Lonestar Reports First Quarter 2021 Results: Financial Position Strengthened, Operational Momentum Resuming

Lonestar Resources US Inc. (OTCQX: LONE) (including its subsidiaries, “Lonestar,” “we,” “us,” “our” or the “Company”) today reported financial and operating results for the three months ended March 31, 2021.

Over the past year, Lonestar has successfully restructured its liabilities, simplified its balance sheet and further reduced debt by utilizing free cash flow. At March 31, 2021, net debt of $239 million provides liquidity of $36 million and a Debt-to-Adjusted EBITDAX ratio of 2.1x. Lonestar continues to target a debt to EBITDAX ratio of 1.5x within the next eight quarters.

HIGHLIGHTS

• Current Production Up 22% From First Quarter Levels. Lonestar reported a 29% decrease in net oil and gas production to 10,377 BOE/d during the three months ended March 31, 2021 (“1Q21”), compared to 14,436 BOE/d for the three months ended March 31, 2020 (“1Q20”). Production was comprised of 75% crude oil and NGL’s on an equivalent basis. However, first quarter production results, which are a product of an extended period without bringing new wells onstream, are expected to represent a trough in terms of quarterly production. Resumption of development activities has increased production to current rates of 12,500 BOE/d. Lonestar expects further growth in production in the second half of 2021 to average rates ranging from 13,400-13,800 BOE/d.
• Adjusted Net Income Was $10.5 Million, or $1.05 Per Share. Lonestar reported a net loss attributable to its common stockholders of $6.3 million, or ($0.63) per share in 1Q21 compared to a net loss of $113.0 million in 1Q20. Lonestar’s adjusted net income for 1Q21 was $10.5 million, or $1.05 per share. Adjusted net income excludes, on a tax-adjusted basis, certain items that the Company does not view as either recurring or indicative of its ongoing financial performance. Most notable among these items include: a $18.8 million unrealized hedging loss on financial derivatives (“mark-to-market”) and $0.7 million of expenses related to our restructuring. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted Net Income (Loss), a reconciliation of net loss before taxes to Adjusted Net Income (Loss), and the reasons for its use.
• Lonestar Reported 1Q21 Discretionary Cash Flow of $19.1 Million. Discretionary Cash Flow for 1Q20 was $19.4 million. However, 1Q21’s Discretionary cash flow was negatively impacted by $5.4 million of hedge losses realized in the quarter while 1Q20’s result was positively impacted by $8.2 million of realized hedge gains. Improved wellhead price realizations and reduced cash expenses positively impacted 1Q21 results. Please see Non-GAAP Financial Measures at the end of this release for the definition of Discretionary Cash Flow, a reconciliation of net loss attributable to common stockholders to Discretionary Cash Flow, and the reasons for its use.
• Lonestar Reported Free Cash Flow For 1Q21 of $7.0 Million. Reported Free Cash Flow yielded a Free Cash Flow yield of 37% for the three months ended March 31, 2021, which compared to Free Cash Flow for 1Q20 of negative $15.1 million. Please see Non-GAAP Financial Measures at the end of this release for the definition of Discretionary Cash Flow, a reconciliation of net loss attributable to common stockholders to Free Cash Flow, and the reasons for its use.
• Lonestar Continues Organic Expansion of Drilling Inventory. As of December 31, 2020, Lonestar had 109 Proved Undeveloped locations and an additional 115 Probable Undeveloped locations. At 2021’s currently projected pace of well completions of 10 per year, our Proved Undeveloped locations represents roughly 11 years of inventory. Lonestar has been especially successful at increasing its drilling inventory on its core assets of Cyclone, Hawkeye and Horned Frog, where its drilling returns are outstanding. Recently, Lonestar concluded a series of primary-term leasing, dispositions and acreage trades that increased our acreage position at Horned Frog and in doing so, nearly doubled our inventory of extended reach laterals to 20, while increasing both our Proved reserves and associated PV-10 on our Horned Frog asset by 38%, at negligible capital outlay.

Lonestar’s Chief Executive Officer, Frank D. Bracken, III commented, “True to form, our drilling and completion program is off to an impressive start. Our new wells at Hawkeye and Horned Frog are performing at or above Type Curve and were completed at costs that were substantially below the costs of our wells completed in these areas last year. Programmatic cost reductions combined with the reduced leverage associated with our restructuring has yielded a more competitive cash cost structure. Lonestar has achieved meaningful reductions in lease operating expenses and interest expenses both in absolute dollar terms and on a per-unit basis. As production increases through the year as we bring new wells online, we expect to register continued improvement in total cash costs per BOE. With production and Discretionary Cash Flow ramping up, our current budget would generate $30-35 million of Free Cash Flow in 2021, which equates to a Free Cash Flow yield of 35-40%. Lonestar intends to principally focus this free cash to continue to reduce long-term debt and associated interest expense.”

OPERATIONAL UPDATE

• Production- Lonestar reported net oil and gas production of 10,377 BOE/d during the three months ended March 31, 2021, representing a 29% decrease year-over-year. Lonestar experienced modest reductions in oil and gas sales as a result of temporary shut-ins related to Winter Storm Uri. 1Q21 production volumes consisted of 5,556 barrels of oil per day (54%), 2,174 barrels of NGLs per day (21%), and 15,880 Mcf of natural gas per day (26%). Since year-end, Lonestar has placed onstream a three-well pad at Hawkeye (50% WI) and a two-well pad at Horned Frog (100% WI). These wells have positively impacted production, with current production exceeding 12,500 BOE/d, consisting of 6,500 barrels of oil per day, 2,700 barrels of NGL’s per day, and 19,800 Mcf of natural gas per day.
• Pricing- Lonestar’s Eagle Ford Shale assets continued to deliver favorable wellhead realizations in 1Q21. Lonestar’s wellhead crude oil price realization was $55.74/bbl, which reflects a discount of $2.10/bbl vs. West Texas Intermediate (“WTI”). Lonestar’s realized NGL price was $21.96/bbl, or 38% of WTI. Lonestar’s realized wellhead natural gas price was $5.35 per Mcf, reflecting a $1.79 premium to Henry Hub. The first quarter natural gas differentials were positively impacted by the effects of the high realizations achieved in February 2021 resulting from increased gas prices during Winter Storm Uri.
• Revenues- Wellhead revenues increased by $2.8 million to $39.8 million in 1Q21, or 8%, compared to 1Q20, primarily driven by a 156% increase in NGL price realizations, a 155% increase in natural gas price realizations, and a 22% increase in oil price realizations, which were partially offset by lower production.
• Expenses- Lonestar initiated cost reduction measures starting in the second quarter of 2020 which continue to deliver a lower operating cost structure for the Company, both on an absolute dollar basis and a per-unit basis. Total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administrative, and interest expenses were $16.5 million. Lonestar reduced 1Q21 cash operating costs by 38%, compared to $26.6 million in 1Q20. When measured on a unit-of-production basis, total cash costs were reduced by 13% from $20.28 per BOE to $17.66 per BOE. Adjusted for non-recurring items discussed below, total cash expenses were $15.5 million, or $16.70 per BOE.
  • Lease Operating Expenses (“LOE”), which includes workover expenses, were $4.4 million for 1Q21, which was 42% lower than LOE of $7.6 million in 1Q20. Additionally, LOE per BOE was reduced by 18%, from $5.81 per BOE in 1Q20 to $4.76 per BOE in 1Q21. 1Q21 lease operating expenses included a prior period settlement of $0.2 million, which the Company does not consider recurring. Adjusted for this item, LOE was $4.2 million, or $4.55 per BOE, a reduction of 22%.
  • Gathering, Processing & Transportation Expenses (“GP&T”) for 1Q21 were $1.5 million, which was 28% lower than the GP&T of $2.2 million in the three months ended 1Q20. On a unit-of-production basis, GP&T remained stable, rising less than 1% year over year from $1.64 per BOE in 1Q20 to $1.65 per BOE in 1Q21.
  • Production & Ad Valorem Taxes for 1Q21 were $2.4 million, which was relatively flat compared to production taxes of $2.4 million in 1Q20. On a unit-of-production basis, production and ad valorem taxes increased 44% year over year from $1.80 per BOE in 1Q20 to $2.59 per BOE in 1Q21, as the Company experienced higher wellhead revenues in 1Q21 which resulted in higher production taxes.
  • General & Administrative ("G&A") expenses were $4.0 million, or $4.26 per BOE in 1Q21 compared to $2.9 million, or $2.19 per BOE in 1Q20. G&A for 1Q21 includes approximately $0.7 million of professional fees residual to the Company’s restructuring in 2020. Adjusted for this non-recurring item, General & Administrative expense were $3.3 million for 1Q21, or $3.51 per BOE. G&A for 1Q20 includes stock-based compensation gains of $1.8 million and as of 1Q21 Lonestar had not implemented any new stock-based compensation plans.
  • Interest Expense was $4.1 million for 1Q21, down 66% from $11.6 million in 1Q20. On a unit-of-production basis, interest expense was reduced from $8.84 per BOE in 1Q20 to $4.40 per BOE in 1Q21. The decrease between periods was primarily due to a decrease in the average debt principal outstanding associated with the Emergence from Voluntary Reorganization. Lonestar expects continued reductions in interest expense per BOE, as the Company reduces long-term debt and increases production.

UPDATED GUIDANCE

• 2021- Lonestar’s principal financial objectives in 2021 are to direct its substantial free cash flow towards reduction in long-term debt. Accordingly, Lonestar plans to spend a range of $45 to $50 million in 2021 on extended-reach laterals in high-return areas of Horned Frog and Hawkeye, $11 million of which was spent in the first quarter of 2021. This capital program will allow for the completion of 3.0 gross / 1.5 net wells (which were DUC’s at December 31, 2020) and drilling and completion of an additional 7.0 gross / 5.5 net wells. Based on this range of capital spending, Lonestar’s production guidance for 2021 is 12,250 to 12,750 BOE/d, with Adjusted EBITDAX guidance of $90-$100 MM and Free Cash Flow of $30-$40 MM.
• 2Q21- Coming off of the first quarter’s base of production which averaged 10,377 BOE/day, Lonestar’s second quarter production volumes have been favorably impacted by the benefit of a full-quarter contribution of the Hawkeye #33H, #34H & #35H wells. Additionally, the Horned Frog NW #1H and #2H wells came onstream in April and will contribute for a significant portion of the second quarter. Accordingly, Lonestar is issuing second quarter 2021 production guidance of 11,500-12,000 BOE/d, which is expected to be approximately 53% crude oil, 21% NGL’s and 26% natural gas. Lonestar’s Adjusted EBITDAX guidance is $20-$22 million, with Discretionary Cash Flow of $16-$18 million.

EAGLE FORD SHALE TREND - WESTERN REGION

In our Western Region, which encompasses Dimmit and LaSalle Counties, production for 1Q21 averaged approximately 5,132 BOE per day, a 25% decrease from 1Q20 production. Production consisted of 1,895 barrels of oil per day (37%), 1,382 barrels of NGL’s per day (27%) and 11,105 Mcf of natural gas per day (36%). The Western region accounted for 49% of the Company’s production during the quarter.

In March 2021 Lonestar began flowback operations on 2.0 gross / 2.0 net wells on its Horned Frog West property, the Horned Frog West #1H and #2H. Lonestar has a 100% WI / 78% NRI in these wells. These wells commenced flowback approximately two weeks ago, and to date, have registered initial production rates averaging 1,517 BOE/d. Production is currently comprised of 77% crude oil and NGL’s on an equivalent basis, which is the highest liquid mix to date at our Horned Frog asset.

• Horned Frog West 1H – With a 7,473’ perforated interval, the #1H recorded initial test rates of 807 Bbls/d oil, 376 Bbls/d of NGLs, and 2,103 Mcf/d, or 1,534 BOE/d on a three-stream basis.
• Horned Frog West 2H – With a 7,518’ perforated interval, the #2H recorded initial test rates of 798 Bbls/d oil, 363 Bbls/d of NGLs, and 2,036 Mcf/d, or 1,501 BOE/d on a three-stream basis.

Lonestar has also recently completed drilling operations on 2.0 gross / 2.0 net wells on its Horned Frog South property, the Horned Frog Alderman #1H and #2H. Lonestar has a 100% WI / 77.96% NRI in these wells. Fracture stimulation operations are scheduled to commence on these wells later this month with first production anticipated in July 2021.

Through a combination of primary-term leasehold acquisitions, leasehold dispositions and an acreage trade, Lonestar has materially enhanced its position in the Horned Frog asset. The net effect of these transactions is to increase our Horned Frog leasehold from 6,530 to 7,262 net acres. More importantly, it reconfigured our position to accommodate significantly more drilling, increasing the number of drillable locations exceeding 5,000 feet in lateral length from 11 to 20, of which Lonestar owns a 100% WI. On average, the transactions increased our average lateral length at Horned Frog from 8,900 feet to 10,100 feet. Most importantly, the transactions increased our Proved reserves at Horned Frog from 30.2 million barrels of oil equivalent to 44.1 million barrels of oil equivalent, and increased PV-10 from $193 million to $280 million, assuming flat prices of $55/bbl for WTI crude oil and $2.75/MMBTU for Henry Hub natural gas.

EAGLE FORD SHALE TREND - CENTRAL REGION

In our Central Region, which principally encompasses Gonzales, Karnes, Lavaca and Fayette Counties, 1Q21 production averaged approximately 5,008 BOE/d, a 31% decrease over 1Q20 rates. Production consisted of 3,511 barrels of oil per day (70%), 741 barrels of NGL’s per day (15%), and 4,543 Mcf of natural gas per day (15%). The Central region accounted for 48% of the Company’s production during the quarter.

In February 2021, Lonestar began flowback operations on 3 gross / 1.5 net wells, the Hawkeye 33H, Hawkeye 34H, and Hawkeye 35H. These wells recorded initial rates over a 30-day period (“Max-30 rates”) of 938 BOE/d, 91% of which was crude oil. Recently, Lonestar introduced artificial lift operations on these wells and they have responded favorably, with current production rates averaging 800 BOE/d per well. The Company holds a 50% working interest (“WI”) / 38% net revenue interest (“NRI”) in these wells.

• Hawkeye #33H – With a perforated interval of 10,875 feet, the #33H tested 931 Bbls/d oil, 43 Bbls/d of NGLs, 307 Mcf/d, or 1,024 BOE/d (three-stream) on a 30/64” choke.
• Hawkeye #34H – With a perforated interval of 10,770 feet, the #34H tested 774 Bbls/d oil, 35 Bbls/d of NGLs, 253 Mcf/d, or 851 BOE/d (three-stream) on a 30/64” choke.
• Hawkeye #35H – With a perforated interval of 10,821 feet, the #35H tested 769 Bbls/d oil, 38 Bbls/d of NGLs, 272 Mcf/d, or 852 BOE/d (three-stream) on a 30/64” choke.

As part of its Joint Venture with Marathon Oil Corporation, Lonestar, as operator, has permitted a three-well pad on its Hawkeye asset. Lonestar recently commenced drilling operations on three wells, the Hawkeye #9H, #10H and #11H, with designed perforated intervals exceeding 11,000 feet.

EAGLE FORD SHALE TREND - EASTERN REGION

In our Eastern Region, 1Q21 production averaged approximately 236 BOE/d, a 10% decrease over 1Q20 rates. Production consisted of 150 barrels of oil per day (64%), 47 barrels of NGL’s per day (20%), and 231 Mcf of natural gas per day (16%).

ABOUT LONESTAR RESOURCES US INC.

Lonestar is an independent oil and natural gas company based in Fort Worth, Texas, 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 72,682 gross (53,550 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of March 31, 2021. For more information, please visit www.lonestarresources.com.

CAUTIONARY & FORWARD-LOOKING STATEMENTS

Cautionary Note Regarding Forward-Looking Statements

Disclosures in this press release contain certain forward-looking statements within the meaning of the federal securities laws. Statements that do not relate strictly to historical or current facts are forward-looking. These statements contain words such as “possible,” “if,” “will,” “expect” and “assuming” and involve risks and uncertainties including, among others that our business plans may change as circumstances warrant and securities of the Company may not ultimately be offered to the public because of general market conditions or other factors. Accordingly, readers should not place undue reliance on forward-looking statements as a prediction of actual results. For more information concerning factors that could cause actual results to differ materially from those conveyed in the forward-looking statements, please refer to the “Risk Factors” section of the Company’s Annual Report on Form 10-K for the year ended December 31, 2020, filed with the Securities and Exchange Commission (the “SEC”) on March 31, 2021 and any subsequently filed quarterly reports on Form 10-Q. Any forward-looking statements in this press release are made as of the date of this press release and the Company undertakes no obligation to update or revise such forward-looking statements to reflect events or circumstances that occur, or of which the Company becomes aware, after the date hereof, unless required by law.

(Unaudited Financial Statements to Follow)

*References to “Successor” refer to the new Lonestar reporting entity after the Company’s emergence from bankruptcy on November 30, 2020, and references to “Predecessor” refer to the Lonestar entity prior to emergence from bankruptcy.*

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 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 loss before taxes for each of the periods indicated.

Discretionary Fee Cash Flow (“DCF”)

Discretionary cash flow is defined as net cash provided by operating activities before changes in operating assets and liabilities. Management believes that the non-US GAAP measure of discretionary cash flow is useful as an indicator of an oil and natural gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Operating cash flow should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with US GAAP.

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