UNITED STATES SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549

Form 10-K

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ☑þ 

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

There were 24,629,33324,403,659 shares of the registrant’s common stock outstanding as of March 13, 2015.February 12, 2016.  

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 the terms “GES,” “predecessor” and “our predecessor” refer to Global Energy Services Operating, LLC.

We provide land-based contract drilling services for oil and natural gas producers targeting unconventional resource plays in the United States. We construct, own and operate a premium land rig fleet comprised entirely of newly constructed, technologically advanced, custom designed ShaleDriller™ShaleDriller® rigs that are specifically engineered and designed to optimize the development of our customers’ most technically demanding oil and gas properties. All of our operating rigs are currently drilling in the Permian Basin, but our rigs have previously operated in the Mid-Continent region and Eagle Ford Shale. We are focused on creating stockholder and customer value through our commitment to operational excellence and our focus on safety. Although we believe the current downturn in oil prices will presentis presenting significant challenges for the drilling industry, we believe that we are well positioned to successfully navigate the downturn due to our premium rigs, operational excellence, commitment to safety, term contract coverage and strong balance sheet.asset base.

Our standardized fleet currently consists of fourteen premium ShaleDriller™ rigs, including three rigs under construction.ShaleDriller® rigs. Of these fourteen rigs, twelve includeare 200 Series rigs equipped with our integrated multi-directionalomni-directional walking system that isdesigned specifically designed to optimize pad drilling for our customers. We also have substantially completed the optionconversion of one of our non-walking rigs to 200 Series status, which we expect will be available for operations at the end of the first quarter of 2016. We also have the ability to upgrade our tworemaining non-walking rigsrig to 200 Series status when they aremarket conditions improve, but until such time this rig has been decommissioned and we do not under contract.intend to market it. Every ShaleDriller™ShaleDriller® rig in our fleet is a 1500-hp, AC programmable rig (“AC rig”) designed to be fast-moving between drilling sites and is equipped with top drives, automated tubular handling systems and blowout preventer (“BOP”) handling systems. Twelve of our fourteen rigs are equipped with bi-fuel capabilities (they operate on either diesel or a natural gas-diesel blend).

Our first rig began drilling in May 2012. All of our operating rigs have been contracted prior to the completion of construction, and every rig has been constructed and commenced drilling operations in accordance with our customers’ delivery requirements. Although our ShaleDriller™ rig is capable of drilling in virtually any onshore area in the U.S., weWe currently focus our operations on unconventional resource plays located in geographic regions that we can efficiently support from our Houston, Texas facilities in order to maximize economies of scale. Currently, our rigs are predominantly operating in the Permian Basin, and we have one rig operating in the Eaglebine region, however, our rigs have previously operated in the Mid-Continent region and Eagle Ford Shale, as well.

Industry Trends

The increase in horizontal drilling in the U.S. over the past ten years has resulted in an ongoing land-rig replacement cycle in which the contract drilling industry is systematically upgrading its legacy fleets of SCRelectrical silicon-controlled rectifier (“SCR”) rigs and mechanical rigs with modern AC rigs that are specifically designed to optimize this type of drilling activity. The following describes the three different types of rig drives:

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

Shift to Developmental DrillingManufacturing Wellbore Model

Following their significant investments made in unconventional resource plays, many E&P companies are now focused on developing these investments in a systematic manner. Efficient development of these resource plays involves drilling programs that drill large numbers of wells 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.

One method in which an E&P company’soperator may reduce overall field development costs and provide them with greater optionality when designing their fieldis through the use of a multi-well pad development program. As a result, we believe that E&P companies drilling horizontal wells are going to increasingly demand not only AC rigs that are optimal for horizontal drilling, but premium AC rigs such as our ShaleDriller™ rig that include the following equipment and design features:

ShiftAnother method utilized by operators to Longer Lateral Lengths

Recent Declines in Oil and Gas Prices and Drilling Activity

Oil prices declined significantly duringbegan to decline in the second half of 2014, declined further during 2015 and have continued to decline in 2015.2016. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, was $37.13 per barrel on December 31, 2015 and has fallen as low as $44.08 per barrel in late$26.68 during January 2015 and around $49.84 per barrel during the last week in February 20152016 (WTI spot price as reported by the United States Energy Information Administration). As a result of the decline in oil prices, our industry is now experiencing a severean exceptional downturn, and market conditions remain very dynamic and are changing quickly. Although the magnitude as well as the duration of this downturn are not yet known, we believe that 20152016 will be a veryan exceptionally challenging year for ICD and our industry.

We believe the vast majority of exploration and productionE&P companies, including our customers, have significantly reduced their 20152016 capital spending plans.plans compared to 2015 levels. The initial impact of these spending reductions is evidenced by the published rig counts which have declined more than 25%60% since their recent peak in October 2014, and we believe the rig count in the United States willmay decline significantly further in 2015.2016 until oil and gas prices begin to stabilize and improve.

As a result of this deterioration in market conditions, our customers are principally focused on their most economic wells, drilling to maintain leasehold positions and on maintaining their most cost efficient operations that deliver the overall lowest cost of producing their wells.wells and minimize their capital expenditures. As a result, operators are focusing more of their capital spending on horizontal drilling programs compared to vertical drilling. They also are more focused on utilizing drilling equipment and techniques that optimize costs and efficiency. Thus, we believe this rapid market deterioration has significantly accelerated the pace of the ongoing land rig replacement cycle and continued shift to horizontal drilling from multi-well pads.pads utilizing “pad optimal” rig technology.

Although we believe that the current market downturn is rapidly increasing the focus of our customers towards the use of premium drilling rigs such as our ShaleDriller™ShaleDriller®, and that premium operations such as ours will behave been less affected by the downturn relative to operations conducted by legacy fleets, the rapid pace and level of the market decline has negatively

impacted pricing, utilization and contract tenors for premium rigs, including our ShaleDriller™ShaleDriller® rig. During 2014, we have operated2015, our premium drilling fleet with 99.7% contractualoperated at 85% utilization, but we do not expect to maintain this level of utilization while this current market downturn continues.  As of December 31, 2015, eleven of our twelve 200 series rigs were generating revenue.

Since December 31, 2014, one2015,

In addition, two of our rigs operating at December 31, 2015 were operating, in the spot-market, under short-term contracts expiring in March 2016, and we also have several rigs operating under term contracts with terms expiringscheduled to expire during the first half of 2015.2016. We expect to market these

We were incorporated in November 2011 but did not have meaningful operations until March 2012. In March 2012, we acquired substantially all of the rig manufacturing and related field service assets and intellectual property (the “GES assets”) of Global Energy Services Operating, LLC (“GES”), including GES’ Houston-based manufacturing facility (the “Houston Facility”), which we currently use to construct our rig fleet. The Houston Facility is located on 14.6 acres in northwest Houston. We believe thisThis acquisition provided us with the necessary infrastructure and asset platform required to accelerate the introduction of our ShaleDriller™ShaleDriller® rig into our target markets and secure initial contracts with key customers. In exchange for the GES assets, we issued 1.6 million shares of our common stock and a warrant to purchase 2.2 million shares of our common stock, which expired unexercised on March 2, 2015, and we assumed approximately $2.1 million of long-term indebtedness from GES. Because we had only limited operations before the GES acquisition and we succeeded tothem in substantially all of the ongoing rig construction operations of GES, GES is considered our predecessor for accounting purposes.

Contemporaneously with the acquisition of the GES assets, we acquired cash balances and two drilling contracts from Independence Contract Drilling LLC (referred to as “RigAssetCo”) in exchange for approximately 2.4 million shares of our common stock.

As a condition to the completion of these two transactions, we also closed a private placement of shares of our common stock resulting in net proceeds to us of $98.4 million. We used the net proceeds of the private placement primarily to continue the construction of our ShaleDriller™ShaleDriller® rig fleet and expansion of our operating capacity, and to repay the indebtedness assumed from GES. We refer to the GES and RigAssetCo transactions, together with the private placement of common stock, collectively as the “GES Transaction.”

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 fixed 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 any, and do not anticipate entering into, any “turn-key” (fixed sum to deliver a hole to a stated depth) or “footage” (fixed rate forper 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 this initial mobilization of a drilling rig and that we receive a demobilization fee at the end of the contract term in certain circumstances 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 numbersnumber of hours in a given day or calendar month.

OurPrior to the significant decline in market conditions that began in late 2014, we were able to regularly obtain long-term contracts with terms between one and three years. However, throughout 2015, the vast majority of new rig contracts available in the market have been short-term well-to-well contracts or contracts with terms less than six months. As a result, our contract drilling backlog, or the expected future revenue from executed contracts with original terms in excess of six months, declined significantly from $152.8 million as of December 31, 2014 was $152.8 million compared to $25.8$74.4 million as of December 31, 2013. The increase in2015. Approximately $53.3 million of our backlog at December 31, 2014 from December 31, 2013 is primarily due to additional term contracts being executed as we

Customers for contract drilling services in the U.S. include major oil and gas companies, independent oil and gas companies as well as numerous small to mid-sized publicly-traded and privately held oil and gas companies. We market our contract drilling services to all such customers. During 2014,2015, our customers representing more than 10% of our revenues were Apache Corporation, BOPCO, L.P.Parsley Energy, LP., Pioneer Natural Resources USA, Inc., Laredo Petroleum, Inc., COG Operating, LLC, a subsidiary of Concho Resources, Inc. and Laredo Petroleum, Inc.Elevation Resources, LLC. While we would attempt to remarket our rigs if we lost any material customer, given current market conditions, the terms of such new contract, if any were found, maywill be less favorable than the terms of our current contracts. Therefore, the loss of any material customer could have an adverse effect on our business.

To a large degree, our business depends on the level of capital spending by oil and 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. For example, theThe recent decrease in oil prices has caused a reduction in E&P company capital expenditures on exploration, development and production activities, which in turn has resulted in a decreased demand for drilling rigs and downward pricing pressure on drilling rigs in operation.

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 U.S. 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, quality of personnel, efficiency of equipment, service quality, experience and safety record.

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

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:

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

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

In the U.S., the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended (“CERCLA”), and comparable state statutes impose strict liability on:

The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes govern the disposal of “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, 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 and the Oil Pollution Act of 1990, as amended (the “Oil Pollution Act”), and implementing regulations govern:

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. 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 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 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 groundwater quality, 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. Such efforts 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 EPAEnvironmental Protection Agency (the "EPA") has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources including pursuing the energy extraction sector under a National Enforcement Initiative. 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 state and local regulations, such as the EPA rules issued in April 2012, which add new requirements for the oil and gas sector under the New Source Review Program and the National Emission Standards for Hazardous Air Pollutants program, could result in increased costs and the need for operational changes. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition.

On December 7, 2009, the EPA announced its findings that emissions of greenhouse gases present an “endangerment to human health and the environment.” The EPA based this finding on a conclusion that greenhouse gases are contributing to the warming of the earth’s atmosphere and other climate changes. The EPA began to adopt regulations that would require a reduction in emissions of greenhouse gases from certain stationary sources and has required monitoring and reporting for other stationary sources. Mandatory reporting requirements for additional regional, federal or state requirements have been imposed and additional requirements may be imposed in the future. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse effect on our operations and demand for our services. For example, during 2012, the EPA published rules that include standards to reduce methane emissions associated with oil and gas production. Pursuant to President Obama’s Strategy to Reduce Methane Omissions, and as part of the Obama Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025, the Obama Administration announced on January 14, 2015 that the2025. The EPA is expected to propose in the summerspring of 2015, and to finalize in 2016, new regulations that will set methane emission standards for new and modified oil and gas facilities, including production facilities. 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”), 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 U.S., 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 could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Our operations are subject to the many hazards inherent in the drilling business, including:

These and other hazards could cause:

Damage to the environment, including property contamination in the form of soil or ground water contamination, could also result from our operations, including through:

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

As of December 31, 2014,2015, we had approximately 323305 employees, including 2one contract employees,employee, none of whowhom were represented by a union. The number of our employees fluctuates depending on our construction and drilling activities.

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.

We use many suppliers of raw materials and services. Although these materials and services have historically been available, there is no assurance that such materials 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 to the rigs that we construct 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.

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. Materials we file with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also 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.

Risks Related to Our Business

Oil prices declined significantly duringbegan to decline in the second half of 2014, declined further during 2015 and have continued to decline in 2015.2016. The closing price of oil was as high as $106.06 per barrel during the third quarter of 2014, was $37.13 per barrel on December 31, 2015 and have fallen to as low as $44.08 per barrel in late January 2015 and around $49.84$26.68 per barrel during the last week in February 2015 (WTIJanuary 2016 (West Texas Intermediate-Cushing, Oklahoma ("WTI") spot price as reported by the United States Energy Information Administration). As a result of the decline in oil prices, our industry is now experiencing a severe downturn. Marketan exceptional downturn and market conditions remain very dynamic and are changing quickly andquickly. Although the magnitude as well as the duration of this downturn are not yet known, we believe that 20152016 will be a veryan exceptionally challenging year for ICD and our industry.

We believe the vast majority of exploration and production companies, including our customers, have significantly reduced their 20152016 capital spending plans.plans compared to 2015. The initial impact of these spending reductions is evidenced by the published rig counts, which have declined more than 25%60% since their recent peak in October 2014, and we believe theincluding an 11% rig count in the United States will decline further insince December 31, 2015.

As a result of this deterioration in market conditions, demand for our contract drilling services has declined. During 2015, our premium drilling fleet operated at 85% utilization, but we do not expect to maintain this level of utilization while this current market downturn continues.  As of December 31, 2015, eleven of our twelve 200 series rigs were generating revenue.

In addition, two of our rigs that areoperating at December 31, 2015 were operating under short-term contracts expiring in March 2016, and we also have several rigs operating under term contracts with terms expiringscheduled to expire during the first half of 2015.2016. We expect to market our rigs rolling off contracts in 2016 at substantially lower dayrates than where they historically have operated, and there can be no assurance that these rigs will be contracted or remain operating at profitable levels. If we are unable to re-contract theserecontract rigs during 2015,in the spot-market or recontract rigs with expiring term contracts, it couldwould have a material adverse affect on our results of operations and financial condition. In addition, we expect that any rig with an expiring term contract that is recontracted during 20152016 will be at dayrates substantially below their current contract rates, which will significantly reduce our profitability and cash flows.

In addition, we currently finance our capital expenditures and operations pursuant to a committed $155.0$125.0 million revolving line of credit. A significant portion of our borrowing base is tied to the appraised value of our drilling rigs, which

As a provider of land-based contract drilling services, our business depends on the level of exploration and production activity by oil and gas companies operating in the U.S., and in particular, the regions where we actively market our contract drilling services. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and 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 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 U.S. and the regions where we market our contract drilling services, whether resulting from changes in oil and gas prices or otherwise, could materially and adversely affect us in many ways by negatively impacting:

Depending on the market prices of oil and gas, oil and 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 gas prices, including, but not limited to:

Oil and natural gas prices have been volatile historically and, we believe, will continue to be so in the future. For example, U.S. Benchmark crude’s price per barrel (West Texas Intermediate - Cushing, Oklahoma)(WTI) was $107.95 on June 20, 2014 and had dropped to $44.08 by$26.68 on January 28, 2015, an approximately 59% decrease over a less than eight month period.20, 2016. Future or continued declines and volatility in oil and gas prices, or no improvement in oil and gas prices, from their current levels for an extended period of time, could materially and adversely affect our business, results of operations, financial condition and growth strategy.

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. DeclinesFurther declines in

In addition, if oil and natural gas prices decline further, 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.

Our customer base consists of E&P companies that drill oil and gas wells in the United States in the regions where we market our rigs. We currentlyAs of December 31, 2015, we have thirteen executed drilling contracts (including for three rigs under construction) withoperating or earning revenues from eight different customers. Furthermore,customers, including three customers who have contracted two of our rigs, and 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. Daywork contracts in the contract drilling industry typically do not obligate those customers to order additional services from the drilling contractor beyond those for which they have currently contracted. If a major 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 major customer revenue would declineor 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.

AllUpon expiration of our currentthe term of a drilling contracts have original or current extended terms of between 12 and 36 months. In any event,contract, our contracts provide that our customers may terminate at any time upon payment to us of an “early termination payment.” One of our drilling rigs became idle in January 2015 and four of our existing drilling contracts are scheduled to terminate during 2015. Our customers have no obligation to extend the contract term of anyor recontract the drilling contractrig, and may elect to release the rig. We have not yet recontractedIn the rigevent a customer elects to terminate a drilling contract prior to the expiration of its drilling term, all of our current drilling contracts provide that went off contract in January 2015 and we cannot assure you that any particular contract will be renewed, or if terminated, that a replacement contract could be immediately secured.our customers pay an early termination payment. In addition, in light of the current downturn in oil prices, we cannot assure you that any replacement contract can be obtained for any of rigs operating in the spot-market or with terms expiring while market conditions remain depressed, and if obtained, that it would be on terms as favorable as those of our existing drilling contracts.contracts or at profitable levels. The failure to renew or timely replace one or more of our expiring spot-market or term contracts could have a material and adverse effect on 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:

Any of these hazards can result in substantial liabilities or losses to us from, among other things:

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. For example, during March 2014, we experienced damage to the mast of one of our operating rigs that removed the rig from operations for a period of time, during which we were not compensated. 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 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 recent downturn in oil prices has decreased demand for drilling rigs and resulted in downward pricing pressure on operating drilling rigs.

Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. Most drilling services contracts are awarded on the basis of competitive bids, which also results in price competition.

In addition to pricing, we believe the principal competitive factors in our markets are availability and condition of equipment, quality of personnel, efficiency of equipment, service quality, experience and safety record. The success of our business depends on our ability to offer safe and highly efficient operations, the quality and efficiency of our rigs and the skills and experience of our rig crews.

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 and ability to implement our growth strategy.condition. In addition, the failure to maintain an adequate safety record could harm our ability to secure new drilling contracts. As a relatively new contract driller with limited operating

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. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets.

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.

In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Smaller competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements.

Finally, some E&P companies perform horizontal and directional drilling on their wells using their own equipment and personnel. Any increase in the development and utilization of in-house drilling capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.

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.

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.

The federal Energy Policy Act of 2005 amended the Underground Injection Control provisions of the federal Safe Drinking Water Act (“SDWA”) to exclude certain hydraulic fracturing practices from the definition of “underground injection.” The Environmental Protection Agency (the “EPA”)EPA has asserted regulatory authority over certain hydraulic fracturing activities involving diesel fuel and published guidance relating to such practices in February 2014. Congress has considered bills to repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate new regulations and permitting requirements for hydraulic fracturing, potentially including chemical disclosure requirements. At the state level, several states in which we operate have adopted regulations requiring the disclosure of certain information regarding hydraulic fracturing fluids.

Scrutiny of hydraulic fracturing activities continues in other ways. The EPA commenced a study of the potential impacts of hydraulic fracturing on drinking water and issued an update on December 21, 2012, with a draft report expected for public comment and peer review in June 2015. On October 21, 2011, the EPA announced its intention to propose regulations under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing. On May 24, 2013,In March 2015, the U.S. Department of the Interior (the “DOI”) published a revised proposed rulefinal rules that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity and handling of flowback water. On April 13, 2012, the DOI, the U.S. Department of Energy and the EPA issued a memorandum outlining a multi-agency

In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, that would require, with some exceptions, disclosure of constituents of hydraulic fracturing fluids, or that would impose higher taxes, fees or royalties on natural gas production. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and 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.

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 has with many of our customers. Losing the services of any of these individuals, in particular Mr. Dunn and Mr. Jacob, our Chief Executive Officer and our President and Chief Operating Officer, respectively, 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.

New drilling rigs or rigs being upgraded, converted or re-activated following a period of stack may experience start-up complications during construction or following delivery, and may encounter other operational problems that could result in significant delays, uncompensated downtime, reduced dayrates or the cancellation, termination or non-renewal of drilling contracts. Rig construction and upgrade projects are subject to risks of delay or significant cost overruns inherent in any large construction project from numerous factors, including the following:

The process of constructing rigs may involve unforeseen difficulties and may require a disproportionate amount of management’s attention and other resources. We may not be able to successfully manage and integrate new rigs into our existing operations or successfully market our rigs and build market share attributable to drilling rigs that we construct. To the extent we experience some or all of these difficulties, our results of operations, financial condition and growth strategy could be adversely affected.

Expanding our fleet may cause us to incur additional financial leverage, increasing our financial risk and debt service requirements, which could adversely affect our business, results of operations, financial condition and growth strategy.

As of December 31, 2014,2015, our estimated contract drilling backlog for future revenues under term contracts, which we define as contracts with a fixed term of six months or more, was approximately $152.8$74.4 million. 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. In addition, we currently expect that several of our rigs under term contracts will realize revenue on a standby-without-crew basis, which allows us to preserve our expected cash margins from the contract but reduces our the overall top line revenues we recognize. 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.

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 do not expect our operating and maintenance costs with respect to our rigs to necessarily fluctuate in proportion to changes in operating revenue. Operating revenue may fluctuate as a function of changes in dayrate, but costs for operating a rig and property taxes are generally fixed or only semi-variable regardless of the dayrate being earned. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, when our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor

costs increase due to higher salary levels, inflation, and increases in workers’ compensation insurance. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.

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 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.

Our ability to make scheduled payments on or to refinance indebtedness under our revolving credit facility 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 revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition.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.

Our revolving credit facility contains a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:

A breach of any covenant in our revolving credit facility 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, our revolving credit facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under any other debt agreements. 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.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which is calculated monthly and is based upon the appraised value of our eligible drilling fleet and a percentage of our eligible accounts receivable. If a rig becomes idle for longer than 90 consecutive days, it is removed from our borrowing base until it resumes operations.is recontracted. The borrowing base under our revolving credit facility was $114.8$98.6 million as calculated as of December 31, 2014,2015, with lender commitments of $155.0$125.0 million.

In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness,based upon the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. As a result, we may be unable to

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.

Our contract drilling operations and our ability to construct new drilling rigs in a timely manner depend on 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 construction of our rigs are either purchased from or fabricated by a single or

limited number of vendors. 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.

Increased or decreased demand among drilling contractors for consumable supplies, including fuel, and ancillary rig equipment, such as pumps, valves, drillpipe and engines, may lead to delays in obtaining these materials and our inability to operate our rigs in an efficient manner. Most of our contracts provide that our customers purchase the fuel that run our drilling rigs and thus bear the financial impact of increased fuel prices. However, prolonged shortages in the availability of fuel to run our drilling rigs resulting from action of the elements, terrorism or other force majeure events could result in the suspension of our contracts and have a material adverse effect on our financial condition and results of operations. 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.

Reduced demand can drive suppliers from the market. With reduced suppliers, consumables for our operations may not be readily available. Additionally, suppliers may experience shortfalls in obtaining their materials and/or labor. Suppliers who have been regular providers to us may experience shortfalls that may lead to delays as we secure other sources.

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.

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.

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 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 and could limit well servicing opportunities. We may not be able to recover some or any of our costs of compliance with these laws and regulations from insurance.

The federal Endangered Species Act (the “ESA”)ESA and analogous state laws regulate a variety of activities, including oil and 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 could cause oil and natural gas

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 federalFederal Clean Air Act addressing emissions of greenhouse gases that may affect the oil and gas industry. During 2012, the EPA published rules that include standards to reduce methane emissions associated with oil and gas production. Pursuant to President Obama’s Strategy to Reduce Methane Omissions, and as part of the Obama Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025, the Obama Administration announced on January 14, 2015 that the EPA is expected to propose in the summerspring of 2015, and to finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas facilities, including production facilities. In addition, the U.S. has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change.Change and was among the 195 nations that signed an international accord in December 2015 with the objective of limiting greenhouse gas emission. 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.

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.

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 and 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.

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 could have a material adverse effect on our business, financial condition and results of operations.

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

The market price of common stock of companies engaged in the oil and gas service industry, including our common stock price, has been highly volatile. Stock price volatility could adversely affect our business operations by, among other things, impeding our ability to attract and retain qualified personnel and to obtain additional financing.

In addition to the other risk factors discussed in this section, the price and volume volatility of our common stock may be affected by:

To the extent that the price of our common stock remains at lower levels or it declines further, our ability to raise funds through the issuance of equity or otherwise use our common stock as consideration will be reduced. In addition, increases in our leverage may make it more difficult for us to access additional capital. These factors may limit our ability to implement our operating and growth plans.

We have not paid cash dividends on our common stock since our incorporation and our revolving 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. Any payment of cash dividends in the future will be dependent on the amount of funds legally available, our financial condition, capital requirements, ability to pay such dividends under our then existing credit facility and other factors that our Board of Directors may deem relevant. 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.

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:

None.

We own an approximately 14.4 acre corporate headquarters and rig assembly yard complex located at 11601 North Galayda Street, Houston, TX 77086. The complex includes approximately 18,000 square feet of office space and 76,000 square feet of warehouse space. We have entered into leasesa lease for an additional approximate 0.2 acres of land for equipment and supply storage. We believe that all of our existing properties are suitable for their intended uses and 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.

Not applicable.

Market Information for Common Stock

Our common stock has traded on the New York Stock Exchange under the symbol “ICD” since August 8, 2014 following our initial public offering. Prior to that time, there was no public market for our common stock. The table below presents the high and low daily closing sales prices of the common stock, as reported by the New York Stock Exchange, for each of the applicable quarters presented during the year ended December 31, 2014:periods indicated:

Holders of Record

As of March 13, 2015,February 12, 2016, we had 24,629,33324,403,659 shares of common stock outstanding held by approximately 20 holders of record. 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 revolving 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 credit facility and other factors deemed relevant by our board.

Our selected historical financial data as of and for the periods presented below were derived from our audited financial statements. Our results of operations during 2012 do not include the results of our predecessor prior to its acquisition. Although we did not commence material operations prior to March 2, 2012, we incurred expenses in connection with our private placement and acquisition activities during January and February 2012 prior to the consummation of these transactions.

The selected historical financial data of our predecessor for the period from January 1, 2012 through March 1, 2012 were derived from the audited financial statements of our predecessor. Our predecessor was engaged in a different line of business and you should not evaluate our results based on our predecessor or consider our results and those of our predecessor on a combined basis.       

Our historical results are not necessarily indicative of our future operating results. The share information gives effect to a 1.57-for-1 stock split in the form of a stock dividend on July 24, 2014. The selected historical financial data presented below is qualified in its entirety by reference to, and should be read in conjunction with, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes included in "Item 8. Financial Statements and Supplementary Data."

Since December 31, 2014, one2015,

In addition, two of our rigs operating at December 31, 2015 were operating under short-term contracts expiring in March 2016, and we also have several rigs operating under term contracts with terms expiringscheduled to expire during the first half of 2015.2016. We expect to market these

On March 9, 2014,During the third quarter of 2015, we began to convert one of our non-walking drilling rigs suspended drilling operations due to damage to the rig’s mastpad optimal status, equipped with our 200 Series substructure, omni-directional walking system and other operating equipment. We believe the cost to repair and replace this equipment is covered by insurance, subject to

Initial Public Offering

On August 7, 2014, our registration statement on Form S-1 (File No. 333-196914) (the "Form S-1") was declared effective by the Securities and Exchange Commission (the "SEC") for our IPO, pursuant to which we sold an aggregate of 11,500,000 shares of our common stock at a price to the public of $11.00 per share, which included 1,500,000 shares of our common stock sold pursuant to the exercise by the underwriters in full of their option to purchase additional shares of common stock to cover over-allotments (the "Over-Allotment Option"). Morgan Stanley & Co. LLC, RBC Capital Markets, LLC and Tudor, Pickering, Holt & Co. Securities, Inc. acted as book runners. We completed our initial public offeringIPO of 10,000,000 shares of our common stock on August 13, 2014 and subsequently closed the issuance and sale of the additional 1,500,000 shares of our common stock pursuant to the Over-Allotment Option on August 29, 2014. Our common stock trades on the New York Stock Exchange under the ticker symbol "ICD."ICD. Net proceeds from the offering were $116.5 million after deducting $7.6 million of underwriting discounts and commissions, as well as legal, accounting, printing and other expenses directly associated with the offering totaling $2.4 million. All

We earn contract drilling revenues pursuant to drilling contracts entered into with our customers. We perform drilling services on a “daywork” contract basis, under which we charge a fixed 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. 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.

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, workersworkers' 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.

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:

The following summarizes our financial and operating data for the years ended December 31, 2015, 2014 2013 and 2012, as well as the financial data for our predecessor for the period from January 1, 2012 through March 1, 2012:2013:

Revenues for the year ended December 31, 2014 were $70.3 million, representing a 64.4% increase over revenues for the year ended December 31, 2013 of $42.8 million. This increase was primarily related to the addition of four drilling rigs into our operating fleet during 2014, which is reflected in the increase in our average number of operating rigs to 8.07 during 2014 compared to 4.78 during 2013 and a full year of operating from the rigs put into service during 2013. Average revenue per operating day increased to $22,723 during 2014, compared to $21,351 during 2013.

Operating costs for the year ended December 31, 2014 were $42.7 million, representing a 50.2% increase over operating costs for the year ended December 31, 2013 of $28.4 million. This increase was primarily related to the addition of four drilling rigs into our operating fleet during 2014. During the year ended December 31, 2014, our cost per operating day was $12,759, representing a 1% increase compared to 2013 operating cost per day of $12,632.

Selling, general and administrative expenses for the year ended December 31, 2014 were $12.3 million, representing a 38.0% increase over selling, general and administrative expenses for the year ended December 31, 2013 of $8.9 million. This increase primarily relates to costs associated with us becoming a public company in August 2014, including costs associated with increased non-cash stock based compensation relating to awards granted at the IPO, higher executive salaries and other costs associated with maintaining and operating a publicly traded company. In addition, during 2014 we incurred approximately $0.7 million of professional fees and acceleration of vesting of stock-based awards directly associated with the closing of the IPO.

Depreciation and amortization for the year ended December 31, 2014 was $16.2 million, representing a 58.9% increase compared to the year ended December 31, 2013.2013 of $10.2 million. This increase was directly related to the introduction of four new

Goodwill impairment and other charges for the year ended December 31, 2014 was $30.6 million. There was no goodwill impairment andor other charges in 2013 or 2012.2013.

Interest expense for the year ended December 31, 2014 was $1.6 million, as compared to $0.3 million for the year ended December 31, 2013 as a result of increased borrowings under our revolving credit facility. Interest expense for the year ended December 31, 2012 was negligible. We did not borrow under our original revolving credit facility until July 2013.

As part of the consideration paid to GES for their contribution of our rig construction operations and intellectual property, we issued to GES a warrant to purchase 2.2 million shares of common stock. The terms of this warrant contained a feature that would allow the exercise price to be adjusted in the event we issued any shares of common stock at a price below $12.74 per share during the term of the warrant. As a result of this feature, we have accounted for the warrant as a derivative liability on our balance sheet and have recorded changes in fair value each reporting period through earnings. The fair value of the warrant on its date of issuance was estimated at $7.9 million. At December 31, 2012, the fair value of the warrant was estimated at $4.2 million, which resulted in us recording a non-cash gain of $3.7 million for the year ended 2012. At December 31, 2013, the fair value of the warrant was estimated at $3.2 million, and we recorded a non-cash gain of $1.0 million for the year ended 2013. Based on the closing price of our stock on December 31, 2014 and the short period of time until the expiration of the GES Warrant on March 2, 2015, the warrant had no value as of December 31, 2014, and we recorded a non-cash gain on warrant derivative associated with the changes in fair value of $3.2 million for the year ended December 31, 2014. The warrant expired unexercised March 2, 2015.

The income tax benefit recorded for the year ended December 31, 2014 amounted to $3.4 million compared to an income tax benefit of $1.9 million for the year ended December 31, 2013. The effective tax rate was 10.7% for the year ended 2014 compared to 48.5% for the year ended 2013 as a result of a permanent difference associated with the impairment of goodwill and a valuation allowance recorded in 2014 on all of our net deferred tax assets.

Cash Flows     

Cash provided by operatingused in investing activities was $6.0$72.2 million for the twelve months ended December 31, 2013 as2015 compared to cash used in operating activities of $8.3 million for the same period in 2012. During 2012, our operating activities did not generate positive cash flows, reflecting the start-up nature of our operations. During that period, we only had an average of 1.29 rigs operating during the year.

Cash used in investing activities was $59.3$112.7 million for the twelve months ended December 31, 20132014 compared to $49.7$59.3 million during the same period in 2012.2013. During 2013, we spent $59.7 million on capital expenditures to fund the completion of three additional ShaleDriller™ShaleDriller® rigs, to begin construction on two additional rigs, to increase our inventory of critical spares, and for maintenance capital expenditures on existing rigs. This amount was offset by $0.4 million we received from the sale of plant, property and equipment. During 2012, we spent $66.9 million on capital expenditures to fund the completion of four ShaleDriller™ rigs, plus building our inventory of spare rig equipment and tubulars. We also had two additional rigs in various stages of construction during 2012. The expenditures were partially offset by the $17.1 million in cash we received as part of the GES Transaction and $0.04 million we received from the sale of certain equipment during 2012.

In light of the purchaseextreme downturn in market conditions and lack of additional equipment necessaryvisibility relating to the timing of any market recovery, we have suspended new build construction activities until market conditions improve. As a result, we intend to complete the one rig conversion we currently have in process, make maintenance capital expenditure required to maintain our critical spare inventoryoperating fleet and additionalcomplete opportunistic equipment that can be utilized inupgrades as market conditions dictate. However, we do not intend to complete the construction of an additional Shaledriller™second rig conversion or the outfitting of one or both of our non-walkingany new rigs with our Shaledriller™ multi-directional walking system. until market conditions improve.

We believe that our cash and cash equivalents, cash flows from operating activities and borrowings available under our revolving credit facility will adequately finance all of our purchase commitments, capital expenditures and other cash requirements over the next 12 months. However, shoulddue to the extreme nature of the current industry downturn and lack of forward visibility, and the fact that a larger portion of our liquidity needs increase,assumed future cash flows will be generated from rigs operating in the spot-market, there is increasing risk that our actual rig utilization and actual future cash flows will fall below our internal projections.  Based on these conditions, we may seek additionalare evaluating and intend to continue to evaluate a variety of public or private equity or debt financing.financings. Additionally, 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 financings. We cannot predict whether any such financings will be available, or on terms acceptable to us.

On February 21,In November 2014, we entered into an amended our Credit Facility in order to increase the aggregate commitments from $60.0 million to $125.0 million. The final $25.0 millionand restated credit agreement (the “Credit Facility”) with a syndicate of commitments under the amended Credit Facility was subject to us obtaining additional equity or indebtedness, subordinated to the Credit Facility, of at least $40.0 million (“Junior Event”). The Credit Facility, as amended, alsofinancial institutions led by CIT Finance LLC that provided for a committed $155.0 million revolving credit facility and an additional uncommitted $25.0 million accordion feature that allowed for future increases in the facility.

The obligations under the pendency of its upgrade. As a resultCredit Facility are secured by all our assets and are unconditionally guaranteed by all of our IPO completed on August 13, 2014, the final $25.0 million of our $125.0 million Credit Facility became available to us.

Our long-term debt as of December 31, 20142015 consisted of amounts due under our revolving credit facility. Interest on long-term debt is related to our estimated future contractual interest obligations on long-term indebtedness outstanding as of December 31, 20142015 under our revolving credit facility. Our operating leases relate primarily to real estate and vehicles.

Our purchase obligations relate primarily to outstanding purchase orders for rig equipment or components ordered but not received.

The 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 financial statements. Other significant accounting policies are summarized in Note 2 to the financial statements included in "Item 8. Financial Statements and Supplementary Data."

We account for the depreciation ofProperty, 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 overbased on the estimated useful lives of the assets considering the estimated salvage valueassets. The cost of the related property, plantmaintenance and equipment. repairs are expensed as incurred. Major overhauls and upgrades are capitalized and depreciated over their remaining useful life.

Off-Balance Sheet Arrangements

Recent Accounting Pronouncements

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

Commodity Price Risk

Credit and Capital Market Risk