Lonestar Resources US, Inc. Year Ended 2016 Conference Call. March 23, 2016

Transcription

1 Lonestar Resources US, Inc. Year Ended 216 Conference Call March 23, 216

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 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 Registration Statement on Form 1, as amended and filed with the Securities and Exchange Commission, or the SEC, on June 9, 216, 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 forwardlooking 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

3 4Q16 Headlines Back to Business 4Q16 Production Averaged 4,56 Boe/d No New Completions During 3Q16 & 4Q16 & Yields Volume Decrease 1Q16 Wells Beall Ranch (Dimmit) Onstream March, 216 (3. gross / 2.9 net wells) 2Q16 Wells Cyclone (Gonzales) Onstream May, 216 (2. gross /.8 net wells). Conventional Assets Sold Effective October 1, 216 Conventional production was 463 BOEPD in 3Q16 Balance Sheet Efforts Cut Debt 34%, Improves Liquidity Asset Sales, Debt Repurchases, Equity Raise Reduced Debt by $17.2 MM Long Term Debt Outstanding $212.3 MM at 12/31/16 Revolver Availability $68.5 MM Drilling & Production Momentum Building Production Running 5,5 Boe/d in Mar. 17 vs. 4,56 Boe/d in 4Q16 1Q17 Wells Burns Ranch 8/9/1H (LaSalle) Onstream Jan, 217 (3. gross / 2.9 net wells) 2Q17 Wells Wildcat B1H (Brazos) Onstream May, 217 (1. gross /.5 net wells) Cyclone 4&5 (Gonzales) Onstream June, 217 (2. gross / 1.7 net wells) 3Q17 Wells Cyclone 26&27 (Gonzales) Onstream Aug, 217 (2. gross / 2. net wells) Horned Frog C1&C2 (LaSalle) Onstream Sept, 217 (2. gross / 2. net wells) 4Q17 Wells Burns Ranch 8&9 (LaSalle) Onstream Nov, 217 (2. gross / 1.8 net wells) Production Guidance 4Q17 Up 65% to 85% over 4Q16 4Q16 Production by Product Product Crude Oil NGL s Oil 55% NGL's 2% Gas 25% Volume 2,457 bbl/d 984 bbl/d Capturing Organic Growth Opportunities Add 1,921 net acres with 6.7 MMBOE, up to 28 extended reach locations Cyclone (Gonzales) 526 net acres adds 2.1 MMBOE (9 gross / 8 net locations) Horned Frog (LaSalle) 1,71 net acres adds 4.2 MMBOE (7 11 gross / 5 8 net locations) Harvey Johnson (Gonzales) 324 net acres adds.4 MMBOE (8 gross / 4 net locations) Natural Gas Total 6,717 Mcf/d 4,56 Boe/d 3

4 Key Financial Highlights Production Growth Has Resumed Production was 4,56 Boe/d in 4Q16 Conventional assets sold produced 436 Boe/d in 3Q17 before sale Liquid hydrocarbon mix was 75% in 4Q16 March 217 Production averaged 5,5 Boe/d Increase of 21% over 4Q16 levels 4Q16 Daily Production Product Volume Crude Oil 2,457 bbl/d NGL s 984 bbl/d Natural Gas 6,717 Mcf/d Total 4,56 Boe/d Asset Sales, Debt Repurchases, Equity Offering Cut Debt Reduced long term debt by $17.2 million from peak Raised $75. MM in equity offering Raised $15.8 MM from Conventional Asset Sale Bought $68.2 MM (par) of 8 ¾% Sr. Unsecured Notes at a 49% discount At 12/31/16 $68.5 million available on Revolver Long Term Debt Outstanding (MM) Issue Dec Jun Sep Dec Revolver $87. $99.5 $94.5 $43.5 Second Lien $. $. $38. $17. Unsecured Notes $22. $22. $151.2 $151.8 Total Debt $37. $319.5 $283.7 $212.3 Oil & Gas Hedging Robust Price Protection Extensive Coverage in Crude Oil 2,877 $53.77 average 217 Natural Gas 7, $3.36 Solid Coverage in Crude Oil 2,5 $55.33 average Hedge Book at 3/23/17 Period Instrument Volume Fixed Price 217 Oil WTI Swap 1,877 bbls/day $ Oil 3Way Collar 1, bbls/day $4./$6./ $ Gas NYMEX Swap 7, mmbtu/day $ Oil WTI Swap 2, bbls/day $ Oil 2Way Collar 5 bbls/day $5./$

5 Gonzales County Expansion Cyclone Cyclone Area Summary Cyclone Leasehold Current In May, 216, LONE placed the Cyclone #9H & #1H wells (42% WI) onstream. The well pair has performed above our initial expectations. Our initial well results encouraged us to build a lease block at Cyclone, which at December 31, 216 totaled 2,96 gross / 2,656 net acres, setting up 26 additional laterals with an average lateral length exceeding 8, feet. Total leasehold cost $3.1 million. Lonestar plans to drill 4 wells at Cyclone in 2Q17 Cyclone #4H & 5H 86.5% WI / 68% NRI, 1, laterals Cyclone #26H & 27H 1% WI / 78.5% NRI, 9, laterals As of December 31, 216, LONE s third party engineers booked reserves at Cyclone: Proved 3.1 MMBOE from 2 PDP s & 8 PUDS s PV 1 $42.5 MM at 12/31/16 Strip Probable 5.5 MMBOE from 18 locations. PV 1 $65.5 MM at 12/31/16 Strip Lonestar has closed a series of bolt on acquisitions at Cyclone Acquisition Cost Leased 526 net acres for $.7 million Lateral Additions Adds 7 net laterals, increasing inventory from 26 to 33 Lonestar has a PSA to acquire a 33.5% WI in the Harvey Johnson Unit for $7.6 million PDP Reserves.4 MMBOE / 147 BOEPD production (85% crude oil) Drilling Potential 967 gross acres half undeveloped Cyclone Offset Wells Lower Eagle Ford Structure Map Cum vs. Time Cyclone Wells vs. Offsets 2 18 Harvey Johnson Cyclone Cyclone #9H #1H Cumulative Production (MBbls) Cyclone #9H #1H Months Deeper Shallower On Strike Cyclone 9H Cyclone 1H 5

6 LaSalle County Performance Update Burns Ranch Cum Oil (mbbls) Figure 1: Burns Ranch Production Comparisons Gen 5 Gen 3/4 Burns Ranch Area Summary In 3Q16, Lonestar drilled three extended reach laterals, achieving 97% faster drilling rates with its 216 wells vs. its 215 wells. 215 wells reached avg. TD of 16,617 in 24.3 days (683 ft/day) 216 wells reached avg. TD of 18,7 in 13.3 days (1,351 ft/day) Lonestar completed fracture stimulation operations on January 5, 217 Gen ft stage spacing / 1,567 lbs/ ft / geometric stages (#1H, #2H, #3H) Gen 4 3 ft stage spacing / 1,5 lb/ft / non geometric stages with diverters (#8H) Gen 5 3 ft stage spacing with BroadBand diverters / 2,2 lb/ft (#9H, #1H) Thus far, LONE s Gen 5 Completions Are Outperforming Older Completions Figure 1 Through 68 days of production, 8% higher cumulative production Days on Production Figure 2 Figure 3 Gen 5 wells Are Being More Aggressively Choke Managed Gen 5 3, bo at 966 GOR Gen 3 3, bo with 1,5 GOR, and increasing rapidly Gen 5 wells Are Achieving Higher Drainage Efficiencies Gen 5 3, bo with 3% drawdown Gen 3 15,9 bo with 3% drawdown Figure 2: Burns Ranch Cum Oil vs. GOR Figure 3: Burns Ranch Cum Oil vs. Pressure Drawdown 2,5 7% GOR (scf/bbl) 2, 1,5 1, 5 Gen 5 Gen 3/4 % Pressure Drawdown 6% 5% 4% 3% 2% 1% Gen 5 Gen 3/ Cum Oil (mbbbls) % Cum OIl (mbbls) 6

7 Current Leasehold With Recent Acquisitions Central Cyclone Western Pirate Burns Ranch Beall Ranch Asherton Horned Frog 7

8 Lonestar Resources US, Inc. Appendix

9 Geo Engineered Completion Alliance Integrated Approach to Drilling, Completion, Stimulation & Production of Eagle Ford Laterals Technical Process Vertical Pilot Logs Used To Select Geo target to Optimize Both Reservoir & Mechanical Properties Reservoir Properties Porosity, Total Organic Content, Clay Volume Mechanical Properties Young s Modulus, Poisson s Ratio, Minimum In situ Stress Results of Analysis Determine Geosteering Target Azimuthal Gamma Ray LWD Tool to Assist in Geosteering Multi planar Gamma ray data determines dip angle and direction in real time Lateral Thru Bit Logs Run to TD for Detailed Rock Properties Analysis Triple Combo Log with Spectral Gamma Ray and Dipole Sonic Logs Mangrove Stimulation Design Utilize Thru Bit Log Data For Reservoir Characterization Models Key Mechanical Properties To Optimize Stimulation Vertical and lateral rock heterogeneity Planar and Non planar fractures Account for multi well stress shadows to optimize zipper fracs Facilitates Design of Engineered (Non Geometric) Completion Broadband TM Sequence Diverter Engineered fibrous pill designed to create near wellbore isolation to augment frac efficacy across all perforations, maximizing wellbore coverage Increase efficiency through fewer pumped stages, coiled tubing plug drill outs Engineered Flowback Analysis Lonestar has been a longstanding proponent of controlled flowbacks Implement SLB solids and fluids analysis to avoid negative impact of hydraulic fractures and assess success of completion strategies Application Experience Horned Frog Beall Ranch New to Lonestar Horned Frog Beall Ranch Horned Frog Beall Ranch New to Lonestar New to Lonestar 9

10 Quarterly Financial Summary Quarterly Production Total Company Quarterly Production Total Company Production (Boe/d) 8, 7, 6, 5, 4, 3, 2, 1, Production (Boe/d) 8, 7, 6, 5, 4, 3, 2, 1, 1Q13 2Q13 3Q13 4Q13 1Q14 2Q143Q144Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q164Q16 Crude Oil Natural Gas Liquids Natural Gas Adjusted EBITDAX 1 Western EFS Central EFS Eastern EFS Conventional Barnett Shale Net Income Quarterly EBITDAX ($MM) $3 $25 $2 $15 $1 $5 $ Net Income ($MM) $3 $2 $1 $ $1 $2 $3 $4 $5 $6 $7 $3 $2 $1 $ $1 $2 $3 $4 $5 $6 $7 Net Income ($MM) Net Income One time charges Note- All 213, 214, 215 and 216 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. 2 One-time charges totaling $5.8 million; $1.2 million non-cash, hedge mark-to-market,$2.8 million impairment for lease expirations, $37.8 tax expense triggered by change in ownership 1

11 Quarterly Production Summary Quarterly Production Total Eagle Ford Quarterly Production Western Eagle Ford 8, 8 6, 45 Production (Boe/d) 7, 6, 5, 4, 3, 2, 1, Eagle Ford Well Count Production (Boe/d) 5, 4, 3, 2, 1, Eagle Ford Well Count Crude Oil Natural Gas Liquids Natural Gas EF Wells Crude Oil Natural Gas Liquids Natural Gas EF Wells Quarterly Production Central Eagle Ford Quarterly Production Eastern Eagle Ford 1,4 21 1,2 12 Production (Boe/d) 1,2 1, Eagle Ford Well Count Production (Boe/d) 1, Eagle Ford Well Count Crude Oil Natural Gas Liquids Natural Gas EF Wells Crude Oil Natural Gas Liquids Natural Gas EF Wells 11

12 Lonestar Eagle Ford Shale Operating Expenses $12. $5. $4.5 Reported Lease Operating Expenses Per BOE $1. $8. $6. $4. $2. $4. $3.5 $3. $2.5 $2. $1.5 $1. $.5 Reported Lease Operating Expenses ($MM) $. 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 Compression & Gas Gathering Chemicals Saltwater Disposal Field Personnel Labor Regulatory, Legal, Insurance Roads & Location Workover & Repairs Direct Well Costs Transportation Expense Reported LOE ($MM) $. 12

13 Non GAAP Reconciliation Reconciliation of Non GAAP Financial Measures Adjusted EBITDAX 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. ($ in thousands) 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 Net Income (Loss) $ 2,974 $ 2,85 $ 1,572 $ 5,289 $ 5,45 $ (6,976) $ 19,132 $ 19,265 $ (725) $ (2,883) $ 7,381 $ (13,16) $ (11,296) $ (12,844) $ (11,26) $ (58,935) Income tax expense (benefit) 15 (4,88) 22 (883) 1,553 (511) 1,58 19,882 (1,12) (11,28) 4,36 (7,333) (5,795) (6,245) 1,684 37,759 Interest expense ,118 1,314 1,553 7,341 5,348 5,78 5,847 5,972 6,666 6,92 6,124 6,174 7,345 9,939 Exploration expense Depletion, depreciation, amortization and accretion 5,471 5,981 7,767 9,61 7,865 9,673 9,217 13,968 12,838 13,37 13,21 19,876 15,195 12,549 1,718 8,67 EBITDAX 8,951 23,519 1,479 14,781 16,16 9,527 35,25 58,919 16,84 (12,581) 31,428 5,7 4,228 (365) 8,497 (2,259) Rig Standby Expense (1) , Non-recurring costs , Stock based compensation , (23) (Gain) loss on sale of properties (1,58) 1,58 (1,531) 53 1,44 Impairment of oil and gas properties 2,762 5,478 19,328 9,295 1,938 29,144 2,811 Unrealized (gain) loss on derivative financial instruments (293) (2,162) 4,538 (1,91) 2,185 6,14 (12,954) (38,127) 3,768 14,98 (1,668) 72 8,429 13,176 4,6 1,163 Unrealized (gain) loss on warrants 611 (1,179) Other (income) expense (2) (9) (149) (1,52) (464) (4) (29,362) 1,119 Adjusted EBITDAX $ 8,819 $ 11,398 $ 15,37 $ 17,815 $ 19,15 $ 16,71 $ 23,371 $ 26,75 $ 21,74 $ 22,13 $ 21,693 $ 18,778 $ 13,593 $ 16,37 $ 14,636 $ 12,52 (1) Represents a non recurring cost associated with a rig contract that expired in July 216. (2) Non recurring costs consist of General and Administrative Expenses related to the re domiciliation to the NASDAQ. (3) For 3Q16, this represents a gain on disposal of bonds due to repurchase at a discount. 13

14 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, 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. 14