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

  • May 12, 2021
  • Business Wire

FORT WORTH, Texas--(BUSINESS WIRE)--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.

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.”

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.

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.

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.

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.

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%).

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 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.

*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.*

Oil and gas properties, using the successful efforts method of accounting

Less accumulated depreciation, depletion and amortization

Oil, natural gas liquid and natural gas sales payable

Common stock, $0.001 par value, 100,000,000 shares authorized, 10,000,149 shares issued and outstanding

Unaudited Condensed Consolidated Statements of Operations

Unaudited Condensed Consolidated Statements of Cash Flows

Adjustments to reconcile net loss to net cash provided by operating activities:

Net decrease in cash, cash equivalents and restricted cash

Cash, cash equivalents and restricted cash, beginning of the period

Cash, cash equivalents and restricted cash, end of the period

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.

Unrealized loss (gain) on derivative financial instruments

1 Interest expense also includes dividends paid on Series A Preferred Stock in Q120.

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.

Unaudited Reconciliation of Loss Before Taxes As Reported To Income (Loss) Before Taxes Excluding Certain Items, a non-GAAP measure (Adjusted Net Income (Loss))

Net income (loss) excluding certain items, a non-GAAP measure

Net income (loss) excluding certain items, a non-GAAP measure

Effective tax rate for 2021 and 2020 is estimated to be approximately 21%.

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.

1 Cash interest is presented on an accrual basis and excludes non-cash amortization expense

Total oil equivalent, excluding the effect from commodity derivatives ($ per BOE)

Total oil equivalent, including the effect from commodity derivatives ($ per BOE)