Lonestar Resources US, Inc. Year Ended 2017 Conference Call March 29, 2018 Exhibit 99.2

Forward-Looking Statements Safe Harbor & Disclaimer Lonestar Resources US, Inc. cautions that this presentation (including oral commentary that accompanies this presentation) contains forward-looking statements, including, but not limited to, statements about our business strategy and operations; discovery and development of crude oil, natural gas liquid (“NGL”) and natural gas reserves; drilling and completion of wells; and cash flows, liquidity, and availability and terms of capital. These statements involve substantial known and unknown risks, uncertainties and other important factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, the following: volatility of oil, natural gas and NGL prices, and potential write-down of the carrying values of crude oil and natural gas properties; inability to successfully replace proved producing reserves; substantial capital expenditures required for exploration, development and exploitation projects; potential liabilities resulting from operating hazards, natural disasters or other interruptions; risks related using the latest available horizontal drilling and completion techniques; uncertainties tied to lengthy period of development of identified drilling locations; unexpected delays and cost overrun related to the development of estimated proved undeveloped reserves; concentration risk related to properties, which are located primarily in the Eagle Ford Shale of South Texas; loss of lease on undeveloped leasehold acreage that may result from lack of development or commercialization; inaccuracies in assumptions made in estimating proved reserves; our limited control over activities in properties Lonestar does not operate; potential inconsistency between the present value of future net revenues from our proved reserves and the current market value of our estimated oil and natural gas reserves; risks related to derivative activities; losses resulting from title deficiencies; risks related to health, safety and environmental laws and regulations; additional regulation of hydraulic fracturing; reduced demand for crude oil, natural gas and NGLs resulting from conservation measures and technological advances; inability to acquire adequate supplies of water for our drilling operations or to dispose of or recycle the used water economically and in an environmentally safe manner; climate change laws and regulations restricting emissions of “greenhouse gases” that may increase operating costs and reduce demand for the crude oil and natural gas; fluctuations in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price actual crude oil and natural gas sales; and the other important factors discussed under the caption “Risk Factors” in our Registration Statement on Form 10, as amended and filed with the Securities and Exchange Commission, or the SEC, on June 9, 2016, as well as other documents that we may file from time to time with the SEC. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Actual results or events could differ materially from the plans, intentions and expectations disclosed in the forward-looking statements we make. The forward-looking statements in this presentation represent our views as of the date of this presentation. We anticipate that subsequent events and developments will cause our views to change. However, while we may elect to update these forward-looking statements at some point in the future, we have no current intention of doing so except to the extent required by applicable law. You should, therefore, not rely on these forward-looking statements as representing our views as of any date subsequent to the date of this presentation. This presentation also contains estimates and other statistical data made by independent parties and by us relating to well performance, finding and development costs, recycle ratio and other data about our industry. This data involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such estimates. In addition, projections, assumptions and estimates of our future performance and the future performance of the markets in which we operate are necessarily subject to a high degree of uncertainty and risk. Lonestar Resources US, Inc. cautions that this presentation (including oral commentary that accompanies this presentation) contains forward-looking statements, including, but not limited to, statements about performance expectations related to our assets and technical improvements made thereto; drilling and completion of wells; and other statements regarding our business strategy and operations. These statements involve substantial known and unknown risks, uncertainties and other important factors that may cause our actual results, levels of activity, performance or achievements to be materially different from the information expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, the following: volatility of oil, natural gas and NGL prices, and potential write-down of the carrying values of crude oil and natural gas properties; inability to successfully replace proved producing reserves; substantial capital expenditures required for exploration, development and exploitation projects; potential liabilities resulting from operating hazards, natural disasters or other interruptions; risks related using the latest available horizontal drilling and completion techniques; uncertainties tied to lengthy period of development of identified drilling locations; unexpected delays and cost overrun related to the development of estimated proved undeveloped reserves; concentration risk related to properties, which are located primarily in the Eagle Ford Shale of South Texas; loss of lease on undeveloped leasehold acreage that may result from lack of development or commercialization; inaccuracies in assumptions made in estimating proved reserves; our limited control over activities in properties Lonestar does not operate; potential inconsistency between the present value of future net revenues from our proved reserves and the current market value of our estimated oil and natural gas reserves; risks related to derivative activities; losses resulting from title deficiencies; risks related to health, safety and environmental laws and regulations; additional regulation of hydraulic fracturing; reduced demand for crude oil, natural gas and NGLs resulting from conservation measures and technological advances; inability to acquire adequate supplies of water for our drilling operations or to dispose of or recycle the used water economically and in an environmentally safe manner; climate change laws and regulations restricting emissions of “greenhouse gases” that may increase operating costs and reduce demand for the crude oil and natural gas; fluctuations in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price actual crude oil and natural gas sales; and the other important factors discussed under the caption “Risk Factors” in our Annual Report on Form 10-K filed with the Securities and Exchange Commission, or the SEC, on March, 23, 2017 our Quarterly Reports on Form 10-Q filed with the SEC, as well as other documents that we have filed and may file from time to time with the SEC. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Actual results or events could differ materially from the plans, intentions and expectations disclosed in the forward-looking statements we make. The forward-looking statements in this presentation represent our views as of the date of this presentation. We anticipate that subsequent events and developments will cause our views to change. However, while we may elect to update these forward-looking statements at some point in the future, we have no current intention of doing so except to the extent required by applicable law. You should, therefore, not rely on these forward-looking statements as representing our views as of any date subsequent to the date of this presentation. This presentation also contains estimates and other statistical data made by independent parties and by us relating to well performance, finding and development costs, recycle ratio and other data about our industry. This data involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such estimates. In addition, projections, assumptions and estimates of our future performance and the future performance of the markets in which we operate are necessarily subject to a high degree of uncertainty and risk.

YE 2017 - Key Messages 4Q17 Production by Product 2017 Accomplishments Assimilated two strategic acquisitions into field operations Proved reserves 1 increased 70% to 76.2 MMBOE Proved PV-10 1 increased 70% to $647.6 MM Reserve replacement was 1,499% of 2017 Production All-Sources Finding & Onstream costs were $6.07 per Boe Fourth Quarter Highlights Production increased 59%, year-over-year to 7,272 Boe/d Adjusted EBITDAX increased 64%, year-over-year to $20.5 million Financial Transformation Complete, Enter 2018 with $100 MM Liquidity… Refinanced 8 ¾% Notes due April 2019. No Unsecured Maturities until 2023 Extended Maturity on Senior Secured Facility from October, 2018 to June, 2020 At December 31, 2017, Lonestar had $100 MM undrawn on its $160 MM Borrowing Base 2 …Securing Energy Services to Deliver Timely Well Results Rigs Under Contract to Drill 2018 Capital Program, with optionality to expand Executed Agreement for Dedication of Frac Spread for 2018 2018 Completions Off to A Strong Start… Hawkeye #1H and #2H (Gonzales County) tested at average rate of 1,115 Boe/d Horned Frog G#1H and H#1H (LaSalle County) tested at average rate of 1,941 Boe/d …And Net Production Is Ramping Quickly 1Q18 Guidance- 7,550 to 7,650 Boe/d March 2018- 8,350 to 8,450 Boe/d 1Q18 Exit Rate- 9,500 to 10,000 Boe/d from existing wells. Product Volume Crude Oil 5,217 bbl/d NGL’s 1,062 bbl/d Natural Gas 5,957 Mcf/d Total 7,272 Boe/d 1 Reserves and PV-10 as of 12/31/17 at NYMEX Strip Pricing 2 Proforma closing our $250 million 11 ¼% Senior Unsecured Note offering

2017 Capital Results vs. Peers Reserve Replacement Ratio All Sources Finding & Onstream Costs ($/Boe) Reserve Replacement as a % of 2017 Production Finding & Onstream Costs ($/Boe) Note: Figures above calculated from data publically disclosed from the peer companies

Strip PV-10 Per Share Strip PV-10 Strip PV-10 Less Net Debt (Per Share) +70% +33%

Effect of Offset Fracs 1 Represents daily production from 16 Lonestar-operated wells at Culpepper, Burns Ranch,, Beall Ranch, Marquis , Ward and Childress properties, which were impacted by fracture stimulation operations by Rosewood Resources, Texas American, Carrizo Oil & Gas, Penn Virginia, Chesapeake Energy, and Earthstone Energy 4Q17 1Q18 Producing Wells Hit by Offset Fracs 1 9,548 bopd lost in 4Q17 Oil production has rebounded above trend line 45,000 Mcf lost in 4Q17 4Q17 Production Reduced by 173 Boe/d as Offset Frac Hits… Oil production reduced by 9,548 bbls Gas production reduced by 45,000 Mcf Three-stream sales reduced by 173 Boe/d, net to Lonestar …But Production Has Recovered to ‘Above Trend’ Rates Oil production rates have been boosted above pre-frac trendline Gas production has been slower to recover, but is now above pre-frac trendline Lonestar believes quick recovery in post-frac rates are attributable to its proppant program and proper artificial lift. Gas production has rebounded above trend line

Gonzales County Performance Update Cyclone / Hawkeye Area (30-day Oil Production Comparison) Cyclone / Hawkeye Area (60-day Oil Production Comparison) Third Party Forecast Third Party Forecast

La Salle County Performance Update Horned Frog- Cumulative Production Horned Frog- Daily Production Rates

Brazos County Update Brazos County Update Wildcat B1H Continues to Outperform Offsets Wildcat B#1H Continues to Perform Well(50% WI/40% NRI) Lat Length- 8,000’ lateral with 2,100 #/ft proppant (20/64” choke) Max-30 Rate- 2,132 BOEPD (42% oil / 36% NGL / 22% gas) 60-Day Rate- 1,867 BOEPD (44% oil / 33% NGL / 23% gas) Wellhead Cumulative Production- 132,000 bbls oil / 696,000 Mcf 3-Stream Cumulative Production- Eclipsed 320,000 BOE Wildcat B#1H Outperforming Offset Wells 10-Month Cumulative Production 62% Better than Average Offset Well 10-Month Cumulative Production 15% Better than Best Offset Well Wildcat Reserves Are 1.0 MMBOE, per Third-Party Engineers Reserves are 73% Liquid Hydrocarbons Crude Oil – 406,000 bbls Natural Gas Liquids- 328,000 bbls Natural Gas- 1.4 Bcf

Quarterly Financial Summary Quarterly Production – Total Company Quarterly Production – Total Company Net Income Adjusted EBITDAX1 Note- All 2014 , 2015, 2016, and 2017 figures are unaudited 1 Please see “Non-GAAP Financial Reconciliation” in the Appendix for the definition of Adjusted EBITDAX, a reconciliation of Net Income (loss) to Adjusted EBITDAX, and the reasons for its use. 2One-time charges totaling $34.0 million; 27.1 million impairment for Poplar Leasehold, $2.7 million one time expense related to acquisition, $2.0 warrant discount recognition due to early payment on second lien, $1.1 million prepayment premium on second lien, $0.6 million non-recurring general and administrative costs, $0.5 stock based compensation, offset by $0.5 million previously recognized income tax benefits 2QFP – 2Q17 Proforma Acquisition

Lonestar Resources US, Inc. Appendix

Non-GAAP Reconciliation Reconciliation of Non-GAAP Financial Measures   Adjusted EBITDAX (Unaudited) Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock-based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense) and unrealized (gain) loss on derivative financial instruments and unrealized (gain) loss on warrants.   Management believes Adjusted EBITDAX provides useful information to investors because it assists investors in the evaluation of the Company’s operating performance and comparison of the results of the Company’s operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at Adjusted EBITDAX to eliminate the impact of certain non-cash items or because these amounts can vary substantially from company to company within its 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. 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. The Company’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.   The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated. (1) Interest expense consists of Amortization of finance costs and Dividends paid on Series A Preferred Stock. (2) Represents downtime associated with a drilling rig contract (3) Non-recurring costs consists of Acquisitions Costs and General and Administrative Expenses related to the re-domiciliation to the United States, and listing on the NASDAQ.

Non-GAAP Reconciliation Reconciliation of Non-GAAP Financial Measures   PV-10 (Unaudited) Certain of our oil and natural gas reserve disclosures included in this presentation are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows, less future development and production costs from our proved reserves before income taxes, discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the Standardized Measure. We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of a pre-tax PV-10 value provides greater comparability when evaluating oil and gas companies. The PV-10 value is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. The definition of PV-10 value, as defined above, may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value, as defined, may not be comparable to similar measures provided by other companies. The following table provides a reconciliation of the Standardized Measure to PV-10:

Key Financial Highlights 4Q17 Volumes Up 59% to 7,272 Boe/d Only 2 Completions Contributed Materially Cyclone #26H & #27H (Gonzales County) Onstream late September, 2017 2.0 gross / 2.0 net wells 2 Completions in Flowback at End of 4Q17 Burns B #1H & B#2H (LaSalle County) Commercial production started Dec 1, 2017 2.0 gross / 1.9 net wells Frac Hits Impaired 4Q17 Volumes by 173 Boe/d Product Pricing Improved 19% Improved Oil Differentials to WTI Oil price realizations up $11.18/bbl Better LLS prices Improved sales contracts Higher Revenue Product Mix Higher oil mix in 4Q17 Better NGL spreads to WTI Driven by Strong Volume Growth, Cash Expenses Per Boe Dropped 23%... LOE- $8.65 per Boe, up 3% Taxes- $2.79 per Boe, up 389% G&A- $3.51 per Boe, down 48% Int. Exp.- $7.95 per Boe, down 43% …Driving Field Margins Per Boe Up 908% in 4Q17 Revenues per Boe- $46.98, up 47% Expenses per Boe- $22.90, down 23% Interest Expense per Boe- $7.95, down 43% Expense 4Q16 4Q17 Chg. 4Q16 4Q17 Chg. LOE $3.5 $5.8 +66% $8.37 $8.65 +3% Taxes $0.2 $1.9 +675% $0.57 $2.79 +389% G&A2 $2.8 $2.9 +3% $6.72 $3.51 (48%) Int. Exp. $5.9 $5.3 (9%) $14.01 $7.95 (43%) Total $12.4 $15.9 (7%) $29.67 $22.90 (23%) Daily Production Cash Expenses1 Product 4Q16 Mix 4Q17 Mix Crude Oil 2,457 54% 5,217 72% NGL’s 984 22% 1,062 14% Natural Gas 6,717 24% 5,957 14% Total 4,560 100% 7,272 100% Product 4Q16 4Q17 Chg. 4Q16 4Q17 Chg. Crude Oil $10.6 $27.8 +163% $46.67 $57.85 +24% NGL’s $1.1 $2.2 +94% $12.89 $23.19 +80% Nat. Gas $1.7 $1.4 (18%) $2.80 $2.56 (9%) Total $13.4 $31.4 +134% $32.06 $46.98 +47% $ / Boe $ MM $ / Boe Product Pricing / Revenues $ MM Field Margin $1.0 $15.5 1414% $2.39 $24.08 908% 1 Cash Operating Costs are controllable expenses incurred by the Company. 2 Excludes stock based compensation Financial Commentary

Quarterly Production Summary Quarterly Production – Total Eagle Ford Quarterly Production – Western Eagle Ford Quarterly Production – Eastern Eagle Ford Quarterly Production – Central Eagle Ford * Well count reflects unconventional Eagle Ford Shale wells

Current Completion Schedule Current 2018 Schedule

Current Hedge Book 1 Based on Guidance midpoint 2 Based on analysts’ consensus estimates Since inception, Lonestar has implemented a strategy to reduce the effects of volatility of oil and natural gas prices on the Company’s results of operations by securing fixed price contracts for a portion of its expected sales volumes Hedging Program focuses on Crude Oil In recent months, Lonestar has entered into additional swap agreements, increasing hedges to 67% of Bal ‘ 17 and 75% of Cal ‘18 analysts’ consensus forecast oil production. ~69% % of Production Hedged 64% 85% ~82%2 Period Instrument Volume Fixed Price Bal ‘17 Oil – WTI Swap 3,039 bbls/day $52.03 Bal ‘17 Oil – 3 Way Collar 924 bbls/day $40.00/ $60.00/ $85.00 Bal ‘17 Gas – NYMEX Swap 7,000 mmbtu/day $3.36 Cal ‘18 Oil – WTI Swap 4,195 bbls/day $51.83 Cal ‘18 Oil – 2 Way Collar 500 bbls/day $50.00/ $59.45 Cal ‘18 Gas-NYMEX Swap 5,000 mmbtu/day $3.09 Cal ‘19 Oil – WTI Swap 2,930 bbls/day $49.16 Cal ’19 Oil- WTI Swap 1,100 bbls/day $50.90 1H20 Oil – WTI Swap 1,119 bbls/day $48.90 Hedge Book at November 1, 2017 1 Volume Hedged At YE-17 Weighted Average Hedge Price Crude Oil- WTI Hedge Summary ~66%2 ~27%2 Hedges after YE 17

Glossary •“bbl” means barrel of oil. • bbls/d means the number of one stock tank barrel, or 42 US gallons liquid volume of oil or other liquid hydrocarbons per day. “Boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil. •Boe/d means barrels of oil equivalent per day. “scf” means standard cubic feet. •“btu” means British thermal units. •“M” prefix means thousand. •“MM” prefix means million. •“B” prefix means billion. •“NGL” means Natural Gas Liquids– these products are stripped from the gas stream at 3rd party facilities remote to the field. •“TEV” means total enterprise value •“LTM” means last twelve months •“NTM” means next twelve months •“HBP” means held by production •“EPS” means earnings per share • “Mcf/d” means thousand cubic feet of natural gas per day • “IRR” means our internal rate of return, calculates the interest rate at which the net present value of all the cash flows (both positive and negative) from a project or investment equal zero • “EUR” means gross estimated ultimate recoveries for a single well Note: One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.