, 2021; however, there are no assurances that possible rate changes would be limited to such amounts.
Commodity Price Risk
Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling and production services activities. Reduced demand for oil and natural gas generally results in lower prices for these commodities and may impact the economics of planned drilling projects and ongoing production projects, resulting in the curtailment, reduction, delay or postponement of such projects for an indeterminate period of time. When drilling and production activity and spending decline, both dayrates and utilization have also historically declined. Further declines in oil and natural gas prices and the general economy, could materially and adversely affect our business, results of operations, financial condition and growth strategy.
In addition, if oil and natural gas prices decline, companies that planned to finance exploration, development or production projects through the capital markets may be forced to curtail, reduce, postpone or delay drilling activities even further, and also may experience an inability to pay suppliers. Adverse conditions in the global economic environment could also impact our vendors’ and suppliers’ ability to meet obligations to provide materials and services in general. If any of the foregoing were to occur, or if 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.
The economic effects of the global actions taken in response to the COVID-19 pandemic caused significant declines in the global demand for crude oil, and although market conditions and commodity prices have been improving, the risk remains that additional outbreaks could cause new declines in demand for crude oil.
We cannot predict whether there will be additional disruptions resulting from the COVID-19 pandemic in the future that could cause commodity prices and demand for our drilling services to fall. The extent to which our operating and financial results are affected by the COVID-19 pandemic will depend on various factors and consequences beyond our control, such as the duration and scope of the pandemic; additional actions by businesses and governments in response to the pandemic; and the speed and effectiveness of responses to combat the virus. As a result, our business, operating results and financial conditions are subject to various risks outlined in our Current Reports on Form 10-Q under Part II, Section 1a “Risk Factors,” as well as the risk factors outlined in this Annual Report on Form 10-K under Part I, Item 1a “Risk Factors,” many of which are aggravated as a result of the declining market conditions and significant uncertainty caused by the COVID-19 pandemic.
Credit and Capital Market Risk
Our customers may finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Any deterioration in the credit and capital markets, as currently being experienced, can make it difficult for our customers to obtain funding for their capital needs. A reduction of cash flow resulting from declines in commodity prices, or a reduction of available financing may result in a reduction in customer spending and the demand
for our drilling services. This reduction in spending could have a material adverse effect on our business, financial condition, cash flows, and results of operations.
All of our customers, lenders and suppliers have been adversely affected in some fashion by the COVID-19 pandemic. Although we are not currently experiencing any material disruption in payments by customers, given the impact the COVID-19 pandemic has had on the oil and gas industry and our customers, there is no assurance that our customers’ financial position will not be adversely impacted which could result in payment delays and payment defaults. Availability under our revolving line of credit is based upon a borrowing base determined by the level of our accounts receivable, with uncollectable amounts or amounts greater than 90 days past due excluded from consideration. As a result, a continued reduction in the utilization of our rigs or delays in payment or payment defaults by any of our customers could have a material adverse impact on our financial liquidity. Similarly, our suppliers may not extend credit to us or require less favorable payment terms or face similar challenges with their own suppliers. We also are reliant upon our third-party lenders’ ability to meet their commitments under our existing credit facilities. Given the impact of the COVID-19 pandemic across industries and geographic regions, we cannot predict the magnitude it may have on our lenders’ ability to meet their commitments to us, and any failure to do so would have a material adverse effect on our liquidity and financial position.

---

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Independence Contract Drilling, Inc.
Report of Independent Registered Public Accounting Firm (PCAOB ID 243)
Consolidated Balance Sheets as of December 31, 2021 and 2020
Consolidated Statements of Operations for the years ended December 31, 2021, 2020 and 2019
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2021, 2020 and 2019
Consolidated Statements of Cash Flows for the years ended December 31, 2021, 2020 and 2019
Notes to Consolidated Financial Statements
Schedule II - Valuation and Qualifying Accounts
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Independence Contract Drilling, Inc.
Houston, Texas
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Independence Contract Drilling, Inc. (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.
Assessment of the Enterprise Valuation in Connection with the 382 Ownership Change
As discussed in Note 9 to the consolidated financial statements, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes, upon the occurrence of an ownership change, an annual limitation on certain net operating losses that can be utilized. In October 2021, the Company experienced an ownership change, and
conducted an analysis of the annual limitation, which included the use of a tangible property and enterprise valuation of the Company.
We identified management’s assessment of the enterprise valuation, specifically the key assumptions relating to future dayrates, rig utilization and the terminal growth rate, used within the enterprise valuation as a critical audit matter. Auditing management’s assessment of the key assumptions relating to future dayrates, rig utilization and the terminal growth rate, involved significant estimation and complex auditor judgement.
The primary procedures we performed to address this critical audit matter included:
● Testing the completeness, accuracy, and relevance of the underlying data used in estimating the undiscounted future cash flows used in the enterprise valuation; and
● Evaluating the reasonableness of the future dayrates, rig utilization and the terminal growth rate used by management in developing the estimate of undiscounted future cash flows, including evaluating whether the assumptions were reasonable considering market data, and current and historical performance, and were consistent with evidence obtained through other areas of the audit.
/s/ BDO USA, LLP
We have served as the Company’s auditor since 2015.
Houston, Texas
March 15, 2022
Independence Contract Drilling, Inc.
Consolidated Balance Sheets
(In thousands, except par value and share amounts)
December 31,
December 31,
Assets
Cash and cash equivalents
$
4,140
$
12,279
Accounts receivable, net of allowance of zero and $0.5 million, respectively
22,211
10,023
Inventories
1,171
1,038
Prepaid expenses and other current assets
4,787
4,102
Total current assets
32,309
27,442
Property, plant and equipment, net
362,346
382,239
Other long-term assets, net
2,449
3,528
Total assets
$
397,104
$
413,209
Liabilities and Stockholders’ Equity
Liabilities
Current portion of long-term debt
$
4,464
$
7,637
Accounts payable
15,304
4,072
Accrued liabilities
15,617
10,723
Current portion of merger consideration payable to an affiliate
2,902
-
Total current liabilities
38,287
22,432
Long-term debt
141,740
137,633
Merger consideration payable to an affiliate
-
2,902
Deferred income taxes, net
19,037
Other long-term liabilities
2,811
2,704
Total liabilities
201,875
166,176
Commitments and contingencies (Note 13)
Stockholders’ equity
Common stock, $0.01 par value, 50,000,000 shares authorized; 10,287,931 and 6,254,396 shares issued, respectively, and 10,206,085 and 6,175,818 shares outstanding, respectively
Additional paid-in capital
532,826
517,948
Accumulated deficit
(333,776)
(267,064)
Treasury stock, at cost, 81,846 shares and 78,578 shares, respectively
(3,923)
(3,913)
Total stockholders’ equity
195,229
247,033
Total liabilities and stockholders’ equity
$
397,104
$
413,209
The accompanying notes are an integral part of these consolidated financial statements.
Independence Contract Drilling, Inc.
Consolidated Statements of Operations
(In thousands, except per share amounts)
Year Ended December 31,
Revenues
$
87,955
$
83,418
$
203,602
Costs and expenses
Operating costs
75,751
65,367
144,913
Selling, general and administrative
15,699
13,484
16,051
Severance and merger-related expense
-
1,076
2,698
Depreciation and amortization
38,915
43,919
45,367
Asset impairment, net
41,007
35,748
(Gain) loss on disposition of assets, net
(245)
4,943
Other expense
-
Total costs and expenses
131,070
165,576
250,097
Operating loss
(43,115)
(82,158)
(46,495)
Interest expense
(15,193)
(14,627)
(14,415)
Gain on extinguishment of debt
10,128
-
-
Loss before income taxes
(48,180)
(96,785)
(60,910)
Income tax expense (benefit)
18,532
(147)
(122)
Net loss
$
(66,712)
$
(96,638)
$
(60,788)
Loss per share:
Basic and diluted
$
(8.89)
$
(19.69)
$
(16.11)
Weighted average number of common shares outstanding:
Basic and diluted
7,507
4,907
3,774
The accompanying notes are an integral part of these consolidated financial statements.
Independence Contract Drilling, Inc.
Consolidated Statements of Changes in Stockholders’ Equity
(In thousands, except share amounts)
Additional
Total
Common Stock(1)
Paid-in
Accumulated
Treasury
Stockholders’
Shares
Amount
Capital
Deficit
Stock(1)
Equity
Balances at December 31, 2018
3,853,909
$
$
504,178
$
(109,638)
$
(3,046)
$
391,533
Restricted stock issued
(6,478)
-
-
-
-
-
RSUs vested, net of shares withheld for taxes
2,737
-
(34)
-
-
(34)
Purchase of treasury stock
(38,118)
(1)
(7)
-
(801)
(809)
Common stock issuance costs
-
-
(177)
-
-
(177)
Stock-based compensation
-
-
1,871
-
-
1,871
Net loss
-
-
-
(60,788)
-
(60,788)
Balances at December 31, 2019
3,812,050
$
$
505,831
$
(170,426)
$
(3,847)
$
331,596
Restricted stock forfeited
(5,716)
-
-
-
-
-
RSUs vested, net of shares withheld for taxes
27,750
-
(44)
-
-
(44)
Purchase of treasury stock
(14,443)
-
-
-
(66)
(66)
Issuance of common stock through at-the-market facility, net of offering costs
2,356,177
10,182
-
-
10,206
Stock-based compensation
-
-
1,979
-
-
1,979
Net loss
-
-
-
(96,638)
-
(96,638)
Balances at December 31, 2020
6,175,818
$
$
517,948
$
(267,064)
$
(3,913)
$
247,033
RSUs vested, net of shares withheld for taxes
28,611
-
(14)
-
-
(14)
Purchase of treasury stock
(3,268)
-
-
-
(10)
(10)
Issuance of common stock through at-the-market facility, net of offering costs
2,860,924
8,940
-
-
8,969
Issuance of common stock under purchase agreement
1,144,000
4,228
-
-
4,239
Stock-based compensation
-
-
1,724
-
-
1,724
Net loss
-
-
-
(66,712)
-
(66,712)
Balances at December 31, 2021
10,206,085
$
$
532,826
$
(333,776)
$
(3,923)
$
195,229
(1) Prior period results have been adjusted to reflect the 1-for-20 reverse stock split that took place in February 2020. See Reverse Stock Split in Note 1 - Nature of Operations and Recent Developments.
The accompanying notes are an integral part of these consolidated financial statements.
Independence Contract Drilling, Inc.
Consolidated Statements of Cash Flows
(In thousands)
Year Ended December 31,
Cash flows from operating activities
Net loss
$
(66,712)
$
(96,638)
$
(60,788)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities
Depreciation and amortization
38,915
43,919
45,367
Asset impairment, net
41,007
35,748
Stock-based compensation
2,295
1,979
1,871
(Gain) loss on disposition of assets, net
(245)
4,943
Non-cash interest expense
5,883
-
-
Non-cash gain on extinguishment of debt
(10,128)
-
-
Deferred income taxes
18,532
(147)
(122)
Amortization of deferred financing costs
1,115
Bad debt (recovery) expense
(52)
Changes in operating assets and liabilities
Accounts receivable
(12,136)
26,026
5,695
Inventories
(133)
(349)
Prepaid expenses and other assets
(1,023)
1,473
Accounts payable and accrued liabilities
12,230
(16,680)
(7,190)
Net cash (used in) provided by operating activities
(9,579)
27,921
Cash flows from investing activities
Purchases of property, plant and equipment
(16,415)
(14,229)
(38,320)
Proceeds from the sale of assets
2,037
5,107
8,951
Proceeds from insurance claims
-
-
1,000
Collection of principal on note receivable
-
-
Net cash used in investing activities
(14,378)
(8,977)
(28,369)
Cash flows from financing activities
Borrowings under Revolving ABL Credit Facility
6,309
11,045
4,511
Repayments under Revolving ABL Credit Facility
(17)
(11,038)
(7,077)
Borrowings under PPP Loan
-
10,000
-
Common stock issuance costs
-
-
(177)
Proceeds from issuance of common stock through at-the-market facility, net of issuance costs
8,969
10,206
-
Proceeds from issuance of common stock under purchase agreement
4,239
-
-
Purchase of treasury stock
(10)
(66)
(809)
RSUs withheld for taxes
(14)
(44)
(34)
Financing costs paid under Term Loan Facility
(64)
-
(5)
Financing costs paid under Revolving Credit Facilities
-
-
(22)
Payments for finance lease obligations
(3,594)
(4,340)
(2,980)
Net cash provided by (used in) financing activities
15,818
15,763
(6,593)
Net (decrease) increase in cash and cash equivalents
(8,139)
7,073
(7,041)
Cash and cash equivalents
Beginning of period
12,279
5,206
12,247
End of period
$
4,140
$
12,279
$
5,206
The accompanying notes are an integral part of these consolidated financial statements.
Independence Contract Drilling, Inc.
Notes to Consolidated Financial Statements
1. Nature of Operations and Recent Developments
Except as expressly stated or the context otherwise requires, the terms “we,” “us,” “our,” the “Company” and “ICD” refer to Independence Contract Drilling, Inc. and its subsidiary.
We 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.
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.
COVID-19 Pandemic, Drilling Activity and Market Conditions Update
During 2020, reduced demand for crude oil related to the COVID-19 pandemic, combined with production increases from OPEC+ early in the year, led to a significant reduction in oil prices and demand for drilling services in the United States. In response to these adverse conditions and uncertainty, our customers reduced planned capital expenditures and drilling activity throughout 2020. During the first quarter of 2020, our operating rig count reached a peak of 22 rigs and temporarily reached a low of three rigs during the third quarter of 2020. During the third quarter of 2020, oil and natural gas prices began to stabilize and steadily improve, and demand for our products began to modestly improve from their historic lows, which allowed us to reactivate additional rigs during the back half of 2020 and throughout 2021. As market conditions improved, dayrates and our revenue per day also began to steadily improve for our contract drilling services, in particular during the second half of 2021. Recently, oil prices (WTI-Cushing) reached a high of $96.13 per barrel on February 28, 2022, and natural gas prices (Henry Hub) reached a high of $6.70 per mmcf on February 2, 2022. Although our customers have increased drilling activity in response to these improvements, capital discipline and adherence to 2021 capital budgets, reduced access to capital markets and hedges in place based on lower commodity prices, have caused such increases to be less dramatic compared to prior industry cycles. As of December 31, 2021, we had 16 rigs operating and 17 contracted, with our 17th rig reactivating in January 2022.
Due to rapidly declining market conditions at the end of the first quarter of 2020, we took actions in order to reduce our cost structure including: salary or compensation reductions, suspension of all cash-based incentive compensation, reduction of the number of executive management and directors, reduction of annual director compensation and reduction of non-field-based personnel headcount. As market conditions improved in 2021, we reinstated our incentive compensation accruals and increased field pay in response to tighter labor markets.
On March 27, 2020, President Trump signed into law the “Coronavirus Aid, Relief, and Economic Security (CARES) Act.” The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations, increased limitations on qualified charitable
contributions, and technical corrections to tax depreciation methods for qualified improvement property. We deferred $0.8 million of employer social security payments during the year ended December 31, 2020. We made the first required payment of $0.4 million on January 3, 2022.
The CARES Act did not have a material impact on our income taxes. Management will continue to monitor future developments and interpretations for any further impacts on our financial condition, results of operations, or liquidity.
PPP Loan
During the second quarter of 2020, we entered into an unsecured loan in the aggregate principal amount of $10.0 million (the “PPP Loan”) pursuant to the Paycheck Protection Program (the “PPP”), sponsored by the Small Business Administration (the “SBA”) as guarantor of loans under the PPP. The PPP was part of the CARES Act, and it provided loans to qualifying businesses in a maximum amount equal to the lesser of $10.0 million and 2.5 times the average monthly payroll expenses of the qualifying business. The proceeds of the loan could only be used for payroll costs, rent, utilities, mortgage interests, and interest on other pre-existing indebtedness (the “permissible purposes”) during the covered period that ended on or about October 13, 2020. Interest on the PPP loan was equal to 1.0% per annum. All or part of the loan was forgivable based upon the level of permissible expenses incurred during the covered period and changes to the Company’s headcount during the covered period to headcount during the period from January 1, 2020 to February 15, 2020. In the third quarter of 2021, we received notice from the SBA that our loan was forgiven and paid in full. The loan is considered an extinguishment of debt and is recorded as “Gain on extinguishment of debt” in our 2021 Statements of Operations. We have not accrued any liability associated with the risk of an adverse SBA review.
Common Stock Purchase Agreement
On November 11, 2020, we entered into a Common Stock Purchase Agreement (the “Commitment Purchase Agreement”) and a Registration Rights Agreement (the “Registration Rights Agreement”) with Tumim Stone Capital LLC (“Tumim”). Pursuant to the Commitment Purchase Agreement, the Company had the right to sell to Tumim up to $5.0 million (the “Total Commitment”) in shares of its common stock, par value $0.01 per share (the “Shares”) (subject to certain conditions and limitations) from time to time during the term of the Commitment Purchase Agreement. Sales of common stock pursuant to the Commitment Purchase Agreement, and the timing of any sales, were solely at our option and we were under no obligation to sell securities pursuant to this arrangement. Shares could be sold by the Company pursuant to this arrangement over a period of up to 24 months, commencing on December 1, 2020.
We determined that the right to sell additional shares represented a freestanding put option under ASC 815 Derivatives and Hedging, but had a fair value of zero, and therefore no additional accounting was required. Transaction costs, of $0.5 million, incurred in connection with entering into the Purchase Agreement were expensed as selling, general and administrative expense during the fourth quarter of 2020. As of December 31, 2021, we had sold 1,144,000 shares for a total of $4.2 million in proceeds at an average sales price of $3.71 per share. On December 14, 2021, the agreement was terminated and no further shares were sold.
Amendments to Term Loan Credit Agreement
On June 4, 2020, we revised our Term Loan Credit Agreement to elect to pay accrued and unpaid interest, solely during one three-consecutive-month period immediately following such notice, in-kind (the “PIK Amount”). We agreed to pay an additional amount equal to 0.75% of the aggregate principal amount of the loans under the Term Loan Credit Agreement plus all PIK Amounts, if any, that are added to such principal amount being repaid or prepaid on either the maturity date or upon the occurrence of an acceleration of obligations under the Term Loan Credit Agreement. On April 1, 2021, we elected to pay in-kind the $2.8 million interest payment due under our Term Loan, which increased our Term Loan balance accordingly.
On September 28, 2021, we executed a Fourth Amendment (the “Fourth Amendment”) to the Term Loan Credit Agreement, dated as of October 1, 2018 (the “Term Loan Credit Agreement”), which amended the Term Loan Credit
Agreement to permit us, at our option, subject to required prior notice, to elect to pay accrued and unpaid interest due October 1, 2021, in-kind (the “PIK Amount”). The payment-in-kind was in lieu of exercising a drawdown under the Accordion under the Term Loan Credit Agreement, thus, the amount of the Term Loan Accordion commitment of $15 million was reduced by the PIK Amount. On September 29, 2021, we elected to pay in-kind the $3.1 million October 1, 2021 interest payment.
On December 30, 2021 we executed a Fifth Amendment (the “Fifth Amendment”) to the Term Loan Credit Agreement, dated as of October 1, 2018, to permit us, at our option, subject to prior notice, to elect to pay accrued and unpaid interest due January 1, 2022 in-kind. The payment-in-kind was in lieu of exercising a drawdown under the Accordion under the Term Loan Credit Agreement, thus the amount of the Term Loan Accordion commitment was further reduced by the PIK Amount. On December 30, 2021, we elected to pay in-kind the $3.2 million January 3, 2022 interest payment. Following this payment-in-kind on January 1, 2022, the Term Loan Accordion commitment was $8.7 million.
ATM Offering
On June 5, 2020, we entered into an equity distribution agreement (the “Agreement”) with Piper Sandler & Co. (the “Agent”), through its Simmons Energy division. Pursuant to the Agreement, we were able to offer and sell through the Agent shares of our common stock, par value $0.01 per share, having an aggregate offering price of up to $11.0 million. We issued and sold approximately $11.0 million of common stock in the second and third quarters of 2020.
On March 8, 2021, in conjunction with the ATM Distribution Agreement entered into on June 5, 2020, our board of directors authorized an additional $2.2 million of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” We began offering shares under this program during the first quarter of 2021 and completed this offering process during the second quarter of 2021, raising $2.2 million of gross proceeds and issuing an aggregate of 585,934 shares at an average gross offering price of $3.75 per share.
On August 19, 2021, we entered into a new ATM Distribution Agreement relating to the offer and sale of an additional $7.5 million of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” During the fourth quarter of 2021, we completed this offering process, raising $7.5 million of gross proceeds and issuing an aggregate of 2,274,990 shares at an average gross offering price of $3.30.
On December 16, 2021, in conjunction with the ATM Distribution Agreement entered into on August 19, 2021, our board of directors authorized the sale of an additional $5.9 million of common stock to be sold in transactions that are deemed to be “at-the-market offerings.” We began offering shares under this program during the first quarter of 2022. As of March 4, 2022, we raised gross proceeds of $3.6 million from the sale of shares in the offering.
Reverse Stock Split
Following approval by our stockholders on February 6, 2020, our Board of Directors approved a 1-for-20 reverse stock split of our common stock. The reverse stock split reduced the number of shares of common stock issued and outstanding from 77,523,973 and 76,241,045 shares, respectively, to 3,876,196 and 3,812,050 shares, respectively, and reduced the number of authorized shares of our common stock from 200,000,000 shares to 50,000,000 shares. The reverse split was effective March 11, 2020, and all share and earnings per share information in these consolidated financial statements have been retroactively adjusted to reflect the reverse stock split and the associated decrease in par value was recorded with the offset to additional paid-in capital.
Sidewinder Merger and Merger Consideration Amendment
We completed the merger with Sidewinder Drilling LLC on October 1, 2018. At the time of consummation of the Sidewinder Merger, Sidewinder owned various mechanical rig assets and related equipment (the "Mechanical Rigs") located principally in the Utica and Marcellus plays. As these assets were not consistent with ICD’s core strategy or geographic focus, ICD agreed that these assets could be disposed of, with the Sidewinder unitholders receiving the net proceeds. As a result of this arrangement, on the merger date, we recorded the fair value of the Mechanical Rigs less
costs to sell, as assets held for sale, with a related liability in contingent consideration. Subsequently, these assets were sold at auction for substantially less than the appraised fair values on the merger date. As a result, in the second quarter of 2020, the contingent consideration liability was reduced by the appraised fair values on the merger date and the proceeds were recorded as merger consideration payable to an affiliate on our consolidated balance sheets.
On June 4, 2020, we entered into a letter agreement (the “Merger Consideration Amendment”) with MSD Credit Opportunity Master Fund, L.P. to allow for the deferral of payment of the Mechanical Rig net proceeds of $2.9 million, to the earlier of (i) June 30, 2022 and (ii) a change of control transaction (such applicable date, the “Payment Date”), and requires us to pay an additional amount in connection with such deferred payment equal to interest accrued on the amount of Mechanical Rig net proceeds during the period between May 1, 2020 and the Payment Date, which interest shall accrue at a rate of 15% per annum, compounded quarterly, during the period beginning on May 1, 2020 and ending on December 31, 2020 and at a rate of 25% per annum, compounded quarterly, during any period following December 31, 2020. The Mechanical Rig net proceeds were previously payable in the second quarter of 2020. Accrued interest as of December 31, 2021 was $1.2 million.
Asset Impairment, net
During 2021, we impaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries. We also sold miscellaneous drilling equipment. Accordingly, we impaired the drilling equipment to fair market value less cost to sell and recorded asset impairment expense of $0.5 million in our consolidated statements of operations.
During the first quarter of 2020, as a result of the rapidly deteriorating market conditions described in "COVID-19 Pandemic and Market Conditions Update", we concluded that a triggering event had occurred and, accordingly, an interim asset impairment test was performed. As a result, we recognized impairment of $3.3 million associated with the decline in the market value of our assets held for sale based upon the market approach method and $13.3 million related to the remaining assets on rigs removed from our marketed fleet, as well as certain other component equipment and inventory; all of which was deemed to be unsaleable and of zero value based upon the macroeconomic conditions at the time and uncertainties surrounding COVID-19.
During the fourth quarter of 2020, due to the highly competitive market and in an effort to minimize capital spending, management drafted and approved a plan to upgrade our existing fleet by utilizing the primary components needed to complete the upgrades from five of our existing rigs and these five rigs were removed from our marketed fleet. We recorded an impairment charge of $21.9 million related to the remaining assets on these non-marketed rigs. Additionally, we recorded a $2.4 million asset impairment based upon the market approach method on certain capital spare parts, all of which were deemed to be incompatible with our upgraded fleet.
2. Summary of Significant Accounting Policies
Basis of Presentation
These audited consolidated financial statements include all the accounts of ICD and its subsidiary. All significant intercompany accounts and transactions have been eliminated. Except for the subsidiary, we have no controlling financial interests in any other entity which would require consolidation. These audited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). As we had no items of other comprehensive income in any period presented, no other comprehensive income is presented.
Cash and Cash Equivalents
We consider short-term, highly liquid investments that have an original maturity of three months or less to be cash equivalents.
Accounts Receivable
Accounts receivable is comprised primarily of amounts due from our customers for contract drilling services. Accounts receivable are reduced to reflect estimated realizable values by an allowance for doubtful accounts based on historical collection experience and specific review of current individual accounts. Receivables are written off when they are deemed to be uncollectible. Allowance for doubtful accounts was zero and $0.5 million as of December 31, 2021 and 2020, respectively.
Inventories
Inventory is stated at lower of cost or net realizable value and consists primarily of supplies held for use in our drilling operations. Cost is determined on an average cost basis.
Property, Plant and Equipment, net
Property, plant and equipment, including renewals and betterments, are stated at cost less accumulated depreciation. All property, plant and equipment are depreciated using the straight-line method based on the estimated useful lives of the assets, which range from two to 39 years. Our determination of the useful lives of property and equipment requires us to make various assumptions when the assets are acquired or placed into service about the expected usage, normal wear and tear and the extent and frequency of maintenance programs. The cost of maintenance and repairs are expensed as incurred. Major overhauls and upgrades are capitalized and depreciated over their remaining useful life.
Depreciation of property, plant and equipment is recorded based on the estimated useful lives of the assets as follows:
Estimated Useful Life
Buildings
-
39 years
Drilling rigs and related equipment
-
20 years
Machinery, equipment and other
-
7 years
Vehicles
-
5 years
Our operations are managed from field locations that we own or lease, that contain office, shop and yard space to support day-to-day operations, including repair and maintenance of equipment, as well as storage of equipment, materials and supplies. We currently have five such field locations.
Additionally, we lease office space for our corporate headquarters in northwest Houston. Leases are evaluated at inception or at any subsequent material modification to determine if the lease should be classified as a finance or operating lease.
We review our assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets that are held and used is measured by comparison of the estimated future undiscounted cash flows associated with the asset to the carrying amount of the asset. If the carrying value of such assets is less than the estimated undiscounted cash flow, an impairment charge is recorded in the amount by which the carrying amount of the assets exceeds their estimated fair value. For further discussion, see Asset Impairments in Note 1 “Nature of Operations and Recent Developments.”
Construction in progress represents the costs incurred for drilling rigs and rig upgrades under construction at the end of the period. This includes third party costs relating to the purchase of rig components as well as labor, material and other identifiable direct and indirect costs associated with the construction of the rig.
Capitalized Interest
We capitalize interest costs related to rig construction projects. Interest costs are capitalized during the construction period based on the weighted-average interest rate of the related debt. We did not capitalize any interest for the years ended December 31, 2021 and 2020. Capitalized interest amounted to $0.3 million for the year ended December 31, 2019.
Financial Instruments and Fair value
Fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, there exists a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:
Level 1
Unadjusted quoted market prices for identical assets or liabilities in an active market;
Level 2
Quoted market prices for identical assets or liabilities in an active market that have been adjusted for items such as effects of restrictions for transferability and those that are not quoted but are observable through corroboration with observable market data, including quoted market prices for similar assets; and
Level 3
Unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date
This hierarchy requires us to use observable market data, when available, and to minimize the use of unobservable inputs when determining fair value.
The carrying value of certain of our assets and liabilities, consisting primarily of cash and cash equivalents, accounts receivable, accounts payable and certain accrued liabilities approximates their fair value due to the short-term nature of such instruments.
The fair value of our long-term debt is determined by Level 3 measurements based on quoted market prices and terms for similar instruments, where available, and on the amount of future cash flows associated with the debt, discounted using our current borrowing rate for comparable debt instruments (the Income Method). Based on our evaluation of the risk free rate, the market yield and credit spreads on comparable company publicly traded debt, we used an annualized discount rate, including a credit valuation allowance, of 7.5%. The following table summarizes the carrying value and fair value of our long-term debt as of December 31, 2021 and 2020.
December 31, 2021
December 31, 2020
Carrying
Fair
Carrying
Fair
(in thousands)
Value
Value
Value
Value
Term Loan Facility
$
135,883
$
140,664
$
130,000
$
106,854
Revolving ABL Credit Facility
$
6,300
$
6,030
$
$
PPP Loan
$
-
$
-
$
10,000
$
8,589
Merger consideration payable to an affiliate
$
2,902
$
4,449
$
2,902
$
3,490
The fair value of our assets held for sale is determined using Level 3 measurements. Fair value measurements are applied with respect to our non-financial assets and liabilities measured on a nonrecurring basis, which would consist of measurements primarily of long-lived assets. There were no transfers between levels of the hierarchy for the years ended December 31, 2021 and 2020.
Revenue and Cost Recognition
We earn contract drilling revenues pursuant to drilling contracts entered into with our customers. We perform drilling services on a “daywork” basis, under which we charge a specified rate per day, or “dayrate.” The dayrate
associated with each of our contracts is a negotiated price determined by the capabilities of the rig, location, depth and complexity of the wells to be drilled, operating conditions, duration of the contract and market conditions. The term of land drilling contracts may be for a defined number of wells or for a fixed time period. We generally receive lump-sum payments for the mobilization of rigs and other drilling equipment at the commencement of a new drilling contract. Revenue and costs associated with the initial mobilization are deferred and recognized ratably over the term of the related drilling contract once the rig spuds. Costs incurred to relocate rigs and other equipment to an area in which a contract has not been secured are expensed as incurred. Our contracts provide for early termination fees in the event our customers choose to cancel the contract prior to the specified contract term. We record a contract liability for such fees received up front, and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract or until such time that all performance obligations are satisfied. While under contract, our rigs generally earn a reduced rate while the rig is moving between wells or drilling locations, or on standby waiting for the customer. Reimbursements for the purchase of supplies, equipment, trucking and other services that are provided at the request of our customers are recorded as revenue when incurred. The related costs are recorded as operating expenses when incurred. Revenue is presented net of any sales tax charged to the customer that we are required to remit to local or state governmental taxing authorities.
Our operating costs include all expenses associated with operating and maintaining our drilling rigs. Operating costs include all “rig level” expenses such as labor and related payroll costs, repair and maintenance expenses, supplies, workers’ compensation and other insurance, ad valorem taxes and equipment rental costs. Also included in our operating costs are certain costs that are not incurred at the rig level. These costs include expenses directly associated with our operations management team as well as our safety and maintenance personnel who are not directly assigned to our rigs but are responsible for the oversight and support of our operations and safety and maintenance programs across our fleet.
Leases
Lease liabilities are measured at the lease commencement date and are based on the present value of remaining payments contractually required under the contract. Payments that are variable in nature are excluded from the measurement of our lease liabilities and are recorded as an expense as incurred. Options to renew or extend a lease are included in the measurement of our lease liabilities only when it is reasonably certain that we will exercise these rights. In estimating the present value of our lease liabilities, payments are discounted at the interest rate stated in the applicable lease agreement or, if not available, our incremental borrowing rate (“IBR”), applied utilizing a portfolio approach. To determine our IBR, we utilize information publicly available from companies within our industry with similar credit profiles to construct a company-specific yield curve in order to estimate the rate of interest we would pay to borrow at various lease terms. At lease commencement, we recognize a lease right-of-use asset equal to our lease liability, adjusted for lease payments paid to the lessor prior to the lease commencement date, and any initial direct costs incurred. Operating lease expense is recorded on a straight-line basis over the lease term. For finance leases, we amortize our right-of-use assets on a straight-line basis over the shorter of the asset’s useful life or the lease term. Additionally, interest expense is recognized each period related to the accretion of our lease liabilities over their respective lease terms.
Stock-Based Compensation
We record compensation expense over the requisite service period for all stock-based compensation based on the grant date fair value of the award. The expense is included in selling, general and administrative expense in our statements of operations or capitalized in connection with rig construction activity.
Income Taxes
We use the asset and liability method of accounting for income taxes. Under this method, we record deferred income taxes based upon differences between the financial reporting basis and tax basis of assets and liabilities, and use enacted tax rates and laws that we expect will be in effect when we realize those assets or settle those liabilities. We review deferred tax assets for a valuation allowance based upon management’s estimates of whether it is more likely than not that a portion of the deferred tax asset will be fully realized in a future period.
We recognize the financial statement benefit of a tax position only after determining that the relevant taxing authority would more-likely-than-not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the consolidated financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
Our policy is to include interest and penalties related to the unrecognized tax benefits within the income tax expense (benefit) line item in our statements of operations.
During the preparation of our annual financial statements, we discovered an immaterial error in the previously disclosed deferred tax table. Management has evaluated the error and revised the previously reported amounts. See Note 9 “Income Taxes” for additional information.
Use of Estimates
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the balance sheet date, and the reported amounts of revenues and expenses recognized during the reporting period. Actual results could differ from these estimates. Significant estimates made by management include depreciation of property, plant and equipment, impairment of property, plant and equipment and assets held for sale, and the collectability of accounts receivable.
Recent Accounting Pronouncements
In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments, as additional guidance on the measurement of credit losses on financial instruments. The new guidance requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions and reasonable supportable forecasts. In addition, the guidance amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The new guidance is effective for all public companies for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. In October 2019, the FASB approved a proposal which grants smaller reporting companies additional time to implement FASB standards on current expected credit losses (CECL) to January 2023. As a smaller reporting company, we will defer adoption of ASU No. 2016-13 until January 2023. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
On April 1, 2020, we adopted the new standard, ASU 2020-04, Reference Rate Reform: Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions for applying generally accepted accounting principles to contracts, hedging relationships, and other transactions affected by reference rate reform (e.g. discontinuation of LIBOR) if certain criteria are met. In January 2021, the FASB issued ASU No. 2021-01, Reference Rate Reform, to provide clarifying guidance regarding the scope of Topic 848, effective immediately. As of December 31, 2021, we have not yet elected any optional expedients provided in the standard. We will apply the accounting relief as relevant contract and hedge accounting relationship modifications are made during the reference rate reform transition period. We do not expect the standard to have a material impact on our consolidated financial statements.
In August 2020, the FASB issued ASU No. 2020-06, Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, to simplify the accounting for convertible instruments by removing certain separation models in Subtopic 470-20, Debt-Debt with Conversion and Other Options, for convertible instruments. The pronouncement is effective for fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We do not expect the standard to have a material impact on our consolidated financial statements.
In May 2021, the FASB issued ASU No. 2021-04, Earnings Per Share (Topic 260), Debt - Modifications and Extinguishments (Subtopic 470-50), Compensation - Stock Compensation (Topic 718), and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options, which clarifies that issuers should account for modifications and exchanges of freestanding equity-classified written call options that remain equity-classified after these transactions as an exchange of the original instrument for a new instrument. The pronouncement is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2021, with early adoption permitted. We adopted this guidance on January 1, 2022 and there is no impact on our consolidated financial statements.
3. Revenue from Contracts with Customers
Drilling Services
Our revenues are principally derived from contract drilling services and the activities in our drilling contracts, for which revenues may be earned, include: (i) providing a drilling rig and the crews and supplies necessary to operate the rig; (ii) mobilizing and demobilizing the rig to and from the initial and final drill site, respectively; (iii) certain reimbursable activities; (iv) performing rig modification activities required for the contract; and (v) early termination revenues. We account for these integrated services provided under our drilling contracts as a single performance obligation, satisfied over time, that is comprised of a series of distinct time increments. Consideration for activities that are not distinct within the context of our contracts, and that do not correspond to a distinct time increment within the contract term, are allocated across the single performance obligation and recognized ratably in proportion to the actual services performed over the initial term of the contract. If taxes are required to be collected from customers relating to our drilling services, they are excluded from revenue.
Dayrate Drilling Revenue. Our drilling contracts provide that revenue is earned based on a specified rate per day for the activity performed. The majority of revenue earned under daywork contracts is variable, and depends on a rate scale associated with drilling conditions and level of service provided for each fractional-hour time increment over the contract term. Such rates generally include the full operating rate, moving rate, standby rate, and force majeure rate and determination of the rate per time increment is made based on the actual circumstances as they occur. Other variable consideration under these contracts could include reduced revenue related to downtime, delays or moving caps.
Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to revenue as services are rendered over the initial term of the related drilling contract. Demobilization fee revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.
In our contracts, there is generally significant uncertainty as to the amount of demobilization fee revenue that may ultimately be collected due to contractual provisions which stipulate that certain conditions be present at contract completion for such revenue to be received. For example, the amount collectible may be reduced to zero if the rig has been contracted with a new customer upon contract completion. Accordingly, the estimate for such revenue may be constrained depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.
Reimbursable Revenue. We receive reimbursements from our customers for the purchase of supplies, equipment and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof is highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer.
Capital Modification Revenue. From time to time, we may receive fees (on either a fixed lump-sum or variable dayrate basis) from our customers for capital improvements to our rigs to meet their requirements. Such revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract, as these activities are not considered to be distinct within the context of our contracts. We record a contract liability for such fees received up front, and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.
Early Termination Revenue. Our contracts provide for early termination fees in the event our customers choose to cancel the contract prior to the specified contract term. We record a contract liability for such fees received up front, and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract or until such time that all performance obligations are satisfied.
Disaggregation of Revenue
The following table summarizes revenues from our contracts disaggregated by revenue generating activity contained therein for the years ended December 31, 2021, 2020 and 2019:
Year Ended December 31,
(in thousands)
Dayrate drilling
$
79,597
$
70,976
$
184,374
Mobilization
3,283
3,256
5,365
Reimbursables
4,920
5,838
11,237
Early termination
-
3,348
1,405
Capital modification
-
Intangible
-
-
1,079
Other
-
Total revenue
$
87,955
$
83,418
$
203,602
Contract Balances
Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Contract asset balances could consist of demobilization fee revenue that we expect to receive that is recognized ratably throughout the contract term, but invoiced upon completion of the demobilization activities. Once the demobilization fee revenue is invoiced the corresponding contract asset is transferred to accounts receivable. Contract liabilities include payments received for mobilization fees as well as upgrade activities, which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.
The following table provides information about receivables and contract liabilities related to contracts with customers as of December 31, 2021 and 2020, respectively. We had no contract assets in either year.
December 31,
December 31,
(in thousands)
Receivables, which are included in “Accounts receivable, net”
$
22,167
$
9,772
Contract liabilities, which are included in “Accrued liabilities - deferred revenue”
$
(542)
$
(119)
Significant changes in the contract liabilities balance during the years ended December 31, 2021 and 2020 are as follows:
Year Ended December 31,
(in thousands)
Revenue recognized that was included in contract liabilities at beginning of period
$
$
(Increase) decrease in contract liabilities due to cash received, excluding amounts recognized as revenue
$
(542)
$
(119)
Transaction Price Allocated to the Remaining Performance Obligations
The following table includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) as of December 31, 2021. The estimated revenue does not include amounts of variable consideration that are constrained.
Year Ending December 31,
(in thousands)
Total
Revenue
$
$
-
$
-
$
The amounts presented in the table above consist only of fixed consideration related to fees for rig mobilizations and demobilizations, if applicable, which are allocated to the drilling services performance obligation as such performance obligation is satisfied. We have elected the exemption from disclosure of remaining performance obligations for variable consideration. Therefore, dayrate revenue to be earned on a rate scale associated with drilling conditions and level of service provided for each fractional-hour time increment over the contract term and other variable consideration such as penalties and reimbursable revenues, have been excluded from the disclosure.
Contract Costs
We capitalize costs incurred to fulfill our contracts that (i) relate directly to the contract, (ii) are expected to generate resources that will be used to satisfy our performance obligations under the contract and (iii) are expected to be recovered through revenue generated under the contract. These costs, which principally relate to rig mobilization costs at the commencement of a new contract, are deferred as a current or noncurrent asset (depending on the length of the contract term), and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Such contract costs, recorded as “Prepaid expenses and other current assets”, amounted to $0.6 million and $0.1 million on our consolidated balance sheets at December 31, 2021 and December 31, 2020, respectively. During the year ended December 31, 2021, contract costs increased by $3.1 million and we amortized $2.6 million of contract costs.
Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement.
4. Leases
As a Lessor
Our daywork drilling contracts, under which the vast majority of our revenues are derived, contain both a lease component and a service component.
We account for these contracts using the practical expedient to not separate non-lease components from lease components and, instead, to account for those components as a single amount, if the non-lease components otherwise would be accounted for under Topic 606 and both of the following are met: (i) the timing and pattern of transfer of non-lease components and lease components are the same; (ii) the lease component, if accounted for separately, would be classified as an operating lease.
If the non-lease component is the predominant component of the combined amount, an entity is required to account for the combined amount in accordance with Topic 606. Otherwise, the entity must account for the combined amount as an operating lease in accordance with Topic 842.
Revenues from our daywork drilling contracts meet both of the criteria above and we have determined both quantitatively and qualitatively that the service component of our daywork drilling contracts is the predominant component. Accordingly, we combine the lease and service components of our daywork drilling contracts and account for the combined amount under Topic 606. See Note 3 “Revenue from Contracts with Customers.”
As a Lessee
We have multi-year operating and financing leases for corporate office space, field location facilities, land, vehicles and various other equipment used in our operations. We also have a significant number of rentals related to our drilling operations that are day-to-day or month-to-month arrangements. Our multi-year leases have remaining lease terms of greater than one year to five years.
As a practical expedient, a lessee may elect not to apply the recognition requirements in ASC 842 to short-term leases. Instead a lessee may recognize the lease payments in profit or loss on a straight-line basis over the lease term and variable lease payments in the period in which the obligation for those payments is incurred. We elected to utilize this practical expedient.
The components of lease expense were as follows:
Year Ended
Year Ended
(in thousands)
December 31, 2021
December 31, 2020
Operating lease expense
$
$
Short-term lease expense
3,033
2,863
Variable lease expense
Finance lease expense:
Amortization of right-of-use assets
$
1,158
$
1,257
Interest expense on lease liabilities
Total finance lease expense
1,743
2,063
Total lease expense
$
6,135
$
5,924
Supplemental cash flow information related to leases is as follows:
Year Ended
Year Ended
(in thousands)
December 31, 2021
December 31, 2020
Cash paid for amounts included in measurement of lease liabilities:
Operating cash flows from operating leases
$
$
Operating cash flows from finance leases
$
$
Financing cash flows from finance leases
$
3,594
$
4,340
Right-of-use assets obtained or recorded in exchange for lease obligations:
Operating leases
$
-
$
1,601
Finance leases
$
1,503
$
2,648
Supplemental balance sheet information related to leases is as follows:
(in thousands)
December 31, 2021
December 31, 2020
Operating leases:
Other long-term assets, net
$
1,437
$
2,150
Accrued liabilities
$
$
Other long-term liabilities
1,036
1,729
Total operating lease liabilities
$
1,729
$
2,693
Finance leases:
Property, plant and equipment
$
14,989
$
13,700
Accumulated depreciation
(1,989)
(981)
Property, plant and equipment, net
$
13,000
$
12,719
Current portion of long-term debt
$
4,464
$
3,351
Long-term debt
1,305
4,570
Total finance lease liabilities
$
5,769
$
7,921
Weighted-average remaining lease term
Operating leases
2.5 years
3.2 years
Finance leases
1.3 years
2.0 years
Weighted-average discount rate
Operating leases
10.84
%
8.25
%
Finance leases
8.64
%
8.88
%
Maturities of lease liabilities at December 31, 2021 were as follows:
(in thousands)
Operating Leases
Finance Leases
$
$
4,868
1,068
-
-
-
-
Thereafter
-
-
Total cash lease payment
1,972
6,136
Less: imputed interest
(243)
(367)
Total lease liabilities
$
1,729
$
5,769
5. Inventories
Inventories consisted of the following:
December 31,
(in thousands)
Rig components and supplies
$
1,171
$
1,038
We determined that no reserve for obsolescence was needed at December 31, 2021 or 2020. No inventory obsolescence expense was recognized during the years ended December 31, 2021, 2020 and 2019.
6. Property, Plant and Equipment
Major classes of property, plant, and equipment, which include finance lease assets, consisted of the following (in millions):
December 31,
(in thousands)
Land
$
$
Buildings
2,800
3,189
Drilling rigs and related equipment
558,530
525,933
Machinery, equipment and other
1,767
1,576
Finance leases
14,989
13,700
Vehicles
Construction in progress
2,024
19,876
Total
$
580,427
$
564,778
Less: Accumulated depreciation
(218,081)
(182,539)
Total Property, plant and equipment, net
$
362,346
$
382,239
Repairs and maintenance expense included in operating costs in our statements of operations totaled $13.4 million, $9.7 million and $27.2 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Depreciation expense was $38.9 million, $43.9 million and $45.4 million for the years ended December 31, 2021, 2020 and 2019, respectively.
7. Supplemental Consolidated Balance Sheet and Cash Flow Information
Prepaid expenses and other current assets consisted of the following:
(in thousands)
December 31, 2021
December 31, 2020
Prepaid insurance
$
3,463
$
3,346
Prepaid other
Deferred mobilization costs
Insurance claim receivable
Other current assets
$
4,787
$
4,102
Accrued liabilities consisted of the following:
(in thousands)
December 31, 2021
December 31, 2020
Accrued salaries and other compensation (1)
$
4,154
$
1,472
Insurance
2,523
2,127
Deferred revenues
Property and other taxes
2,594
2,166
Interest
4,372
3,573
Operating lease liability - current
Other
$
15,617
$
10,723
(1) The increase in accrued salaries primarily relates to an increase in the number of operating rigs and higher incentive compensation accruals in 2021. We cancelled our incentive compensation program in 2020 and reinstated it in 2021 as market conditions improved.
Supplemental consolidated cash flow information:
Year Ended December 31,
(in thousands)
Supplemental disclosure of cash flow information
Cash paid during the year for interest
$
6,918
$
13,309
$
13,974
Supplemental disclosure of non-cash investing and financing activities
Change in property, plant and equipment purchases in accounts payable
$
3,564
$
(7,201)
$
1,607
Additions to property, plant & equipment through finance leases
$
1,503
$
2,650
$
13,143
Transfer of assets from held and used to held for sale
$
(1,082)
$
-
$
(18,506)
Transfer from inventory to fixed assets
$
-
$
-
$
(406)
Extinguishment of finance lease obligations from sale of assets classified as finance leases
$
(65)
$
(1,549)
$
(249)
Gain on extinguishment of debt
$
10,000
$
-
$
-
8. Long-term Debt
Our Long-term Debt consisted of the following:
December 31,
(in thousands)
Term Loan Facility due October 1, 2023
$
135,883
$
130,000
Revolving ABL Credit Facility due October 1, 2023
6,300
PPP Loan
-
10,000
Finance lease obligations
5,769
7,921
147,952
147,929
Less: current portion of PPP Loan
-
(4,286)
Less: current portion of finance leases
(4,464)
(3,351)
Less: Term Loan Facility deferred financing costs
(1,748)
(2,659)
Long-term debt
$
141,740
$
137,633
Presented below is a schedule of the principal repayment requirements of long-term debt by fiscal year as of December 31, 2021:
(in thousands)
Thereafter
Total
Term Loan Facility
$
-
$
135,883
$
-
$
-
$
135,883
Revolving ABL Credit Facility
-
6,300
-
-
6,300
Total
$
-
$
142,183
$
-
$
-
$
142,183
Future payments of finance leases are included in Note 5 “Leases.”
Credit Facilities
On October 1, 2018, we entered into a term loan Credit Agreement (the “Term Loan Credit Agreement”) for an initial term loan in an aggregate principal amount of $130.0 million, (the “Term Loan Facility”) and (b) a delayed draw term loan facility in an aggregate principal amount of up to $15.0 million (the “DDTL Facility”, and together with the Term Loan Facility, the “Term Facilities”). The Term Facilities have a maturity date of October 1, 2023, at which time all outstanding principal under the Term Facilities and other obligations become due and payable in full. The Term Loan Credit Agreement balance was $135.9 million at December 31, 2021 and increased to $139.1 million on January 1, 2022. As of December 31, 2021 the DDTL Facility commitment was $11.9 million and decreased to $8.7 million on January 1, 2022.
At our election, interest under the Term Loan Facility is 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%.
The Term Loan Credit Agreement contains financial covenants, including a liquidity covenant of $10.0 million and a springing fixed charge coverage ratio covenant of 1:1 that is tested when availability under the ABL Credit Facility (defined below) and the DDTL Facility is below $5.0 million at any time that a DDTL Facility loan is outstanding. The Term Loan Credit Agreement also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments, investments and transactions with affiliates. The Term Loan Credit Agreement also provides for customary events of default, including breaches of material covenants, defaults under the ABL Credit Facility or other material agreements for indebtedness, and a change of control. We are in compliance with our covenants as of December 31, 2021.
The obligations under the Term Loan Credit Agreement are secured by a first priority lien on collateral (the “Term Priority Collateral”) other than accounts receivable, deposit accounts and other related collateral pledged as first priority collateral (“Priority Collateral”) under the ABL Credit Facility (defined below) and a second priority lien on such Priority Collateral, and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries. MSD PCOF Partners IV, LLC (an affiliate of MSD Partners, L.P. “MSD Partners”) is the lender of our $130.0 million Term Loan Facility.
In June 2020, we revised our Term Loan Credit Agreement to elect to pay accrued and unpaid interest, solely during one three-consecutive-month period immediately following such notice, in-kind (the “PIK Amount”). We agreed to pay an additional amount equal to 0.75% of the aggregate principal amount of the loans under the Term Loan Credit Agreement plus all PIK Amounts, if any, that are added to such principal amount being repaid or prepaid on either the maturity date or upon the occurrence of an acceleration of obligations under the Term Loan Credit Agreement. As such, the additional amount, approximately $1.0 million, was recorded as a direct deduction from the face amount of the Term Loan Facility and as a long-term payable on our consolidated balance sheets. The additional amount is amortized as interest expense over the term of the Term Loan Facility. On April 1, 2021, we elected to pay in-kind the $2.8 million interest payment due under our Term Loan, which increased our Term Loan balance accordingly. In September 2021, we amended our Term Loan Credit Agreement to permit us, subject to required prior notice, to elect to pay accrued and unpaid interest due October 1, 2021, in-kind. The payment-in-kind is in lieu of exercising a drawdown under the DDTL Facility under the Term Loan Credit Agreement, reducing the amount of the DDTL Facility commitment of $15 million by the amount of the accrued and unpaid interest due October 1, 2021. On October 1, 2021, we elected to pay in-kind the $3.1 million interest payment due under our Term Loan Credit Agreement. Subsequent to December 31, 2021, we elected to pay in-kind $3.2 million of interest due on January 1, 2022, which will draw down our remaining $11.9 million DDTL Facility and increase our Term Loan Facility balance accordingly.
Additionally, on October 1, 2018, we entered into a $40.0 million revolving Credit Agreement (the “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 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 ABL Credit Facility has a maturity date of the earlier of October 1, 2023 or the maturity date of the Term Loan Credit Agreement.
At our election, interest under the ABL Credit Facility is 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) LIBOR with an interest period of one month, plus 1.0%, and (c) 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 LIBOR for the applicable interest period plus an applicable LIBOR margin ranging from 2.0% to 2.5% 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 ABL Credit Facility commitment.
The ABL Credit Facility contains a springing fixed charge coverage ratio covenant of 1:1 that is tested when availability is less than 10% of the maximum credit. The ABL Credit Facility also contains other customary affirmative and negative covenants, including limitations on indebtedness, liens, fundamental changes, asset dispositions, restricted payments, investments and transactions with affiliates. The ABL Credit Facility also provides for customary events of default, including breaches of material covenants, defaults under the Term Loan Credit Agreement or other material agreements for indebtedness, and a change of control. We are in compliance with our financial covenants as of December 31, 2021.
The obligations under the ABL Credit Facility are secured by a first priority lien on Priority Collateral, which includes all accounts receivable and deposit accounts, and a second priority lien on the Term Priority Collateral, and are unconditionally guaranteed by all of our current and future direct and indirect subsidiaries. As of December 31, 2021, the weighted-average interest rate on our borrowings was 8.81%. At December 31, 2021, the borrowing base under our ABL Credit Facility was $17.8 million, and we had $11.3 million of availability remaining of our $40.0 million commitment on that date.
On April 27, 2020, we entered into an unsecured loan in the aggregate principal amount of $10.0 million (the “PPP Loan”) pursuant to the Paycheck Protection Program (the “PPP”), sponsored by the Small Business Administration (the “SBA”) as guarantor of loans under the PPP. The PPP was part of the CARES Act, and it provided loans to qualifying businesses in a maximum amount equal to the lesser of $10.0 million and 2.5 times the average monthly payroll expenses of the qualifying business. The proceeds of the loan could only be used for payroll costs, rent, utilities, mortgage interests, and interest on other pre-existing indebtedness (the “permissible purposes”) during the covered period that ended on or about October 13, 2020. Interest on the PPP loan was equal to 1.0% per annum. All or part of the loan was forgivable based upon the level of permissible expenses incurred during the covered period and changes to the Company’s headcount during the covered period to headcount during the period from January 1, 2020 to February 15, 2020. In the third quarter of 2021, we received notice from the SBA that our loan was forgiven and paid in full. The loan is considered an extinguishment of debt and is recorded as “Gain on extinguishment of debt” in our Statements of Operations. We have not accrued any liability associated with the risk of an adverse SBA review.
9. Income Taxes
In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes, to simplify the accounting for income taxes. We adopted this guidance on January 1, 2021 and there has been no material impact on our consolidated financial statements.
The components of the income tax expense are as follows:
Year Ended December 31,
(in thousands)
Current:
Federal
$
-
$
-
$
-
State
-
-
-
$
-
$
-
$
-
Deferred:
Federal
$
17,417
$
-
$
-
State
1,115
(147)
(122)
Income tax expense (benefit)
$
18,532
$
(147)
$
(122)
The effective tax rate (as a percentage of net loss before income taxes) is reconciled to the U.S. federal statutory rate as follows:
Year Ended December 31,
(in thousands)
Income tax benefit at the statutory federal rate (21%)
$
(10,128)
$
(20,285)
$
(12,791)
Nondeductible expenses
PPP Loan Forgiveness
(2,127)
-
-
Valuation allowance
29,268
19,800
12,626
State taxes, net of federal benefit
(116)
(396)
Stock-based compensation and other
Income tax expense (benefit)
$
18,532
$
(147)
$
(122)
Effective tax rate
(38.5)
%
0.2
%
0.2
%
Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of our deferred tax assets and liabilities are as follows:
December 31,
(in thousands)
Deferred income tax assets
Merger-related expenses
$
$
1,130
Bad debts
-
Stock-based compensation
1,247
1,168
Accrued liabilities and other
Deferred revenue
Interest limitation
3,281
3,298
ROU Asset
Net operating losses
93,733
79,373
Total net deferred tax assets
$
100,011
$
85,929
Deferred income tax liabilities
Prepaids
$
(740)
$
(769)
Property, plant and equipment
(38,000)
(35,086)
Intangible assets
-
-
ROU Liability
(315)
(738)
Other
-
(194)
Total net deferred tax liabilities
$
(39,055)
$
(36,787)
Valuation allowance
$
(79,993)
$
(49,647)
Net deferred tax liability
$
(19,037)
$
(505)
During the course of preparing the financial statements for the year ended December 31, 2021, we discovered an error in the tax accounting relating to certain asset impairments and the related tax attributes in prior years. We evaluated the materiality of the error and determined it was immaterial, although we have corrected the amounts above. As a result, as of December 31, 2020, deferred tax assets increased approximately $14.3 million, deferred tax liabilities increased approximately $14.8 million and the valuation allowance decreased by approximately $0.5 million. This correction did not impact net deferred taxes or the consolidated balance sheet, results of operations or cash flows.
As of December 31, 2021, we had a total of $432.5 million of net operating loss carryforwards, of which $131.1 million will begin to expire in 2031 and $301.4 million will be carried forward indefinitely.
Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an ownership change. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than
50 percentage points over a three-year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382. We believe we had an ownership change in April 2016, October 2018 in connection with the Sidewinder Merger, and in October 2021. We are subject to an annual limitation on the usage of our NOL and as a result of our limitation from the ownership change in October 2021, we expect to have approximately $81.2 million of NOLs expire before becoming available to be utilized by the Company. Management will continue to monitor the potential impact of Section 382 with respect to our NOL carryforward.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2021, we had no unrecognized tax benefits. We file income tax returns in the United States and in various state jurisdictions. With few exceptions, we are subject to United States federal, state and local income tax examinations by tax authorities for tax periods 2012 and forward. Our federal and state tax returns for 2012 and subsequent years remain subject to examination by tax authorities due to existence of NOLs in each jurisdiction. Although we cannot predict the outcome of future tax examinations, we do not anticipate that the ultimate resolution of these examinations will have a material impact on our financial position, results of operations, or cash flows.
In assessing the realizability of the deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized. In prior years, we determined that the deferred tax assets did not meet the more likely than not threshold of being utilized and thus recorded a valuation allowance. However, due to the IRC Section 382 change and the annual limitation on our NOL, we do not anticipate having enough NOL available to offset our deferred tax liabilities in the appropriate years. We have increased our valuation allowance to reflect such.
Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the consolidated statement of operations. We have not recorded any interest or penalties associated with unrecognized tax benefits.
10. Stock-Based Compensation
Prior to June 2019, we issued common stock-based awards to employees and non-employee directors under our 2012 Long-Term Incentive Plan adopted in March 2012 (the “2012 Plan”). In June 2019, we adopted the 2019 Omnibus Incentive Plan (the “2019 Plan”) providing for common stock-based awards to employees and non-employee directors. The 2019 Plan permits the granting of various types of awards, including stock options, restricted stock and restricted stock unit awards, and up to 275,000 shares were authorized for issuance. Restricted stock and restricted stock units may be granted for no consideration other than prior and future services. The purchase price per share for stock options may not be less than the market price of the underlying stock on the date of grant. In connection with the adoption of the 2019 Plan, no further awards will be made under the 2012 Plan. As of December 31, 2021, approximately 50,212 shares were available for future awards. Our policy is to account for forfeitures of share-based compensation awards as they occur.
A summary of compensation cost recognized for stock-based payment arrangements is as follows:
Year Ended December 31,
(in thousands)
Compensation cost recognized:
Restricted stock and restricted stock units
$
1,724
$
1,979
$
1,871
Cash-settled stock appreciation rights
-
-
Total stock-based compensation
$
2,295
$
1,979
$
1,871
Stock Options
Prior to 2016, we granted stock options that remain outstanding. No options were exercised or granted during the years ended December 31, 2021, 2020 or 2019. It is our policy that in the future any shares issued upon option exercise will be issued initially from any available treasury shares or otherwise as newly issued shares.
We use the Black-Scholes option pricing model to estimate the fair value of stock options granted to employees and non-employee directors. The fair value of the options is amortized to compensation expense on a straight-line basis over the requisite service periods of the stock awards, which are generally the vesting periods.
The following summary reflects the stock option activity and related information for the year ended December 31, 2021:
Year Ended December 31, 2021
Weighted
Average
Exercise
Options
Price
Outstanding at January 1, 2021
33,458
$
254.80
Granted
-
-
Exercised
-
-
Forfeited/expired
(5,591)
254.80
Outstanding at December 31, 2021
27,867
$
254.80
Exercisable at December 31, 2021
27,867
$
254.80
The number of options exercisable at December 31, 2021 was 27,867 with a weighted-average remaining contractual life of 0.16 years and a weighted-average exercise price of $254.80 per share.
As of December 31, 2021, there was no unrecognized compensation cost related to outstanding stock options. No options vested during the years ended December 31, 2021, 2020 and 2019.
Time-Based Restricted Stock and Restricted Stock Units
We have granted time-based restricted stock and restricted stock units to key employees under the 2012 plan and the 2019 plan.
Time-Based Restricted Stock
Time-based restricted stock awards consist of grants of our common stock that vest over three to five years. We recognize compensation expense on a straight-line basis over the vesting period. The fair value of time-based restricted stock awards is determined based on the estimated fair market value of our shares on the grant date. As of December 31, 2021, there was $1.0 million in unrecognized compensation cost related to unvested time-based restricted stock awards. This cost is expected to be recognized over a weighted-average period of 1.0 years.
A summary of the status of our time-based restricted stock awards and of changes in our time-based restricted stock awards outstanding for the year ended December 31, 2021, 2020 and 2019 is as follows:
Year Ended December 31, 2021
Weighted
Average
Grant-Date
Fair Value
Shares
Per Share
Outstanding at January 1, 2019
69,295
$
64.40
Granted
-
-
Vested
-
-
Forfeited/expired
(6,478)
64.40
Outstanding at January 1, 2020
62,817
64.40
Granted
-
-
Vested
(16,767)
64.40
Forfeited/expired
(5,716)
64.40
Outstanding at January 1, 2021
40,334
$
64.40
Granted
-
-
Vested
(10,176)
64.40
Forfeited
(3,268)
64.40
Outstanding at December 31, 2021
26,890
$
64.40
Time-Based Restricted Stock Units
We have granted three-year time-based vested restricted stock unit awards where each unit represents the right to receive, at the end of a vesting period, one share of ICD common stock with no exercise price. The fair value of time-based restricted stock unit awards is determined based on the estimated fair market value of our shares on the grant date. As of December 31, 2021, there was $0.3 million of total unrecognized compensation cost related to unvested time-based restricted stock unit awards. This cost is expected to be recognized over a weighted-average period of 0.6 years.
A summary of the status of our time-based restricted stock unit awards and of changes in our time-based restricted stock unit awards outstanding for the year ended December 31, 2021, 2020 and 2019 is as follows:
Year Ended December 31, 2021
Weighted
Average
Grant-Date
Fair Value
RSUs
Per Share
Outstanding at January 1, 2019
20,479
95.80
Granted
28,244
38.80
Vested and converted
(2,737)
94.20
Forfeited/expired
(1,547)
94.20
Outstanding at January 1, 2020
44,439
59.71
Granted
64,914
12.96
Vested and converted
(26,490)
54.97
Forfeited/expired
(18,966)
30.75
Outstanding at January 1, 2021
63,897
$
22.78
Granted
77,938
4.95
Vested and converted
(28,611)
25.75
Forfeited
(3,313)
51.34
Outstanding at December 31, 2021
109,911
$
8.50
Performance-Based and Market-Based Restricted Stock Units
We have granted three-year performance-based and market-based restricted stock unit awards, where each unit represents the right to receive, at the end of a vesting period, up to two shares of ICD common stock with no exercise price. Exercisability of the market-based restricted stock unit awards is based on our total shareholder return ("TSR") as measured against the TSR of a defined peer group and vesting of the performance-based restricted stock unit awards is based on our cumulative return on invested capital ("ROIC") as measured against ROIC performance goals determined by the compensation committee of our Board of Directors, over a three-year period. We used a Monte Carlo simulation model to value the TSR market-based restricted stock unit awards. The fair value of the performance-based restricted stock unit awards is based on the market price of our common stock on the date of grant. During the restriction period, the performance-based and market-based restricted stock unit awards may not be transferred or encumbered, and the recipient does not receive dividend equivalents or have voting rights until the units vest. As of December 31, 2021, unrecognized compensation cost related to unvested performance-based and market-based restricted stock unit awards totaled $0.1 million, which is expected to be recognized over a weighted-average period of 0.5 years.
The assumptions used to value our TSR market-based restricted stock unit awards granted during the year ended December 31, 2019 were a risk-free interest rate of 1.86%, an expected volatility of 58.2% and an expected dividend yield of 0.0%. Based on the Monte Carlo simulation, these restricted stock unit awards were valued at $29.00.
The assumptions used to value our TSR market-based restricted stock unit awards granted during the year ended December 31, 2020 were a risk-free interest rate of 1.38%, an expected volatility of 68.5% and an expected dividend yield of 0.0%. Based on the Monte Carlo simulation, these restricted stock unit awards were valued at $12.42.
A summary of the status of our performance-based and market-based restricted stock unit awards and of changes in our restricted stock unit awards outstanding for the year ended December 31, 2021, 2020 and 2019 is as follows:
Year Ended December 31, 2021
Weighted
Average
Grant-Date
Fair Value
RSUs
Per Share
Outstanding at January 1, 2019
-
-
Granted
23,480
33.90
Vested and converted
-
-
Forfeited/expired
-
-
Outstanding at January 1, 2020
23,480
33.90
Granted
24,854
12.42
Vested and converted
(1,260)
30.89
Forfeited/expired
(8,515)
21.24
Outstanding at January 1, 2021
38,559
$
22.95
Granted
-
-
Vested and converted
-
-
Forfeited
(11,274)
19.20
Outstanding at December 31, 2021
27,285
$
24.50
Time-Based Cash-Settled Stock Appreciation Rights
We have granted time-based, cash-settled stock appreciation rights (“SARs”) to certain employees. The SARs have a term of seven years, an exercise price of $5.73 per share, with the market price upon exercise capped at $10.00 per share, and vest ratably on the first, second and third anniversaries of the date of grant. Because these SARs are cash-settled, they are classified as “liability-classified awards” which are remeasured at their fair value at the end of each reporting period until settlement.
Time-based, cash-settled SARs have no effect on dilutive shares or shares outstanding as any appreciation of our common stock over the exercise price is paid in cash and not in common stock.
The fair value of time-based cash-settled SARs is revalued (mark-to-market) each reporting period using a Monte Carlo simulation model based on period-end stock price. Expected term of the SARs is calculated as the average of each vesting tranche’s midpoint between vesting date and expiration date plus the vesting period. Expected volatility is based on the historical volatility of our stock for the length of time corresponding to the expected term of the SARs. The risk-free interest rate is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the SARs.
The following weighted-average assumptions were used in calculating the fair value of time-based cash-settled SARs granted during the year ended December 31, 2021 using the Monte Carlo simulation model:
Year Ended
December 31, 2021
Expected term of cash-settled SARs
3.6 years
Expected volatility factor
124.5
%
Expected dividend yield
-
%
Risk-free interest rate
1.08
%
Changes to the company’s non-vested time-based cash-settled SARs during the year ended December 31, 2021 are as follows:
Year Ended December 31, 2021
Weighted Average
Cash-settled SARs
Fair Value Price
(in thousands)
Per Share
Non-vested cash-settled SARs at January 1, 2021
-
$
-
Granted
2,954
0.66
Vested
-
-
Forfeited
(41)
0.66
Non-vested cash-settled SARs at December 31, 2021
2,913
$
0.66
As of December 31, 2021, there was $1.4 million of unrecognized compensation cost related to non-vested time-based cash-settled SARs that is expected to be recognized over a weighted-average period of 1.1 years.
11. Stockholders’ Equity and Loss per Share
As of December 31, 2021, we had a total of 10,206,085 shares of common stock, $0.01 par value, outstanding, including 26,890 shares of restricted stock. We also had 81,846 shares held as treasury stock. Total authorized common stock is 50,000,000 shares.
Basic earnings (loss) per common share (“EPS”) are computed by dividing income (loss) available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that would occur if securities or other contracts to issue common stock were exercised or converted into common stock. A reconciliation of the numerators and denominators of the basic and diluted losses per share computations is as follows:
For the Years Ended December 31,
(in thousands, except per share data)
Net loss (numerator):
$
(66,712)
$
(96,638)
$
(60,788)
Loss per share:
Basic and diluted
$
(8.89)
$
(19.69)
$
(16.11)
Shares (denominator):
Weighted average common shares outstanding - basic
7,507
4,907
3,774
Weighted average common shares outstanding - diluted
7,507
4,907
3,774
(1) Prior period results have been adjusted to reflect the 1-for-20 reverse stock split that took place in February 2020. See Reverse Stock Split in Note 1 “Nature of Operations and Recent Developments.”
For all years presented, the computation of diluted loss per share excludes the effect of certain outstanding stock options and restricted stock units because their inclusion would be anti-dilutive. The number of options that were excluded from diluted loss per share were 27,867, 33,458 and 33,458 during the years ended December 31, 2021, 2020 and 2019, respectively. RSUs, which are not participating securities and are excluded from our diluted loss per share because they are anti-dilutive were 137,196, 102,456 and 44,447 for the years ended December 31, 2021, 2020 and 2019, respectively.
12. Segment and Geographical Information
We report one segment because all of our drilling operations are all located in the United States and have similar economic characteristics. We build rigs and engage in land contract drilling for oil and natural gas in the United
States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by rig; however, financial performance is measured as a single enterprise and not on a rig-by-rig basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.
13. Commitments and Contingencies
Purchase Commitments
As of December 31, 2021, we had outstanding purchase commitments to a number of suppliers totaling $2.9 million related primarily to rig equipment or components ordered but not received. We have paid deposits of $0.2 million related to these commitments.
Letters of Credit
As of December 31, 2021, we had outstanding letters of credit totaling $0.2 million as collateral for Sidewinder’s pre-acquisition insurance programs. As of December 31, 2021, no amounts had been drawn under these letters of credit.
Employment Agreements
We have entered into employment agreements with six key executives, with original terms of three years, that automatically extend a year prior to expiration, provided that neither party has provided a written notice of termination before that date. These agreements in aggregate provide for minimum annual cash compensation of $1.9 million and cash severance payments totaling $4.9 million for termination by ICD without cause, or termination by the employee for good reason, both as defined in the agreements.
Contingencies
Our operations inherently expose us to various liabilities and exposures that could result in third party lawsuits, claims and other causes of action. While we insure against the risk of these proceedings to the extent deemed prudent by our management, we can offer no assurance that the type or value of this insurance will meet the liabilities that may arise from any pending or future legal proceedings related to our business activities. There are no current legal proceedings that we expect will have a material adverse impact on our consolidated financial statements.
14. Concentration of Market and Credit Risk
We derive all our revenues from drilling services contracts with companies in the oil and natural gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility in oil and natural gas prices. We have a number of customers that account for 10% or more of our revenues. For 2021, these customers included Indigo Minerals, LLC, a subsidiary of Southwestern Energy Company, (25%) and Endeavor Energy Resources (10%). For 2020, these customers included Diamondback Energy, Inc. (16%), BPX Operating Company (15%), GeoSouthern Energy Corporation (12%) and Indigo Minerals, LLC (12%). For 2019, these customers included Diamondback Energy, Inc. (17%), GeoSouthern Energy Corporation (15%) and COG Operating, LLC, a subsidiary of Concho Resources, Inc. (14%).
Our trade receivables are with a variety of E&P and other oilfield service companies. We perform ongoing credit evaluations of our customers, and we generally do not require collateral. We do occasionally require deposits from customers whose creditworthiness is in question prior to providing services to them. As of December 31, 2021, Indigo Minerals, LLC, a subsidiary of Southwestern Energy Company, (23%), Endeavor Energy Resources (21%) and Bayswater Operating Company, LLC (12%) accounted for 10% or more of our accounts receivable. As of December 31, 2020, BPX Operating Company (26%), Indigo Minerals, LLC (25%), GeoSouthern Energy Corporation (13%) and Triple Crown Resources, LLC (10%) accounted for 10% or more of our accounts receivable. As of
December 31, 2019, Diamondback Energy, Inc. (21%) and GeoSouthern Energy Corporation (14%) accounted for 10% or more of our accounts receivable.
We have concentrated credit risk for cash by maintaining deposits in major banks, which may at times exceed amounts covered by insurance provided by the United States Federal Deposit Insurance Corporation (“FDIC”). We monitor the financial health of the banks and have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk. As of December 31, 2021, we had approximately $3.8 million in cash and cash equivalents in excess of FDIC limits.
15. Related Parties and Other Matters
In conjunction with the closing of the Sidewinder Merger on October 1, 2018, we entered into the Term Loan Credit Agreement for an initial term loan in an aggregate principal amount of $130.0 million and a delayed draw term loan facility in an aggregate principal amount of up to $15.0 million. MSD PCOF Partners IV, LLC (an affiliate of MSD Partners) is the lender of our $130.0 million Term Loan Facility.
We made interest payments on the Term Loan Facility totaling $5.9 million during the year ended December 31, 2021. Additionally, we have recorded merger consideration payable to an affiliate of $2.9 million plus accrued interest of $1.2 million related to proceeds received from the sale of specific assets earmarked in the Sidewinder Merger agreement as assets held for sale with the Sidewinder unitholders receiving the net proceeds. We are contractually obligated to make this payment to MSD, the unitholders’ representative, by the earlier of (i) June 30, 2022 and (ii) a Change of Control Transaction.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Balance at
Charged to
Beginning of
Costs and
Balance at
(in thousands)
Period
Expenses
Deductions
Other (1)
End of Period
Year Ended December 31, 2021:
Allowance for doubtful accounts
$
$
(52)
$
(466)
$
-
$
-
Valuation allowance for deferred tax assets
$
49,647
$
30,346
$
-
-
$
79,993
Year Ended December 31, 2020:
Allowance for doubtful accounts
$
$
$
-
$
-
$
Valuation allowance for deferred tax assets
$
28,846
$
20,801
$
-
-
$
49,647
Year Ended December 31, 2019:
Allowance for doubtful accounts
$
-
$
$
-
$
-
$
Valuation allowance for deferred tax assets
$
16,022
$
12,626
$
-
$
$
28,846
(1) Amount comprised principally of purchase accounting adjustments in connection with the Sidewinder Merger.

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Our principal executive officer and principal financial officer have concluded that our current disclosure controls and procedures were effective as of December 31, 2021 at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of our internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the 2013 framework). Based on this assessment using this criteria, our management determined that our internal control over financial reporting was effective as of December 31, 2021.
Attestation Report of the Independent Registered Public Accounting Firm
Not applicable.

---

ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of December 31, 2021.
Our Board of Directors has adopted a Code of Business Conduct and Ethics, which applies to all our officers and employees, a Code of Ethics for Senior Officers of the Company and a Code of Business Conduct and Ethics for Directors, which applies to all our directors. A copy of each of these codes of business conduct and ethics is available on our website at http://icdrilling.investorroom.com. Stockholders may also request a printed copy of either code of business conduct and ethics, free of charge, by contacting us at Independence Contract Drilling, Inc., 20475 State Highway 249, Suite 300, Houston, TX 77070 or by telephone at (281) 598-1230 or by emailing Investor.relations@icdrilling.com. Any waiver of any of the codes of business conduct and ethics for executive officers or directors may be made only by our Board of Directors or a committee of the Board of Directors committee to which the Board of Directors has delegated that authority and will be promptly disclosed to our stockholders as required by applicable United States federal securities laws and the corporate governance rules of the NYSE. Amendments to either code of business conduct and ethics must be approved by our Board of Directors and will be promptly disclosed (other than technical, administrative or non-substantive changes) on our website.

---

ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of December 31, 2021.

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of December 31, 2021.

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of December 31, 2021.

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2022 Annual Meeting of Shareholders, which will be filed with the SEC within 120 business days of December 31, 2021.
PART IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) List of filed documents:
(1) Financial Statements
Our Consolidated Financial Statements and accompanying footnotes are included under Part II, “Item 8. Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
(2) Financial Statement Schedules
Schedule II - Valuation and Qualifying Accounts is included under Part II, “Item 8. Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.
(3) Exhibits
The exhibits required by Item 601 of Regulation S-K are listed in subparagraph (b) below.
(b) Exhibits
The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Annual Report on Form 10-K and are incorporated herein by reference.