Lonestar Announces Fourth Quarter 2019 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 December 31, 2019.

HIGHLIGHTS

• Lonestar reported a 33% increase in net oil and gas production to a 17,547 BOE/d during the three months ended December 31, 2019 (“4Q19”), compared to 13,152 BOE/d for the three months ended December 31, 2018 (“4Q18”). Production was comprised of 72% crude oil and NGLs on an equivalent basis and just under the high end of the Company’s guidance of 17,200 – 17,600 BOE/d.
• Lonestar reported a net loss attributable to its common stockholders of $76.2 million during 4Q19 compared to a net income of $75.2 million during 4Q18. 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 4Q19 was $6.2 million. In particular, the largest items include a $25.3 million unrealized hedging loss on financial derivatives (‘mark-to-market’) and a $48.4 million impairment on oil and gas properties. 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 4Q19 of $32.6 million, within guidance of $32.0 - $34.0 million. On a sequential basis, Adjusted EBITDAX decreased 12%, as the Company only placed 2 gross / 2.0 net wells onstream in 4Q19 after placing 4 gross / 3.5 net wells onstream in 3Q19. 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 7,543 Bbls/d for Bal ’20, at an average WTI price of $57.09/bbl, and 7,000 Bbls/d for Cal ‘21 at an average WTI price of $50.40/bbl. Our crude oil hedges cover greater than 95% of oil production for Bal ‘20 and depending on activity, similar levels of our production in 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, representing coverage of 65% and 75% for both periods, respectively. 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.
• Based on current market conditions, Lonestar has updated its 2020 guidance. Currently, Lonestar plans to spend a range of $80 to $85 million, a reduction of as much as 25% versus our prior guidance. This capital program will allow for the drilling of a range of 10 gross/ 8.5 net wells to 12 gross / 10.5 net wells and the completion of a range of 13 gross / 11.5 net wells. Based on this range of capital spending, Lonestar is issuing updated 2020 production guidance of 16,000 to 16,500 Boe/d, which is approximately 7% higher than 2019 volumes, at the mid-point. 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 $125 to $130 million.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, commented, "2019 marked a year of continued achievement, both technically and operationally. Continued refinement in our Geo-Engineered drilling and completion process drove positive reserve revisions related to new well performance and pushed Proved reserves to over 100 million barrels of oil equivalent. 2019 saw oil and gas production grow 36% versus 2018 levels, which provides the Company enhanced scale which is driving reduced unit costs. Operating expenses decreased 11% y-o-y on a per unit basis. Our industry is reeling from the recent price collapse induced by the Saudi/Russian rift and exacerbated by demand curtailment due to governmental actions in response to the COVID-19 virus. Fortunately, Lonestar is highly insulated from this price collapse with a robust hedge book that insulates virtually all of the Company’s production not only for 2020 but also 2021. The current mark-to-market of Lonestar’s hedge book is approximately $100 million and is a significant financial and strategic asset for the Company. These hedges allow us to conduct a drilling and completion program focused on core areas that generate excellent rates of return at our realized swap prices. This focused program is allowing Lonestar to capture additional leasehold in its Hawkeye and Horned Frog areas while also supporting our borrowing base. While we are already one of the lowest cost operators in the Eagle Ford Shale, we have taken on many initiatives in response to the massive drop in commodity prices which are reducing costs Company-side. Lastly, during this very difficult time, I want to thank all of our employees who are working tirelessly to maintain high levels of production and profitability.”

OPERATIONAL UPDATE

• Production- Lonestar reported net oil and gas production of 17,547 BOE/d during the three months ended December 31, 2019, representing a 33% increase year-over-year. 4Q19 production volumes consisted of 7,252 barrels of oil per day (41%), 5,430 barrels of NGLs per day (31%), and 29,195 Mcf of natural gas per day (28%). Production rose 33% vs. 4Q18 levels.
• Pricing- Lonestar’s Eagle Ford Shale assets continued to deliver favorable wellhead realizations in 4Q19. Lonestar’s wellhead crude oil price realization was $56.02/bbl, which reflects a discount of $0.94/bbl vs. West Texas Intermediate. Lonestar’s realized NGL price was $10.59/bbl, or 19% of WTI. This was largely the result of a sharp drop in ethane, which fell as much as 47% from 1Q19 prices, and propane and other heavy liquids pricing, which fell as much as 37% from 1Q19 prices. Lonestar’s realized wellhead natural gas price was $2.38 per Mcf, reflecting a $0.02 discount to Henry Hub.
• Revenues- Operating revenues fell by $8.8 million to $49.1 million, or 18%, compared to 4Q18, primarily driven by a 14% decrease in oil price realizations, a 52% decrease in NGL price realizations and a 36% decrease in natural gas price realizations, which were partially offset by a 33% increase in production.
• Expenses- 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 $27.1 million for 4Q19. 4Q19 cash operating costs rose 8% compared to $25.1 million in 4Q18, but were reduced by 19% per unit of production.
  • Lease Operating Expenses (“LOE”) were $8.5 million for 4Q19, which was 16% higher than LOE of $7.3 million in 4Q18. However, on a unit-of-production basis, LOE per BOE were decreased 13% year over year to $5.24 per BOE in 4Q19.
  • Gathering, Processing & Transportation Expenses (“GP&T”) for 4Q19 were $1.4 million, which was 48% higher than the GP&T of $1.0 million in the three months ended 4Q18. On a unit-of-production basis, GP&T increased 11% year over year from $0.80 per BOE in 4Q18 to $0.89 per BOE in 4Q19 with higher gas sales.
  • Production and ad valorem taxes for 4Q19 were $3.0 million, which was in line with production taxes of $2.9 million in 4Q18. On a unit-of-production basis, production and ad valorem taxes decreased 21% year over year from $2.38 per BOE in 4Q18 to $1.88 per BOE in 4Q19.
  • General & Administrative Expenses (“G&A”) in 4Q19 were $4.1 million vs. $2.6 million in 4Q18. G&A Expenses, excluding stock-based compensation of ($1.7) million in 4Q18 and $0.5 million in 4Q19, decreased from $4.4 million to $3.6 million, respectively. Excluding stock-based compensation, on a unit-of-production basis, G&A per BOE decreased 38% year over year from $3.62 per BOE in 4Q18 to $2.23 per BOE in 4Q19.
  • Interest expense was $11.2 million for 4Q19 vs. $10.2 million for 4Q18. Interest expense excluding amortization of debt issuance cost, premiums, and discounts increased 10% year over year from $9.5 millionin 4Q18 to $10.5 million in 4Q19. On a unit-of-production basis, interest expense per BOE decreased 17% from $7.89 per BOE in 4Q18 to $6.52 per BOE in 4Q19.

EAGLE FORD SHALE TREND - WESTERN REGION

In our Western Region, production for 4Q19 averaged approximately 8,106 BOE per day, a 19% increase from 4Q18 production. Production consisted of 2,609 barrels of oil per day (40%), 2,839 barrels of NGL’s per day (30%) and 15,948 Mcf of natural gas per day (30%). The Western region accounted for 46% of the Company’s production during the quarter. The Company did not complete any wells in this region in the fourth quarter.

In March, Lonestar began flowback operations on 2 gross / 2.0 net wells on its Horned Frog property, known as the Horned Frog AE A2H and Horned Frog AE B3H. These wells were drilled to average total measured depths of 22,480’ and fracture-stimulated with an average proppant concentration of exceeding 2,000 pounds per foot using diverters. The Horned Frog AE A2H has a perforated interval of approximately 12,460 lateral feet and recorded test rates of 521 Bbls/d oil (29%), 465 Bbls/d of NGLs (26%), and 4,983 Mcf/d (45%), or 1,816 BOE/d (three-stream) on a 32/64” choke. The Horned Frog AE B3H has a perforated interval of approximately 12,170 lateral feet and recorded test rates of 557 Bbls/d oil (28%), 521 Bbls/d of NGLs (26%), and 5,581 Mcf/d (46%), or 2,008 BOE/d (three-stream) on a 32/64” choke. Lonestar has a 100% WI / 78% NRI in these wells.

Additionally, in March, the Company began completion operations on the Beall Ranch #14H and #15H. These wells were drilled to average total measured depths ranging from 17,380 and 17,360 feet. Completion operations finished last week. The wells were fracture-stimulated using diverters with an average proppant concentration of 1,500 pounds per foot over 25 stages with average perforated intervals of 8,800 feet. The wells are in early stages of flowback and are currently averaging 720 bbl/day and 386 Mcf/day, or 809 BOE/day. Lonestar holds a 98% WI / 73% NRI in these wells.

EAGLE FORD SHALE TREND - CENTRAL REGION

In our Central Region, 4Q19 production averaged approximately 9,017 BOE/d, a 51% increase over 4Q18 rates. Production consisted of 4,439 barrels of oil per day (84%), 2,470 barrels of NGLs per day (9%), and 12,661 Mcf of natural gas per day (8%). The Central region accounted for 51% of the Company’s production during the quarter.

In October 2020, Lonestar began flowback operations on 2 gross / 2.0 net on its Marquis property, the FMC EB #A1H and FMC EB #B2H. These wells have recorded maximum rates over a 30-day period (“Max-30 rates”) averaging 935 BOE/d, 85% of which was crude oil. Through their first 150 days of production, these wells have produced an average of 98,000 BOE with current average production rates still averaging approximately 500 Boe/d. The Company holds an 100% working interest (“WI”) / 73% net revenue interest (“NRI”) in these wells.

In January, Lonestar began flowback operations on 3 gross / 3.0 net wells on its Cyclone property, the Cyclone 23H, Cyclone 36H, and Cyclone 37H. These new wells have since cleaned up after flowback and registered the following Max-30 rates which average 638 BOE/d:

• Cyclone 23H – With a 9,886 perforated interval, the #23H recorded Max-30 rates of 620 Bbls/d oil, 31 Bbls/d of NGLs, and 224 Mcf/d, or 688 BOE/d on a three-stream basis.
• Cyclone 36H – With a 9,949’ perforated interval, the #36H recorded Max-30 rates 506 Bbls/d oil, 28 Bbls/d of NGLs, and 200 Mcf/d, or 567 BOE/d on a three-stream basis.
• Cyclone 37H – With a 10,174’ perforated interval, the #37H recorded Max-30 rates 594 Bbls/d oil, 30 Bbls/d of NGLs, and 214 Mcf/d, or 659 BOE/d on a three-stream basis.

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 (53,831 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of December 31, 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 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 income (loss) 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 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.

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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