Lonestar Resources Announces Second Quarter 2017 Results And Provides Operational Update

FORT WORTH, Texas, Aug. 4, 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 June 30, 2017.

SECOND QUARTER HIGHLIGHTS

• Lonestar reported a 7% sequential increase in net oil and gas production during the three months ended June 30, 2017 ("2Q17").  Net oil and gas production averaged 5,635 Boe/d in the second quarter of 2017 compared to 5,266 Boe/d during three months ended March 31, 2017 ("1Q17"). The Company expects to grow production at an accelerated rate during the remainder of 2017 and 2018 as drilling activity accelerates on the Company's expanded acreage position.
• Adjusted EBITDAX for the quarter ended June 30, 2017 increased 10% to $12.7 million, compared to $11.5 million for the quarter ended March 31, 2017.  Please 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.
• On June 15, 2017, Lonestar closed its previously-announced acquisition of oil and gas properties in the Eagle Ford Shale play.  After post-closing adjustments, Lonestar paid total consideration of $99 million in cash and approximately 2.7 million shares of Lonestar Series B preferred stock, which are convertible into 2.7 million Class A common shares. The properties, located in Karnes, Gonzales, DeWitt, Lavaca and Fayette Counties, Texas, had Proved reserves of approximately 25.4 million barrels of crude oil, 3.1 million barrels of natural gas liquids, and 17.5 billion cubic feet of natural gas, equating to 31.4 million barrels of oil equivalent ("MMBOE"), as estimated by Lonestar, as of December 31, 2016.
• Lonestar estimates that net oil and gas production for the third quarter of 2017 will average between 7,600 Boe/d and 8,100 Boe/d, which would represent a sequential increase of 35 to 44% over our 2Q17 production.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, stated, "The second quarter is a springboard for Lonestar.  While the 2Q17 results minimally reflect the positive impact of our Eagle Ford Shale acquisitions, 3Q17 results will fully reflect their impact, as well as newly-completed wells.  Moreover, as we assimilate our new acquisitions, we are increasingly confident in our ability to enhance the value of these assets by better managing the current producing assets and by applying Lonestar's technical abilities to drilling new wells on the properties. We are also encouraged by the apparent coming slowdown in drilling and completion activity disclosed by a number of industry participants which should result in more pliable energy service costs and better availability at a time when Lonestar expects to scale-up our drilling and completion program.  In summary, we accomplished much in the first half of 2017, as we significantly grew Lonestar through acquisitions, had exceptional drilling results, and greatly strengthened our financial position and locked-in cash flow and returns by hedging.  As a result, we are well-positioned to build shareholder value into the second half of 2017 and beyond."

FINANCIAL UPDATE

• Lonestar reported a 7% sequential increase in net oil and gas production during the three months ended June 30, 2017 ("2Q17"). Net oil and gas production averaged 5,635 Boe/d in the second quarter of 2017 compared to 5,266 Boe/d during three months ended March 31, 2017 ("1Q17"). Production growth was the result of the addition of the Wildcat B1H well (50% WI) in May, and the inclusion of the recent acquisitions for 15 days of the second quarter.
• 2Q17 production volumes consisted of 3,564 barrels of oil per day (63%), 1,004 barrels of NGLs per day (18%), and 6,402 Mcf of natural gas per day (19%). The Company's production mix for the second quarter of 2017 was 81% liquid hydrocarbons. While 2Q17 production volumes increased 7%, crude oil production increased 10% sequentially, further improving the profitability of Lonestar's production.
• During the quarter ended June 30^, 2017, Lonestar placed 1.0 gross / 0.5 net wells onstream. Lonestar has placed 2 gross / 2 net wells online at Cyclone thus far in 3Q17, and anticipates placing an additional 2 gross / 2 net wells at Cyclone later in 3Q17.
• Lonestar's operating cost structure saw modest sequential increases in the three months ended June 30, 2017, which was predominately caused by the Marquis and Battlecat acquisitions and several non-recurring charges:
• Lease Operating Expense increased from $3.0 million in 1Q17 to $3.5 million in 2Q17. On a unit-of-production basis, LOE per Boe increased 10% sequentially, from $6.24 per Boe in 1Q17 to $6.87 per Boe in 2Q17. This increase was partially attributable to the inclusion of the Marquis and Battlecat assets for 15 days during the quarter, which currently bear higher operating costs. As Lonestar integrates the newly acquired properties, we anticipate reducing operating costs to superior levels.
• General & Administrative Expense was increased from $2.5 million in 1Q17 to $3.1 million in 2Q17. On a unit-of-production basis, G&A per Boe increased 16% sequentially, from $5.26 per Boe in 1Q17 to $6.12 per Boe in 2Q17. G&A expenses included $0.6 million of non-recurring expenses related legal expenses incurred for the establishment corporate governance charters, policies and procedures related to moving our domicile from Australian to Delaware and listing on the NASDAQ, s employee relocation expenses associated with our recent acquisitions, and the write-off project evaluation costs. Adjusted for these items, G&A expense would have been $2.5 million, or $4.85 per Boe in 2Q17.
• Interest Expense increased from $4.4 million in 1Q17 to $6.0 million in 2Q17. Included in Interest Expense was a charge of $1.1 million related to the early payment premium associated with the extinguishment of the Company's second lien debt. Excluding the non-recurring $1.1 million charge associated with the extinguishment of debt, adjusted interest expense would have been $4.9 million, or $9.56 per Boe in 2Q17.
• Since its inception, Lonestar has implemented a strategy using commodity derivatives to reduce financial risk and create a higher degree of certainty to our cash flows and our returns. As part of this ongoing strategy, Lonestar entered into additional WTI crude oil swaps across 2017, 2018, and 2019. Subsequent to the end of the second quarter:
• For 2017, the Company added swaps on 122,600 barrels a price of $49.85/bbl for the period of September 2017 through December 2017, increasing its coverage for the second half of 2017 to 664,800 barrels, or approximately 3,613 Bbls/day at a volume weighted average price of $53.10/bbl.
• For 2018, the Company added swaps on 509,000 barrels at a price of $50.17/bbl for the period of January 2018 to December 2018, increasing its total crude oil hedge position coverage for 2018 to 1,713,500, or approximately 4,695 Bbls/day at a volume weighted average price of $51.63/bbl.
• For 2019, the Company added swaps on 508,900 barrels at a price of $50.40/bbl for the period of January 2019 to December 2019, increasing its total crude oil hedge position coverage for 2019 to 1,069,600, or approximately 2,930 Bbls/day at a volume weighted average price of $49.16/bbl.
• For the period January 1, 2020 through June 30, 2020, the Company has WTI crude oil swaps covering approximately 1,119 Bbls/day at an average price of $48.90/bbl.
• Additionally, we hold contracts that hedge our natural gas production, covering 7,000 MMBTU/Day at a weighted average price of $3.36 per MMBtu for 2017.
• Lonestar reported a net loss attributable to its common stockholders of $23.5 million, or ($1.07) per weighted average share, during the three months ended June 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 2Q17 was $1.2 million, or ($0.06) per common share. Most notable among these items include: 1) During the three months ended June 30, 2017, the Company recorded an impairment charge of approximately $27.1 million relating to its West Poplar property located in Montana. Upon completion of the Company's recent acquisitions in the Eagle Ford Shale, the Company expects to direct virtually all of its capital expenditures towards development of its Eagle Ford Shale properties. Given the reduced likelihood of directing capital towards to the West Poplar asset, the Company fully impaired the asset in the second quarter; 2) Lonestar expensed $2.7 million in investment banking fees related to its recently announced Eagle Ford Shale property acquisitions; 3) the Company expensed $2.8 million related to the early extinguishment of its second lien notes; 4) the Company recognized a $3.8 million non-cash gain on our commodity derivative contracts related to the change in the mark-to-market value of our derivative contracts. Please see Non-GAAP Financial Measures for additional information.

OPERATIONS UPDATE

EAGLE FORD SHALE TREND- WESTERN REGION

• Asherton – In Dimmit County, no new wells were completed during the three months ended June 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 June 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 – Lonestar is pleased to report continued excellent performance out of its three wells drilled at Burns Ranch in 2017- the #8H, #9H and #10H.  Lonestar implemented a number of technical improvements to these wells which included: employing azimuthal gamma ray to stay in our petrophysically determined geo-target through multiple dip changes, increasing proppant concentrations to 2,000 lb/ft, which included the use of diverters, and more conservatively choke managing production to maintain lower Gas-Oil-Ratios ("GOR") in our Generation 5 wells ("Gen 5").  Lonestar is encouraged with the results of our Gen 5 wells thus far. We believe that our advancement in stimulation design has resulted in the increased effectiveness of the Gen 5 well stimulations in contacting additional reservoir rock volume that allows for a more complex fracture volume in the same fracture half-length, resulting in better fracture and drainage efficiency.  At 57% pressure drawdown, our Gen 3 wells had recovered 40,000 barrels of oil.  By contrast, our Gen 5 wells have recovered over 70,000 barrels of oil with 57% pressure drawdown, an improvement of 75%.  We believe that the rapid increase in GOR that we experienced in our Gen 3 wells impaired oil EUR's by prematurely reducing flowing pressures below bubble point.  As a result, we have been more stringent in our choke management techniques on our Gen 4 and Gen 5 wells as part of our oil maximization strategy.  At 70,000 barrels of oil recovery, our Gen 3 wells exhibited GOR's of 2,700 scf/bbl, while our newer Gen 5 wells, which have been more stringently choke-managed, have recovered 70,000 barrels of oil while registering a GOR of 1,300 scf/bbl.  Lonestar is drilling again at Burns Ranch.  The B1H and B2H on Burns Ranch have been permitted with the Texas Railroad Commission with projected total depths of 17,900 and 18,000 feet respectively. Projected perforated intervals for these wells will be approximately 9,000 feet. Lonestar owns a 92% working interest and a 69% net revenue interest in these wells.  Upon completion 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, or 95% of our total leasehold.
• Horned Frog – In La Salle County, no new wells were completed during the three months ended June 30, 2017.  Lonestar holds a total of 5,828 gross / 4,642 net acres in the Horned Frog area.  Our 4,402 acre block acquired by farm-in is Held By Production, while the 1,426 gross / 1,071 net acres we acquired in 2017 is in primary term.  We had previously planned to drill two wells on this block in 2017, but have elected to defer these wells, and Lonestar currently plans to drill two 10,000-foot laterals in the first quarter of 2018.

EAGLE FORD SHALE TREND- CENTRAL REGION

• Cyclone – During the second quarter of 2017, Lonestar drilled and completed the Cyclone #4H and Cyclone #5H.  Lonestar has a 100% working interest ("WI") in these wells.  These wells were fracture-stimulated in engineered completions with an average proppant concentration of 1,820 pounds per foot over 30 stages per well, and utilized diverters.  The #4H and #5H were placed into flowback operations on July 1, 2017, and therefore did not contribute to the Company's second quarter 2017 financial results.  The Cyclone #4H was completed with a perforated interval of 8,706 feet and tested 648 bbls/d and 405 Mcf/d, or 741 Boe/d (three-stream) on a 22/64'' choke.  The Cyclone #5H was completed with a perforated interval of 9,286 and tested 670 bbls/d and 327 Mcf/d, or 771 Boe/d (three-stream) on a 22/64'' choke.  On average, these two new producers have recovered 7% of their frac load, to date.  It is notable that both of these wells were classified at Probable in the Company's third-party reserve report as of December 31, 2016, which has positive implications for our Proved reserves at year-end 2017.  In addition to these completions, Lonestar has drilled the Cyclone #26H and #27H to a total depth of 18,125 and 18,098 respectively.  The Cyclone #26H is planned to be stimulated in 29 stages with a perforated interval of 8,600 feet and the Cyclone #27H is planned to be stimulated in 28 stages with a perforated interval of 8,500 feet.  Fracture stimulation operations on these wells are scheduled to commence in August, 2017.  Lonestar has a 100% working interest ("WI") and 79% net revenue interest ("NRI") in these wells.  Lonestar continues to encounter success in leasing additional tracts which are contiguous to its Cyclone leasehold.  At December 31, 2016, our acreage totaled 2,906 gross / 2,656 net acres, which accommodated 26 gross / 24 net laterals.  At June 30, 2017, we had increased our leasehold to 3,762 gross / 3,512 net acres, which accommodates 38 gross / 36 net laterals, which in several cases have been elongated with our leasehold acquisitions.  Lonestar estimates that when production is established on its Cyclone #26H and #27H wells, approximately 86% of its leasehold in the Cyclone area will be Held By Production.
• Pirate – Lonestar completed the Pirate #M1H and Pirate #N1H wells in February, 2017.  These wells tested at rates of 331 Boe/d and 429 Boe/d respectively.  As of June 30, 2017, the Pirate #M1H produced 36,650 BOE and is currently producing 271 Boepd while the Pirate #N1H has produced 47,600 BOE and is currently producing 309 Boepd. Lonestar holds a 100% WI / 76.4% NRI in these wells. 

EAGLE FORD SHALE TREND- EASTERN REGION

• Brazos & Robertson Counties – Lonestar owns a 50% WI/ 38% NRI in the Wildcat B1H, which was placed onstream in May, 2017.  The Company previously reported that the Wildcat B1H well established a 30‐day maximum production rate of 2,123 barrels of oil equivalent per day (Boe/d), consisting of 890 barrels of oil per day (42%), 764 barrels of natural gas liquids (36%) and 2,815 Mcf per day of natural gas (22%).  Today, Lonestar reports that the Wildcat B1H has produced at a 60-day rate which has averaged 1,867 barrels of oil equivalent per day (Boe/d), consisting of 817 barrels of oil per day (44%), 610 barrels of natural gas liquids (33%), and 2,634 Mcf per day of natural gas (23%).  These rates were achieved on a 20/64‐inch choke, as Lonestar remains conservative in its choke management procedures, with a goal of maximizing crude oil recoveries.  The Wildcat B1H was classified at Probable in the Company's third-party reserve report as of December 31, 2016.  The results of the Wildcat B1H are extremely 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 booked any Proved reserves to the area.  Lonestar estimates that its leasehold in the Wildcat area holds 38 potential extended-reach drilling locations, based on 800-foot spacing.  Lonestar has interpreted its 3-D seismic data across its leasehold, and it now conducting rock properties analysis with a goal of concluding its resource assessment in September, at which point in time it will determine a capital plan for the asset.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Monday, August 7, 2017 at 8:00 AM CDT to discuss the second quarter 2017 results and operational highlights.

To access the conference call, participants should dial:

USA: 800-950-8523

International: +1 212-231-2939

A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately August 8, 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 June 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.