November 2022 Investor Presentation Exhibit 99.2

Various statements contained in this presentation, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. These forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal,” “will” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this presentation speak only as of the date of this presentation; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These and other important factors, including those discussed under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s filings with the Securities and Exchange Commission, including the Company’s Annual Report on Form 10-K, may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. These risks, contingencies and uncertainties include, but are not limited to, the following: inability to predict the duration or magnitude of the effects of the COVID-19 pandemic on our business, operations, and financial condition and when or if worldwide oil demand will stabilize and begin to improve; decline in or substantial volatility of crude oil and natural gas commodity prices; a decrease in domestic spending by the oil and natural gas exploration and production industry; fluctuation of our operating results and volatility of our industry; inability to maintain or increase pricing of our contract drilling services, or early termination of any term contract for which early termination compensation is not paid; our backlog of term contracts declining rapidly; the loss of any of our customers, financial distress or management changes of potential customers or failure to obtain contract renewals and additional customer contracts for our drilling services; overcapacity and competition in our industry; an increase in interest rates and deterioration in the credit markets; our inability to comply with the financial and other covenants in debt agreements that we may enter into as a result of reduced revenues, financial performance or financial requirements; unanticipated costs, delays and other difficulties in executing our long-term growth strategy; the loss of key management personnel; new technology that may cause our drilling methods or equipment to become less competitive; labor costs or shortages of skilled workers; the loss of or interruption in operations of one or more key vendors; the effect of operating hazards and severe weather on our rigs, facilities, business, operations and financial results, and limitations on our insurance coverage; increased regulation of drilling in unconventional formations; the incurrence of significant costs and liabilities in the future resulting from our failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment; and the potential failure by us to establish and maintain effective internal control over financial reporting. All forward-looking statements are necessarily only estimates of future results, and there can be no assurance that actual results will not differ materially from expectations, and, therefore, you are cautioned not to place undue reliance on such statements. Any forward-looking statements are qualified in their entirety by reference to the factors discussed throughout this presentation and in the Company’s filings with the Securities and Exchange Commission, including the Company’s Annual Report on Form 10-K. Further, any forward-looking statement speaks only as of the date of this presentation, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events. Adjusted Net Income or Loss, EBITDA and adjusted EBITDA are supplemental non-GAAP financial measures that are used by management and external users of the Company’s financial statements, such as industry analysts, investors, lenders and rating agencies. The Company’s management believes adjusted Net Income or Loss, EBITDA and adjusted EBITDA are useful because such measures allow the Company and its stockholders to more effectively evaluate its operating performance and compare the results of its operations from period to period and against its peers without regard to its financing methods or capital structure. See non-GAAP financial measures at the end of this presentation for a full reconciliation of Net Income or Loss to adjusted Net Income or Loss, EBITDA and adjusted EBITDA. Preliminary Matters

Land Drilling’s Only U.S. Publicly-Traded, Pure-Play, Pad-Optimal, Super-Spec, Growth Story Highest Asset Quality 100% Pad-Optimal, Super-Spec Fleet Premier Customer Base Rapidly Expanding Margins/Cash Flows Driven by Strategic Investments and Market Conditions Significant Investment Opportunity - Meaningful Current Valuation Discount to Market Based Upon Both Asset Values and Cash Flow Multiples Fleet 100% Dual-Fuel Enabled / Electric Hi- Line Capable: Substantial GHG Reduction / Elimination Recognized Industry Leader for Service and Professionalism Ideal Geographic Focus on Most Prolific Oil and Natural Gas Producing Regions

Company Background: Pure-Play, 100% Pad-Optimal, Super-Spec U.S. Land Contract Driller Very Constructive Market Dynamics and Outlook Drivers of Returns and Free Cash Flow in Current Market Drivers of Debt Reduction and Imbedded Value ESG Appendices Presentation Outline

COMPANY BACKGROUND Pure-Play, 100% Pad-Optimal, Super-Spec U.S. Land Contract Driller

Introduction: ICD Sector’s only U.S. publicly-traded, pure-play, Pad-Optimal, Super-Spec drilling contractor focused solely on North America’s most attractive oil and natural gas basins Best-in-Class Asset Quality and Geographic Focus Marketed fleet comprised entirely of Pad-Optimal, Super-Spec rigs Established presence in oil rich Permian play Leading presence in natural gas rich Haynesville and East Texas regions Fit-for-purpose rigs engineered/outfitted to address particular basin drivers All rigs software-optimization-capable High Quality Customer Base Supported by Industry Leading Customer Service and Operations #1 ranked land contract driller for service and professionalism past five years: 2018 - 2022 Established relationships with publics and well-capitalized private operators Constructive Market, Asset Quality Driving Incremental Cash Flows and Shareholder Upside Extremely tight market driving rapidly improving dayrates, margins and utilization Rapidly improving margins on par with or exceeding larger public-company land drillers One of only a few contract drillers with spare capacity that can be economically reactivated into an extremely tight, improving market ESG Focus Marketed fleet 100% dual-fuel and hi-line power capable Omni-directional walking reduces operational footprints and environmental impacts Increasingly diverse workforce: 38% from under-represented groups Leading percentage concentration of rigs directed at natural gas production

18 rigs operating at quarter-end Future rig reactivations 19th rig: Early Nov ’22 (contracted) 20th rig: Mid Dec ‘22 (contracted) 21st rig: Early to Mid Q1’23 (scheduled) 22nd rig: Late Q1’23 / Early Q2’23 (scheduled) 23rd-26th rigs: TBD 200-300 Series Conversions: One completed early Q4’22 Rapidly expanding margins and EBITDA operating leverage Sequential margin increase of 27% and sequential adjusted EBITDA increase of 35% Forecasting Q4’22 and Q1’23 margin per day of $12,750 and $14,750, respectively, at midpoint of guidance range, representing 12.5% and 30% increases over reported Q3’22 margin per day 2023 backlog with expected margin per day over 55% higher than reported Q3’22 revenue per day 3Q ’22 Earnings Highlights One-year term contracts with expected revenue per day in the high 30’s. Less than one-year pay back on reactivation costs.

Rig Fleet & Geographic Markets ICD Operating Area AVERAGE AGE OF MARKETED FLEET: 7.10 YEARS(3) 26 Marketed Pad-Optimal Super-Spec Rigs(1) 17 “300” Series ShaleDriller Rigs(2) 1,500 – 2,000 HP drawworks; 25K+ racking Three pump / four engine capable; drilling optimization software capable Targeting developing market niche for larger diameter casing strings and extreme laterals Dual-Fuel Enabled / Hi-Line Electric Power Capable Hi-torque top drive 9 “200” Series ShaleDriller Rigs 1,500 HP drawworks; 20K+ racking / 750K lb. hook Three pump / four engine capable; drilling optimization software capable Dual-Fuel Enabled / Hi-Line Electric Power Capable Includes eight rigs capable of conversion to 300 Series specifications with only modest capex pursuant to recently announced 200-to-300 Series conversion program announced in August ’22 Excludes six idle but not marketed rigs (three rigs capable of conversion to 300 Series specifications) Includes two planned 200-to-300 Series conversions and one substantially complete conversion in process at October 31, 2022 As of October 31, 2022; based upon date of first well spud following rig construction or material upgrade ICD Operations Strategically Focused on the Most Prolific Oil and Natural Gas Producing Regions in the United States

300 Series Rigs Lead Transformation of Operating Fleet Compared to Pre-COVID levels Demand for 300 Series spec rigs being driven by rapidly evolving industry dynamics: Shift towards longer laterals and deeper wells Shift towards larger diameter and high-torque drill pipe Steadily increasing number of wells per drilling pad Increased deep gas drilling by ICD customers in Haynesville / E. TX gas plays Rigs meeting 300 Series specs are in the shortest supply and command the highest dayrates when matched with customers requiring such specifications Initial fourteen 300 Series rigs acquired by ICD in 4Q’18 Sidewinder merger – current recovery represents first opportunity for ICD to market and place these rigs with customers in an improving rig count environment ICD 200-300 Series Conversion Program: ICD recently announced 200-to-300 Series conversion program, and contemporaneous increase in marketed fleet to 26 rigs, resulting in ICD now marketing 96% of its marketed fleet with 300 Series specifications Conversion cost per rig: $650K Payback less than one year based upon dayrate differential Conversion completed on long rig move (minimal operational downtime) 2018 Pre-Sidewinder Merger Post Sidewinder Merger Current: Following 200-300 Series Conversion Program 0% 60% 96% ICD Marketed Fleet Transformation: % 300 Series 200 Series 300 Series

ICD Margins Rapidly Expanding Beyond Pre-COVID Levels as Operating Fleet Evolves to 300 Series Specs ICD Fleet Composition Compared to ICD Margin-Per-Day Progression (1) 1) Margin and fleet operating mix per Q3’22 earnings call press release guidance Margin Per Day Operating Rigs (1) Most recent quarter: ICD already reporting record margin per day

Geographic Mix / Customer Relationships Current and Prior ICD Customers Premier Customer Base Current ICD Contracted Rigs By Basin Occidental Petroleum Corporation via Anadarko Petroleum acquisition; ConocoPhillips via Concho Reources acquisition Permian 10 Haynesville / ETX 10 (1) (1)

Very Constructive Market Dynamics and Outlook

Defining a Pad-Optimal, Super-Spec Rig Omni-Directional Walking 1500 HP Drawworks High-Pressure Mud Systems (7500 psi) Fast Moving AC Programmable Fleet must have flexibility to provide differing equipment packages to meet particular requirements of E&Ps’ drilling programs Three pump / four engine: 100% of ICD marketed fleet High-Torque top drive: 96% of ICD marketed fleet Enhanced racking (25K ft) : 96% of ICD marketed fleet Drilling optimization software capable: 100% of marketed fleet Dual-fuel / Electric Hi-line capable : 100% of marketed fleet 1) Source: Enverus and Company estimates. Includes AC, 1500HP+, 750,000lb+ hookload; excludes rigs not operating since 2018 and rigs owned by non-operating entities 2) 1500HP AC rigs with skidding systems upgradeable to omni-directional walking (capex estimated at $7M+ per rig)

Drivers for Expected Improvements in Pad-Optimal, Super-Spec Utilization / Dayrates Constructive oil supply / natural gas demand fundamentals Prolonged underinvestment and industry capital discipline Depleted drilled-but-uncompleted (DUC) inventories Spare Pad-Optimal, Super-Spec capacity consolidating within small number of players U.S. Pad-Optimal, Super-Spec fleet utilization exceeding 90%

Industry Underinvestment & Capital Discipline Source: Capital IQ as of October 26, 2022. Companies include: Antero, APA, Chesapeake, Conoco Phillips, Continental, Coterra, Devon, Dimaondback, EOG, EQT, Hess, Marathon, Occidental, Ovintiv & Pioneer Source: EIA US E&P Cash Flows Compared to Capital Expenditures(1) $millions Significant industry underinvestment since 2014, industry capital discipline and depleted DUC inventories driving constructive market backdrop despite general U.S. and global recessionary concerns

Minimal Spare Pad-Optimal Super Spec Capacity AC, walking, 1500HP+, 750,000lb hookload +, 3 pumps (7500psi) / 4 engines; excludes rigs stacked as of FYE 2018, skidding rigs, and rigs held by non-operating entities Source: Enverus and Company estimates Source: Enverus and Company estimates as of Septmember 30, 2022 Minimal supply of active Pad-Optimal, Super-Spec rigs causes incremental rig supply to come from rig reactivations where spare capacity controlled by small number of competitors Q4’18

Drivers of Returns and Free Cash Flow in Current Market

Drivers of Returns /FCF Through Oil and Gas Cycle Improving Fleet Utilization Signed contracts for reactivation of rigs 19 and 20; Rig 21 scheduled for early-to mid Q1’23 and Rig 22 scheduled for late Q1’23 / early Q2’23 All ICD reactivations will be 300 Series rigs, which are in shortest supply and command highest dayrates in the market Increasing Dayrate and Margin Momentum Dayrates and margins expanding in very tight, constructive Pad Optimal, SuperSpec market U.S. Pad-Optimal, Super-Spec fleet utilization exceeding 90% with continuing improvements in U.S. rig count expected Increasing 300 Series market penetration drives sequential dayrate improvements Growing backlog into 2023 at expected margins exceeding $17.5K per day at Q3’22 cost levels Over 60% of ICD fleet will recontract to current spot market rates through Q1’23 Scalable Cost Structure Drives Substantial Improvements in Cash Flows Costs to operate a rig do not fluctuate meaningfully with increases in dayrates - dayrate improvements fall directly to bottom line driving incremental margins and cash flows Contract terms and short-term contract structures allow ICD to pass through labor and other cost increases Scalable SG&A cost structure: minimal increases in SG&A as operating fleet and revenues increase

ICD Margins Expanding in Market Recovery In a continuing market recovery and improving rig count environment, the following factors are positively impacting ICD revenues and margin per day compared to pre-COVID levels: 300 Series rig pricing and market penetration Efficiency improvements made in 2018 and 2019 following Sidewinder Merger(1) and in response to COVID continue to be realized and drive additional cost savings Current short-term contract structures for majority of ICD rigs permit steady repricing of contracts into an improving market; 2023 backlog priced at dayrates exceeding current Q4’22 and Q1’23 estimates Cost escalation provisions and frequent repricings buffer margins from labor and other cost inflation that is occurring Dayrate increases outpacing labor and other inflationary pressures 1) Sidewinder Merger closed 10/1/2018 2) Estimates from ICD Q3’22 earnings press release Margin Per Day ICD current contractual backlog extending into 2023 is priced at an average revenue per day exceeding $35K, with expected margin on these contracts exceeding $17.5K per day at current operating cost levels

Led By Increasing 300 Series Market Penetration, ICD Margins Closing Historical Pre-COVID Profitability Gap (1) Average margin per day for HP, PTEN, NBR and PDS Source: Public company filings, 4Q’22 estimates derived from quarterly earnings conference calls or preliminary press releases ICD margin guidance at midpoint - Q4’22: $12,750; Q1’23: $14,750 ICD contractual backlog of term contracts in 2023 priced at average revenue per day exceeding $35,000 per day, indicating an expected margin on such contracts over $17,500 per day at 3Q’22 reported cost levels

ICD Backlog and Spot Market Exposure ICD 3Q’22 backlog increased 87% over 2Q’22. Pricing within existing backlog and exposure to the spot market through contract repricings and future rig reactivations positions ICD for continued margin expansion in 2023+ Backlog Revenue Days Spot Market Exposure Revenue Per Day in ICD Contracted Backlog Q4’22 Revenue Per Day Guidance $31,200 $34,342 $35,958 $36,400 $36,849 $28,646

Drivers of Debt Reduction and Imbedded Value

ICD Operating Leverage Potential in an Improving Market Adjusted Annualized EBITDA Potential Across Various Rig Margin Per Day Scenarios ICD has significant operating leverage potential in an improving market in which dayrates and U.S. land rig count are increasing; currently expect 4Q’22 margin per day between $12,500 and $13,000 and 1Q’23 margin per day between $14,500 and $15,000 Future margin progression in 2023 above Q1’22 levels expected to be driven by: Current contractual backlog extending into 2023 priced at average revenue per day exceeding $35,000 generating $17,500+ per day margins at current operating cost levels Continued benefit from contract repricings on short term contracts Incremental rig reactivations of 300 Series rigs Incremental 200-to-300 Series conversions Indicative potential Adjusted EBITDA based upon the following additional assumptions: Cash SG&A: $18.0 million, reflecting recruiting, labor and other cost inflation Indicative operating rigs at full effective utilization (99% realization) $000s Illustrative Margin Per Day

Illustrative ICD Free Cash Flow Growth Key Assumptions Assume average margin of $14.75K consistent with Q1’23 margin guidance throughout the illustrative periods (ICD current 2023 backlog pricing $2,500+ higher than this assumption) Cash SG&A: $18 million per year Maintenance/Other capex: $2,250 per day Growth capex: Reactivate rigs 21-24 (2023): $30 million Reactivate rigs 25-26 (2024): $16 million 200-to-300 Series conversions: $3M in each of 2023/2024 Full effective utilization of rigs (99% realization) PIK interest in 2022 and 2023 (SOFR + 9.5%) Cash interest in 2024 and 2025 (SOFR + 12.5%) SOFR: 4.0% ICD does not exercise any rights to repurchase convertible debt Mandatory offer to repurchase notes not accepted by noteholders ICD becomes cash federal income taxpayer beginning in 2025 when NOL usage not expected to fully offset estimated taxable income 1 Assuming a constructive market through 2025, ICD poised to generate significant free cash flow that can be utilized to reduce net debt, repay outstanding indebtedness and return capital to stockholders

ICD Balance Sheet & Capital Structure Refinancing completed March 18, 2022 significantly de-risked ICD balance sheet Prior to refinancing, near-term debt maturities and balance sheet risk impeded investor interest and ICD’s ability to reactivate rigs into a very strong market Refinancing provides access to liquidity that allows ICD to reactivate remaining marketed rigs (all 300 Series) into a very strong market ICD poised to significantly delever balance sheet even with no conversion of the Convertible Notes Even assuming full conversion of the Convertible Notes issued in the refinancing, significant upside exists for ICD stockholders Convertible Notes Material Terms Maturity: March 18, 2026 Conversion Price: $4.51 (at Holder’s option) Ability to PIK interest at ICD option for entirety of the Convertible Notes term PIK Interest Rate: SOFR + 9.5% Cash Interest Rate: SOFR + 12.5% See Appendices for additional terms and details

Illustrative Debt Reduction Assuming a constructive market through 2025, ICD cash flow significantly improves ICD leverage position that can be utilized to repay/refinance outstanding indebtedness or return capital to stockholders 1 PIK interest assumed through March ’24 Utilizes cash flow assumptions from Slide 24 Ratio of Net Debt / Adjusted EBITDA as of end of period 0.30X $000s

Significant potential for uplift as the overhang related to our prior leverage profile gives way to imbedded value in our premier fleet. Newbuild Super-Spec, Pad-Optimal rigs estimated to cost $30+ million with 12+ month lead times Adjusted Enterprise Value / Active Rig(1) ($ in millions) Significant Potential Value Uplift Source: public filings and Enverus as of 10/27/22 calculated as Adjusted Enterprise Value divided by Active Rigs. Active rig counts based upon U.S. active rigs per Enverus (50% value for SCR rigs) for each of HP, PTEN, NBR and PDS. Adjusted Enterprise Values reflect estimated proportion of total company represented by U.S. land drilling business based upon reported asset book values and segment operating income, as reported. “Unconverted” value per rig based upon current ICD stock price and no conversion of Notes; “As-Converted” value per rig assumes full conversion of the Notes and ICD stock price of $6.00 per share 3) As of October 27, 2022 Unconverted (2) As-Converted(2) ICD current share price: $4.03(3) Even assuming a $6.00 share price, ICD is discounted on $/rig metrics ICD is materially undervalued vs. peers based on $/rig metrics Average: $19.5 million

Even assuming full conversion of the convertible notes, significant upside exists for ICD stockholders as they participate in value creation driven by a constructive market, additional rig reactivations, 200-to-300 Series conversions, and ICD closing the valuation gap between its public company peers PIK interest through Q1’24 expected to exceed the cost to reactivate ICD’s idle marketed rigs and provide liquidity Current public company valuations for active super-spec rigs currently estimated to be approximately $19.5 million Illustrative table based on the following assumptions: ICD ends 2022 with 20 operating rigs (all currently contracted) ICD reactivates four additional 300 Series rigs in 2023 (24 rig fleet) ICD reactivates two additional 300 Series rigs in 2024 (26 rig fleet) ICD elects PIK interest through Q1’24 PIK interest rate is 13.5% (9.5% + SOFR, with SOFR assumed to be 4%) No redemption of Convertible Notes during term / No mandatory offer accepted by Holders Convertible Notes fully convert at maturity Valuation analysis ignores any cash build up during Notes term: see slide 24 for an illustration of free cash flow build ICD closing share price on October 27, 2022: $4.03 Significant Potential Value Uplift Illustration of potential stockholder upside assuming full conversion of convertible notes based upon enterprise value to active rig ($millions except per share data) As of September 30, 2022 See Appendix Slide 38 for roll forward of debt balance and PIK interest

Significant Potential Value Uplift Illustration of potential stockholder upside assuming full conversion of convertible notes based upon illustrative EBITDA trading multiples ($millions except margin per day and per share data) Even based upon reasonable EBITDA trading multiples and assuming full conversion of the convertible notes, significant upside exists for ICD stockholders as they participate in value creation driven by a constructive market, additional rig reactivations, 200-to-300 Series conversions, and ICD closing the valuation gap between its public company peers Illustrative table based on the following assumptions: ICD currently has 20 contracted rigs and has scheduled two additional reactivations in Q1’23 / early Q2’23 (22 rig fleet) ICD reactivates two additional rigs in 2023 (24 rig fleet) ICD reactivates two additional rigs in 2024 (26 rig fleet) Rigs operate at full effective utilization (99% realization) ICD elects PIK interest through Q1’24 PIK interest rate is 9.5% + SOFR, with SOFR assumed to be 4.0%) No redemption of Notes during term Convertible notes fully convert at maturity (estimated 58.64 million shares) Valuation analysis ignores any cash build up during Notes term: see slide 24 for an illustration of free cash flow build

ESG

ESG and Sustainability Focused 1) As of September 30, 2022 Environment ICD operations substantially reduce GHG emissions and environmental footprints at the wellsite 100% of ICD marketed rigs are dual fuel enabled and high line capable, permitting substantial reduction and elimination of GHG emissions at the wellsite from rig operations 100% of ICD rigs utilize omni directional walking systems that enable large scale pad operations which substantially reduces environmental footprints at the wellsite 100% of ICD rigs utilize energy efficient LED lighting and/or crown lighting which substantially reduces energy use and “dark sky” environmental impacts ICD is a leading provider of contract drilling services in the natural gas producing regions located in ETX/Haynesville areas which are expected to become increasingly relevant as energy transition efforts continue to develop and accelerate Social ICD believes our people are our greatest resource and continuously focuses on creating a culture where employee safety, opportunity, well being and development is prioritized ICD utilizes leading safety management and training systems; 100% of ICD employees completed social, ethics and compliance training in 2021 ICD is committed to a culture of diversity and inclusion 38% of ICD’s workforce is currently comprised of historically underrepresented groups (1) ICD provides industry leading health and welfare benefits focused on employee well being ICD actively participates in community outreach programs in regions where we operate Governance ICD’s Board prioritizes shareholder alignment and ESG initiatives that benefit all stakeholders and the environment Board level oversight of ESG goal setting, performance and outreach ICD Executive LTIP compensation substantially at risk and performance based, and thus closely aligned with shareholder interests Executive compensation structures include safety, environmental and other ESG goals and metrics

Leading Exposure to U.S. Natural Gas Production ICD Exposure to Natural Gas Drilling Compared to Overall Market Contracted rigs as of October 31, 2022 Source: Enverus

ICD ShaleDriller Rigs Substantially Reduce and Eliminate GHG Emissions at the Wellsite Utilizing natural gas rather than diesel substantially reduces GHG emissions. ICD customers routinely use field natural gas to power our rigs, providing even more significant positive impacts on the environment. The first rig ICD built in 2012 was equipped with Dual-Fuel engines and today 100% of ICD’s marketed fleet is equipped with Dual- Fuel capabilities. Dual-Fuel Equipped 100% of ICD’s Rigs Similar to an electric car, utilizing the electric grid to power a rig’s engines substantially eliminates GHG emissions at the wellsite. All ICD rigs are capable of running on Hi-Line Electric Power. ICD began operating rigs on Hi-Line Electric power in 2019 and continually markets this option to its customers where operational infrastructure permits. Hi-Line Electric Power Capable 100% of ICD’s Rigs LED/CROWN LIGHTING 100% of ICD’s Rigs In 2019, ICD converted all of its rigs from fluorescent lighting to LED lighting and is in process of converting all of its rigs from traditional lighting to crown lighting systems. LED and crown lighting systems substantially reduce energy use and eliminate light pollution, in particular in environmentally sensitive areas where “dark sky” environmental issues exist.

Land Drilling’s Only U.S. Publicly-Traded, Pure-Play, Pad-Optimal, Super-Spec, Growth Story Highest Asset Quality 100% Pad-Optimal, Super-Spec Fleet Premier Customer Base Rapidly Expanding Margins/Cash Flows Driven by Strategic Investments and Market Conditions Significant Investment Opportunity - Meaningful Current Valuation Discount to Market Based Upon Both Asset Values and Cash Flow Multiples Fleet 100% Dual-Fuel Enabled / Electric Hi- Line Capable: Substantial GHG Reduction / Elimination Recognized Industry Leader for Service and Professionalism Ideal Geographic Focus on Most Prolific Oil and Natural Gas Producing Regions

Investor Contact Information Email inquiries: investor.relations@icdrilling.com Phone inquiries: (281) 878-8710

APPENDICES

Convertible Debt Terms Amount/Maturity Current balance at 9/30/22: $170.2 million: optional $7.5 million uncommitted accordion upsizing Matures March 18, 2026 Defeasance options begin 18 months prior to maturity Interest; PIK Amount Cash interest at SOFR + 12.5% PIK Interest at SOFR + 9.5% ICD has right to PIK interest throughout term of the Notes Conversion Conversion price: $4.51 ICD has the right to mandatorily convert Notes in certain change of control transactions involving larger public companies, subject to a minimum MOIC Redemption Through 9/18/23, ICD has right to redeem up to $25 million at 104% plus accrued interest. Redemptions funded by equity sales at price equal to greater than conversion price (“Optional Redemption Rights”) Company obligated to offer to redeem notes at par in principal amount of $5.0 million on each of June 30, 2023, Sept 30, 2023, Dec 31, 2023, and in principal amounts of $3.5 million on each of Mar 31, 2024, June 30, 2024 and September 30, 2024 (obligation falls away to extent optional redemption rights exercised) Governance Limitation on Voting Rights. Each Holder’s beneficial common stock ownership post conversion limited to 19.9% or lower of outstanding shares; any conversion in excess of ownership limitations issued in pre funded, non voting warrants Board Rights: Holders entitled to appoint up to three members of a seven member Board, one of which must be independent, subject to reduction if note ownership declines

PIK Interest Feature Creates Flexibility to Maximize Returns While Executing Strategic Initiatives ICD permitted to PIK interest at its option over entirety of Convertible Notes term: assuming PIK interest through March 31, 2024 to fund reactivation of remaining marketed fleet, there is no economic dilution to ICD stockholders as the significant returns and cash flows generated far exceed incremental share dilution 1) PIK interest rate SOFR + 9.5%; SOFR Assumed: 4%; interest compounds/paid semi-annually on March 31st and September 30th of each calendar year through maturity; convertible debt balances between interest payment dates include accrued interest 2) Assumes incremental cash flow per day of $15K (incremental margin per day less maintenance capex) for each reactivated 300 Series rig, consistent with most recent reactivation contracts signed

Maximizing Returns By Strategically Marketing ICD Fleet Across Target Markets Permian – Midland Basin 200 Series Target Market Eagle Ford/STX 200 Series Target Market Haynesville/ETX 300 Series Target Market Permian – Delaware Basin 300 Series Target Market

ICD Fleet Utilization Growth Substantially Outperforming Overall Market Source: BHI Rig Count ICD currently has 20 rigs contracted and is marketing six additional rigs for reactivation during 2023+

ICD Positioning in a Consolidating Market Number of Operating Super-Spec or AC Rigs Convertible into Super-Spec Rigs ICD Target Markets: TX, LA, NM(1) Enverus. Active AC rigs with 1500-2000hp drawworks (as of July 27, 2022) Defined as a company listed on NYSE, NASDAQ, or Toronto Exchanges with market cap of at least US$350M and public float of at least US$250M ICD well positioned to participate in industry consolidation activity as it develops during the current market upcycle ICD SG&A overhead structure scalable and will not materially increase in the event of additions to its operating fleet in its target markets ICD has the ability to mandatorily convert the convertible notes and deliver a delevered company in transaction with larger public company(2)

Appendices: Financial Statements INDEPENDE CONTRACT DRILLING, INC. Unaudited (in thousands, except per value and share data) CONSOLIDATED BALANCE SHEET September 30, 2022 December 31, 2021 Assets Cash and cash equivalents $ 7,566 $ 4,140 Accounts receivable 33,967 22,211 Inventories 1,433 1,171 Prepaid expenses and other current assets 2,940 4,787 Total current assets 45,906 32,309 Property, plant and equipment, net 365,160 362,346 Other long-term assets, net 2,159 2,449 Total assets $ 413,225 $ 397,104 Liabilities and Stockholder’s Equity Liabilities Current portion of long-term debt (1) $ 3,302 $ 4,464 Accounts payable 28,859 15,304 Accrued liabilities 13,162 11,245 Accrued interest 122 4,372 Current portion of merger consideration payable to an affiliate – 2,902 Total current liabilities 45,445 38,287 Long-term debt (2) 136,756 141,740 Deferred income taxes, net 19,391 19,037 Other long-term liabilities 1,661 2,811 Total liabilities 203,253 201,875 Commitments and contingencies Stockholder’s equity Common stock, $0.01 par value, 250,000,000 shares authorized; 13,698,851 and 1,287,931 shares issued, respectively, and 13,617,005 and 10,206,085 shares outstanding, respectively 136 102 Additional paid-in capital 616,316 532,826 Accumulated deficit (402,557) (333,776) Treasury stock, at cost 81,846 shares 81,846 shares, respectively (3,923) (3,923) Total stockholders’ equity 209,972 195,229 Total liabilities and stockholder’s equity $413,225 $397,104 (1) AS of September 30,2022, and December 31,2021, current portion of long-term debt includes $3.3 million and $4.5 million, respectively, of finance lease obligations. (2) As of September 30,2022, and December 31,2021, long-term debt includes $1.7 million and $1.3 million, respectively, of long-term finance lease obligations.

Appendices: Financial Statements INDEPENDENCE CONTRACT DRILLING, INC. Unaudited (in thousands, except par value and share data) CONSOLIDATED STATEMENTS OF OPERATIONS Three Months Ended Nine Months Ended September 30. June 30 September 30. 2022 2021 2022 2022 2021 Revenues s 49,147 s 24,035 s 42,313 s 126,451 s 59,394 Costs and expenses Operating costs 31,379 20,123 28,904 87,448 51,704 Selling, general and administrative 7.007 4.068 4,860 17.096 11,829 Depreciation and amortization 10.120 9.739 9.848 29.719 29.244 Asset impairment. net 482 775 Loss (gain) on disposition of assets, net 433 222 (582) (665) (182) Total costs and expenses 48,939 34,634 43,030 133,598 93,370 Operating income (loss) 208 (10,599) (717) (7,147) (33,976) Interest expense (8.098) (3,812) (8.232) (21.005) (11.294) Gain (loss) on extinguishment of debt 10.128 (46.347) 10.128 Change in fair value of embedded derivative liability (2,408) (4265) Realized gain on extinguishment of derivative 10 765 10 765 Loss before income taxes (7,890) (4,283) (592) (67,999) (35,142) Income tax (benefit) expense (696) 19 2,199 783 86 Net loss s (4,302) s (2,791) s (68,782) s (35,229 Loss per share Basic and diluted s (0.59) s (5.36) s (5.22) Weighted average number of common shares outstanding• Basic and diluted 13 590 7 321 13 590 12 836 6 754

Appendices: Financial Statements CONSOLIDATED STATEMENTS OF CASH FLOWS Cash flows from operating activities Net loss Nine Months Ended September 30, 2022 2021 $ (68,782) $ (35,228) Adjustments to reconcile net loss to net cash provided by (used in) operating activities Depreciation and amortization 29,719 29,244 Asset impairment, net — 775 Stock-based compensation 2,976 1,770 Gain on disposition of assets, net (665) (182) Non-cash interest expense 15,859 2,828 Non-cash loss (gain) on extinguishment of debt 46,347 (10,128) Amortization of deferred financing costs 320 836 Amortization of Convertible Notes issuance costs and debt discount 4,310 Change in fair value of embedded derivative liability 4,265 — Gain on extinguishment of derivative (10,765) — Deferred income taxes 354 86 Bad debt expense (recovery) 256 (52) Changes in operating assets and liabilities Accounts receivable (12,012) (6,863) Inventories (291) (40) Prepaid expenses and other assets 2,098 1,929 Accounts payable and accrued liabilities 208 7,322 Net cash provided by (used in) operating activities 14,197 (7,703) Cash flows from investing activities Purchases of property. plant and equipment (22,286) (9,692) Proceeds from the sale of assets 2,749 1,849 Net cash used in investing activities (19,537) (7,843) Cash flows from financing activities Proceeds from issuance of convertible debt 157,500 Repayments under Term Loan Facility (139,076) — Borrowings under Revolving ABL Credit Facility 1,576 4,309 Repayments under Revoking ABL Credit Facility (28) (17) Payment of merger consideration (2,902) Proceeds from issuance of common stock through at-the-market facility, net of issuance costs 3,038 3,859 Proceeds from issuance of common stock under purchase agreement — 2,072 RSUs withheld for taxes (32) (11) Convertible debt issuance costs (7,230) Financing costs paid under Revolving ABL Credit Facility’ (266) — Payments for finance lease obligations (3,814) (2,643) Net cash provided by financing activities 8,766 7,569 Net increase (decrease) in cash and cash equivalents 3,426 (7,977) Cash and cash equivalents Beginning of period 4,140 12,279 End of period $ 7,566 $ 4,302 Nine Months Ended September 30, 2022 2021 Supplemental disclosure of cash flow information Cash paid during the period for interest $ 4,745 $ 6,660 Supplemental disclosure of non-cash investing and financing activities Change in property, plant and equipment purchases m accounts payable $ 9,015 $ 3,755 Additions to property. plant and equipment through finance leases $ 3,250 $ 754 Extinguishment of finance lease obligations from sale of assets classified as finance leases $ (163) $ Transfer of assets from held and used to held for sale $ $ (1,082) Gain on extinguishment of debt $ — $ 10,000 Shares issued for structuring fee $ 9,163 $ —

Appendices: Other Financial & Operating Data The following table provides various financial and operational data for the Company’s operations for the three months ended September 30, 2022and 2021 and June 30. 2022 and the nine months ended September 30, 2022 and 2021. This information contains non-GAAP financial measures of the Company’s operating performance. The Company believes this non-GAAP information is useful because it provides a means to evaluate the operating performance of the Company on an ongoing basis using criteria that are used by the Company’s management. Additionally, it highlights operating trends and aids analytical comparisons. However, this information has limitations and should not be used as an alternative to operating income (loss) or cash flow performance measures determined in accordance with GAAP, as this information excludes certain costs that may affect the Company's operating performance in future periods. OTHER FINANCIAL & OPERATING DATA Unaudited Three Months Ended Nine Months Ended September 30, June 30, September 30, 2022 2021 2022 2022 2021 Number of marketed rigs end of period (1) 26 24 24 26 24 Rig operating days (2) 1,601 1,268 1,540 4,604 3,273 Average number of operating rigs (3) 17.4 13.8 16.9 16.9 12.0 Rig utilization (4) 70 % 58 % 71 % 69 % 50 % Average revenue per operating day (5) $ 28,646 $ 17,141 $ 24,875 $ 25,216 $ 16,459 Average cost per operating day (6) $ 17,305 $ 13,685 $ 15,929 $ 16,452 $ 13,285 Average rig margin per operating day $ 11,341 $ 3,456 $ 8,946 $ 8,764 $ 3,174 (1) Marketed rigs exclude idle rigs that will not be reactivated unless market conditions materially improve. (2) Rig operating days represent the number of days the Company’s rigs are earning revenue under a contract during the period, including days that standby revenue is earned. (3) Average number of operating rigs is calculated by dividing the total number of rig operating days in the period by the total number of calendar days in the period. (4) Rig utilization is calculated as rig operating days divided by the total number of days the Company’s marketed drilling rigs are available during the applicable period. (5) Average revenue per operating day represents total contract chilling revenues earned during the period divided by rig operating days in the period. Excluded in calculating average revenue per operating day are revenues associated with the reimbursement of out-of-pocket costs paid by customer's of $3.3 million, $2.3 million and $4.0 million during the three months ended September 30, 2022 and 2021, and June 30, 2022, respectively, and $10.3 million and $5.5 million during the nine months ended September 30, 2022 and 2021. respectively. (6) Average cost per operating day represents operating costs incurred during the period divided by rig operating days in the period. The following costs are excluded in calculating average cost per operating day: (i) out-of-pocket costs paid by customers of $3.3 million. $2.3 million and $4.0 million during the three months ended September 30, 2022 and 2021, and June 30, 2022, respectively, and $10.3 million and $5.5 million during the nine months ended September 30, 2022 and 2021, respectively; (ii) overhead costs of $0.4 million, $0.4 million and $0.4 million during the three months ended September 30, 2022 and 2021, and June 30,2022, respectively, and $1.4 million and $1.2 million during the nine months ended September 30, 2022 and 2021, respectively; and (iii) rig reactivation costs, inclusive of new crew training costs, of zero. $0.1 million and zero during the three months ended September 30,2022 and 2021, and June 30, 2022, respectively, and zero and $1.4 million during the nine months ended September 30, 2022 and 2021, respectively.

Appendices: Non-GAAP Measures Non-GAAP Financial Measures Adjusted net debt, adjusted net (loss) income. EBITDA and adjusted EBITDA are supplemental non-GAAP financial measures that are used by management and external users of the Company’s financial statements, such as industry analysts, investors, loaders and rating agencies. In addition, adjusted EBITDA is consistent with how EBITDA is calculated under the Company’s credit facility for purposes of determining the Company’s compliance with various financial covenants. The Company defines ’’adjusted net debt” as long-term notes (excluding long-term capital leases) less cash. The Company defines “adjusted net (loss) income” as net (loss) income before: asset impairment, net; gain or loss on disposition of assets, net; amortization of debt discount; amortization of issuance costs; gain or loss on extinguishment of debt; change in fail' value of embedded derivative liability, gain on extinguishment of derivative and other adjustments. The Company defines "EBITDA” as earnings (or loss) before interest, taxes, depreciation and amortization, and asset impairment, net and the Company defines "adjusted EBITDA” as EBITDA before stock-based compensation, gain or loss on disposition of assets, gain or loss on extinguishment of debt, gain on extinguishment of derivative and other non-recurring items added back to, or subtracted from, net income for purposes of calculating EBITDA under the Company’s credit facilities. Neither adjusted net (loss) income, EBITDA or adjusted EBITDA is a measure of net income as determined by U.S. generally accepted accounting principles (“GAAP”). Management believes adjusted net debt, adjusted net (loss) income, EBITDA and adjusted EBITDA are useful because they allow the Company’s stockholders to more effectively evaluate the Company’s operating performance and compliance with various financial covenants under the Company’s credit facility and compare the results of the Company’s operations from period to period and against the Company’s peers without regard to the Company’s financing methods or capital structure or non-recurring, non-cash transactions. The Company excludes the items listed above from net income (loss) in calculating adjusted net (loss) income, EBITDA and adjusted EBITDA because these amounts can vary substantially from company to company within the Company’s industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. None of adjusted net (loss) income, EBITDA or adjusted EBITDA should be considered an alternative to, or more meaningful than, net income (loss), the most closely comparable financial measure calculated in accordance with GAAP, or as an indicator of the Company’s operating performance or liquidity. Certain items excluded from adjusted net (loss) income, EBITDA and adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company's return on assets, cost of capital and tax structure. The Company’s presentation of adjusted net debt adjusted net (loss) income. EBITDA and adjusted EBITDA should not be construed as an inference that the Company’s results will be unaffected by unusual or non-recurring items. The Company’s computations of adjusted net debt adjusted net (loss) income, EBITDA and adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Calculation of Adjusted Net Debt: (in thousands) September 30, 2022 Convertible Notes $ 170,166 Revolving ABL Credit Facility 7,848 Less: Cash (7,566) Adjusted net debt $ 170,448 Reconciliation of Adjusted Net Debt to Reported Long-Term Debt: (in thousands) September 30, 2022 Adjusted net debt $ 170,448 Add back: Cash 7,566 Long-term portion of finance lease obligations 1,745 Less: Debt discount, net of amortization (34,761) Deferred issuance costs, net of amortization (8,242) Total reported long-term debt $ 136,756 Reconciliation of Net Loss to Adjusted Net Loss: (Unaudited) (Unaudited) Three Months Ended Nine Months Ended September 30. June 30, September 30, 2022 2021 2022 2022 2021 Amount Per Share Amount Per Share Amount Per Share Amount Per Share Amount Per Share (in thousands) Net loss $ (7,194) $ (0.53) $ (4,302) $ (0.59) $ (2,791) $ (0.21) $ (68,782) $ (5.36) $ (35,228) $ (5.22) Add back: Asset impairment, net (1) Loss (gain) on disposition of — — 482 0.07 — — — — 775 0.12 assets, net (2) 433 0.03 222 0.03 (582) (0.04) (665) (0.05) (182) (0.03) Amortization of debt discount 1,354 0.10 — — 1,462 0.11 2,816 0.22 — — Amortization of issuance costs 606 0.05 — — 518 0.04 1,124 0.09 — — Loss (gain) on extinguishment of debt(3) — — (10,128) (1.38) — — 46,347 3.61 (10,128) (1.50) Change in fair value of embedded derivative liability (4) — — — — 2,408 0.17 4,265 0.33 — — Gain on extinguishment of derivative (5) — — — — (10,765) (0.79) (10,765) (0.84) — — Adjusted net loss $ (4,801) $ (0.35) $ (13,726) $ (1.87) $ (9.750) $ (0.72) $ (25,660) $ (2.00) $(44,763) $ (6.63)

Appendices: Non-GAAP Measures Reconciliation of Net Loss to EBITDA and Adjusted EBITDA: (Unaudited) (Unaudited) Three Months Ended Nine Months Ended September 30. June 30, September 30, 2021 2011 2022 2022 2021 (in thousands) Net loss $ (7,194) $ (4,302) $ (2,791) $ (68,782) $ (35,228) Add back: Income tax (benefit) expense (696) 19 2,199 783 86 Interest expense 8,098 3,812 8,232 21,005 11,294 Depreciation and amortization 10,120 9,739 9,848 29,719 29,244 Asset impairment, net (1) 482 775 EBITDA 10,328 9,750 17,488 (17,275) 6,171 Loss (gain) on disposition of assets, net (2) 433 222 (582) (665) (182) Stock-based and deferred compensation cost 1,709 819 674 3,361 2,421 Loss (gain) on extinguishment of debt (3) — (10,128) 46,347 (10,128) Change in fair value of embedded derivative liability (4) — 2,408 4,265 Gain on extinguishment of derivative (5) — — (10,765) (10,765) — Adjusted EBITDA $ 12,470 $ 663 $ 9,223 $ 25,268 $ (1,718) (1) During the third quarter of 2021, we impaired $0.5 million of drilling equipment that we deemed obsolete or no longer usable in our business. During the second quarter of 2021, we unpaired a damaged piece of drilling equipment for $0.3 million, net of insurance recoveries. (2) Loss or gain on disposition of assets, net represents the sale or disposition of miscellaneous drilling equipment in each respective period. (3) Loss on extinguishment of debt related to unamortized debt issuance costs on our prior term loan facility, non-cash structuring fees settled in shares to the affiliates of our prior term loan facility and the fair value of the embedded derivatives attributable to the affiliates of our prior term loan facility in the first quarter of 2022. During the third quarter of 2021, we received notice from the SBA of full forgiveness of our PPP loan and recorded a gain on extinguishment of debt of $10.1 million. (4) Represents the change in fair value of embedded derivative liability between March 31, 2022and June 8,2022, and March 18, 2022 and June 8, 2022, respectively. The embedded derivative liability was extinguished on June 8, 2022. (5) Represents the gain on extinguishment of the variable PIK interest rate feature of the derivative liability.