Exhibit 99.1
Enercom: The Oil and Gas Conference August 16-18, 2021 |
2 Preliminary Matters 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 sustained 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 and financial performance; • 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. |
3 Land Drilling’s Only Publicly-Traded, Pure-Play, Pad-Optimal, Super-Spec, Growth Story Highest Asset Quality 100% Super Spec - Pad Optimal Marketed Fleet with Best Geographic Focus Improving Dayrates & Utilization Driven by Market Fundamentals Market Share Gains Driven By 300 Series Rigs and Overall Market Consolidation Poised for Significant Free Cash Flow Yields Fleet 100% Dual-Fuel Enabled / Electric Hi- Line Capable: Substantial GHG Reduction / Elimination Customer Focused and Proven Operational Excellence Geographic Locations Focused on Most Prolific Oil and Natural Gas Producing Regions |
4 Introduction: NYSE: ICD Best-in-Class Asset Quality and Geographic Focus • Marketed fleet comprised entirely of pad-optimal, super-spec rigs • Established presence in oil rich Permian and Eagle Ford plays • Leading presence in natural gas rich Haynesville and East TX regions • Increasing market penetration of 300 Series rigs • 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 by Energy Point Research past three years: 2019, 2020 and 2021 • Established relationships with publics and well-capitalized private operators • Industry leading and scalable safety, maintenance and financial systems Returns & Free Cash Flow Generation • Steadily increasing utilization and spot dayrates as market recovers from COVID-19 impacts drives potential for significant free cash flow generation and yields • Increasing market penetration of 300 Series rigs • Scalable cost structure for organic growth / M&A opportunities ESG Focus • Marketed fleet 100% dual-fuel and hi-line power capable • Omni-directional walking reduces operational footprints and environmental impacts • Increasingly diverse workforce: over 25% from under-represented groups • Shareholder alignment: executive comp substantially at-risk/ performance based • Leading presence in natural-gas-rich Haynesville and East TX regions Sectors only publicly-traded, pure-play, pad-optimal, super-spec, drilling contractor focused solely on North America’s most attractive oil and natural gas basins |
5 14 “300” Series ShaleDriller Rigs(1) ◼ 1,500 – 2,000 HP drawworks; 25K+ racking / 1M lb. hook with only modest capex ◼ 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 17 “200” Series ShaleDriller Rigs ◼ 1,500 HP drawworks; 20K+ racking / 750K lb. hook ◼ Three pump / four engine capable; drilling optimization software capable ◼ Dual-Fuel / Hi-Line Electric Power Capable 1 “100” Series ShaleDriller Rig ◼ 1,000 HP drawworks ◼ Three pump / four engine capable; drilling optimization software capable ◼ Dual-Fuel enabled / Hi-Line Electric Power Capable ICD Operations Strategically Focused on the Most Prolific Oil and Natural Gas Producing Regions in the United States Texas Oklahoma Arkansas Louisiana New Mexico ICD owned or leased location ICD Operating Area (1) Includes two 200 Series rigs scheduled for conversion (aggregate capex < $1M) (2) Based upon date of first well spud following rig construction or material upgrade ICD CURRENT ACTIVE MARKETED FLEET: 24 RIGS AVERAGE RIG AGE: 6.55 YEARS(2) |
6 Maximizing Returns By Strategically Marketing ICD Fleet Across Target Markets Texas Oklahoma Arkansas Louisiana New Mexico Haynesville/ETX 300 Series Target Market Permian – Delaware Basin 300 Series Target Market Permian – Midland Basin 200 Series Target Market Eagle Ford/STX 200 Series Target Market |
7 Geographic Mix And Customer Relationships Recent ICD Customers Strong Customer Base Current ICD Operating Rigs By Basin (1) Occidental Petroleum Corporation via Anadarko Petroleum acquisition (2) ConocoPhillips via Concho Reources acqusition Permian 7 Permian 8 STX/ Eagle Ford 3 Haynesville/ ETX 4 1 2 |
8 0% 50% 100% 150% 200% 250% 300% 350% 400% Q3'20 Q4'20 Q1'21 Q2'21 Current CUMULATIVE PERCENTAGE INCREASE IN RIG COUNT SINCE PANDEMIC TROUGH US Land Rig Count % Growth ICD Operating Rig Count % Growth Since Beginning of Pandemic Recovery ICD Fleet Utilization Growth Substantially Outperforming Overall Market Source: BHI Rig Count |
9 0 5 10 15 20 25 Precovid (1Q'20) 3Q'21 4Q'21 1Q'21 2Q'21 Current Working ICD 300 Series Rigs Total ICD Working Rigs 300 Series Rigs Leading Acceleration in Fleet Utilization ICD Total Working Rigs ICD Total 300 Series Fleet ICD 300 Series Rigs • Rigs meeting these specs command highest dayrates when matched with customers requiring such specification - 14 total 300 Series rigs in ICD fleet. Expect these rigs to represent majority of future rig reactivations and growing % of ICD’s overall operating fleet - Target operating fleet composition: 50% 300 Series / 50% 200 Series • Target customers requiring larger racking capacity, hookload, high-torque drill pipe: predominantly Delaware Basin and Haynesville • Minimal excess capacity for rigs meeting 300 Series specification • 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 |
10 ICD Performance Meeting and Exceeding Customer Expectations ICD has been the #1 ranked U.S. Land Driller for Service and Professionalism for the past three years by Energy Point Research’s independent customer survey Independence Contract Drilling was one of only three land drillers recognized in 2021 by Energy Point Research in the Overall Total Satisfaction category of its customer survey. |
11 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: 50% of ICD marketed fleet • Enhanced racking (25K ft) and hookload (1M lb) capable: 50% of ICD marketed fleet • Drilling optimization software capable: 100% of marketed fleet • Dual-fuel / Electric Hi-line capable : 100% of marketed fleet Total U.S. Pad-Optimal Super-Spec Supply: ̴ 620 Rigs(1) 450 Pad Optimal Rigs 170 Upgradeable Rigs(2) (1) Source: Enverus and Company estimates. Includes AC, 1500HP+, 750000lb+ Hookload. Excludes rigs not operating since 2018 and rigs owned by non-operating entities (2) 1500HP AC Rigs with skidding systems upgradeable to omnidirectional walking. Capex estimated at $5M+ per rig. |
12 Drivers for Expected Improvements in Pad-Optimal Utilization / Dayrates • Accelerating rig count with improving fundamentals • Rapidly normalizing demand for oil • Constructive U.S. natural gas supply / demand fundamentals • Rapidly decreasing drilled-but-uncompleted (DUC) inventories • Pad Optimal market share consolidating within few players with ICD utilization growth outpacing overall market • U.S. land pad optimal, super-spec fleet approaching 80% utilization |
13 U.S. Land Rig Count has Trailed Commodity Price Recovery but is Expected to Accelerate Quickly 0 10 20 30 40 50 60 70 80 0 200 400 600 800 1,000 1,200 Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Q2'18 Q3'18 Q4'18 Q1'19 Q2'19 Q3'19 Q4'19 Q1'20 Q2'20 Q3'20 Q4'20 Q1'21 Q2'21 U.S. Average Land Rig Count vs WTI Avg US Land Rig Count Avg WTI Price Current WTI Price(1) 2022 Average U.S. Land Rig Count Estimates Avg: 548(2) Source:Baker Hughes, EIA (1) As of August 10, 2021 (2) Average Estimates per JP Morgan Morgan Stanley, Wells Fargo, Evercore, Spears, Rystadt, Simmons |
14 Rapidly Normalizing Demand for Oil Source: EIA Short-Term Energy Outlook 80% 82% 84% 86% 88% 90% 92% 94% 96% 98% 100% 2019 Q1'20 Q2'20 Q3'20 Q4'20 Q1'21 Q2'21 Q3'21 Q4'21 Q1'22 Q2'22 Q3'22 Q4'22 Quarterly Worldwide Oil Demand as a % of 2019 Demand Trough demand: (17%) vs 2019 daily average Demand expected to reach 2019 levels by Q3’22 |
15 Decreasing DUC Inventories Should Drive Incremental Drilling Activity 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 Jan-19 Feb-19 Mar-19 Apr-19 May-19 Jun-19 Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19 Jan-20 Feb-20 Mar-20 Apr-20 May-20 Jun-20 Jul-20 Aug-20 Sep-20 Oct-20 Nov-20 Dec-20 Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Duc Inventory Completed Wells (Spuds, Completions, DUCs) U.S. Drilled-But-Uncompleted Well (DUC) Inventory Compared to Completed Wells Over Time DUC Inventories Completed Wells Source: EIA |
16 Consolidating Pad Optimal Super-Spec Market ICD 34% 54% 12% 2018 Total Industry Operating Rigs in ICD Primary Target Mkts: TX, NM, LA 24% 66% 10% 2021 Total Industry Operating Rigs in ICD Primary Target Mkts: TX, NM, LA (1) SCR, Mechanical and AC below 1500hp (2): HP, PTEN, NBR, PDS, ESI, ICD; includes PTEN planned acquisition of Pioneer Energy Services; Includes upgradeable AC rigs Source: Enverus as of 6/30/18 and 8/4/21 Legacy Rigs(1) Pad Optimal: Top Public Contractors(2) Pad Optimal: Other Contractors |
17 Total U.S. Pad Optimal Fleet Utilization Approaching 80% in an Improving Market Should Drive Incremental Dayrate Increases 8/16/2021 0 50 100 150 200 250 300 350 400 450 500 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 80% Utilization Estimated Pad Optimal Fleet Pad Optimal Operating Rigs: U.S. Land (2) Estimated Pad Optimal Supply(1) 12/31/18 Drivers for increasing rig count and improving U.S. pad-optimal super-spec fleet utilization and dayrates include: • Strong oil and natural gas commodity price environment • Substantially declining DUC inventories • 2022 E&P Capex Budgets reset higher based upon current commodity price environment • Increasing size and complexity of well pads and depth and length of well laterals • Increasing rig reactivation costs (minimal idle pad optimal – super- spec rigs that have not been stacked less than 18 months) (1) 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 (2) Source: Enverus and Company estimates 8/1/21 |
18 ESG and Sustainability Focused 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 2020 • ICD is committed to a culture of diversity and inclusion - over 25% 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 • 100% of ICD 2021 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 (1) As of Aug 1, 2021 |
19 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. |
20 Drivers Towards Returns / Free Cash Flow Through Oil and Gas Cycle Improving Fleet Utilization • Since pandemic trough in Aug ‘20, ICD rig count has increased 400% compared to overall rig count increase of 100%(1). • ICD rig count poised to increase with further increases in overall US rig count weighted to ICD target markets and pad optimal / super spec rigs • ICD expects continued market penetration and increased utilization of its 300 Series rigs Increasing Dayrate Momentum • In response to post-pandemic recovery, spot dayrates are steadily rising • Increasing 300 Series market penetration expected to drive sequential dayrate improvements • Short-term contract structures allow ICD to steadily reprice contracts into an improving dayrate environment, driving sequential improvements in revenue-per- day statistics • U.S. pad-optimal fleet utilization expected to approach 80% with continuing improvements in U.S. rig count during the remainder of 2021 and during 2022 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 • Increasing rig utilization drives operating efficiencies expected to result in steady improvements in cost-per-day metrics • Scalable SG&A cost structure: minimal increases in SG&A as operating fleet and revenues increase as COVID-19 pandemic recovery continues (1) Baker Hughes as of 8.14.20 and 8.6.21 |
21 ICD Margins Already Expanding in Market Recovery In a continuing market recovery and improving rig count environment, the following factors are expected to positively impact ICD revenues, costs, and margin per day compared to Pre-COVID periods: • 300 Series rig pricing and differentiation • Efficiency improvements made in 2018 and 2019 following Sidewinder Merger(1) and in response to COVID expected to be fully realized and drive additional cost savings • Cost savings from economies of scale • Current short term contract structures permit steady repricing of contracts into an improving market $12,000 $14,000 $16,000 $18,000 $20,000 $22,000 4Q'18 FYE'19 FYE'20 1Q'21 2Q'21 3Q'21 Forecast Revenue Per Day Cost Per Day (1) Sidewinder Merger closed 10/1/2018 (2) Guide: Represents Company forecasts provided on 2Q’21 Earnings Conference Call held 8/4/21 Margin Per Day |
22 Closing Improving and Constructive Market Fundamentals 100% Super-Spec Pad Optimal Fleet Expanding 300 Series Market Penetration and Overall Fleet Utilization Free Cash Flow Growth/Yields 100% Fleet Carbon Reducing Enabled Expanding Margins |
23 |
24 Corporate Snapshot Capitalization(1) ($ millions, except share price) ¹ Financial data other than share price as of 6/30/21. Shares outstanding as of 8/1/21. ² PPP applicaton for forgiveness filed 2Q’21 Financial Liquidity June 30, 2021 Cash $6.0 Undrawn Revolver Capacity 11.3 Undrawn Committed Accordion 15.0 Undrawn Equity Line of Credit 3.1 Total Liquidity $35.4 $ millions Share Price as of 8/12/21 $3.18 Shares Outstanding 7.2 Equity Value $22.9 Term Loan 132.8 Revolver Outstanding - PPP Loan Outstanding(2) 10.0 Capital Leases 6.8 Total Debt $149.6 Cash 6.0 Net Debt $143.6 Enterprise Value $166.5 $133 million term loan • Matures October 2023 • No amortization • Additional committed $15 million delayed-draw accordion • Minimal financial covenants • Pre-payable at any time Revolving line of credit • $40M total capacity • Borrowing base tied to eligible accounts receivable – as incremental rigs reactivate, borrowing base increases • Matures October 2023 • Minimal financial covenants PPP Loan • Forgiveness application filed 2Q’21 |
25 Consolidated Balance Sheet |
26 Consolidated Statement of Operations |
27 Adjusted net income and loss, EBITDA and adjusted EBITDA are supplemental non-GAAP financial measure that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. In addition, adjusted EBITDA is consistent with how EBITDA is calculated under our revolving credit facility for purposes of determining our compliance with various financial covenants. We define “EBITDA” as earnings (or loss) before interest, taxes, depreciation, and amortization, and we define “adjusted EBITDA” as EBITDA before stock-based compensation, non-cash asset impairments, gains or losses on disposition of assets, and other non-recurring items added back to, or subtracted from, net income for purposes of calculating EBITDA under our revolving credit facility. Neither adjusted net income or loss, EBITDA or adjusted EBITDA is a measure of net income as determined by U.S. generally accepted accounting principles (“GAAP”). Management believes adjusted net income and loss, EBITDA and adjusted EBITDA are useful because they allow our stockholders to more effectively evaluate our operating performance and compliance with various financial covenants under our revolving credit facility and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure or non-recurring, non-cash transactions. We exclude the items listed above from net income (loss) in calculating adjusted net loss, EBITDA and adjusted EBITDA because these amounts can vary substantially from company to company within our 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, 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 our operating performance or liquidity. Certain items excluded from adjusted net loss, EBITDA and adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s return of assets, cost of capital and tax structure. Our presentation of adjusted net loss, EBITDA and adjusted EBITDA should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of adjusted net income (loss), EBITDA and adjusted EBITDA may not be comparable to other similarly titled measures of other companies. The table on the following page present a reconciliation of net loss to adjusted net income (loss), EBITDA and adjusted EBITDA. Non-GAAP Financial Measures |
28 Reconciliation of Net Loss to Adjusted Net Income (Loss): Reconciliation of Net Loss to EBITDA and Adjusted EBITDA: See footnote explanations on following page. Non-GAAP Financial Measures |
29 Non-GAAP Financial Measures |
30 Non-GAAP Financial Measures See footnote explanations on following page. |
31 Non-GAAP Financial Measures |
32 |