The Transformed Earthstone J u n e   2 ,   2 0 2 2 1 Exhibit 99.2

Disclaimer Forward‐Looking Statements This presentation contains forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not strictly historical statements constitute forward‐looking statements and may often, but not always, be identified by the use of such words such as “expects,” “believes,” “intends,” “anticipates,” “plans,” “estimates,” “guidance,” “target,” “potential,” “possible,” or “probable” or statements that certain actions, events or results “may,” “will,” “should,” or “could” be taken, occur or be achieved. The forward‐looking statements include statements about the expected benefits of Earthstone Energy, Inc. (“ESTE,” “Earthstone” or the “Company”) and its stockholders from the acquisition (the “Bighorn Acquisition”) of certain assets from Bighorn Permian Resources, LLC (“Bighorn”) by Earthstone, the acquisition (the “Chisholm Acquisition” and with the Bighorn Acquisition, the “Acquisitions”) of certain assets from Chisholm Energy Operating, LLC and Chisholm Energy Agent, Inc. (collectively, “Chisholm”) by Earthstone, the private placement (the “PIPE”) of Series A Convertible Preferred Stock by Earthstone in the amount of $280 million, the expected future reserves, production, financial position, business strategy, revenues, earnings, free cash flow, costs, capital expenditures and debt levels of the Company, and plans and objectives of management for future operations. Forward‐looking statements are based on current expectations and assumptions and analyses made by Earthstone and its management in light of experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances. However, whether actual results and developments will conform to expectations is subject to a number of material risks and uncertainties, including but not limited to: Earthstone’s ability to integrate the assets acquired in the Acquisitions and achieve anticipated benefits from them; risks relating to any unforeseen liabilities of Earthstone or the assets acquired in the Acquisitions; declines in oil, natural gas liquids or natural gas prices; the level of success in exploration, development and production activities; adverse weather conditions that may negatively impact development or production activities; the timing of exploration and development expenditures; inaccuracies of reserve estimates or assumptions underlying them; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write‐downs; risks related to level of indebtedness and periodic redeterminations of the borrowing base under the Company’s credit facility; Earthstone’s ability to generate sufficient cash flows from operations to fund all or portions of its future capital expenditures budget or to support a shareholder return program; Earthstone’s ability to obtain external capital to finance exploration and development operations and acquisitions; the impacts of hedging on results of operations; uninsured or underinsured losses resulting from oil and natural gas operations; competition for assets, equipment, materials and qualified people; supply chain disruptions; Earthstone’s ability to replace oil and natural gas reserves; any loss of senior management or technical personnel; regulatory matters, including environmental regulations; social, market and regulatory efforts to address climate change; and the direct and indirect impact on most or all of the foregoing on the evolving COVID‐19 pandemic. Earthstone’s annual report on Form 10‐K for the year ended December 31, 2021, recent current reports on Form 8‐ K, and other Securities and Exchange Commission (“SEC”) filings discuss some of the important risk factors identified that may affect Earthstone’s business, results of operations, and financial condition. The forward‐looking statements included in this presentation speak only as of the date of this presentation and Earthstone undertakes no obligation to revise or update publicly any forward‐looking statements except as required by law. This presentation contains estimates of Earthstone’s, Bighorn’s and Chisholm’s 2022 production, capital expenditures and expense guidance. The actual levels of production, capital expenditures and operating expenses may be higher or lower than these estimates due to, among other things, uncertainty in drilling schedules, oil and natural gas prices, changes in market demand for hydrocarbons and unanticipated delays in production and well completions. These estimates are based on numerous assumptions. All or any of these assumptions may not prove to be accurate, which could result in actual results differing materially from estimates. No assurance can be made that any new wells will produce in line with historical performance, or that existing wells will continue to produce in line with Earthstone’s expectations. Earthstone’s ability to fund its 2022 and future capital budgets is subject to numerous risks and uncertainties, including volatility in commodity prices and the potential for unanticipated production and completion delays and increases in costs associated with drilling, production and transportation. Use of Non‐GAAP Information This presentation may include financial measures that are not in accordance with accounting principles generally accepted in the United States (“GAAP”) such as PV‐10, free cash flow and Adjusted EBITDAX. Such non‐GAAP measures are not alternatives to GAAP measures, and you should not consider these non‐GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. For additional disclosure regarding such non‐GAAP measures, including reconciliations to their most directly comparable GAAP measure, please refer to the Appendix or to Earthstone’s 10‐Q and 10‐K filings with the SEC. Cautionary Note on Reserves and Resource Estimates The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves or locations not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. You are urged to consider closely the oil and gas disclosures in our 2021 Form 10‐K and our other reports and filings with the SEC. Industry and Market Data This presentation has been prepared by Earthstone and includes market data and other statistical information from third‐party sources, including independent industry publications, government publications or other published independent sources. Although Earthstone believes these third‐party sources are reliable as of their respective dates, Earthstone has not independently verified the accuracy or completeness of this information. Some data are also based on Earthstone’s good faith estimates, which are derived from its review of internal sources as well as the third‐party sources described above. 2

High Free Cash Flow Generation with  Low Reinvestment Needs ~50% of cash flow needed to   maintain production levels, creates robust  free cash flow generation1 Top Basins /  Long Inventory Life Midland Basin and Delaware Basin  asset base with ~13 years of high  quality inventory life The New Earthstone: Significantly Larger Scale, Same Core Values 1. Free cash flow is a non‐GAAP measure defined as Adjusted EBITDAX less interest expense less capital expenditures (accrual basis). Greater Efficiency from  Increased Critical Mass Six acquisitions since early 2021 increased  production by >4x and improved cost and  operating efficiencies Low Leverage Recent acquisitions approximately  leverage neutral with year‐end 2022  leverage expected well below 1.0x Progressing Towards  Shareholder Returns “New Earthstone” provides for  accelerated consideration of shareholder  return program Commitment  & Focus “Do the right thing” commitment  to stakeholders, employees and  environment 3

A Much Larger Earthstone: Corporate Snapshot 4 Select Operational Data 323 MMBoe Est. Proved Reserves1 $4.8 Billion PV‐10 at Strip1 78,000 Boe/d 2H22 Production Guidance ~248,000 Permian Net Acres Select Financial Data3 Stock Price (5/27/22) $19.10 Market Cap $2.6 B Net Debt $1.0 B  Enterprise Value $3.7 B Shares Outstanding 139 MM Liquidity $337 MM $14.63 / Boe 1Q22 “All‐In” Cash Cost2 776  Gross Operated Drilling Locations Texas MIDLAND DELAWARE PERMIAN BASIN New Mexico   Lea Eddy Howard Ector Upton Midland Crockett Irion Sterling Glasscock Reagan Note:  See appendix for additional details. Martin

Conservative Valuation Methodology Leads to High Impact Acquisitions 5 Cumulative Proved Developed Reserves Value Outweighs Combined Total Purchase Price  1. Cumulative estimated PD value based upon forward strip pricing at the time of each announced transaction.   $‐  $500  $1,000  $1,500  $2,000 IRM Tracker Foreland Chisholm Bighorn $  in  m ill io ns Across all five recent transactions, proved  developed value1 of reserves has underpinned  purchase price  Undeveloped locations acquired “virtually”  free as PD value of acquired properties is  higher than cumulative total purchase price Cumulative PD PV‐10 value  Cumulative Purchase Price IRM Tracker Chisholm Bighorn 582 Gross Operated Drilling Locations

Leverage profile Expect to be under ~0.75x leverage  by YE 20222 EBITDAX growth Since 2020 through strategic  acquisition and ongoing development Strategic Acquisitions Driving Robust Cash Flow Outlook 6 ~600% <1.0x Massive Growth in Adjusted EBITDAX While Reducing Leverage Metrics1 Share Count Growth Since 2020, minimizing impact to  shareholders while growing per share value  meaningfully <120% 1. 2022 EBITDAX and debt figures are based upon management estimates utilizing NYMEX Strip pricing as of 5/2/22.  Leverage is measured as Debt to Adjusted EBITDAX for annual periods except for at YE 2022 which utilizes  annualized 4Q22 Adjusted EBITDAX. 2. Leverage measured as Debt to LQA Adjusted EBITDAX. Expected Leverage: 0.50x to 0.75x

$0.5 B 79 MMBoe $2.0 B 148 MMBoe $4.8 B 323 MMBoe YE20 SEC Pricing YE21 SEC Pricing 5/1/22 Reserves 5/2/22 Strip PD PUD Shareholder Value Accretion Reflected in Enormous Proved Reserves Growth 7 PV‐10 Uplift from YE20 With estimated PD reserves composing  ~60% of the total proved reserves value In Proved Reserves Value  Based on common shares outstanding2 ~10x ~$28 per share Est. Proved Developed Value Current PD reserves value is significantly  higher than current enterprise value1 >$3.8B Robust Value Growth in Proved Reserves With Majority Coming from Proved Developed Reserves Additions 1. Estimated PD reserves value of $3.8 billion based reserves as of 5/1/22 at NYMEX strip pricing as of 5/2/22. See appendix for additional details. 2. Calculated as 5/1/22 estimated proved reserves value at NYMEX strip pricing as of 5/2/22 less net debt and divided by total share count of ~138.6 million (includes PIPE shares). 

Lea 336  Eddy 74  Midland/Ector 119  Upton 35  Reagan/Irion 212  Robust Inventory Within Premier Shale Basins  8 400% Growth In Operated Inventory • Added over 580 gross locations since early 2021 • Combined inventory represents more than 13 years of drilling  activity at current development pace • Delaware helps drive oil content higher over time due to  commodity mix of locations of locations generate IRRs in excess  of 25% at $60 oil and $3 gas85% 61 207 279 310 362 153 315 387 413 414 < $40 $50 $60 $70 $80 Delaware Midland 214 522 666 723 776 1. Includes all locations across reserve categories. Gas and NGL pricing scaled with WTI assuming $60/bbl / $3.00/MMbtu. Operated Inventory with IRRs ≥ 25% at Various WTI Oil Prices1 776 Gross Operated  Locations

$13.79  $14.07  $14.63  $14.86  $18.22  $18.44  $19.95  $20.44  $21.16  Peer 1 Peer 2 ESTE Peer 4 Peer 6 Peer 8 Peer 3 Peer 5 Peer 7 80%  80%  77%  76%  76%  72%  71%  71%  69%  Peer 1 Peer 2 Peer 3 ESTE Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Focused On Remaining a Low‐Cost Leader With Top Tier Cash Margins 9 1Q22 “All‐in” Cash Costs11Q22 Unhedged Cash Margins1 1. Cash margins are calculated as revenues less all‐in cash costs which consist of LOE, ad valorem & production taxes, transportation expense, cash G&A, and interest expense.  Large‐Cap peers include FANG and PXD.  SMID‐Cap  peers include CDEV, CPE, HPK, LPI, MTDR and SM.  Cash G&A is a non‐GAAP financial measure defined as general and administrative expenses excluding stock‐based compensation. Large‐Cap Peers SMID‐Cap Peers Peer Average: 74% Peer Average: $17.62 Large‐Cap Peers SMID‐Cap Peers

Expanded Capital Program Greatly expanded footprint and  highly‐economic inventory allows for  increased capital deployment and  supports program consistency  Enhanced Optionality Diversification and capital flexibility  in the Delaware and Midland  mitigate concentration risk Oily Delaware Addition Recently acquired Delaware Basin  assets improve oil content as  development ramps (impact in  2023 and beyond) Strategic Advantages Gained Through Our Expanded Scale 10 Operational Efficiency Scaled activity levels drives D&C  efficiency and enhances  relationships with key service  provider Low Decline Asset Base PDP decline rate of ~20‐23%  provides for low reinvestment rate  with some organic growth

Delaware D&C Infrastructure Non‐Op D&C Midland D&C Expanded Scale Supports Continuous Asset Development 11 Midland Basin Delaware Basin 2 rigs ~40 gross operated wells ~9,500 LL  ~90% WI 2 rigs  ~20 gross operated wells ~8,700 LL ~60% WI $410‐$440 Million Inflation Mitigation Efforts • ESTE has locked in frac sand pricing and  supply in Midland Basin through 2023 and  in Delaware Basin through 2022 • 6‐to‐9‐months rig contracts and longer‐ term completion arrangements versus  previous spot pricing structure limits cost  escalation • Regularly source casing and tubulars and  other essentials six months in advance to  ensure development plan continuity and  lock in pricing 2022 Capital Budget

– 0.5x 1.0x 1.5x 2.0x 0 30,000 60,000 90,000 1Q22 2Q22 3Q22 4Q22 2023 N et  D eb t /  A dj . E BI TD AX  (x ) Da ily  P ro du ct io n  (B oe /d ) Daily Production Net Debt / Adj. EBITDAX Strong Free Cash Flow Expected to Quickly Reduce Leverage to Well Below 1.0x 12 Robust Production and FCF Profile Rapidly Drives LQA Leverage Well Below 1.0x12022 Capital Program Benefits • Significant additional activity reflecting much larger  scale of operations • Expands previous capital development program from  ~$100 MM to over $400 MM • Combined production nearing ~80 MBoe/d generating  significant FCF, but with a greatly improved corporate  decline rate (~20‐23%) • Scaled production base reduces impact of new well  timing and provides for more predictable cash flows • Immediate FCF focus will be on quickly reducing LQA  debt metrics to well below 1.0x1 1. Production and leverage estimates based upon current company guidance applying recent strip pricing. Leverage metrics based on Last Quarter Annualized (“LQA”) Debt to Adjusted EBITDAX. 1Q22 leverage based upon full  quarter of Chisholm.  See appendix for additional notes. Continued  deleveraging  from strong FCF

FCF Potential1 $75 $100WTI Oil Prices Multiple avenues available for allocation value creation for shareholders will dictate Levered FCF outcomes from  >$375 MM to >$550 MM Opportunities Broaden for Free Cash Allocation in the Future 13 FCF Likely Shifts Away from Deleveraging • Efficiency of capital development allows for some  growth with reinvestment of just 40‐50% of  operational cash flow • At $85 oil and $3 gas still expected to generate >$1.3 B  in revenue and >$450 MM in FCF • With debt levels below target threshold of 1.0x, a  broader opportunity for FCF allocation becomes  available • Additional debt reduction becomes less critical and  allows for greater focus on scale opportunities and  consideration of shareholder returns Additional Debt  Reduction Increased  Development  Pace Opportunistic  Acquisitions Initiation of  Shareholder  Returns 1. FCF estimates based upon a maintenance capital scenario that holds production for 2023+ approximately flat with 2H22 current guidance levels. Free cash flow is a non‐GAAP measure defined as Adjusted EBITDAX less interest  expense less capital expenditures (accrual basis). See appendix for additional notes.

2022 2023 2024 2025 2026 2027 Current Mkt Cap Cumulative Free Cash Flow Durable Multi‐Year Free Cash Flow Profile Provides Extensive Options 14 Free Cash Flow Outlook Under Maintenance Capital Program1Reliable Production and Reduced  Capital Needs Provide a  “Mountain” of FCF • Based upon a continuous maintenance  capital scenario, recent strip pricing  generates more than $2.6 B in cumulative  FCF by 20271 • Increased scale, cash flow, and relative  debt ratios support credit rating  improvement and lower corporate cost of  capital over time 1. FCF estimates based upon a maintenance capital scenario that holds production for 2023+ approximately flat with 2H22 current guidance levels at NYMEX strip pricing as of 5/2/22. Free cash flow is a non‐GAAP measure defined as  Adjusted EBITDAX less interest expense less capital expenditures (accrual basis). See appendix for additional notes. Significant FCF generation  supports recent growth to  market cap

$0 $500 $1,000 $1,500 YE20 YE21 3/31/22 PF 3/31/22 $  in  m ill io ns Drawn RBL Debt Undrawn RBL Commitments Uncommitted Borrowing Base Availability Liquidity and Capital Structure Benefitting from Expanded Scale and Recent Offering 15 Significant Liquidity Supports All Potential  Capital Deployment Scenarios • Borrowing Base has grown from $240 MM at YE20 to  $1.4 B driven primarily by high value reserves and  production additions • Robust estimated PD reserves of ~$3.8 B with low  corporate decline rate (~20‐23%) support continued  availability1 • YE22 facility utilization estimated to be <10% of  elected commitments of $800 MM • Amended Credit Facility in June 2022 to extend  maturity to 2027 with a borrowing base of $1.4 B and  elected commitments of $800 MM • $550 MM unsecured senior notes, 8% coupon,  matures in 2027 1. Estimated PD reserves of ~$3.8 billion reflect proved developed reserves as of 5/1/22 utilizing NYMEX strip pricing as of 5/2/22. See appendix for additional details. Borrowing Base increased to  $1.4 B with amended Credit  Facility

Progressing Our Sustainability Initiatives While Leading the Pack 16 Actively reducing emissions via  multiple initiatives • Installation of Vapor Recovery Units  (“VRUs”) as part of standard facility design • Leak Detection and Repair (“LDAR”) active  since 2019 and complemented by FLIR  imagery feedback program • Established corporate target of zero  routine flaring  • Continued focus on pipeline based  saltwater disposal options for reduced  trucking impact 0.2% 0.2% 0.2% 0.4% 0.4% 0.4% 0.5% 0.5% 0.6% 0.6% 0.7% 0.8% 1.0% 1.0% 1.1% 1.2% 1.3% 1.5% 1.5% 1.6% 2.1% ESTE 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 ESTE Among the Leaders in Permian Flaring Intensity Regardless of Market Cap1,2 Earthstone Mega‐Cap Permian SMID‐Cap Permian Large‐Cap Permian 1. Data courtesy of Rystad Energy, “Permian Flaring Intensity Report from February 2022”.  2. Mega‐Cap peers include BP, COP, CVX, and XOM. Large‐Cap peers include APA, CLR, DVN, EOG, FANG, MRO, OVV, OXY, and PXD. SMID‐Cap peers include CDEV, CPE, CTRA, LPI, MTDR, PDCE and SM. 

Highly Focused Environmental Stewardship 17 Key Environmental Priorities Focus on Responsible Operatorship Minimize fugitive emissions with the installation of emission reducing equipment in conjunction with  new facility construction: • Vapor Recovery Units (“VRUs”)  • Air compression equipment for Pneumatic Actuators • Participation in fly over surveys Target Zero Flaring: Connect natural gas pipelines ahead of flowback and first production negates need for flaring Leak Detection & Repair (“LDAR”) program since 2019 to further minimize air emissions Vast majority of water disposal occurs on pipeline, reducing truck hauls and CO2 emissions

Responsible Management of Fugitive Emissions and Flaring 18 “Do the Right Thing” approach and proactive plan driving reductions in GHG emissions and flaring 68% Reduction vs. 2020 Below peer average 2021 Flaring Intensity of 0.7% (operated gas flared /  operated gas produced) 67% Note: Peers include CDEV, CPE, FANG, LPI, MTDR, PXD and SM.  Data based on latest publicly disclosed metrics provided by each company. 2021 Greenhouse Gas Emissions Intensity of 7.9 (T CO2e / Mboe) 36% Reduction vs. 2020 Below peer average 45%

Focused on Providing Shareholders a Path to Value Accretion 19 Earthstone Management has consistently shown fundamental conservatism in assessing and  executing a broader corporate strategy of value driven investment in high quality assets,  operating cost leadership, and management of its balance sheet offering investors a reliable and predictable opportunity to invest in a growing operator. Greater Efficiency Achieved from  Increased Critical Mass Robust Inventory in the Premier Shale  Basins of the US Growing Free Cash Flow Generation with  Low Reinvestment Needs Historically Low Leverage and expected to  be well below 1.0x by YE22  Improving the Opportunity to Implement  Meaningful Shareholder Returns Committed to Delivering for Stakeholders,  Employees, and the Environment 

Guidance & Appendix 20

2022 Primary activity areas Development Optionality Across A Larger Footprint 21 Scaled Development Plans Continuous multi‐zone development program spread across both Midland and Delaware  Basin positions with typical development spacing at 3‐5 wells per section Midland: ~208,000 net acres Delaware: ~38,000 net acres 1st Bone Spring Carb /  Avalon Shale 1st Bone Spring Sand 2nd Bone Spring Carb 2nd Bone Spring Sand 3rd Bone Spring Carb 3rd Bone Spring Sand Wolfcamp A / XY Wolfcamp B Middle Spraberry Shale Lower Spraberry Sands Jo Mill Silt Lower Spraberry Shale Dean Wolfcamp A Upper Wolfcamp B Lower Wolfcamp B Wolfcamp C Wolfcamp D / Cline Shale 2, 57 5’  ‐3 ,6 50 ’ g ro ss  th ic kn es s 3,200’ gross thickness Secondary Target Zones Primary Target Zones MIDLAND DELAWARE New Mexico   Texas

Company Guidance 22 2022 Operational and Financial Guidance Category 1Q22 Actuals 2Q22 3Q22 - 4Q22 FY22 Production (Boe/d) 35,509 70,000 - 74,000 76,000 - 80,000 64,250 - 67,750 % Oil 44% ~ 41% ~ 41% ~ 41% % Liquids 71% ~ 67% ~ 67% ~ 67% Total Capital Expenditures ($MM) $82 $410 - $440 Lease Operating Expense ($/Boe) $6.77 $7.25 - $7.75 Production & Ad Valorem Taxes (% of Revenue) 6.8% 7.5% - 8.0% Cash G&A ($MM) $6 $31 - $34 1. Cash G&A is a non‐GAAP financial measure defined as general and administrative expenses excluding stock‐based compensation. 1

$3.673  $3.626  $3.332  $3.546  $3.352  $4.115 / $6.161 $4.115 / $6.161 $4.048 / $6.738 $4.054/$6.334 $3.461 / $5.344 75,352  90,000  90,000  85,153  48,775  2Q 2022 3Q 2022 4Q 2022 2Q ‐ 4Q 2022 FY 2023 Swaps Collars $64.48  $66.70  $66.70  $65.96  $76.20  $68.03/$82.69 $70.00/$83.96 $70.00/$83.96 $69.42/$83.59 $64.50/$85.73 16,937  17,750  17,750  17,481  9,500  2Q 2022 3Q 2022 4Q 2022 2Q ‐ 4Q 2022 FY 2023 Swaps Collars Oil and Gas Hedge Summary 23 Oil Hedge Positions (WTI based, Bbls/d, and $/Bbl) Natural Gas Hedge Positions (HH based, MMBtu/d, and $/MMBtu) Focused on protecting cash flow  while leaving upside for a stronger  commodity outlook • Utilize a mix of collars and swaps on both  oil and gas to preserve cash flow • Actively adding additional 2023 protection  as the year progresses • Hedge position that provides coverage for  50‐60% of oil and gas production for the  remainder of 2022

Oil and Gas Hedge Positions 24 WTI Oil Hedges - Swaps HH Gas Hedges - Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu 2Q 2022 1,085,250 11,926 $64.48 2Q 2022 2,902,500 31,896 $3.595 3Q 2022 1,081,000 11,750 $66.70 3Q 2022 3,266,000 35,500 $3.626 4Q 2022 1,081,000 11,750 $66.70 4Q 2022 1,893,500 20,582 $3.332 2Q - 4Q 2022 3,247,250 11,808 $65.96 2Q - 4Q 2022 8,062,000 29,316 $3.546 FY 2023 1,277,500 3,500 $76.20 FY 2023 3,670,000 10,055 $3.352 WTI Oil Hedges - Collars HH Gas Hedges - Collars Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Floor) $/Bbl (Ceiling) Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu (Floor) $/MMBtu (Ceiling) 2Q 2022 456,000 5,011 $68.03 $82.69 2Q 2022 3,954,500 43,456 $3.985 $5.901 3Q 2022 552,000 6,000 $70.00 $83.96 3Q 2022 5,014,000 54,500 $4.115 $6.161 4Q 2022 552,000 6,000 $70.00 $83.96 4Q 2022 6,386,500 69,418 $4.048 $6.738 2Q - 4Q 2022 1,560,000 5,673 $69.42 $83.59 2Q - 4Q 2022 15,355,000 55,836 $4.054 $6.334 FY 2023 2,190,000 6,000 $64.50 $85.73 FY 2023 14,133,000 38,721 $3.461 $5.344 WTI Midland Argus Crude Basis Swaps WAHA Differential Basis Swaps Period Volume (Bbls) Volume (Bbls/d) $/Bbl (Differential) Period Volume (MMBtu) Volume (MMBtu/d) $/MMBtu 2Q 2022 1,077,500 11,841 $0.51 2Q 2022 1,820,000 20,000 ($0.327) 3Q 2022 1,150,000 12,500 $0.51 3Q 2022 1,840,000 20,000 ($0.327) 4Q 2022 1,150,000 12,500 $0.51 4Q 2022 1,840,000 20,000 ($0.327) 2Q - 4Q 2022 3,377,500 12,282 $0.51 2Q - 4Q 2022 5,500,000 20,000 ($0.327) FY 2023 1,825,000 5,000 $0.57 FY 2023 29,200,000 80,000 ($1.324) FY 2024 FY 2024 29,280,000 80,000 ($1.019)

SEC Stand‐Alone Reserves Summary & PV‐10 – Year‐End 2021 25 Stand‐Alone Year‐End 2021 SEC Proved Reserves Reconciliation of PV‐10 As shown in the table below, Earthstone’s stand‐alone estimated proved reserves at year end 2021 were independently estimated by Cawley, Gillespie & Associates, Inc. (“CGA”), independent petroleum engineers, and which was prepared in accordance with Securities and Exchange Commission (“SEC”) guidelines, were approximately 147.6 million barrels of oil equivalent (“MMBoe”). SEC rules require that calculations of economically recoverable reserves use the unweighted average price on the first day of the month for the prior twelve‐ month period. The resulting oil and natural gas prices used for Earthstone’s stand‐alone 2021 year end reserve report, prior to adjusting for quality and basis differentials, were $66.56 per barrel and $3.598 per million British Thermal Units (“MMBtu”), respectively. SEC prices net of differentials were $65.64 per barrel, $30.16 per equivalent barrel of NGL and $3.01 per Mcf. PV‐10 is a measure not prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) that differs from a measure under GAAP known as “standardized measure of discounted future net cash flows” in that PV‐10 is calculated without including future income taxes. Management believes that the presentation of the PV‐10 value of our oil and natural gas properties is relevant and useful to investors because it presents the estimated discounted future net cash flows attributable to our estimated proved reserves independent of our income tax attributes, thereby isolating the intrinsic value of the estimated future cash flows attributable to our reserves. We believe the use of a pre‐tax measure provides greater comparability of assets when evaluating companies because the timing and quantification of future income taxes is dependent on company‐specific factors, many of which are difficult to determine. For these reasons, management uses and believes that the industry generally uses the PV‐10 measure in evaluating and comparing acquisition candidates and assessing the potential rate of return on investments in oil and natural gas properties. PV‐10 does not necessarily represent the fair market value of oil and natural gas properties. PV‐10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. The table below provides a reconciliation of PV‐10 to the standardized measure of discounted future net cash flows (in thousands): Present value of estimated future net revenues $2,016,686  Future income taxes, discounted at 10% $198,314  Standardized measure of discounted future net cash flows $1,818,372  Oil Gas NGL Total PV‐10 Reserves Category (Mbbls) (MMcf) (Mbbls) (Mboe) ($ in thousands) Proved Developed 35,824 190,999 25,917 93,575 1,371,697 Proved Undeveloped 25,251 93,882 13,114 54,012 644,989 Total 61,075 284,881 39,031 147,587 $2,016,686 

Estimated Proved Reserves Summary as of 5/1/22 at NYMEX Strip Pricing as of 5/2/22 26 This summary as shown in the table below based on management estimates and has been prepared as of May 1, 2022, utilizing NYMEX strip benchmark prices and basis differentials as of May 2, 2022. Proved Proved Reserves Category Developed Undeveloped Total Oil (MBbls) 77,322 44,579 121,901 Gas (MMcf) 548,255 126,070 674,325 NGL (MBbls) 71,073 17,572 88,645 Total 239,771 83,163 322,934 PV‐10 ($ in thousands) $3,840,373  $973,074  $4,813,447 

Reconciliation of Non‐GAAP Financial Measure – Adjusted EBITDAX 27 1Q 2022 Adjusted EBITDAX ($ in 000s) 1. Consists of expense for non‐cash equity awards and also for cash‐based liability awards that are expected to be settled in cash.  No cash‐based liability awards were settled in cash during 2021.  On February 9, 2022, cash‐based awards  were settled in the amount of $8.1 million.  Stock‐based compensation is included in General and administrative expense in the Consolidated Statements of Operations. Earthstone uses Adjusted EBITDAX, a financial measure that is not presented in accordance with GAAP. Adjusted EBITDAX is a supplemental non‐GAAP financial measure that is used by Earthstone’s management team and external users of its financial statements, such as industry analysts, investors, lenders and rating agencies. Earthstone’s management team believes Adjusted EBITDAX is useful because it allows Earthstone to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. Earthstone defines Adjusted EBITDAX as net (loss) income plus, when applicable, (gain) on sale of oil and gas properties, net; accretion of asset retirement obligations; depletion, depreciation and amortization; transaction costs; interest expense, net; exploration expense; unrealized loss on derivative contracts; stock based compensation(1); and income tax (benefit) expense. Earthstone excludes the foregoing items from net (loss) income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within their industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net (loss) income as determined in accordance with GAAP or as an indicator of Earthstone’s operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Earthstone’s computation of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies or to similar measures in Earthstone’s revolving credit facility. The following table provides a reconciliation of Net income to Adjusted EBITDAX for: FY 2021 Adjusted EBITDAX ($ in 000s) 1Q22 Net (loss) income ($51,877) Accretion of asset retirement obligations $397  Depreciation, depletion and amortization $34,326  Interest expense, net $5,318  Transaction costs $10,742  (Gain) on sale of oil and gas properties $0  Exploration expense $92  Unrealized loss on derivative contracts $119,794  Stock based compensation(1) $5,830  Income tax (benefit) expense ($1,533) Adjusted EBITDAX $123,089  FY21 Net (loss) income $61,506  Accretion of asset retirement obligations $1,065  Depreciation, depletion and amortization $106,367  Interest expense, net $10,796  Transaction costs $4,875  (Gain) on sale of oil and gas properties ($738) Exploration expense $341  Unrealized loss on derivative contracts $40,795  Stock based compensation(1) $21,014  Income tax (benefit) expense $1,859  Adjusted EBITDAX $247,880 

Reconciliation of Non‐GAAP Financial Measure – Adjusted EBITDAX 28 Chisholm – 1/1/22 to 2/14/22 Adjusted EBITDAX ($ in 000s) 1. Based on unaudited preliminary operating results, for the period presented, obtained from the seller. Earthstone uses Adjusted EBITDAX, a financial measure that is not presented in accordance with GAAP. Adjusted EBITDAX is a supplemental non‐GAAP financial measure that is used by Earthstone’s management team and external users of its financial statements, such as industry analysts, investors, lenders and rating agencies. Earthstone’s management team believes Adjusted EBITDAX is useful because it allows Earthstone to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. Earthstone defines Adjusted EBITDAX as net income plus, when applicable, (gain) loss on sale of oil and gas properties, net; accretion of asset retirement obligations; depletion, depreciation and amortization; transaction costs; interest expense, net; exploration expense; unrealized loss (gain) on derivative contracts; stock based compensation; and income tax expense. Earthstone excludes the foregoing items from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within their industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of Earthstone’s operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Earthstone’s computation of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies or to similar measures in Earthstone’s revolving credit facility. The following table provides a reconciliation of Net income to Adjusted EBITDAX for: 1/1/22 to 2/14/22 Net (loss) income1 $20,414  Depreciation, depletion and amortization 7,140 Adjusted EBITDAX $27,554 

Market Capitalization Table 29 Provided as of 5/27/20221 1. Includes the impact of the 5.7MM shares of Class A Common Stock issued to Bighorn on 4/14/22.  Adjustments also reflect the impact of the closing of the Bighorn Acquisition, the $550MM notes offering, the $280MM PIPE  issuance, the payment of the $70MM of deferred cash consideration from the Chisholm Acquisition and the voluntary reduction in the elected commitments under the Credit Facility from $825MM to $800MM, all of which  occurred during April 2022. 2. Equity issued in the PIPE was convertible equity that is expected to be converted into 25.2MM shares of Class A Common Stock and is included in the ~138.6MM shares outstanding.  ($ in millions, except share price) Class  A Common Stock (MM) 79.1 Class  A Expected PIPE Convers ion (MM)2 25.2 Class  B Common Stock (MM) 34.3 Total Common Stock Outstanding (MM) 138.6 Stock Price (as  of 5/27/22) $19.10 Market Capitalization $2,647.0 Plus : Tota l  Debt $1,013.00 Less : Cash  ($0.5) Enterprise Value $3,659.6

Notes and Supplemental Information 30 Recent Strip Pricing (5/2/2022) Year WTI HH 2022 $97.37 $6.70 2023 $85.13 $5.40 2024 $76.55 $4.30 2025 $70.70 $4.02 2026 $66.77 $4.03 • Management has provided forwarding looking charts and figures on various slides that utilize a “maintenance capital” scenario. These figures are for example purposes only and do not constitute specific  guidance beyond 2022. Proposed corporate guidance for 2023 and beyond will be designated as such at the time it is made available. In addition, the assumptions utilized for these scenario are as follows;   – Future production levels beyond 2022 are roughly flat with the projected 2H22 guidance provided by management – Capital costs for development and operating field costs on a unit basis are held roughly flat to 2022 guidance – The corporate PDP decline rate is estimated at ~20‐23% for 2022 and continues to decline at slightly lower rates in the following years Supplementary Footnotes (Page 4) 1. Total estimated proved reserves as of 5/1/22 using NYMEX strip pricing as of 5/2/22. 2. All‐In cash cost is a non‐GAAP financial measure defined as lease operating expenses plus production and ad valorem taxes, interest expense, net, and general and administrative expense (excluding stock‐ based compensation).  3. Includes the impact of the 5.7MM shares of Class A Common Stock issued to Bighorn on 4/14/22.  Adjustments also reflect the impact of the closing of the Bighorn Acquisition, the $550MM notes offering,  the $280MM PIPE issuance, the payment of the $70MM of deferred cash consideration from the Chisholm Acquisition and the voluntary reduction in the elected commitments under the Credit Facility from  $825MM to $800MM, all of which occurred during April 2022. Equity issued in the PIPE was convertible equity that is expected to be converted into 25.2MM shares of Class A Common Stock and is included  in the ~138.6MM shares outstanding.