Lonestar Announces Second Quarter 2019 Financial Results And Increases 2019 Guidance

Lonestar Resources US Inc. (NASDAQ: LONE) (including its subsidiaries, “Lonestar,” “we,” “us,” “our” or the “Company”) today reported financial and operating results for the three months ended June 30, 2019.

HIGHLIGHTS

• Production Increases 22%- Lonestar reported a 22% increase in net oil and gas production to 13,630 BOE/d during the three months ended June 30, 2019 (“2Q19”), compared to 11,140 BOE/d for the three months ended June 30, 2018 (“2Q18”). Reported production volumes exceeded the Company’s guidance of 12,400 - 12,800 BOE/d and also exceeded our preliminary estimated result of 13,500 Boe/d announced on July 8, 2019. Production was comprised of 78% crude oil and NGL’s on an equivalent basis. As Lonestar brings new wells onstream at rates that exceed third-party type curves, production continues to climb rapidly. For the month of July, net oil and gas production exceeded 16,000 BOE/d.
• Outstanding Drilling Results- Lonestar’s 2019 drilling program continues to deliver outstanding results. In Karnes County, our Georg 3H-6H wells, which delivered average Max-30 IP’s of 1,045 BOE/d, are outperforming our third-party type curves by 19%. At Horned Frog, the F #A1H and F #B1H wells delivered average Max-30 IP’s of nearly 2,500 BOE/d, a record for the Company. Additionally, the Horned Frog NW #4H and #5H have produced an average of 114,000 BOE through their first 90 days of production, a 27% improvement over their offsets over the same time period. Our first three wells in DeWitt County have recently been placed on production on our Sooner property and are averaging over 3,460 BOE/d per well (53% liquids) in their first week of production.
• Net Income Rises- Lonestar reported net income attributable to its common stockholders of $11.2 million during 2Q19 compared to a net loss of $23.5 million during 2Q18, or a net income of $0.28 and a net loss of $0.96 per basic and diluted share, respectively.
• EBITDAX Increases 15%- Lonestar reported a 15% increase in Adjusted EBITDAX for 2Q19 of $33.5 million compared to $29.2 million for 2Q18. This improvement was driven by a 22% increase in production, partially offset by a 2% increase in unit cash operating expenses. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net loss to Adjusted EBITDAX, and the reasons for its use.
• Robust Hedging Program- Lonestar continues to utilize commodity derivatives to create a higher degree of certainty in our cash flows and returns while mitigating financial risk. During 2Q19, Lonestar added hedges which bring total swap volumes to 7,305 Bbls/d for the remainder of 2019 (“Bal ‘19”) at an average WTI price of $54.60/bbl and added hedges which bring total swap volumes to 7,480 bbls/d for Cal ‘20 at an average WTI price of $56.95/bbl, and 3,000 Bbls/d for Cal ’21 at an average WTI price of $54.68/bbl. Additionally, Lonestar has LLS/WTI Basis Swaps covering 6,000 bbls/d at a weighted-average price of $5.05/bbl for Cal ‘19. By locking in these swaps, it should allow the Company to realize a premium to WTI after marketing, regardless of market conditions. Lonestar also has Henry Hub natural gas swaps covering 15,000 Mcf/d at a weighted-average price of $2.82 per MMBTU for Bal ’19 and added 15,000 Mcf/d of Henry Hub natural gas swaps for Cal ’20 at an average price of $2.59 per MMBTU, further insulating Lonestar from fluctuations in the commodity markets.
• 2019 And 2020 Guidance Increased- Given its outstanding drilling and completion results, deep drilling inventory and strong hedging position, Lonestar has materially enhanced its financial outlook. For 2019, production guidance was increased from 13,700-14,700 BOE/d to 14,800-15,000 BOE/d, and guides to $135-$140 million of EBITDAX. For 2020, Lonestar now believes it can achieve its previously issued production target of 17,000-18,300 BOE/d while drilling 20-25% fewer wells in 2020, and therefore, materially less capital. Lonestar’s 2020 target yields a range of cash flow outcomes that generates $5-$20 million of free cash flow.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, commented, "Our technologically focused smart completions continue to deliver differential results that exceed our third-party type curves and our budget. In the second quarter, those well results are beginning to show up in our financial results. The third quarter is set to deliver even more impressive results, with July’s production having exceeded 16,000 BOE/d, as our new Horned Frog and Sooner wells are delivering impressive daily rates and were placed onstream ahead of schedule. Looking ahead, we see record production results in the third and fourth quarters of 2019, and strong growth in EBITDAX. Given the progress we made in 2019 we have the potential to achieve our previously issued production targets while drilling 20-25% fewer wells. With production anticipated to rise 19% and generate a substantial increase in EBITDAX, free cash flow generation of $5-$20 million is on the horizon. We have positioned Lonestar to thrive in the current environment and continue to build shareholder value.”

OPERATIONAL UPDATE

• Lonestar reported net oil and gas production of 13,630 BOE/d during the three months ended June 30, 2019, an increase of 20% sequentially compared to 11,372 BOE/d during 1Q19. 2Q19 production volumes consisted of 7,795 barrels of oil per day (57%), 2,901 barrels of NGLs per day (21%), and 17,601 Mcf of natural gas per day (22%).
• Lonestar’s Eagle Ford Shale assets continued to deliver outstanding wellhead realizations in 2Q19. Lonestar’s wellhead crude oil price realization was $63.05/bbl, which reflects a premium of $3.24/bbl vs. West Texas Intermediate. Lonestar’s realized NGL price was $13.44/bbl, or 22% of WTI. This was largely driven by a drop in Ethane which fell as much as 47% from 1Q19 prices and Propane and other heavy liquids pricing which fell as much as 38% from 1Q19 prices. Lonestar’s realized wellhead natural gas price was $2.46 per Mcf, reflecting a $0.10 discount to Henry Hub. This discount to Henry Hub was largely driven by increase in gas sales at the end of the quarter with the additions of the new Horned Frog F #A1H and #B1H when the gas prices were at their lowest levels in the quarter.
• Operating revenues increased sequentially by $11.5 million to $52.2 million, or 28%, compared to 1Q19, primarily driven by a 20% increase in production coupled with a 6% increase in commodity price realizations.
• Total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administrative, and interest expenses were $25.3 million for 2Q19. While 2Q19 cash operating costs rose 9% compared to $23.3 million in 1Q19, strong volume growth yielded a 10% reduction on a per-unit basis to $20.43 per BOE in 2Q19.
  • Lease Operating Expenses (“LOE”), excluding rig standby costs of $0.3 million, were $7.9 million for 2Q19, which was 17% higher than LOE of $6.7 million in 1Q19. However, on a unit-of-production basis, LOE per BOE were reduced 3% sequentially to $6.35 per in 2Q19.
  • Gathering, Processing & Transportation Expenses (“GP&T”) for 2Q19 were $0.7 million, which was 15% lower than the GP&T of $0.9 million in the three months ended 1Q19. On a unit-of-production basis, GP&T decreased 30% sequentially from $0.86 per BOE in 1Q19 to $0.60 per BOE in 2Q19.
  • Production taxes for 2Q19 were $2.8 million, which was 23% higher than production taxes of $2.3 million in 1Q19. On a unit-of-production basis, production taxes increased 2% sequentially from $2.24 in 1Q19 to $2.27 per BOE in 2Q19.
  • General & Administrative Expenses (“G&A”) in 2Q19 were $3.8 million vs. $4.4 million in 1Q19. G&A Expenses, excluding stock-based compensation of $0.9 million in 1Q19 and $0.1 million in 2Q19, increased from $3.5 million to $3.7 million, respectively. However, on a unit-of-production basis, G&A per BOE decreased 10% sequentially from $3.37 per BOE in 1Q19 to $3.02 per BOE in 2Q19.
  • Interest Expense was $10.8 million for 2Q19 vs. $10.7 million for 1Q19. Interest Expense excluding amortization of debt issuance cost, premiums, and discounts, increased 2% sequentially from $10.0 million in 1Q19 to $10.2 million in 2Q19. Lonestar’s robust production growth generated a 16% sequential decrease in Interest Expense per BOE, from $9.73 per BOE in 1Q19 to $8.19 per BOE in 2Q19.

GUIDANCE

• 2019 Activity- The Company has executed on its 2019 drilling plan with great success through the first six months. By mid-year, Lonestar had placed 11 of its planned 20 wells into production and had concluded drilling operations on its 3 Sooner wells, which commenced flowback operations in July. Despite fluctuations in oil and gas prices over the quarter, Lonestar expects little impact to guidance for the remainder of the year as the Company has hedged 89% of oil at $54.60/bbl and approximately 50% of gas as an average price of $2.83 per MMBTU. Lonestar anticipates placing 3 gross / 3.0 net wells online during 3Q19. In July, these 3 gross / 3.0 net wells at Sooner were placed into flowback. Lonestar recently completed drilling operations on 1 gross / 0.5 net wells in Brazos County with a projected completion interval of 10,000’, which it anticipates bringing online in September. The Company has recently finished drilling operations on 2 gross / 2.0 net wells on its Marquis property. These two wells are anticipated to begin flowback operations in October 2019.
• 3Q19 Production- Based on the continued success of its 2019 capital program, Lonestar issued production guidance of 17,000 to 17,500 BOE/d for the third quarter of 2019, a 27% increase over 2Q19 results at the midpoint. The primary sources for production growth in the third quarter of 2019 will be a full quarter’s contribution from its 2 gross / 2.0 net wells at Horned Frog that began flowback in June, and partial contribution from 3 gross / 3.0 net wells at Sooner, which commenced flowback in late July.
• 3Q19 EBITDAX- Lonestar issued Adjusted EBITDAX guidance of $36.0 to $37.5 million for the third quarter of 2019, a 9% sequential increase over 2Q19 results. During the quarter, the Company anticipates oil realizations of +$2.00/bbl to WTI, NGL realizations which are 25% of WTI, and gas price realizations of -$0.10/Mcf to Henry Hub, and lease operating expenses of $5.35-$5.45/BOE.
• 2019 Production- In aggregate, Lonestar’s completion results have been outperforming their third-party type curves, which is the basis for Lonestar’s budget and guidance. While the Company still only plans to drill 20 gross wells in 2019, visibility on production is sufficiently positive that it is raising its 2019 production guidance from 13,700-14,700 BOE/d to 14,800-15,000 BOE/d.
• 2020 Targets- Previously, as part of its two-year forecasts and based on drilling 20 wells in 2020, Lonestar provided a 2020 production target of 17,000-18,300 BOE/d, which equates to production growth of 19% over its increased 2019 guidance (at their midpoints). Based on the production outperformance associated with the 2019 capital program and our current plans to focus our 2020 capital plan at Horned Frog, Karnes County, Cyclone/Hawkeye and Sooner, Lonestar reiterates its 2020 production target of 17,000-18,300 Boe/d, but now believes that this target can be achieved with fewer wells and less capital spending. Lonestar believes that it can achieve its 2020 production target by drilling and completing 15-16 wells at a cost of $115 to $120 million. At assumed pricing of $55.00 per barrel for West Texas Intermediate crude oil and $2.50 per MMBTU for Henry Hub natural gas prices, Lonestar’s EBITDAX target is $165-$185 million. Lonestar’s 2020 target yields a range of cash flow outcomes that generates $5-$20 million of free cash flow.

EAGLE FORD SHALE TREND - WESTERN REGION

In our Western Region, production for 2Q19 averaged approximately 7,717 BOE per day, a 24% sequential increase in production. This region accounted for 57% of the Company’s production during the quarter. During the second quarter, Lonestar placed 2 wells onstream at both its Horned Frog and Horned Frog NW properties, respectively, where it has some of the highest internal rates of return (“IRR”) in the Company’s asset base.

In April, Lonestar began flowback operations on 2 gross / 2.0 net wells, the Horned Frog NW #4H and #5H. These wells recorded Max-30 production rates of 1,453 BOE/d, within 1% of their direct offsets on a per foot basis. Now, through the first 90 days, these wells have produced an average of 114,000 BOE, which is 2% better than the parent wells drilled in 2018 and 5% better than the third-party type curve. The Company holds a 100% working interest (“WI”) / 75% net revenue interest (“NRI”) in these wells.

In June, the Company began flowback operations on a second pair of wells in its Western Region. At Horned Frog South, Lonestar previously announced initial test results averaging 2,497 BOE/d. These new wells have since cleaned up after flowback and registered the following maximum rates over a 30-day period (“Max-30” rates) which average 2,493 BOE/d:

• Horned Frog F #A1H – With a 12,461’ perforated interval, the F #A1H recorded a Max-30 production rate of 549 Bbls/d oil, 674 Bbls/d of NGLs, 7,283 Mcf/d, or 2,436 BOE/d on a three-stream basis.
• Horned Frog F #B1H – With a 12,170 perforated interval, the F #B1H recorded a Max-30 production rate of 578 Bbls/d oil, 704 Bbls/d of NGLs, 7,605 Mcf/d, or 2,550 BOE/d on a three-stream basis.

Lonestar’s newest wells on its 4,975-acre Horned Frog South property represent continued progress in the advancement of its Geo-Engineered completion practices. On a per-foot basis through the first 30-days, our 2019 wells have recorded production rates that are 20% higher than our initial pad at Horned Frog, the Horned Frog #A1H and #B1H (completed in 2015) and 7% higher than our most recent Horned Frog wells, the Horned Frog #G1H and Horned Frog #H1H (completed in 2018). Our 2019 Horned Frog wells recorded Max-30 day rates that eclipsed 200 BOE/d per-foot, and importantly, are registering oil production rates that are 17% better than our 2018 completions, on a per-foot basis. Lastly, to date, our 2019 Horned Frog completions are outperforming the projections of our third-party engineers by 25% thus far. Lonestar holds a 100% WI / 78% NRI in these wells.

EAGLE FORD SHALE TREND - CENTRAL REGION

In our Central Region, 2Q19 production averaged approximately 5,652 BOE/d, a 69% increase over 1Q19 rates. The Company’s second quarter results were positively impacted by 4 gross / 3.2 net wells placed onstream in Karnes County. The Company’s third quarter results will be positively impacted by 3 gross / 3.0 net wells it has recently placed onstream on its Sooner property in DeWitt County.

In May 2019, the Company began flowback operations on the Georg #3H, Georg #4H, Georg #5H, and Georg #6H. These wells have some of the highest oil profiles (87%) in the Company’s portfolio and have registered the following Max-30 rates:

• Georg #3H – 7,156’ perforated interval, 893 Bbls/d oil, 70 Bbls/d of NGLs, 369 Mcf/d, or 1,025 BOE/d (three-stream) on a 32/64” choke.
• Georg #4H – 7,230’ perforated interval, 804 Bbls/d oil, 62 Bbls/d of NGLs, 325 Mcf/d, or 920 BOE/d (three-stream) on a 32/64” choke.
• Georg #5H – 7,227’ perforated interval, 881 Bbls/d oil, 68 Bbls/d of NGLs, 359 Mcf/d, or 1,009 BOE/d (three-stream) on a 32/64” choke.
• Georg #6H – 7,236’ perforated interval, 1,056 Bbls/d oil, 90 Bbls/d of NGLs, 474 Mcf/d, or 1,225 BOE/d (three-stream) on a 32/64” choke.

Our 2019 wells in Karnes County follow 6 wells we placed onstream in 2018, and the Company has been able to continue to improve on prior results. By acquiring offsetting acreage contiguous to our existing leasehold, Lonestar was able to increase lateral lengths by 18% compared to 2018 wells but continues to exhibit modestly better productivity on a per-foot basis through 60 days of production, yielding superior well economics. Our 2019 wells have outperformed the type curve by 19% thus far. Lonestar has an 80% WI / 61% NRI in these wells.

In late July, Lonestar began flowback operations on 3.0 gross / 3.0 net wells on its Sooner property, which was acquired in November 2018, known as the Buchhorn #4H, Buchhorn #5H, and Buchhorn #6H. These wells are the first wells Lonestar has drilled on its Sooner property and were drilled to total measured depths of 20,327’, 20,238’, and 20,260’, respectively. Lonestar fracture-stimulated these wells with an average proppant concentration of approximately 2,000 pounds per foot over 21 stages, using diverters. Test rates have averaged 3,460 BOE/d. Perforations and test rates for the wells are:

• Buchhorn #4H – 6,157 perforated feet tested 542 Bbls/d oil, 1,311 Bbls/d of NGLs, 9,857 Mcf/d, or 3,496 BOE/d (three-stream) on a 24/64” choke.
• Buchhorn #5H – 5,981 perforated feet tested 514 Bbls/d oil, 1,252 Bbls/d of NGLs, 9,407 Mcf/d, or 3,333 BOE/d (three-stream) on a 22/64” choke.
• Buchhorn #6H – 6,021 perforated feet tested 545 Bbls/d oil, 1,334 Bbls/d of NGLs, 10,023 Mcf/d, or 3,549 BOE/d (three-stream) on a 22/64” choke.

Lonestar has 100% WI / 78% NRI in these wells.

EAGLE FORD SHALE TREND - EASTERN REGION

In our Eastern Region, production for the second quarter of 2019 averaged approximately 261 BOE/d, a 24% decrease compared to 1Q19 rates. The Company did not complete any wells in this region in the second quarter. However, Lonestar recently completed drilling operations on the Smith Family Ranch #1H, reaching a total measured depth of 22,025 feet. Lonestar expects to complete the well with a perforated interval of approximately 10,300 feet, stimulate the well in August, and place this well into flowback operations in September 2019. Lonestar has a 50% WI / 38% NRI in the well. Lonestar has engaged Intrepid Financial Partners, LLC to represent the Company in marketing its Eagle Ford Shale assets in Brazos and Robertson Counties for sale, with a target of concluding a transaction before year-end.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Tuesday, August 6, 2019 at 9:00 AM CDT to discuss the second quarter 2019 results and operational highlights.

To access the conference call, participants should dial:

USA: 1-888-221-1875
International: +1-303-223-4396
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately August 7, 2019.

ABOUT LONESTAR RESOURCES US INC.

Lonestar is an independent oil and natural gas company, focused on the development, production, and acquisition of unconventional oil, NGLs, and natural gas properties in the Eagle Ford Shale in Texas, where we have accumulated approximately 72,178 gross (52,419 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of June 30, 2019. For more information, please visit www.lonestarresources.com.

CAUTIONARY & FORWARD-LOOKING STATEMENTS

Lonestar Resources US Inc. cautions that this press release contains forward-looking statements, including, but not limited to; Lonestar’s execution of its growth strategies; growth in Lonestar’s leasehold, reserves and asset value; and Lonestar’s ability to create shareholder value. 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 13, 2019, 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 press release represent our views as of the date of this press release. 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 press release.

NON-GAAP FINANCIAL MEASURES (Unaudited)

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 income (loss) before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, loss (gain) 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), 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 (loss) 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.

Adjusted Net Income (Loss)

Adjusted net income (loss) comparable to analysts’ estimates as set forth in this release represents income or loss from operations before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes. We believe adjusted net income (loss) is calculated on the same basis as analysts’ estimates and that many investors use this published research in making investment decisions and evaluating operational trends of the Company and its performance relative to other oil and gas producing companies. Diluted earnings per share (adjusted) as set forth in this release represents adjusted net income (loss) comparable to analysts’ estimates on a diluted per share basis.

The following table presents a reconciliation of Adjusted Net Income (Loss) to the GAAP financial measure of net income (loss) before taxes for each of the periods indicated.

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