Lonestar Resources Announces Third Quarter 2017 Results

FORT WORTH, Texas, Nov. 13, 2017 /PRNewswire/ -- Lonestar Resources US, Inc. (NASDAQ: LONE) (including its subsidiaries, "Lonestar," "we," "us," "our" or the "Company") reported today its financial and operating results for the three months ended September 30, 2017.

THIRD QUARTER HIGHLIGHTS

• Lonestar reported a 36% sequential increase in net oil and gas production during the three months ended September 30, 2017 ("3Q17"). Net oil and gas production averaged 7,662 Boe/d in the third quarter of 2017 compared to 5,635 Boe/d during three months ended June 30, 2017 ("2Q17"). The Company expects to grow production at an accelerated rate during 2018 as drilling and completion activity accelerates on the Company's expanded acreage position. The growth was associated with the $116.6 million acquisition of producing properties that closed June 15, 2017 which added 81 gross / 75.2 net wells ("the Acquisitions"). The third quarter also benefited by the addition of 2 gross / 2 net newly drilled wells placed into service at our Cyclone property in Gonzales County in July, which more than offset natural declines from our producing wells. The proactive work of our field operations team, Lonestar only incurred 150 Boe/d of curtailments from producing wells associated with Hurricane Harvey.
• The recent acquisitions and our drilling program significantly increased Adjusted EBITDAX. Lonestar generated a 61% increase in Adjusted EBITDAX for the quarter ended September 30, 2017 to $20.3 million, versus to $12.7 million for the quarter ended June 30, 2017. See "Non-GAAP Financial Measures" at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net income (loss) to Adjusted EBITDAX, and the reasons for its use.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, stated, "The third quarter results represent a significant step forward for Lonestar.  Our 3Q17 results are the first results that fully reflect the positive impact of our Acquisitions, which have brought significant scale to our business, as reflected in our dramatically improved cash margins.  Moreover, I applaud our operations team, who have quickly and proactively assumed control of operations, and associated lease operating expenses.  Our ability to reduce costs has added significant value to the Acquisitions."

Bracken further commented, "On an annualized basis, our Adjusted EBITDAX increased sequentially from $50.8 million in 2Q17 to $81.2 million in 3Q17, driven by significant growth in production, most particularly oil production while keeping our cash expenses in check.  The growth in our third quarter results will serve as a platform for continued in 2018.  We forecast that 2018 production will range between 10,000 to 10,700 Boe/d and we currently anticipate that Adjusted EBITDAX will total between $100 and $110 million.  Importantly, we expect to achieve this significant growth in production and EBITDAX while also significantly enhancing our credit metrics.  We currently anticipate that Debt / EBITDAX will improve to between 2.7x and 2.9x by year-end 2018."

FINANCIAL UPDATE

• 3Q17 production volumes which were up 36% sequentially, consisted of 5,250 barrels of oil per day (69%), 1,228 barrels of NGLs per day (16%), and 7,105 Mcf of natural gas per day (15%). The Company's production mix for the third quarter of 2017 was 85% liquid hydrocarbons. While 3Q17 production volumes increased 36%, crude oil production increased 47% sequentially, further improving the profitability of Lonestar's production.
• During the quarter ended September 30, 2017, our drilling program added 2.0 gross / 2.0 net wells, the Cyclone #4H and #5H which contributed meaningfully to the Company's quarterly results. Lonestar also commenced flowback of 2.0 gross / 2.0 net wells, the Cyclone #26H and #27H, on September 22, 2017, which contributed negligibly to our third quarter results. Lonestar originally expected these wells to be placed onstream by August 15^th, but fracture stimulation of these wells was deferred by our third-party service provider, in large part due to lack of crew availability related to Hurricane Harvey.
• Lonestar reported a net loss attributable to its common stockholders of $6.8 million, or ($0.39) per weighted average share, during the three months ended September 30, 2017. 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 3Q17 was ($2.7) million, or ($0.12) per common share. Most notable among these items include: 1) $9.4 million unrealized hedging loss on financial derivatives; 2) $0.3 million non-recurring general and administrative costs related to additional fees associated with the acquisition; 3) $0.3 in stock based compensation. Please see Non-GAAP Financial Measures for additional information.
• Lonestar's operating cost structure saw significant sequential improvement on a per Boe basis in the three months ended September 30, 2017, which was achieved by stringent cost control and expanded production volumes provided by our recent acquisitions:
• Lease Operating Expense increased from $3.5 million in 2Q17 to $4.5 million in 3Q17. However, on a unit-of-production basis, LOE per Boe decreased 7% sequentially, from $6.87 per Boe in 2Q17 to $6.40 per Boe in 3Q17.
• Production Taxes increased 43% from $1.1 million in 2Q17 to $1.5 million in 3Q17, in proportion to a 48% increase in oil and gas revenues. On a unit-of-production basis, LOE per Boe rose 4%, from $2.10 per Boe to $2.19 per Boe.
• General & Administrative Expense declined 26% from $3.1 million in 2Q17 to $2.3 million in 3Q17. On a unit-of-production basis, G&A per Boe decreased 47% sequentially, from $6.12 per Boe in 2Q17 to $3.26 per Boe in 3Q17, largely as a function of our ability to operate an expanded asset base associated with the Acquisitions without expanded our overhead.
• Interest Expense decreased 16% from $6.0 million in 2Q17 to $5.0 million in 3Q17 as a result of the extinguishment of the Company's 12% second lien debt during 2Q17.

OPERATIONS UPDATE

EAGLE FORD SHALE TREND- WESTERN REGION

• Asherton – In Dimmit County, no new wells were completed during the three months ended September 30, 2017. The Asherton leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2017.
• Beall Ranch – In Dimmit County, no new wells were completed during the three months ended September 30, 2017. The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2017.
• Burns Ranch Area – The Company's Gen 5 wells continue to perform at a high level. Through 300 days of production our Burns Ranch #9H and #10H have produced over 100,000 barrels of oil, and are outperforming the forecast of our third-party reservoir engineering consultants. By comparison, our Gen 3 wells, drilled in 2015, have produced a cumulative 131,000 barrels of oil in 900 days of production. Additionally, Lonestar has drilled the B#1H and B#2H on Burns Ranch to total depths of 17,927 and 18,002 feet, respectively, with projected perforated intervals for these wells at approximately 9,450 feet. Originally scheduled for early September, 2017, but deferred by our third-party service provider, fracture stimulation operations commenced in late October, 2017. Lonestar owns a 92% working interest ("WI") and a 69% net revenue interest ("NRI") in these wells. Fracture stimulation of these wells has been completed and flowback is expected to commence on November 22nd, with commercial sales expected by December 1st. Upon first production of these 2 wells, Lonestar will have completed five producing wells on this leasehold during 2017, and consequently, Lonestar will have increased its acreage that is Held By Production from approximately 2,770 gross / 2,673 net acres to approximately 4,632 gross / 3,817 net acres, which means that Burns Ranch is now 100% HBP'd.
• Horned Frog – In La Salle County, no new wells were completed during the three months ended September 30, 2017. The Horned Frog leasehold is held by production. During the third quarter, Lonestar acquired a 3-D seismic survey over its Horned Frog acreage, and has now completed its interpretation of the 3-D data. Lonestar is constructing a drilling pad and currently plans to drill and complete the Horned Frog B#4H and C#1H wells, planned for perforated intervals of 10,000 feet in the first quarter of 2018.

EAGLE FORD SHALE TREND- CENTRAL REGION

• Cyclone – On July 1, Lonestar established commercial sales on its Cyclone #4H & Cyclone #5H, which were drilled and completed during the second quarter and placed into flowback in late June, 2017. The production results during the first 120 days in service are encouraging, as the 52,000 barrel average cumulative production from these wells is 31% higher than the first 120 days of Lonestar's initial wells at Cyclone, the #9H and #10H. Additionally, the Cyclone #26H and Cyclone #27H wells were drilled and completed in the third quarter and commenced flowback on September 22, 2017. Lonestar has a 100% WI and 79% NRI in these wells. The Cyclone #26H and #27H wells were fracture-stimulated in engineered completions with an average proppant concentration of 1,525 pounds per foot over 28 stages per well, and utilized diverters. The Cyclone #26H was completed with a perforated interval of 8,351 feet and tested 766 Bbls/d and 420 Mcf/d, or 862 Boe/d (three-stream) on a 24/64'' choke. The Cyclone #26H well recently established a 30-day production rate of 723 Boe/d, consisting of 637 barrels of oil per day (88%), 39 barrels of natural gas liquids (5%), and 282 Mcf per day of natural gas (7%). The Cyclone #27H was completed with a perforated interval of 8,278 feet and tested 733 Bbls/d and 428 Mcf/d, or 831 Boe/d (three-stream) on a 22/64'' choke. The #27H well has recently established a 30-day production rate of 695 Boe/d, consisting of 609 barrels of oil per day (88%), 39 barrels of natural gas liquids (6%), and 282 Mcf per day of natural gas (6%). The 30-day rates established by the #26H and #27H wells are the highest achieved at Cyclone to date.
• Pirate – In Wilson County, no new wells were completed during the three months ended September 30, 2017. The Pirate leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2017.

EAGLE FORD SHALE TREND- EASTERN REGION

• Brazos & Robertson Counties – Lonestar owns a 50% WI/ 39% NRI in the Wildcat B#1H, which was placed onstream in May 2017. The Wildcat B#1H has now been producing for in excess of six months. The Company is encouraged by the productivity of the well, with cumulative production having eclipsed 250,000 barrels of oil equivalent, which is 66% greater than the average cumulative production from the 20 offset wells drilled by another operator and 21% higher than the most prolific producing offset well. The Wildcat B#1H was classified as "Probable" in the Company's third-party reserve report as of December 31, 2016. In that third-party report, gross reserves were estimated at 840,000 barrels of oil equivalent. At the request of the Company, our third-party engineer updated its reserves forecast for the Wildcat B#1H to account for actual production results. The updated reserves estimates yield a 29% increase in forecasted Estimated Ultimate Recovery ("EUR") to 1.1 million barrels of oil equivalent. The results of the Wildcat B#1H are encouraging, as Lonestar has a sizable leasehold position in the Wildcat Area in the deep Eagle Ford section in Brazos County, and notably, has not yet booked any proved reserves to the area. Lonestar has 9,555 gross / 6,420 net acres in the Wildcat area, which holds 38 extended-reach drilling locations, based on 800-foot spacing.

RECENT ACQUISITIONS 

• Karnes, Gonzales, Fayette, Lavaca, DeWitt Counties – Lonestar assumed operatorship of its recently announced acquisitions on June 15^th, 2017. The Company quickly transferred daily operations from third party contractors to Lonestar employees and has been successful in reducing personnel, chemicals and electricity costs. Lonestar has already conducted approximately $2 million of capital improvements on 41 of the 81 wells to bring the wells to the Company's operational standards. This spending has resulted in improved performance, reduced maintenance and September's production represented the highest month of production since April, 2017.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Tuesday, November 14, 2017 at 8:00 AM CST to discuss the third quarter 2017 results and operational highlights.

To access the conference call, participants should dial:

USA: 800-915-4731
International: +1 212-231-2900

A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately November 15, 2017.  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 have accumulated approximately 72,244 gross (57,172 net) acres in what we believe to be the formation's crude oil and condensate windows, as of September 30, 2017.  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 23, 2017 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.

The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms. Estimates of reserves in this press release are based on economic assumptions with regard to commodity prices that differ from the prices required by the SEC (historical 12 month average) to be used in calculating reserves estimates prepared in accordance with SEC definitions and guidelines. In addition, reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The estimates of reserves in this press release were prepared by the Company's internal reserve engineers and are based on various assumptions, including assumptions related to oil and natural gas prices as discussed above, drilling and operating expenses, capital expenditures, taxes and availability of funds and are subject to confirmation and revision from the Company's independent reserve engineering firm. The Company's internal estimates of reserves may not be indicative of or may differ materially from the year-end estimates of the Company's reserves prepared by a third party as a result of the SEC pricing and other assumptions employed by an independent reserve engineering firm. Investors are urged to consider closely the disclosure in the Company's filings with the SEC, which you can obtain from the SEC's website at www.sec.gov.

(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.