Lonestar Resources US, Inc. Third Quarter 2018 Conference Call November 6, 2018

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 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 Amended Annual Report on Form 10-K/A filed with the Securities and Exchange Commission, or the SEC, on November, 2, 2018, our Quarterly Reports on Form 10-Q/A 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. 2

Quarterly Highlights 3Q18 Production by Product Product Volume Crude Oil 7,183 bbl/d NGL's 23% NGL’s 2,855 bbl/d Oil 58% Natural Gas 14,600 Mcf/d Gas 19% Total 12,471 Boe/d Third Quarter 2018 Highlights . Production increased to 12,471 Boe/d, up 63%, year‐over‐year and up 12% sequentially . Adjusted EBITDAX increased to $37.0 million, up 82% year‐over‐year and 27% sequentially . Debt / EBITDAX ratio reduced from 3.4x in 1Q18 to 2.5x in 3Q18. More Outperformance In Financial Results . Production 12,471 Boe/d, exceeding guidance of 11,800 to 12,200 boe/d . Adjusted EBITDAX of $37.0 million, exceeded guidance of $32.0 to $34.0 million . Flooding at Burns Ranch reduced September production by 250 boe/d 2018 New Completions Are Substantially Outperforming . Hawkeye (Gonzales)‐ online January, Max‐30 day rates 938 Boe/d, 24% above Type Curve to date  . Horned Frog (LaSalle )‐ online March, Max 30 day rates 2,155 Boe/d, 15% above Type Curve to date  . Georg 18H‐20H(Karnes)‐ online May, Max‐30 day rates 948 Boe/d, 2% above Type Curve to date  . Horned Frog NW (LaSalle)‐ online June, Max 30 day rates 1,080 Boe/d, 11% above Type Curve to date . Georg 24H‐26H(Karnes)‐ online July, Max‐30 day rates 866 Boe/d, in‐line with Type Curve to date  Tack‐On Acquisitions Add Reserves, Enhance Wellbore Returns . 3Q18 Tack‐Ons totaled ~3,000 acres at a cost of $3.0 MM in Karnes & Gonzales Counties . Increase lateral lengths on 41 drilling locations by an average of 42% . Year‐to‐date, added ~4,000 net acres, which we estimate adds 8.2 MMBOE and $90 MM PV‐101 Reiterating 2019 Outlook… . 17 gross / 16 net wells at a cost of $120 to $130 million . 2019 Production Outlook of 13,000 – 14,000 Boe/d, an increase of 27% . 2019 Adjusted EBITDAX Outlook of $140 to $160 million, an increase of 23% …Currently Sharpening Our Views On Costs and Well Timing . Bidding out drilling services for 2019 . Negotiating a dedicated frac spread for 2019 3

Key Financial Highlights Financial Commentary Daily Production 3Q18 Volumes Up 63% to 12,471 Boe/d Product 3Q17 Mix 3Q18 Mix . Materially Contributing Completions . Horned Frog NW #2H & 3H (LaSalle County) Crude Oil 5,250 69% 7,183 58% . Onstream June, 2018 NGL's 1,228 16% 2,855 23% . 2.0 gross / 2.0 net wells . Cyclone DM #14H & #3H (Gonzales County) Natural Gas 7,105 15% 14,600 19% . Onstream July, 2018 Total 7,662 100% 12,471 100% . 2.0 gross / 2.0 net wells . Georg #24H, #25H, & #26H (Karnes County) . Onstream August, 2018 . 3.0 gross / 2.4 net wells Product Pricing / Revenues . Culpepper #3‐2H, #3‐3H, & #3‐4H (Gonzales County) . Onstream September, 2018 $MM $ / Boe . 3.0 gross / 2.4 net wells Product 3Q17 3Q18 Chg. 3Q17 3Q18 Chg. Product Pricing Improved 34%...  • Oil  & Gas Prices All Improved Crude Oil $23.2  $47.8  +107% $47.96  $72.40  +51% • Basis Differentials Improved for All Three Products NGL’s $1.8  $6.8  +271% $16.20  $25.87  +60% . Oil price differentials were +$2.90/bbl vs. WTI  . Benchmark price increased $24.44 vs. 3Q17 Nat. Gas $1.9  $4.1  +117% $2.89  $3.05  +5% . Better LLS pricing Total $26.9  $58.7  +118% $38.14  $51.19  +34% . NGL price differentials were 37% of WTI  . Realizations up 60% , or $9.67/bbl vs. 3Q17 . 3Q18 was 37% of WTI vs. 34% of WTI in 3Q17 Cash Expenses1 . Gas price differentials were +$0.15/Mcf vs. HH  . Benchmark price increased 5% vs. 2Q17 $MM $ / Boe Per‐Unit Cash Expenses Are Declining… Expense 3Q17 3Q18 Chg. 3Q17 3Q18 Chg. . LOE‐ $5.14 per Boe, 9% Y‐0‐Y,  5% Q‐o‐Q 2 . G,P&T‐ $0.69 per Boe, 8% Y‐o‐Y, 13% Q‐o‐Q LOE $4.0  $5.9  +48% $5.66  $5.14  (9%) .   3 Taxes‐ $2.80 per Boe,  28% Y‐o‐Y,  3% Q‐o‐Q G,P&T $0.5  $0.8  +50% $0.74  $0.69  (8%) . G&A‐ $3.13 per Boe, 11%, Y‐o‐Y,  5% Q‐o‐Q . Int. Exp.‐ $8.00 per Boe,  12% Y‐o‐Y,  2% Q‐o‐Q Taxes $1.5  $3.2  +109% $2.19  $2.80  +28% . Total.‐ $19.76 per Boe,  3% Y‐o‐Y,  1% Q‐o‐Q G&A4 $2.5  $3.6  +45% $3.51  $3.13  (11%) Int. Exp.5 $5.0  $9.2  +82% $7.14  $8.00  +12% …Increasing Cash Margins in 3Q18 . Revenues‐ $51.19 per Boe,  34% Y‐o‐Y, 8% Q‐o‐Q Total $13.6  $22.7  +67% $19.24  $19.76  +3% . Expenses‐ $19.76 per Boe,  3% Y‐o‐Y,  1% Q‐o‐Q . Total.‐ $31.43 per Boe,  66% Y‐o‐Y,  16% Q‐o‐Q Cash  $13.3  $36.1  +171% $18.90  $31.43  +66% Margin 1 Cash Operating Costs are controllable expenses incurred by the Company 4Excludes stock based compensation 2 LOE – Excludes $0.2 million of nonrecurring legal expenses 5 Excludes amortization of debt issuance cost, premiums & discounts 3 G,P&T – Gathering, processing and transportation expense 4

Rapidly Improving Financial Metrics Average Daily Production vs. Annualized Adjusted EBITDAX1 $210 14,000 $180 12,000 $150 10,000 ($MM)   (Boepd)   $120 8,000 EBITDAX    $90 6,000 Production   $60 4,000 Daily Annualizeed $30 2,000 $0 0 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 EBITDAX excl. Hedging Hedging Revenue Hedging Expense Production Debt / Adjusted EBITDAX 5.5x 5.0x 4.5x EBITDAX   4.0x Adjsuted 3.5x    /   3.0x Debt   LQA 2.5x 2.0x 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 1 Annualized Adjusted EBITDAX is reported quarterly Adjusted EBITDAX multiplied by 4 5

Gonzales County Performance Update Cyclone / Hawkeye Area Lease Map Gonzales Hawkeye #1H/#2H vs. Type Curve  1 Type Curve Statistics 160 900 140 Avg Lateral Length: 9,645' (MBO) 120 EUR (Mboe):632  800 100 2 PV‐10  ($MM) : $8.2 80 Production   60 Oil Cap Ex ($MM):$7.2  700 40 2 Cum. IRR : 80% 20 600 0 (Bopd) 0123456789   Months 500 WDVG Actual Production 400 300 Production   To date3, production  Oil 200 outperformance have  100 increased PV‐10 to  $9.0MM and IRR to 90% 0 1 2 3 4 5 6 7 8 9101112131415161718192021222324 Months WDVG Actual Production 1 2 Type Curve data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten & Co. Economics assume $65 flat oil 6 price and $2.75 flat gas deck. 3 Production outperformance assumes actuals to date and type curve thereafter.

Gonzales County Lateral Extensions Cyclone / Hawkeye Area Development Map Lonestar Acreage Acquired Acreage Legend PDP PUD PROB Lateral Inventory • Lengthens 22 of our 60 locations by 50%  11,000 • Adds $27.5 MM of PV‐10 & 1.7 MMBOE 10,000 9,000 8,000 (feet)   7,000 6,000 5,000 Length   4,000 3,000 Lateral 2,000 1,000 0 12345678910111213141516171819202122 Original Extended 1 All reserves and economic data calculated using a $65 flat oil price and $2.75 flat gas deck for the purposes of illustrating the potential impact to reserves and PV-10 for the company. 7

La Salle County Performance Update Horned Frog Area Lease Map NW   Frog   Horned Legend PDP PUD PROB Horned Frog Wells vs. Competitor Offsets 1,750 G1H H1H 1,500 (#/ft)   1,250 Concenration 1,000   750 Proppant 500 0306090120150180 210‐Day  Production  (BOEPD / 1,000' Lateral) Vintage Completions Modern Completions LONE Wells Average Production 8

LaSalle County Performance Update Horned Frog  G#1H & H#2H vs. Type Curve 1 400 2,500 Type Curve Statistics Avg Lateral Length: 11,363' 350 (MBoe)   300 EUR (Mboe):1,163250 2 $5.3 200 PV‐10 ($MM) : Production 2,000   150 ($MM) Cum. Cap Ex  :$7.9  100 2 55% Stream (Boepd) IRR : ‐ 50   3 0 1,500 01234567 Months WDVG Actual Production Production 1,000   To date3, production  Stream ‐ 500 outperformance has  3 increased  PV‐10 to  $7.4MM and IRR to 106% 0 123456789101112131415161718192021222324 Months WDVG Actual Production Horned Frog NW 2H & 3H vs. Type Curve Type Curve Statistics 1 120 1,100 110 Avg Lateral Length: 7,410' 100 90 (Mboe) 1,000 EUR (Mboe):733  80 2 70 900 PV‐10 ($MM) : $5.0 60 Production 50   Cap Ex ($MM):$7.040 800 30 Stream Board Book Versions 2 ‐ 3 20 (Boepd) 49%   IRR : 700 10 0 01234 600 Months 500 WDVG Actual Pr od uctio n Production   400 300 To date3, production  Stream ‐ 200 outperformance have  3 increased PV‐10 to  100 $6.1MM and IRR to 72% 0 123456789101112131415161718192021222324 Months LONE Curve Actual Production 1 Type Curve data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten & Co. 2 Economics assume $65 flat oil price and $2.75 flat gas deck. “LONE Curve” sourced internally. 3 Production outperformance assumes actuals to date and type curve thereafter. 9

Karnes County Performance Update Karnes County Leasehold Map Legend PDP PUD PROB Karnes County Well Results Type Curve Statistics 1 90 1,000 80 70 Avg Lateral Length: 6,123' (MBoe)   60 EUR (Mboe):45850 2 40 800 Production $6.4   PV‐10 ($MM) : 30 (Boepd) Cum. 20 Cap Ex ($MM):$5.8    10 2 99% IRR : Stream 0  ‐ 600 3 01234 Months  of Production WDVG GRG 18H ‐ 20H GRG 24H ‐ 26H Production 400   200 Stream  ‐ 3 0 123456789101112131415161718192021222324 Months  of Production WDVG GRG 18H‐20H GRG 24H ‐ 26H 1 Type Curve data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten & Co. 2 Economics assume $65 flat oil 10 price and $2.75 flat gas deck. 3 Production outperformance assumes actuals to date and type curve thereafter.

Karnes County Lateral Extensions Karnes Area Development Map Lonestar Acreage Acquired Acreage Legend PDP PUD PROB Lateral Inventory 8,400 • Lengthens 19 of our 27 locations by 34%  7,800 • 7,200 Adds $24.2 MM of PV‐10 & 1.5 MMBOE 6,600 6,000 5,400 (feet)   4,800 4,200 Length   3,600 3,000 2,400 Lateral 1,800 1,200 600 0 123456789101112131415161718192021 Original Extended 1 All reserves and economic data calculated using a $65 flat oil price and $2.75 flat gas deck for the purposes of illustrating the potential impact to reserves and PV-10 for the company. 11

Year to Date Acreage Additions  Lonestar’s Acreage Position Lonestar Acreage Cyclone  Acquired Acreage Hawkeye Karnes Horned Frog Impact of Acreage Additions Net Reserves Proved Locations Length Property Acres Bonus Payment (MMBOE) PV‐10 Affected Increased Horned Frog NW 993 $1,250 $1.2 5.0 $38.1 7 100% Cyclone/Hawkeye 2,727 $1,069 $2.9 1.7 $27.5 22 50% Karnes County 275 $192 $0.1 1.5 $24.2 19 34% Total 3,995 $1,053 $4.2 8.2 $89.8 48 51% 1 All reserves and economic data calculated using a $65 flat oil price and $2.75 flat gas deck for the purposes of illustrating the potential impact to reserves and PV-10 for the company. 12

Quarterly Highlights 3Q18  4Q18 Guidance  Product Reported Mix Low Mix High Mix Crude Oil (bbl/d) 7,183 58% 7,700 60% 8,000 62% NGL’s (bbl/d) 2,855 23% 2,450 19% 2,400 19% Natural Gas (Mcf/d) 14,600 19% 14,700 21% 14,400 19% Total (boe/d) 12,471 100% 12,600 100% 12,800 100% Third Quarter 2018 Highlights . Production increased to 12,471 Boe/d, up 63%, year‐over‐year and up 12% sequentially . Adjusted EBITDAX increased to $37.0 million, up 82% year‐over‐year and 27% sequentially . Debt / EBITDAX ratio reduced from 3.4x in 1Q18 to 2.5x in 3Q18. More Outperformance In Financial Results . Production of 12,471 Boe/d exceeding guidance of 11,800 to 12,200 boe/d . Adjusted EBITDAX of $37.0 million exceeded guidance of $32.0 to $34.0 million . Flooding impaired at Burns Ranch, reduced September production by 250 boe/d Fourth Quarter Guidance‐ Continued Growth . Production guidance of 12,600 to 12,800 boe/d, negatively impacted by Frio River flooding . Equates to 10% crude oil production growth (at midpoint) . Adjusted EBITDAX of $39.0‐$41 million 2018 New Completions Are Substantially Outperforming . Hawkeye (Gonzales)‐ online January, Max‐30 day rates 938 Boe/d, 24% above Type Curve to date  . Horned Frog (LaSalle )‐ online March, Max 30 day rates 2,155 Boe/d, 15% above Type Curve to date  . Georg 18H‐20H(Karnes)‐ online May, Max‐30 day rates 948 Boe/d, 2% above Type Curve to date  . Horned Frog NW (LaSalle)‐ online June, Max 30 day rates 1,080 Boe/d, 11% above Type Curve to date . Georg 24H‐26H(Karnes)‐ online July, Max‐30 day rates 866 Boe/d, in‐line with Type Curve to date  Tack‐On Acquisitions Add Reserves, Enhance Wellbore Returns . 3Q18 Tack‐Ons totaled ~3,000 acres at a cost of $3.0 MM in Karnes & Gonzales Counties . Increase lateral lengths on 41 drilling locations by an average of 42% . Year‐to‐date, added ~4,000 net acres, which we estimate adds 8.2 MMBOE and $90 MM PV‐101 Reiterating 2019 Outlook… . 17 gross / 16 net wells at a cost of $120 ‐ $130 million . 2019 Production Outlook of 13,000 – 14,000 Boe/d, an increase of 27% . 2019 Adjusted EBITDAX Outlook of $140 to $160 million, an increase of 23% …Currently Sharpening Our Views On Costs and Well Timing . Bidding out drilling services for 2019 . Negotiating a dedicated frac spread for 2019  13

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. Stock-based compensation 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Net Income (Loss) $ (725) $ (20,883) $ 7,381 $ (13,106) $(11,297) $ (12,844) $(11,260) $ (63,300) $ 3,118 $ (24,011) $ (8,948) $ (17,612) $ (18,425) $ (23,525) $ (21,685) Income tax expense (benefit) (1,120) (11,028) 4,360 (7,333) (5,795) (6,245) 1,684 35,341 1,703 (12,601) (4,956) (13,165) (3,109) (3,103) (282) Interest expense (1) 5,847 5,972 6,666 6,092 6,124 6,174 7,345 9,939 5,032 9,115 7,789 8,103 11,148 11,230 12,190 Exploration expense — 51 — 171 — 1 10 371 — 205 — 421 — — 109 Depletion, depreciation, amortization and accretion 12,838 13,307 13,021 19,876 15,195 12,549 10,718 13,713 11,974 13,498 16,530 14,955 15,425 20,737 23,775 EB ITDAX 16,840 (12,581) 31,428 5,700 4,227 (365) 8,497 (3,935) 21,827 (13,794) 10,415 (7,298) 5,039 5,339 14,107 Rig standby expense (2) — — 10 653 313 1,584 364 — — — 61 561 — — 27 Non-recurring costs (3) — 19 25 1,182 323 321 607 308 — 3,127 337 175 — — 60 Stock-based compensation 433 433 880 839 95 95 122 135 178 461 346 644 450 2,281 924 (Gain) loss on sale of oil and gas properties — — — — — (1,531) 53 1,404 142 205 119 — — — — Impairment of oil and gas properties — 19,328 — 9,295 — 1,938 29,144 4,488 — 27,081 — 6,332 — — 12,169 Unrealized (gain) loss on derivative financial instruments 3,768 14,908 (10,668) 720 8,429 13,176 4,600 10,163 (8,339) (3,770) 9,437 19,860 7,594 18,896 9,911 Unrealized (gain) loss on warrants — — — — — — 611 (1,179) (2,270) (613) (402) 198 152 2,462 (509) Office lease write-off — — — — — — — — — — — — 1,568 — — Loss on extinguishment of debit — — — — — — — — — — — — 8,619 — — Other (income) expense 663 (4) 18 389 206 819 (29,362) 1,118 (4) (46) (4) (8) (7) 232 315 Adjusted EBITDAX $21,704 $ 22,103 $ 21,693 $ 18,778 $ 13,593 $ 16,037 $ 14,636 $ 12,502 $ 11,534 $ 12,651 $ 20,309 $ 20,464 $ 23,415 $ 29,210 $ 37,004 (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. 15

Current Completion Schedule 2Q18 Conference Call ‐ 2018 Schedule 30 6.0 25 6.4 20 2.4 Onstream   15 3.8 Wells   3.8 10 Net 2.0 5 2.9 0.5 0 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Burns Ranch Wildcat Cyclone Hawkeye Horned Frog Battlecat Asherton Current 2018 Schedule 30 3.6 6.8 25 20 4.4 Onstream   15 3.8 Wells   3.8 10 Net 2.0 5 2.9 0.5 0 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Burns Ranch Wildcat Cyclone Hawkeye Horned Frog Battlecat Asherton 1 Two Horned Frog NW wells added in 2Q18 contributed approximately 14 days in June 2018 16

Lease Operating Expenses $10.00 $7.5 $8.00 $6.0 Lease BOE     Operating Per   $6.00 $4.5   Expenses Expenses   $4.00 $3.0    ($MM) Operating   Lease $2.00 $1.5 $0.00 $0.0 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Compression Chemicals Saltwater Disposal Field Personnel Labor Regulatory, Legal, Insurance Roads & Location Workover & Repairs Direct Well Costs Reported LOE ($MM) 17

Financial Statistics & Guidance Quarterly Production –Total Company Quarterly Production –Total Company 14,000 14,000 12,000 12,000 10,000 10,000 8,000 (Boe/d) 8,000 (Boe/d)     6,000 6,000 4,000 4,000 Production Production 2,000 2,000 0 ‐ Western EFS Central EFS Eastern EFS Conventional Crude Oil Natural Gas Liquids Natural Gas Adjusted EBITDAX1  ($MM) Net Income ($MM) $40 $30 $30 $35 $20 $20 $10 $10 $30 $0 $0 $25 ($MM) ‐$10 ‐$10 ($MM)     $20 ‐$20 ‐$20 ‐$30 ‐$30 Income $15   EBITDAX   ‐$40 ‐$40 Net $10 ‐$50 ‐$50 $5 ‐$60 ‐$60 Quarterly ‐$70 ‐$70 $0 Net Income Adjusted Net Income (Graph) Note- All 2014 , 2015, 2016, 2017 and 2018 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 18

Quarterly Production Summary Quarterly Production –Total Eagle Ford Quarterly Production –Western Eagle Ford 14,000 200 7,000 60 180 12,000 6,000 160 50 10,000 140 5,000 Count Count   40   8,000 120 (Boe/d) (Boe/d) 4,000   Well   Well   100 30   6,000 80 3,000 Ford Ford   20   4,000 60 2,000 Production Production 40 Eagle 2,000 10 Eagle 20 1,000 ‐ 0 ‐ 0 Crude Oil Natural Gas Liquids Natural Gas Crude Oil Natural Gas Liquids Natural Gas Quarterly Production – Central Eagle Ford Quarterly Production –Eastern Eagle Ford 6,000 140 1,500 12 5,000 120 1,200 10 100 Count Count 4,000   8   80 900 (Boe/d) (Boe/d) Well     Well   3,000 6   60 Ford 600 Ford   2,000   40 4 Production Production Eagle 300 Eagle 1,000 20 2 0 0 0 0 Crude Oil Natural Gas Liquids Natural Gas Crude Oil Natural Gas Liquids Natural Gas * Well count reflects unconventional Eagle Ford Shale wells  19

Current Hedge Book • 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  98% of Bal ‘ 18 and 69% of Cal ‘19 analysts’ consensus forecast oil production. • During the third quarter, Lonestar bolstered its 2019 hedge book by adding 2.2 MMBbls or 5,930  Bbls/day at a weighted average price of $5.05 of Louisiana Light Sweet (LLS) basis swaps to lock  in a premium to WTI. Crude Oil‐ WTI Hedge Summary Crude Hedge Book at September 30, 2018 % of  Period Instrument Volume Fixed Price Production  64% 85% ~69%  ~98%1 ~69%1 ~29%1 Hedged 9,000 $90 Bal ‘18 Oil –WTI Swap 7,755 bbls/day $57.37 7,755 8,000 $80 $53.94 Cal ’19 Oil‐ WTI Swap 1,536 bbls/day $48.04 7,000 $70 5,930 6,000 $60 Cal ’19 Oil –WTI Swap 1,394 bbls/day $50.40 (bopd)   5,000 $50 Bbl Cal ’19 Oil‐WTI Swap 1,100 bbls/day $50.90   /   $56.97 $ Hedged 4,000 $40   3,213 2,753 $57.37 Cal ’19 Oil‐WTI Swap 900 bbls/day $58.25 3,000 2,698   $51.21 2,680 $30     Volume $53.36 2,000 $71.02 $20 $85.76 Cal ’19 Oil‐WTI Swap 500 bbls/day $65.20 1,000 $53.02 $10 Cal ’19 Oil‐WTI Swap 500 bbls/day $69.57 0 $0 2015 2016 2017 2018 2019 2020 Volume Hedged At 2Q18 Weighted Average Hedge Price Cal ’20 Oil‐WTI Swap 556 bbls/day $48.90 Hedges during 3Q18 Weighted Average Price with new Hedges Cal ’20 Oil‐WTI Swap 1,124 bbls/day $55.06 2018 Hedging Volumes from October – December 2018 LLS Basis Swaps Cal ’20 Oil‐WTI Swap 500 bbls/day $61.65 Period Instrument Volume Fixed Price Cal ’20 Oil‐WTI Swap 500 bbls/days $65.56 Cal ’19 WTI – LLS  5,930 bbls/day $5.05 Swap 20 1Based on analysts’ consensus estimates

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. 21