Lonestar Resources US, Inc. Announces Third Quarter 2016 Results

FORT WORTH, Texas, Nov. 10, 2016 /PRNewswire/ -- Lonestar Resources U.S., 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, 2016 ("3Q16").

THIRD QUARTER HIGHLIGHTS

• During the quarter, the Company was primarily focused on balance sheet improvements, and therefore completed no new Eagle Ford Shale wells during the third quarter of 2016.  Consequently, the Company experienced a 10% decrease in net oil and gas production to 5,921 Boe/d during 3Q16, compared to 6,614 Boe/d during the three months ended September 30, 2015 ("3Q15").  In the third quarter of 2016, 75% of the Company's production was crude oil and NGLs.  The Company production from its focus, the Eagle Ford Shale play of south Texas, fell by 8% in 3Q16 versus 3Q15 results, to 5,485 Boe/d primarily due to the lack of new wells added during the quarter. The sale of the Company's Morgan's Bluff property also contributed to lower volumes.
• Lonestar reported a net loss of $11.3 million for 3Q16 versus a net income of $6.6 million in 3Q15.  This loss in 3Q16 includes $5.2 million associated with non-cash, mark-to-market revaluation of Lonestar's crude oil hedge portfolio and equity warrants and a $29.4 million gain on the disposal of bonds largely offset by a $29.1 million impairment on our Conventional assets.
• Adjusted EBITDAX for the third quarter of 2016 was $14.6 million compared to $21.3 million for 3Q15, primarily due to a 10% decrease in production volumes coupled with a 26% decrease in revenues due to a sharp decline in West Texas Intermediate oil prices and Henry Hub gas prices compared to 3Q15. 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.

CORPORATE UPDATE

Corporate

During the third quarter of 2016, Lonestar was primarily focused on improving its balance sheet, liquidity profile and cost structure.  The Company consummated a series of transactions during the quarter to achieve these goals:

• As of September 30, 2016, in a series of open-market transactions, Lonestar had purchased $68.2 million of its 8.750% Senior Unsecured Notes due April 15, 2019, leaving $151.8 million of these Notes outstanding. 
• Lonestar funded the repurchases of its Senior Unsecured Notes through the incurrence of debt on its 12% Second Lien facility. As of September 30, 2016, the Company had drawn $38.0 million on this facility. The facility had remaining availability of $11.9 million as of that date.
• As of September 30, 2016, Lonestar's borrowings under its Senior Secured Credit Facility were $94.5 million.

Subsequent to the end of the quarter, on October 31, 2016, Lonestar concluded a sale of certain of its non-core Conventional assets.  In total, the Company has received a total of $15.8 million in proceeds from the sale of these assets which carried substantially higher operating costs than its core Eagle Ford Shale assets.

Operational

• Lonestar completed no new Eagle Ford Shale wells during the third quarter of 2016, and consequently reported a 10% decrease in total company production in the third quarter of 2016 and an 8% decrease in its Eagle Ford Shale production. Third quarter 2016 volumes of 5,921 Boe/d consisted of 3,175 barrels of oil per day, 1,238 barrels of NGLs per day, and 9,041 Mcf of natural gas per day.  The Company's production mix for the third quarter of 2016 was 75% liquid hydrocarbons.  The Company produced 6,348 Boe/d through the first nine months of 2016, an increase of 6% over the comparable period in 2015.  
• Lonestar's lease operating expenses for the third quarter of 2016 were $4.0 million, representing a 6% decrease over 3Q15 lease operating expenses of $4.2 million. On a per unit basis, Lonestar's lease operating expenses per BOE was reduced 5% from $6.97 per BOE in 3Q15 to $7.36 per BOE in 3Q16. 
• The sale of the Company's Conventional assets is expected to not only further sharpen the focus of its management and technical teams towards its core Eagle Ford Shale assets, but also to improve the Company's operating cost structure.  To illustrate, in the third quarter of 2016, the Company's total lease operating expenses were $7.36 per BOE.  Giving effect to the sale of the Conventional assets, lease operating expenses would have been $6.64 per BOE during the period.
• Crude oil hedging continues to be an important element of Lonestar's strategy. We believe crude oil hedging provides increased visibility to cash flow streams and associated liquidity in the current crude oil price environment, and augments the Company's borrowing base.  For 2016, the Company has West Texas Intermediate ("WTI") swaps covering 2,528 barrels of oil per day for October 2016 through December 2016 at an average strike price of $70.41 per barrel.  As previously announced, the Company has three-way collars covering 1,000 bbls/d for calendar 2017, which provide an effective floor of $55.25 per barrel with WTI prices between $40.00 per barrel and $60.00 per barrel but also gives upside to $80.25 per barrel.   In October 2016, we entered into additional WTI crude oil swaps covering a total of 1,000 bbls/d for the period of January 2017 through December 2017 at an average strike price of $52.90 per barrel. The addition of these swaps increased our total 2017 crude oil hedge position coverage to a total of approximately 2,500 barrels of oil per day at an average strike price of $53.43 per barrel. Also in October 2016, we entered into WTI crude oil swaps covering a total of 1,000 bbls/d for the period of January 2018 through December 2018 at an average strike price of $54.18 per barrel. Lastly we entered into Henry Hub natural gas swaps covering a total of 7,000 mcf/d for the period of January 2017 through December 2017 at an average strike price of $3.36 per million British Thermal Unit "MMBTU".
• Effective August 1, 2016, Lonestar added to its Eagle Ford Shale leasehold and reserves position by issuing 500,227 shares of its Class A common stock to Juneau Energy, LLC (98% owned by Leucadia National Corp.) in exchange for 2,567 gross / 1,284 net acres in Brazos County, which includes the purchase of a 50.0% Working Interest ("WI")/ 39% Net Revenue Interest ("NRI") in two wells which hold all of the acreage by production. On August 1, 2016, Lonestar assumed operatorship of this leasehold.  In the month of July, these two wells produced 650 Boe/d gross / 254 Boe/d net.  The acreage has the potential for 11 horizontal wells.  Since assuming operations of the property, Lonestar has made a number of operational improvements that have improved productivity of the two producing wells while substantially reducing operating costs.  As a result, Lonestar's internal reserves estimates for proved and probable reserves have increased from 1.1 million barrels of oil equivalent ("MMBOE") at closing to its current estimate of 1.6 MMBOE.

EAGLE FORD SHALE TREND- WESTERN REGION

• Asherton – In central Dimmit County, no new wells were completed during the three months ended September 30, 2016.  Production rates from the four producing wells continued to outperform the third-party engineering projections.  The Asherton leasehold is held by production, and Lonestar does not plan drilling activity here in 2016.
• Beall Ranch – In Dimmit County, Lonestar continues to operate the Beall Ranch #20H - #22H, completed in the first quarter of 2016 and the first three wells completed in partnership with Schlumberger as part of the companies' Geo-Engineered Completion Alliance ("GECA").  While still preliminary, the production results during the first 225 days onstream are encouraging, as the average cumulative production from these wells of 64,000 barrels of oil is 11% higher than that of the #26H - #28H wells, drilled 12 months prior, when compared on a barrel-per-lateral-foot basis for the same period of time. The #26H-#28H wells utilized certain elements of the GECA, which Lonestar believes were significant contributors to the 42% outperformance as compared to the offsets, the #32H-#34H, which were completed in July, 2015.  In total, through two iterations of technology improvements, Lonestar has achieved a 58% improvement in cumulative oil production per lateral foot.  Lonestar is encouraged by the results of the GECA to date, and has been applying them across its portfolio during 2016.
• Burns Ranch Area –In August 2016, Lonestar executed a lease swap agreement with another operator and consolidated Lonestar's leasehold position so that we can now drill at our own discretion.  Within the leasehold associated with this trade prior to this lease swap, Lonestar had 19 gross/15.1 net laterals engineered totaling 152,000 lateral feet. Following the lease swap, Lonestar has 18 gross/16.1 net laterals totaling 151,000 lateral feet. Lonestar recently completed drilling operations on the Burns Ranch Eagle Ford #8H, #9H and #10H wells with lateral lengths of approximately 9,620, 9,440 and 8,460 feet, respectively.  These wells were drilled to an average measured depth of 18,007 feet and were drilled from spud to total depth in an average of 13.3 days.  These results compare favorably with the wells that Lonestar drilled in 2015 on the Burns Ranch property, which were drilled to an average measured depth of 16,617 feet and were drilled from spud to total depth in an average of 24.3 days.  Lonestar's recently drilled Burns Ranch Eagle Ford wells achieved a 97% improvement in rates of penetration, with the 2016 wells improving to 1,351 feet per day compared to the Burns Ranch Eagle Ford wells drilled in 2015, which averaged 683 feet per day. Lonestar plans to utilize BroadBand diverters on the #8H, #9H and #10H, which will allow Lonestar to set stage spacing at 300 foot increments, reducing the number of frac stages and associated costs while achieving a designed proppant concentration of up to 2,000 pounds per foot, which would be the highest in the Company's history.  Based on availability of frac crews capable of conducting pressure pumping operations with BroadBand proppant diverter, Lonestar anticipates that it will commence fracture stimulation operations in mid-November 2016. Production from these three wells is expected to increase the leasehold that is held by production at Burns Ranch from 2,712 net acres to 3,279 net acres, which equates to 86% of our total net leasehold at Burns Ranch. 
• Horned Frog – In southern La Salle County, no new wells were completed during the three months ended September 30, 2016. Lonestar does not plan drilling activity on the Horned Frog property in the remainder of 2016, having held on the leasehold by production with our drilling activity during 2015.

EAGLE FORD SHALE TREND- CENTRAL REGION

• Southern Gonzales County –Lonestar continues to operate its Cyclone #9H and #10H wells, which were placed onstream on May 12, 2016.  Lonestar drilled and completed the Cyclone #9H & #10H with an average perforated interval of 6,685 feet. Lonestar holds a 42% WI / 33% NRI in these wells.  The wells were fracture-stimulated with an average proppant concentration of 1,518 pounds per foot, utilizing BroadBand diverters, which allowed us to frac on 300-foot stage spacing.  The Cyclone #9H tested 543 bbl/d and 239 Mcf/d, or 598 Boe/d on an 18/64" choke and achieved a 30-day production rate of 486 Boe/d.  The Cyclone #10H tested 576 bbl/d and 239 Mcf/d, or 631 Boe/d on an 18/64" choke and achieved a 30-day production rate of 521 Boe/d.  After being placed on jet pump during the quarter, the wells are outperforming the Company's prior internal expectations. The #9H has produced cumulative production of 56,900 bbls of oil in 180 days. Meanwhile, the #10H has produced cumulative production of 59,600 bbls of oil in 180 days.  Based on the results of its initial wells on the Cyclone project, Lonestar has executed agreements to lease an additional 1,456 gross / 1,322 net acres that directly offset the Cyclone #9H and #10H wells. These additions are expected to increase Lonestar's total leasehold in its Cyclone project to 2,906 gross / 2,656 net acres which is expected to accommodate 29 additional laterals with an average lateral length exceeding 7,000 feet. At December 31, 2015, Lonestar had no proved reserves booked to the Cyclone property.

EAGLE FORD SHALE TREND- EASTERN REGION

• Brazos & Robertson Counties – In central Brazos County, Lonestar has permitted two 8,000-foot laterals with the Texas Railroad Commission and on March 8^th, 2016 Lonestar was granted operations permits with the City of College Station. The Company is encouraged by the results of offset drilling by a leading operator, who recently announced 30-day production rates on four wells immediately offsetting Lonestar's leasehold, which have ranged from 1,587 to 1,973 BOE per day.  Based on its current drilling schedule, Lonestar currently plans to drill these wells in the first quarter of 2017. 

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Friday, November 11, 2016 at 8:00 AM CST to discuss the third quarter 2016 results and operational highlights.

To access the conference call, participants should dial:

     USA: 877-221-2749

     International: 212-271-4657

A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately November 11, 2016.  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 38,242 gross (33,951 net) acres in what we believe to be the formation's crude oil and condensate windows, as of December 31, 2015. As of December 31, 2015, we also held a portfolio of conventional, long-lived, crude oil-weighted onshore assets in Texas and are conducting resource evaluation on approximately 44,084 gross (28,655 net) acres in the West Poplar area of the Bakken-Three Forks trend in Roosevelt County, Montana. For more information, please visit www.lonestarresources.com.

FORWARD-LOOKING STATEMENTS

This press release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements contained in this press release that do not relate to matters of historical fact should be considered forward-looking statements, including, without limitation, beliefs and expectations with respect to: discovery and development of crude oil, NGLs and natural gas reserves; drilling and completion of wells and the size of Lonestar's leasehold; cash flows and liquidity, including statements regarding the expected benefits of the Company's crude oil hedging;  availability and terms of capital; timing, amount and rate of future production of crude oil, NGLs and natural gas; Lonestar's business strategy, including its partnership with Schlumberger and the GECA; and the expected benefits from the GECA.

These forward-looking statements are based on management's current expectations. These statements are neither promises nor guarantees, but involve known and unknown risks, uncertainties and other important factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements, including, but 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; ability to successfully replace proved producing reserves; substantial capital expenditures required 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, which could increase costs and materially alter the occurrence or timing of their drilling; 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, which could materially adversely affect Lonestar's crude oil, natural gas and NGLs reserves and future production; inaccuracies in assumptions made in estimating proved reserves; Lonestar's limited control over activities in properties Lonestar does not operate; customer concentration risk; potential inconsistency between the present value of future net revenues from Lonestar's proved reserves and the current market value of Lonestar's estimated oil and natural gas reserves; risks related to derivative activities; covenant restrictions related to the revolving credit facility and the indenture that governs 8.75% Senior Notes due 2019; losses resulting from title deficiencies; risks related to health, safety and environmental laws and regulations; additional regulation of hydraulic fracturing, which has recently come under increased scrutiny; 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; recent federal legislation that may have adverse impact on ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with the business;  and risks in connection with acquisitions and integration. These and other important factors discussed under the caption "Risk Factors" in the Company's Registration Statement on Form 10, as amended and filed with the Securities and Exchange Commission, or the SEC, on June 9, 2016, along with our other reports filed with the SEC could cause actual results to differ materially from those indicated by the forward-looking statements made in this press release. Any such forward-looking statements represent management's estimates as of the date of this press release. While we may elect to update such forward-looking statements at some point in the future, we disclaim any obligation to do so, even if subsequent events cause our views to change. These forward-looking statements should not be relied upon as representing our views as of any date subsequent to the date of this press release.

(Financial Statements to Follow)

NON-GAAP FINANCIAL MEASURES

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.

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SOURCE Lonestar Resources US, Inc.