Lonestar Announces First Quarter 2018 Financial Results And Provides Operational Update

FORT WORTH, Texas, May 13, 2018 /PRNewswire/ -- 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, 2018.

RECENT HIGHLIGHTS

• Lonestar reported a 48% increase in net oil and gas production to 7,777 Boe/d during the three months ended March 31, 2018 ("1Q18"), compared to 5,266 Boe/d for the three months ended March 31, 2017 ("1Q17"). Production volumes exceeded the high end of the Company's guidance, and were 86% crude oil and NGLs on an equivalent basis. The increase in production was attributable to the drilling of new Eagle Ford Shale wells and production associated with our acquisition of producing properties in June 2017.
• Lonestar's 2018 drilling program continues to deliver outstanding results. At Hawkeye, our two wells, which delivered Max-30 IP's of 938 Boe/d, have now outperformed third party forecasts by 16% through 90 days. At Horned Frog, our two wells delivered average Max-30 IP's of 2,155 Boe/d, a record for the Company. In Karnes County, our first three wells there have recently been placed on production and are averaging over 1,250 Boe/d per well (95% liquids) in their first week of production, surpassing third party forecasts.
• Benefitting from better-than-expected production results, Lonestar issued production guidance of 10,000 to 10,500 Boe/d for the second quarter of 2018. The midpoint of guidance represents a 32% increase over 1Q18 results and is 82% higher than production reported for the three months ended June 30, 2017 ("2Q17"). Lonestar also issued guidance for Adjusted EBITDAX for 2Q18 of $27 to $29 million.
• Based on the strength of its drilling results to date, Lonestar is raising its full-year 2018 production guidance to a range of 10,300 to 11,000 Boe/d. Commensurately, Lonestar is increasing its EBITDAX guidance to $110 to $125 million, based on a $60 WTI oil price average oil price for 2018. The Company has contractually locked in most of its service costs for 2018, but based on results-to-date, is extending some of its laterals and/or increasing proppant concentrations on several of its remaining wells in its 2018 drilling program, which will increase budgeted 2018 capital spending by $5 million, to a range of $100 to $105 million. The source of higher EBITDAX guidance is a result of outstanding performance of our 2018 drilling program, more lateral length, higher WTI crude oil prices, and sustained positive basis realizations of our Eagle Ford Shale crude oil.
• Lonestar reported a net loss attributable to its common stockholders of $18.5 million, or ($0.75) per weighted average share, during 1Q18 compared to net income of $3.1 million, or $0.14 per weighted average share during the 1Q17. Excluding, on a tax-adjusted basis, certain items that the Company does not view as either recurring or indicative of its ongoing financial performance, our adjusted net loss for 1Q18 was ($3.1) million, or ($0.13) per common share. Most notable among these items include: unrealized hedging losses on financial derivatives; loss on the extinguishment of debt; office lease write-off; and stock-based compensation. Please see Non-GAAP Financial Measures for additional information.
• Lonestar reported a 103% increase in Adjusted EBITDAX for the three months ended March 31, 2018 of $23.4 million compared to $11.5 million for the prior year period. This improvement was driven by a 48% increase in production and a 24% increase in the Company's oil-equivalent price realization after the effect of hedging. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net (loss) income to Adjusted EBITDAX, and the reasons for its use.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, stated, "In the first quarter, production increased  by 48% and realized prices after hedging rose 24%, resulting in a 103% increase in EBITDAX.  While we are pleased with the progress that our first quarter represents, our second quarter results will more fully reflect the outstanding drilling results we have generated thus far in 2018.  The midpoint of our 2Q18 guidance reflects significant increases in production and EBITDAX over our 1Q18 results.  Importantly, these results are expected to significantly strengthen our financial position.  Since 2Q17, we have reduced Debt / EBITDAX (Last Quarter Annualized) from 5.4x to 3.4x, and expect that this ratio will improve to 3.0x or better in 2Q18.  Our stronger financial position has allowed us to secure dedicated drilling and pressure pumping services, which is greatly enhancing our ability to control the quality, timing and costs of our capital program.  Given the excellent start, we have increased our 2018 full-year production guidance to 10,300 to 11,000 Boe/d, which represents 65% growth versus 2017. We have also raised our full year 2018 Adjusted EBITDAX guidance to $110 to $125 million, representing a similar growth rate.  While encouraged by our drilling results to date, we are highly focused on delivering exceptional results for our shareholders as we move through 2018 and beyond."

OPERATIONAL UPDATE

• Lonestar reported net oil and gas production of 7,777 Boe/d during the three months ended March 31, 2018, an increase of 48% compared to 5,266 Boe/d during the three months ended March 31, 2017. Production volumes during 1Q18 consisted of 5,740 barrels of oil per day (74%), 965 barrels of NGLs per day (12%), and 6,435 Mcf of natural gas per day (14%). The Company's production mix for the three months ended March 31, 2018 was 86% liquid hydrocarbons.
• Lonestar delivered excellent wellhead realizations in 1Q18. Lonestar's realized wellhead crude oil price was $64.18 per barrel, which reflects a positive differential of $1.31/bbl vs. West Texas Intermediate. Lonestar's realized NGL price was $19.97 per barrel in the first quarter of 2018. Lonestar's natural realized wellhead natural gas price was $3.12 per Mcf, which reflects a positive differential of $0.04 to the Henry Hub.
• Lonestar has delivered consistent non-tax cash operating costs in the first quarter of 2018, and exhibited significant sequential improvement in lease operating expenses in the quarter ended March 31, 2018:
• Lease Operating Expenses ("LOE") for the three months ended March 31, 2018 were $4.1 million, which was 56% higher than Lease Operating Expenses of $2.7 million in the three months ended March 31, 2017, but commensurate with a 48% increase in production. On a unit-of-production basis, lease operating expenses were fairly flat, rising 5% to $5.92 per Boe for the three months ended March 31, 2018. This comparison is somewhat misleading in that in June 2017, Lonestar acquired the Marquis and Battlecat assets, which were more mature and bear structurally higher operating expenses. However, on a sequential basis, Lonestar reduced lease operating expenses by 19% vs. 4Q17 on an absolute basis, and by 23% vs. 4Q17 to $5.92 per Boe. For 2018, the Company expects LOE to be between $5.60 and $6.50 per Boe, as relatively fixed costs are spread over substantially larger production volumes.
• Gathering, Processing & Transportation Expenses ("G,P&T") for the three months ended March 31, 2018 were $0.5 million, which was 50% higher than the G,P&T of $0.3 million in the three months ended March 31, 2017, but commensurate with a 48% increase in production. On a unit-of-production basis, G,P&T was fairly flat, rising 2% to $0.63 per Boe for the three months ended March 31, 2018. For 2018, the Company expects G,P&T to be between $0.75 and $0.85 per Boe.
• General & Administrative Expenses, excluding stock-based compensation of $0.2 million in the three months ended March 31, 2017 and $0.4 million in the three months ended March 31, 2018 ("G&A"), increased from $2.5 million to $3.0 million, respectively. On a unit-of-production basis, G&A per Boe was reduced 19% year over year, from $5.26 per Boe in 2017 to $4.24 per Boe in 2018. For 2018, the Company expects G&A to be between $2.80 and $3.00 per Boe.
• Interest Expense excluding amortization of debt issuance cost, premiums, and discounts increased year over year from $4.4 million in the three months ended March 31, 2017 to $8.2 million in 2018. This was primarily due to a combination of higher stated interest rates and principal on the new 11.25% Senior Notes versus the 8.75% Senior Notes that were retired in January 2018. On a unit-of-production basis, interest per Boe was rose 25% year over year from $9.38 per Boe in 2017 to $11.72 per Boe in 2018. For 2018, the Company expects interest expense to be between $8.15 and $8.75 per Boe.
• Lonestar has commenced a more active drilling and completion program in 2018, and all four wells with established production rates are producing at rates that exceed our forecasts. In the first quarter of 2018, Lonestar placed online 4.0 gross / 3.8 net wells. In May, Lonestar placed its first three (3.0 / 2.4 net wells) Karnes County wells onstream and anticipates production from an additional 2.0 gross / 2.0 net wells in the Horned Frog area in June 2018.

EAGLE FORD SHALE TREND- WESTERN REGION

Asherton – In Dimmit County, no new wells were completed during the three months ended March 31, 2018.  The Asherton leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.  

Beall Ranch – In Dimmit County, no new wells were completed during the three months ended March 31, 2018.  The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018. 

Burns Ranch Area – In La Salle County, Lonestar was hit by offset fracs that negatively impacted production during the three months ended December 31, 2017 and the beginning of the three months ended March 31, 2018.  Oil and gas rates have since rebounded above the production trend lines. The Company did not drill or complete any new wells during the three months ended March 31, 2018.  The Burns Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.

Horned Frog – In La Salle County, the Company completed the Horned Frog G #1H and H #1H, and commenced flowback operations on March 19, 2018.  These wells were drilled to total measured depths of approximately 22,800 and 20,950 feet, respectively and were fracture-stimulated in engineered completions with an average proppant concentration of 1,650 pounds per foot across an average of 40 stages per well utilizing diverters. The Horned Frog G #1H, which has a perforated interval of 12,280 feet, produced at a Max 30-day production rate of 2,243 Boe/d, consisting of 467 barrels of oil per day, 643 barrels of natural gas liquids, and 6,799 Mcf per day of natural gas.  The H #1H, which has a perforated interval of 10,445 feet, produced at a Max 30-day production rate of 2,067 Boe/d, consisting of 427 barrels of oil per day, 592 barrels of natural gas liquids, and 6,286 Mcf per day of natural gas. The Horned Frog G #1H rate marks the highest 30-day rate in the Company's history, exceeding the 2,123 Boe/d rates at Wildcat established in June 2017.  As it has successfully done at Wildcat, Lonestar plans to stringently choke manage these wells to optimize the total liquids recovery over the life of these wells. Lonestar is encouraged by the early performance of its newest wells at Horned Frog.  Lonestar has a 100% WI and 80% NRI in these wells.  Lonestar has completed drilling operations on the Horned Frog North West #2H and #3H, in which it holds a 100% WI and 75% NRI. These wells have been drilled to measured depths of 17,560 feet and 17,440 feet, respectively and estimated perforated intervals of approximately 7,700 feet, each.  Lonestar plans to initiate fracture stimulations on these wells in May 2018.

EAGLE FORD SHALE TREND- CENTRAL REGION

Gonzales County – In April 2018, Lonestar commenced drilling the Cyclone #13H and Cyclone #14H with planned total measured depths of 20,150 feet and 19,650 feet, respectively.  We project that these wells will have perforated intervals of approximately 11,000 feet.  Completion of drilling operations is expected this week.  Fracture stimulation operations are scheduled for June 2018. Lonestar owns a 100% WI and 78.5% NRI in these two wells.

Hawkeye – Lonestar owns an 87.5% WI in the Hawkeye #1H and Hawkeye #2H, which were placed onstream in January 2018. These wells have now been producing for in excess of three months and the results continue to be encouraging.  After registering Max-30 IP's averaging 938 Boe/d, these wells continue to exhibit robust performance.  During the first 90 days of production, the Hawkeye #1H has produced cumulative production of 65,600 barrels of oil, 37,250 Mcf, or 74,136 barrels of oil equivalent on a three-stream basis or 824 Boe/d over its first 90 days of production. Over the same period, the Hawkeye #2H has produced cumulative production of 57,020 barrels of oil, 30,655 Mcf, or 64,045 barrels of oil equivalent on a three-stream basis or 712 Boe/d over its first 90 days of production.  Through 90 days of production, the Hawkeye wells are 28% better than the average Cyclone well and 19% better than our best Cyclone well, on a per-foot basis.  To date, our initial Hawkeye wells are outperforming Third-Party projections by 16%.

Karnes County – In March 2018, the Company completed drilling operations on the Georg EF #18H, Georg EF #19H, and Georg EF #20H to an average total measured depth of approximately 15,450 feet. These wells have perforated intervals of approximately 6,300 feet with an average proppant concentration of 2,040 pounds per foot.  Lonestar owns an 80% WI and 61% NRI in these wells.  Fracture stimulation of these wells was completed with our dedicated frac spread in April, 2018 and flowback operations commenced on May 7, 2018.  With 1% of their load recovered, the three wells are currently flowing on a 22/64" choke at an average of 1,121 barrels of oil per day and 639 Mcfpd, or 1,269 Boe/d on a three-stream basis.

Pirate – In Wilson County, no new wells were completed during the three months ended March 31, 2018.  The Pirate leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.  

EAGLE FORD SHALE TREND- EASTERN REGION

Brazos & Robertson Counties – In Brazos County, no new wells were completed during the three months ended March 31, 2018. Generally speaking, this area is not an area where we have a clear line of site on meaningful acquisitions, and while our results here have augmented returns, we are reviewing our options on this asset with our partner. Lonestar does not currently have drilling activity budgeted here in 2018.   

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Monday, May 14, 2018 at 9:00 AM CDT to discuss the first quarter 2018 results and operational highlights.

To access the conference call, participants should dial:

USA: 800-931-3971
International: +1 212-231-2929

A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately May 15, 2018.  The playback will be available for approximately 2 weeks.

ABOUT LONESTAR RESOURCES US, INC.

Lonestar is an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, natural gas liquids ("NGLs") and natural gas properties in the Eagle Ford Shale in Texas, where we accumulated approximately 75,479 gross (55,922 net) acres in what we believe to be the formation's crude oil and condensate windows, as of March 31, 2018. 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 on our Annual Report on Form 10-K filed with the Securities and Exchange Commission, or the SEC, on March 29, 2018 our Quarterly Reports on Form 10-Q filed with the SEC, 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.

(Financial Statements to Follow)

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

Adjusted net income 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 comparable to analysts' estimates 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 comparable to analysts' estimates on a diluted per share basis.  A table is included which reconciles income or loss from operations to adjusted net income comparable to analysts' estimates and diluted earnings per share (adjusted).

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

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SOURCE Lonestar Resources US Inc.