Attached files
| file | filename |
|---|---|
| EX-99.1 - EXHIBIT 99.1 - Lonestar Resources US Inc. | pressrelease-2q18.htm |
| 8-K - 8-K - Lonestar Resources US Inc. | a8-kxq2earningsreleaseands.htm |
Lonestar Resources US, Inc. Second Quarter 2018 Conference Call August 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 Annual Report on Form 10-K filed with the Securities and Exchange Commission, or the SEC, on March, 29, 2018 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. 2
Quarterly Highlights 2Q18 Production by Product Product Volume Crude Oil 6,378 bbl/d NGL's 22% NGL’s 2,438 bbl/d Oil 57% Natural Gas 13,943 Mcf/d Gas 21% Total 11,140 Boe/d Second Quarter 2018 Highlights . Production increased to 11,140 Boe/d, up 98%, year-over-year and up 43% sequentially . Adjusted EBITDAX increased to $29.2 million, up 131%, year-over-year and 25% sequentially . Debt / EBITDAX ratio reduced from 5.4x in 2Q17 to 2.8x in 2Q18. 2018 New Completions Are All Outperforming . Hawkeye (Gonzales)- online January, Max-30 day rates 938 Boe/d, 23% 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 (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, 9% above Type Curve to date 3Q18 Guidance Calls For More Growth . Production of 11,750 to 12,200 Boe/d, up 56% year-over-year and 8% sequentially . Production mix- 61% Oil, 18% NGL’s, 21% Natural Gas . Adjusted EBITDAX of $32 to $34 million, up 63%, year-over-year and 13% sequentially Extending 2018 Drilling & Completion Program . Increasing completion program from 19 to 21 wells . Increases 2018 Drilling and Completion budget to $120 to $130 MM . Allows for seamless transition into 2019 program . Allows LONE to achieve 2019 production and financial objectives with 1 rig Increasing Full-Year 2018 Guidance Again… . 2018 Production Guidance- Increasing from 10,300 - 11,000 Boe/d to 10,600 - 11,200 Boe/d . 2018 EBITDAX Guidance- Increasing from $110 MM - $125 MM to $115 - $130 MM …And Issuing 2019 Preliminary 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% Executing Plan to Deliver Value to Shareholders . Implement Ge0-Engineered Completion Strategy to Drive Production Results & Returns . Increase Scale of Business to Expand Margins and Increase Profitability . Expand Borrowing Base While Rapidly Improving Debt Metrics = Increase Asset Value and Equity Valuation 3
Key Financial Highlights Financial Commentary Daily Production 2Q18 Volumes Up 98% to 11,140 Boe/d Product 2Q17 Mix 2Q18 Mix . Materially Contributing Completions . Horned Frog G1H & H1H (LaSalle County) Crude Oil 3,564 63% 6,378 57% . Onstream March, 2018 NGL's 1,004 18% 2,438 22% . 2.0 gross / 2.0 net wells . Added ~3,500 Boe/d net to 2Q18 results Natural Gas 6,401 19% 13,943 21% . Georg #18H, #19H, & #20H (Karnes County) Total 5,635 100% 11,140 100% . Onstream May, 2018 . 3.0 gross / 2.4 net wells . Added ~825 Boe/d net to 2Q18 results Product Pricing / Revenues . Horned Frog NW #2H & #3H(LaSalle County) . Onstream June 14, 2018 $MM $ / Boe . 2.0 gross / 2.0 net wells Product Pricing Improved 33%... Product 2Q17 2Q18 Chg. 2Q17 2Q18 Chg. • Oil and Gas Prices Both Improved Crude Oil $15.1 $39.7 +163% $46.52 $68.41 +47% . Oil price differentials were +$0.47/bbl vs. WTI . Oil price increased $11.82 vs. 2Q17 NGL’s $1.3 $4.4 +234% $14.43 $19.88 +38% . Better LLS pricing Nat. Gas $1.7 $3.8 $2.96 $2.94 . Gas price differentials were +$0.11/Mcf vs. HH +117% (1%) . Gas price flat vs. 2Q17 Total $18.1 $47.9 +164% $35.38 $47.20 +33% Cash Expenses1 Per-Unit Cash Expenses Are Declining… . LOE- $5.37 per Boe, i14% Y-0-Y, i 9% Q-o-Q $MM $ / Boe . G,P&T- $0.79 per Boe, h30% Y-o-Y, h 25% Q-o-Q . h i Taxes- $2.72 per Boe, 30% Y-o-Y, 12% Q-o-Q Expense 2Q17 2Q18 Chg. 2Q17 2Q18 Chg. . G&A- $2.98 per Boe, i 51%, Y-o-Y, i 30% Q-o-Q . Int. Exp.- $8.15 per Boe, i 30% Y-o-Y, i 30% Q-o-Q LOE2 $3.2 $5.4 +70% $6.26 $5.37 (14%) . Total.- $20.01 per Boe, i 25% Y-o-Y, i 22% Q-o-Q G,P&T3 $0.3 $0.8 +157% $0.60 $0.79 +30% Taxes $1.1 $2.8 +156% $2.10 $2.72 +30% …Increasing Cash Margins in 2Q18 G&A4 $3.1 $3.0 (4%) $6.12 $2.98 (51%) . Revenues- $47.20 per Boe, h33% Y-o-Y, i10% Q-o-Q Int. Exp.5 $6.0 $8.3 +38% $11.64 $8.15 (30%) . Expenses.- $20.01 per Boe, i 25% Y-o-Y, i 22% Q-o-Q . h h Total.- $27.49 per Boe, 214% Y-o-Y, 2% Q-o-Q Total $13.7 $20.3 +48% $26.72 $20.01 (25%) Cash $4.4 $27.6 +523% $8.66 $27.19 +214% Margin 1 Cash Operating Costs are controllable expenses incurred by the Company 3 Excludes stock based compensation 2 LOE – Excludes $0.2 million of nonrecurring legal expenses 4 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 $120 8,000 $90 6,000 $60 4,000 Daily ProductionDaily (Boepd) Annualizeed EBITDAX ($MM) EBITDAX Annualizeed $30 2,000 $0 0 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Est. Est. EBITDAX excl. Hedging Hedging Revenue Hedging Expense Production Debt / Adjusted EBITDAX 6.0x 5.5x 5.0x 4.5x 4.0x 3.5x 3.0x 2.5x 2.0x 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Est. Est. LQA 1 Annualized Adjusted EBITDAX is reported quarterly Adjusted EBITDAX multiplied by 4 5
Gonzales County Performance Update Cyclone / Hawkeye Area Lease Map Hawkeye Cyclone Hawkeye Wells vs. Cyclone Offsets Thru 180 days 700 70 600 62 65 60 500 55 400 51 49 50 300 46 45 Day Production (Bopd) Production Day 200 - 40 Day Production (Bopd/1,000') Production Day - 180 100 35 180 180 0 30 6
Gonzales County Performance Update Cyclone / Hawkeye Area (180 Day Oil Production Comparison) 150 125 100 75 50 Cumulative Production (MBbls) ProductionCumulative 25 0 Months Hawkeye #1H/#2H vs. Type Curve 900 Well Statistics 1 800 Avg Lateral Length: 9,645' 700 EUR (Mboe): 638 PV-10: $8.2 600 Cap Ex: $7.2 IRR: 80% 500 400 300 Oil Oil Production (Bopd) 200 100 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Months WDVG Actual Production 1 All reserves and economic data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten & Co. Assumes $65 flat oil price and $3.00 flat gas deck 7
La Salle County Performance Update Horned Frog Area Lease Map Horned Frog NW Horned Frog Wells vs. Competitor Offsets 2,000 1,750 G1H H1H 1,500 1,250 1,000 750 Proppant Proppant Concenration (#/ft) 500 0 50 100 150 200 120-Day Production (BOEPD / 1,000' Lateral) Vintage Completions Modern Completions LONE Wells 8
LaSalle County Performance Update Horned Frog G#1H & H#2H vs. Type Curve 2,500 Well Statistics 1 2,000 Avg Lateral Length: 11,363' EUR (Mboe): 1,163 PV-10: $4.4 1,500 Cap Ex: $7.9 IRR: 46% 1,000 Stream Stream Production(Boepd) - 500 3 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Months WDVG Actual Production Horned Frog NW 2H & 3H vs. Type Curve 1,100 1,000 Well Statistics 1 900 Avg Lateral Length: 7,410' 800 EUR (Mboe): 733 700 PV-10: $3.9 600 Cap Ex: $7.0 500 IRR: 39% 400 300 Stream Stream Production(Boepd) - 200 3 100 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Months LONE Curve Actual Production 1 All reserves and economic data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten & Co. Assumes $65 flat oil price and $3.00 flat gas deck. “LONE Curve” sourced internally – assumes $65 flat oil price and $3.00 flat gas deck 9
Karnes County Performance Update Karnes County Leasehold Map Karnes County Well Results • In May 2018, LONE placed the Georg #18H / #19H / #20H online (80% WI / 61% NRI) • Avg. Lat Length- 5,997’ lateral with 2,040 #/ft proppant (with diverters) • Max 30 IP Rate- 948 Boe/d • Max 30 I Rate by product- 827 bbls/d Oil / 65 bbls/d NGL’s / 340 Mcf/d gas • Current Hydrocarbon Mix- 87% oil / 7% NGL’s / 6% gas • Lonestar Has Completed 6 wells in the area in 2018 (80% WI / 61% WI) • Est. Avg. Lat Length- 6,000’ lateral • Georg (Karnes County)- 3.0 gross / 2.4 net wells fracture stimulation wrapping up • Culpepper (Gonzales County) 3.0 gross / 2.4 net wells awaiting fracture stimulation • Projected Internal Rates of Return- 94% IRR at $65 WTI • Lonestar has 35 drilling locations in the Area • 35 Proved Undeveloped 10
Karnes County Performance Update Karnes County Well Results 1,000 900 Well Statistics 1 800 Avg Lateral Length: 6,245' 700 EUR (Mboe): 447 600 PV-10 ($MM): $5.7 500 Cap Ex: $5.2 400 IRR: 94% 300 200 100 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 3 Stream Production (Boepd) 3Stream Months of Production WDVG Actual Production Karnes County Well Performance vs. Type Curve 100 75 50 25 Cumulative Cumulative Production (MBbls) 0 0 1 2 3 Months 1 All reserves and economic data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten & Co. Assumes $65 flat oil price and $3.00 flat gas deck. 11
Current Completion Schedule 1Q18 Conference Call - 2018 Schedule 30 4.4 25 6.4 20 2.4 15 3.8 3.8 10 Net Net Onstream Wells 2.0 5 2.9 0.5 0 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Burns Ranch Wildcat Cyclone Hawkeye Horned Frog Battlecat Current 2018 Schedule 30 6.0 25 6.4 20 2.4 15 3.8 3.8 10 Net Net Onstream Wells 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 3Q18 contributed approximately 14 days in June 2018 12
Quarterly Highlights 2Q18 Production by Product Product Volume Crude Oil 6,378 bbl/d NGL's 22% NGL’s 2,438 bbl/d Oil 57% Natural Gas 13,943 Mcf/d Gas 21% Total 11,140 Boe/d Second Quarter 2018 Highlights . Production increased to 11,140 Boe/d, up 98%, year-over-year and up 43% sequentially . Adjusted EBITDAX increased to $29.2 million, up 131%, year-over-year and 25% sequentially . Debt / EBITDAX ratio reduced from 5.4x in 2Q17 to 2.8x in 2Q18. 2018 New Completions Are All Outperforming . Hawkeye (Gonzales)- online January, Max-30 day rates 938 Boe/d, 23% 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 (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, 9% above Type Curve to date 3Q18 Guidance Calls For More Growth . Production of 11,750 to 12,200 Boe/d, up 56% year-over-year and 8% sequentially . Production mix- 61% Oil, 18% NGL’s, 21% Natural Gas . Adjusted EBITDAX of $32 to $34 million, up 63%, year-over-year and 13% sequentially Extending 2018 Drilling & Completion Program . Increasing completion program from 19 to 21 wells . Increases 2018 Drilling and Completion budget to $120 - $130 MM . Allows for seamless transition into 2019 program . Allows LONE to achieve 2019 production and financial objectives with 1 rig Increasing Full-Year 2018 Guidance Again… . 2018 Production Guidance- Increasing from 10,300 - 11,000 Boe/d to 10,600 - 11,200 Boe/d . 2018 EBITDAX Guidance- Increasing from $110 MM - $125 MM to $115 - $130 MM …And Issuing 2019 Preliminary Outlook . 17 gross / 16 net wells at a cost of $110 to $120 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% Executing Plan to Deliver Value to Shareholders . Implement Ge0-Engineered Completion Strategy to Drive Production Results & Returns . Increase Scale of Business to Expand Margins and Increase Profitability . Expand Borrowing Base While Rapidly Improving Debt Metrics = Increase Asset Value and Equity Valuation 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 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Net Income (Loss) $ 5,045 $ (6,976) $19,132 $19,265 $ (725) $(20,883) $ 7,381 $(13,106) $(11,297) $(12,844) $(11,260) $(58,934) $ 3,066 $ (23,457) $ (8,585) $(13,654) $ (18,541) $ (20,707) Income tax expense (benefit) 1,553 (511) 1,508 19,882 (1,120) (11,028) 4,360 (7,333) (5,795) (6,245) 1,684 37,759 1,587 (12,208) (4,718) (14,402) (3,131) (4,648) Interest expense (1) 1,553 7,341 5,348 5,708 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 Exploration expense — — — 96 — 51 — 171 — 1 10 371 — 205 — 421 — — Depletion, depreciation, amortization and accretion 7,865 9,673 9,217 13,968 12,838 13,307 13,021 19,876 15,195 12,549 10,718 8,607 12,142 12,551 15,929 12,235 15,563 19,464 EBITDAX 16,016 9,527 35,205 58,919 16,840 (12,581) 31,428 5,700 4,227 (365) 8,497 (2,258) 21,827 (13,794) 10,415 (7,297) 5,039 5,339 Rig standby expense (2) — — — — — — 10 653 313 1,584 364 — — — 61 561 — — Non-recurring costs (3) 501 612 449 138 — 19 25 1,182 323 321 607 308 — 3,127 337 175 — — Stock-based compensation 448 886 627 (23) 433 433 880 839 95 95 122 135 178 461 346 644 450 2,281 (Gain) loss on sale of oil and gas properties — — — — — — — — — (1,531) 53 1,404 142 205 119 — — — Impairment of oil and gas properties — — — 5,478 — 19,328 — 9,295 — 1,938 29,144 2,811 — 27,081 — 6,332 — — Unrealized (gain) loss on derivative financial instruments 2,185 6,140 (12,954) (38,127) 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 Unrealized (gain) loss on warrants — — — — — — — — — — 611 (1,179) (2,270) (613) (402) 198 152 2,462 Office lease write-off — — — — — — — — — — — — — — — — 1,568 — Loss on extinguishment of debit — — — — — — — — — — — — — — — — 8,619 — Other (income) expense — (464) 44 365 663 (4) 18 389 206 819 (29,362) 1,118 (4) (46) (4) (9) (7) 232 Adjusted EBITDAX $19,150 $16,701 $23,371 $26,750 $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 (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
Lease Operating Expenses $10.00 $7.5 $8.00 $6.0 Operating Expenses($MM) Lease $6.00 $4.5 $4.00 $3.0 Lease Operating Expenses Expenses OperatingLeasePer BOE $2.00 $1.5 $0.00 $0.0 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Compression Chemicals Saltwater Disposal Field Personnel Labor Regulatory, Legal, Insurance Roads & Location Workover & Repairs Direct Well Costs Reported LOE ($MM) 16
Financial Statistics & Guidance Quarterly Production – Total Company Quarterly Production – Total Company 12,000 12,000 10,000 10,000 8,000 8,000 6,000 6,000 4,000 4,000 Production Production (Boe/d) 2,000 2,000 Production (Boe/d) 0 - Crude Oil Natural Gas Liquids Natural Gas Western EFS Central EFS Eastern EFS Conventional Adjusted EBITDAX1 ($MM) Net Income ($MM) $30 $30 $30 $20 $20 $25 $10 $10 $0 $0 $20 -$10 -$10 -$20 -$20 $15 -$30 -$30 -$40 -$40 $10 NetIncome ($MM) -$50 -$50 $5 -$60 -$60 Quarterly Quarterly EBITDAX ($MM) -$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 17
Quarterly Production Summary Quarterly Production – Total Eagle Ford Quarterly Production – Western Eagle Ford 12,000 200 7,000 60 180 6,000 10,000 160 50 140 5,000 8,000 40 120 4,000 6,000 100 30 80 3,000 4,000 20 60 2,000 Production Production (Boe/d) Production Production (Boe/d) 40 Eagle Ford Well Count 2,000 10 Eagle Ford Well Count 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 6,000 120 1,500 12 5,000 100 1,200 10 4,000 80 8 900 3,000 60 6 600 2,000 40 4 Production Production (Boe/d) Eagle Eagle Ford Well Count Production Production (Boe/d) 300 1,000 20 Eagle Ford Well Count 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 18
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 93% of Bal ‘ 18 and 64% of Cal ‘19 analysts’ consensus forecast oil production. Crude Oil- WTI Hedge Summary Hedge Book at June 30, 2018 % of Period Instrument Volume Fixed Price 1 Production 64% 85% ~69% ~93% ~63%1 ~22%1 Hedged 8,000 $90 Bal ‘18 Oil – WTI Swap 1,000 bbls/day $54.18 7,189 7,000 $80 $52.50 Bal ‘18 Oil – WTI Swap 500 bbls/day $55.65 $70 6,000 5,430 Bal ‘18 Oil – WTI Swap 500 bbls/day $55.50 $60 5,000 $50 Bal ‘18 Oil – WTI Swap 800 bbls/day $47.10 4,000 3,213 $55.00 $40 $Bbl / 3,000 2,753 $56.66 Bal ‘18 Oil- WTI Swap 1,684 bbls/day $50.17 2,698 $51.21 2,181 $30 Volume Volume Hedged (bopd) 2,000 $53.36 Bal ‘18 Oil – 2 way 500 bbls/day $50.00/$59.45 $71.02 $20 $85.76 Collar 1,000 $53.02 $10 Bal ‘18 Oil- WTI Swap 826 bbls/day $60.97 0 $0 2015 2016 2017 2018 2019 2020 Bal ’18 Oil-WTI Swap 1,377 bbls/day $69.15 Volume Hedged At YE-17 Weighted Average Hedge Price Cal ’19 Oil- WTI Swap 1536 bbls/day $48.04 Hedges added after 2Q18 Weighted Average Price with hedges added during 2Q18 Cal ’19 Oil –WTI Swap 1394 bbls/day $50.40 2018 Hedging Volumes from July – December 2018 Cal ’19 Oil-WTI Swap 11100 bbls/day $50.90 Hedges Added Subsequent to 2Q18 Cal ’19 Oil-WTI Swap 900 bbls/day $58.25 Period Instrument Volume Fixed Price Cal ’20 Oil-WTI Swap 556 bbls/day $48.90 Cal ’19 Oil – WTI Swap 500 bbls/day $65.20 Cal ‘20 Oil – WTI Swap 500 bbls/day $61.65 Cal ’20 Oil-WTI Swap 1124 bbls/day $55.06 19 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. 20