Lonestar Announces First Quarter 2020 Results

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 March 31, 2020.

HIGHLIGHTS

• Lonestar reported a 27% increase in net oil and gas production to 14,436 BOE/d during the three months ended March 31, 2020 ("1Q20"), compared to 11,372 BOE/d for the three months ended March 31, 2019 ("1Q19"). Production was comprised of 73% crude oil and NGLs on an equivalent basis.
• On February 26^th, Lonestar announced that it entered into a Joint Development Agreement ("JDA") in Gonzales County with one of the largest producers in the Eagle Ford Shale which encompasses an Area of Mutual Interest ("AMI") totaling approximately 15,000 acres. The JDA allows for the two companies to consolidate their respective positions into a single development plan which should: 1) maximize lateral lengths; 2) optimize economic returns; and 3) efficiently HBP the combined leasehold with the fewest number of wells. Furthermore, the JDA will allow Lonestar to increase its inventory of gross drilling locations by roughly 50% in the Hawkeye area to a total of 32. Lonestar has completed its first 3 wells on the JDA leasehold and these wells have set records as the largest oil producers in the Company's history.
• Lonestar reported a net loss attributable to its common stockholders of $113.0 million during 1Q20 compared to a net loss of $60.6 million during 1Q19. Excluding, on a tax-adjusted basis, certain items that the Company does not view as either recurring or indicative of its ongoing financial performance, Lonestar's adjusted net loss for 1Q20 was $7.8 million. Most notable among these items include: a $93.0 million unrealized hedging gain on financial derivatives (?mark-to-market') and a $199.9 million impairment. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted Net Income (Loss), a reconciliation of net income (loss) before taxes to Adjusted Net Income (Loss), and the reasons for its use.
• Lonestar reported Adjusted EBITDAX for 1Q20 of $28.9 million. On a year-over-year basis, Adjusted EBITDAX increased 7%, as the Company placed 5 gross / 5.0 net wells onstream in 1Q20 while placing 3 gross / 3.0 net wells onstream in 1Q19. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net (loss) income attributable to common stockholders to Adjusted EBITDAX, and the reasons for its use.
• Lonestar continues to utilize commodity derivatives to create a higher degree of certainty in our cash flows and returns while mitigating financial risk. Lonestar has crude swap volumes of 7,565 Bbls/d for Bal '20, at an average WTI price of $57.38/bbl, and 7,000 Bbls/d for Cal ?21 at an average WTI price of $50.40/bbl. In most capital spending scenarios, our crude oil hedges cover all of oil production for Bal ?20 and Cal ?21. Lonestar also has Henry Hub natural gas swaps covering 20,000 MMBTU/d at a weighted-average price of $2.55 per MMBTU for Bal ?20, and 27,500 MMBTU/d at a weighted-average price of $2.36 per MMBTU for Cal '21, which cover substantial portions of our anticipated production. Notably, all of the Company's current hedges are swaps. Lonestar's hedge book significantly insulates our future production from fluctuations in the commodity markets. At the end of the quarter, the mark-to-market of Lonestar's hedge book is approximately $93 million and is a significant financial and strategic asset for the Company.
• Highly volatile oil and gas pricing experienced during the second quarter of 2020 has dictated unprecedented actions by the industry, and Lonestar is no exception. During April, prices were attractive and Lonestar sold its full deliverability. In May, oil pricing was extremely volatile. At the wellhead, prices started the month at approximately $5.00/bbl, ended the month at approximately $20.00/bbl, and averaged approximately $15.00/bbl. Based on this price action, Lonestar elected to shut-in virtually all of its crude oil production in the month of May. By contrast, Lonestar's properties in the Condensate Window offered favorable cash flow and profitability, and the Company elected to sell gas and NGLs in May, while storing all of its condensate in frac tanks in anticipation of improved pricing in June. Lonestar estimates that it sold 50% of its deliverability in May. With oil prices essentially doubling in June, Lonestar is again selling it full deliverability, including the condensate it stored during May, and did so at twice the price it would have received in May. Lonestar estimates that second quarter sales will range between 13,300 and 13,700 Boe/d, while current production rates are averaging 16,500 Boe/d.
• Based on current market conditions, Lonestar has updated its 2020 guidance. Currently, Lonestar plans to spend a range of $55 to $65 million in 2020, a reduction of as much as 27% versus the midpoint of our prior guidance. This capital program will allow for the drilling of 10 gross/ 7.0 net wells and the completion of a range of 10 gross / 8.5 net wells. Based on this range of capital spending, Lonestar is issuing updated 2020 production guidance of 13,500 to 14,000 Boe/d. Current NYMEX futures strip indicates an average West Texas Intermediate oil price of $35.00 per barrel and an average Henry Hub gas price of approximately $2.00 for 2020. Based on these prices, in combination with the Company's hedge position, Lonestar is issuing Adjusted EBITDAX guidance for 2020 of $115 to $120 million.

OPERATIONAL UPDATE

• Production- Lonestar reported net oil and gas production of 14,436 BOE/d during the three months ended March 31, 2020, representing a 27% increase year-over-year. 1Q20 production volumes consisted of 7,236 barrels of oil per day (50%), 3,335 barrels of NGLs per day (23%), and 23,191 Mcf of natural gas per day (27%). Notably, Lonestar generated increased volumes among all three hydrocarbon products sold.
• Pricing- Lonestar's Eagle Ford Shale assets continued to deliver favorable wellhead realizations in 1Q20. Lonestar's wellhead crude oil price realization was $45.54/bbl, which reflects a discount of $0.03/bbl vs. West Texas Intermediate. Lonestar's realized NGL price was $8.56/bbl, or 19% of WTI. Lonestar's realized wellhead natural gas price was $2.09 per Mcf, reflecting a $0.18 premium to Henry Hub.
• Revenues- Wellhead revenues fell by $3.7 million to $37.0 million, or 9%, compared to 1Q19, primarily driven by a 20% decrease in oil price realizations, a 45% decrease in NGL price realizations and a 28% decrease in natural gas price realizations.
• Expenses- Combined with the Company's efforts to reduce costs among all of its vendors and service providers, Lonestar's ramp-up in production has generated a powerful reduction in its cash unit-cost structure. Total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administrative, and interest expenses were $27.7 million for 1Q20. 1Q20 cash operating costs rose 18% compared to $23.4 million in 1Q19, but were reduced by 8% per unit of production.
  • Lease Operating Expenses ("LOE") were $7.6 million for 1Q20, which was 12% higher than LOE of $6.8 million in 1Q19. However, on a unit-of-production basis, LOE per BOE were decreased 13% year over year to $5.81 per BOE in 1Q20.
  • Gathering, Processing & Transportation Expenses ("GP&T") for 1Q20 were $2.2 million, which was 145% higher than the GP&T of $0.9 million in the three months ended 1Q19. On a unit-of-production basis, GP&T increased 91% year over year from $0.86 per BOE in 1Q19 to $1.64 per BOE in 1Q20, in proportion with higher gas sales.
  • Production and ad valorem taxes for 1Q20 were $2.4 million, which was in line with production taxes of $2.3 million in 1Q19. On a unit-of-production basis, production and ad valorem taxes decreased 19% year over year from $2.24 per BOE in 1Q19 to $1.80 per BOE in 1Q20.
  • General & Administrative Expenses ("G&A") in 1Q20 were $2.9 million vs. $4.4 million in 1Q19. G&A Expenses, excluding stock-based compensation of $0.9 million in 1Q19 and ($1.8) million in 1Q20, increased from $3.5 million to $4.7 million, respectively. Excluding stock-based compensation, on a unit-of-production basis, G&A per BOE increased 6% year over year from $3.37 per BOE in 1Q19 to $3.56 per BOE in 1Q20.
  • Interest expense was $11.6 million for 1Q20 vs. $10.7 million for 1Q19. Interest expense excluding amortization of debt issuance cost, premiums, and discounts increased 9% year over year from $10.0 million in 1Q19 to $10.8 million in 1Q20. On a unit-of-production basis, interest expense per BOE decreased 15% from $9.73 per BOE in 1Q19 to $8.25 per BOE in 1Q20.

EAGLE FORD SHALE TREND - WESTERN REGION

In our Western Region, production for 1Q20 averaged approximately 6,869 BOE per day, a 20% increase from 1Q19 production. The increase in production is associated with new completions at Horned Frog and Beall Ranch. Production consisted of 2,350 barrels of oil per day (34%), 1,943 barrels of NGLs per day (28%) and 15,458 Mcf of natural gas per day (38%). The Western region accounted for 48% of the Company's production during the quarter.

In March, Lonestar began flowback operations on 2.0 gross / 2.0 net wells on its Horned Frog property, the Horned Frog AE A2H and Horned Frog AE B3H. Lonestar has a 100% WI / 78% NRI in these wells. These new wells have since cleaned up after flowback and registered the following Max-30 rates which average 1,761 BOE/d. Production was comprised of 53% crude oil and NGLs on an equivalent basis which is the highest liquid concentration to date at our Horned Frog Proper location.

• Horned Frog AE A2H ? With a 12,460' perforated interval, the #A2H recorded Max-30 rates of 480 Bbls/d oil, 450 Bbls/d of NGLs, and 4,822 Mcf/d, or 1,733 BOE/d on a three-stream basis.
• Horned Frog AE B3H ? With a 12,170' perforated interval, the #A2H recorded Max-30 rates of 473 Bbls/d oil, 472 Bbls/d of NGLs, and 5,059 Mcf/d, or 1,788 BOE/d on a three-stream basis.

Also in March, Lonestar commenced flowback operations on 2.0 gross / 2.0 net wells on its Beall Ranch property, the Beall Ranch #14H and #15H. Lonestar has a 98% WI / 73% NRI in these wells. These new wells have since cleaned up after flowback and registered the following Max-30 rates which average 711 BOE/d:

• Beall Ranch #14H ? With a 9,027' perforated interval, the #A2H recorded Max-30 rates of 598 Bbls/d oil, 34 Bbls/d of NGLs, and 245 Mcf/d, or 672 BOE/d on a three-stream basis.
• Beall Ranch #15H ? With an 8,649' perforated interval, the #A2H recorded Max-30 rates of 660 Bbls/d oil, 41 Bbls/d of NGLs, and 297 Mcf/d, or 750 BOE/d on a three-stream basis.

EAGLE FORD SHALE TREND - CENTRAL REGION

In our Central Region, 1Q20 production averaged approximately 7,281 BOE/d, a 35% increase over 1Q19 rates. Production consisted of 4,690 barrels of oil per day (64%), 1,344 barrels of NGLs per day (18%), and 7,486 Mcf of natural gas per day (17%). The growth in production is largely driven by development of our Cyclone/Hawkeye assets in Gonzales County. The Central region accounted for 50% of the Company's production during the quarter.

In January, Lonestar began flowback operations on 3 gross / 3.0 net wells, the Cyclone 23H, Cyclone 36H, and Cyclone 37H. These wells recorded maximum rates over a 30-day period ("Max-30 rates") of 638 BOE/d, 90% of which was crude oil. Now, through their first 120 days of production, these wells have produced an average of 48,000 BOE, which is in-line the 8 previous wells drilled at our Cyclone area, despite being up dip to our other producers. The Company holds an 80% working interest ("WI") / 61% net revenue interest ("NRI") in these wells.

In June, the Company began flowback operations on the Hawkeye #14H, Hawkeye #15H, and Hawkeye #16H. These wells were drilled to total measured depths of 21,221, 20,924, and 20,228 feet, respectively. The Hawkeye #14H, #15H, and #16H wells were fracture-stimulated in engineered completions using diverters with an average proppant concentration of 1,827 pounds per foot over 37, 36 and 34 stages, respectively. Lonestar currently holds a 90% WI / 67% NRI in these wells.

These wells are the first 3 wells completed on the previously announced JDA leasehold and these wells have set records as the largest oil producers in the Company's history.

• Hawkeye #14H ? With a perforated interval of 10,979 feet, the #14H tested 1,419 Bbls/d oil, 108 Bbls/d of NGLs, 774 Mcf/d, or 1,656 BOE/d (three-stream) on a 30/64" choke.
• Hawkeye #15H ? With a perforated interval of 10,608 feet, the #15H tested 1,598 Bbls/d oil, 118 Bbls/d of NGLs, 849 Mcf/d, or 1,858 BOE/d (three-stream) on a 30/64" choke.
• Hawkeye #16H ? With a perforated interval of 9,885 feet, the #16H tested 1,483 Bbls/d oil, 111 Bbls/d of NGLs, 799 Mcf/d, or 1,727 BOE/d (three-stream) on a 30/64" choke.

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 72,642 gross (53,249 net) acres in what we believe to be the formation's crude oil and condensate windows, as of March 31, 2020. 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 April 13, 2020, 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 (loss) income attributable to common stockholders 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 (loss) income attributable to common stockholders 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 (loss) income attributable to common stockholders 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 (loss) income attributable to common stockholders for each of the periods indicated.

Adjusted Net Income (Loss)

Adjusted net (loss) income comparable to analysts' estimates as set forth in this release represents income or loss before income taxes adjusted for certain non-cash items (detailed in the accompanying table) less income taxes. We believe adjusted net (loss) income 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.

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