Lonestar Announces Year Ended 2017 Results And Provides Operational Update

FORT WORTH, Texas, March 28, 2018 /PRNewswire/ -- Lonestar Resources US Inc. (NASDAQ: LONE) (including its subsidiaries, "Lonestar," "we," "us," "our" or the "Company") today reported its financial and operating results for the three months and year ended December 31, 2017.

RECENT HIGHLIGHTS

• Lonestar reported a 59% increase in net oil and gas production to 7,272 Boe/d during the three months ended December 31, 2017 ("4Q17"), compared to 4,560 Boe/d for the three months ended December 31, 2016 ("4Q16"). The increase in production was attributable to the contribution from the drilling of new Eagle Ford Shale wells and additions to production associated with our acquisition of producing properties in June, 2017.
• Lonestar issued production guidance of 7,550 to 7,650 Boe/d for the first quarter of 2018. Of note is that Lonestar estimates that March production benefitted partially from the addition of the Company's Horned Frog wells, and estimates that March 2018 production will rise to an average of 8,350 to 8,450 Boe/d and that production will exit the first quarter at rates of 9,500 to 10,000 Boe/d.
• Lonestar has disclosed its Standardized Measure of $479.6 million, as of December 31, 2017, which is an increase of 229% compared to its Standardized Measure of $145.8 million, as of December 31, 2016. Lonestar recently announced the PV-10 of its Proved reserves as per SEC guidelines, as of December 31, 2017.  On this basis, the Company's proved reserves increased 82% to 73.6 million barrels of oil equivalent ("MMBOE") while SEC PV-10 also increased by 223% to $538.3 million.  On this basis, Lonestar's proved reserves are comprised of 50.7 million barrels of crude oil, 10.9 million barrels of Natural Gas Liquids and 73.6 Billion cubic feet of natural gas.  On an energy equivalent basis, Lonestar's proved reserves are 83% liquid hydrocarbons.
• Lonestar recently announced the PV-10 of its Proved reserves at NYMEX strip prices, as of December 31, 2017.  On this basis, the Company's proved reserves increased 70% to 76.2 million barrels of oil equivalent ("MMBOE") while PV-10 also increased by 70% to $647.6 million. Lonestar's proved reserves are comprised of 52.5 million barrels of crude oil, 11.3 million barrels of Natural Gas Liquids and 74.9 Billion cubic feet of natural gas. On an energy equivalent basis, Lonestar's proved reserves are 83% liquid hydrocarbons.
• In 2017, Lonestar's all-sources reserves replacement ratio was 1,499% and its all-sources finding & development costs ("F&D") were $6.07 per BOE. 2017's results mark the third consecutive year during which Lonestar has maintained all-sources finding & development costs below $12.00 per Boe. Moreover, over the past five years, Lonestar has delivered all-sources reserve replacement of 778% and an all-sources finding & onstream cost of $8.94 per Boe.
• In December 2017, the Company agreed to issue $250.0 million of 11.250% senior unsecured notes due 2023 (the "11.250% Senior Notes") to U.S.-based institutional investors. The transaction closed on January 4, 2018. The net proceeds of $244.4 million were used to fully retire the Company's 8.750% Senior Notes due April, 2019, which included principal, interest and prepayment premium and totaled approximately $162 million. The remaining net proceeds were used to reduce borrowings under the Senior Secured Credit Facility. Pro forma the issuance of the 11.250% Senior Notes, as of December 31, 2017, we had approximately $100 million available on our $160.0 million Senior Secured Credit Facility.
• Lonestar reported 77% decrease in net loss attributable to its common stockholders of $13.7 million, or ($0.58) per weighted average share, during the three months ended December 31, 2017 compared to a net loss of $58.9 million, or ($6.19) per weighted average share during the three months ended December 31, 2016. 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 2017 was ($0.7) million, or ($0.03) per common share. Most notable among these items include: unrealized hedging losses on financial derivatives; impairment of oil and gas properties; and stock-based compensation. Please see Non-GAAP Financial Measures for additional information.
• Lonestar reported a 64% increase in Adjusted EBITDAX for the three months ended December 31, 2017 of $20.5 million compared to $12.5 million for the three months ended December 31, 2016. This improvement was driven by a 59% increase in production and a 6% 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 income (loss) to Adjusted EBITDAX, and the reasons for its use.
• Lonestar recently executed an agreement with a leading energy service provider which dedicates a frac spread to the Company for 2018. This agreement should significantly improve our ability to turn wells into production in a timely and efficient fashion, delivering more predictable results to our shareholders.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, stated, "Over the past two years, we have dramatically strengthened our balance sheet and have made significant technical advancements to drilling, completing and producing our Eagle Ford Shale wells. As a result, 2018 will be a breakout year  for Lonestar.  Our 2018 full-year production guidance remains at 10,000 to 10,700 Boe/day, and represents approximately a 65% increase versus 2017.  Our Adjusted EBITDAX guidance of $100 to $110 million represents similar growth versus 2017 results. The combination of significantly higher cash flows and our currently contemplated capital spending are expected to drive down our Debt to EBITDAX ratio to below 3.0x by year-end 2018.  Our stronger financial position has allowed us to secure dedicated drilling and pressure pumping services, which in turn will greatly enhance our ability to control the quality and timing of our operations with a goal of delivering production more quickly.  The impact of our progress is already evident, as our first four wells of 2018 are outperforming our expectations.  Additionally, we have drilled our first three wells in Karnes County and have scheduled to begin fracture stimulation operations in early April.  We are excited about the success and momentum we are created to date in 2018, with first quarter exit rates approaching 10,000 Boe/day, providing us increased confidence that we will fully deliver on our 2018 guidance.  Most importantly, we are now well-positioned to consistently increase shareholder value in 2018 and in the years ahead."

OPERATIONAL UPDATE

• Lonestar reported net oil and gas production of 7,272 Boe/d during the three months ended December 31, 2017, compared to 4,560 Boe/d during the three months ended December 31, 2016. Production volumes during the three months ended December 2017 consisted of 5,217 barrels of oil per day (72%), 1,062 barrels of NGLs per day (14%), and 5,957 Mcf of natural gas per day (14%). The Company's production mix for the three months ended 2017 was 86% liquid hydrocarbons. Lonestar's net oil and gas production was hampered by: 1) delays in arrival and timely execution on its Hawkeye wells, which are now performing above expectations; and 2) a series of offset fracs, which temporarily reduced volumes from 16 wells. Lonestar estimates that these frac hits reduced 4Q17 production by an average of 173 Boe/d. Lonestar is pleased to report that in aggregate these 16 wells are now producing at higher rates than before they were hit.
• Lonestar's non-tax cash operating cost structure saw significant sequential improvement in the year ended December 31, 2017, which was achieved through stringent cost control, operational efficiencies and expanding production volumes:
• Lease Operating Expenses ("LOE") for the three months ended December 31, 2017 were $5.8 million, representing a 66% increase in lease operating expenses of $3.5 million in the three months ended December 31, 2016. This increase was largely due to additional lease operating expenses associated with our acquisitions of producing properties in June 2017, offset fracs at our Battlecat, Beall Ranch, Burns Ranch, and Marquis properties, and workovers at our newly acquired 6,257 gross / 1,655 net acres in Gonzales County, Texas to bring historical wells back to production. On a unit-of-production basis, lease operating expenses remained relatively flat increasing 3% to $8.65 per Boe for the three months ended December 31, 2017 from $8.37 per Boe in the year ended December 31, 2016. 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.
• General & Administrative Expenses ("G&A") remained relatively flat year over year, increasing from $2.8 million in the three months ended December 31, 2106 to $2.9 million in the three months ended December 31, 2017. On a unit-of-production basis, G&A per Boe was reduced 50% year over year, from $6.72 per Boe in 2016 to $3.51 per Boe in 2017. For 2018, the Company expects G&A to be between $2.80 and $3.00 per Boe.
• Interest Expense was reduced year over year from $5.9 million in the three months ended December 31, 2016 to $5.3 million in 2017. This was primarily a result of the repurchase of $68.2 million of 8.750% Senior Notes in the second half of 2016. On a unit-of-production basis, interest per Boe was reduced 46% year over year from $14.01 per Boe in 2016 to $7.95 per Boe in 2017. 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 are producing at rates that exceed our forecasts. The Company has already brought online 4 gross / 3.8 net wells. In January, our first two wells on our Hawkeye property in Gonzales County tested at average rates of 1,115 Boe/d a three-stream basis. Last week, we placed our second two wells online at our Horned Frog property in La Salle County and are already showing promising results, registering average test rates of 1,939 Boe/d. Additionally, Lonestar has drilled its first 3 wells in Karnes County, and they are scheduled to commence fracture stimulation with our newly-dedicated frac spread in early April.

EAGLE FORD SHALE TREND- WESTERN REGION

Asherton – In central Dimmit County, no new wells were completed during the three months ended December 31, 2017.  The Asherton 9HS, the Company's longest flowing well, which had been flowing unassisted since March, 2014, was put on gas lift after it was hit by an offset frac.  Production rates have since recovered, and the production rates from all four producing wells continued to outperform the third-party engineering projections.  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 December 31, 2017.  The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2018.  

Burns Ranch Area – On November 23, 2017, Lonestar commenced flowback operations of the Burns Ranch Eagle Ford #B 1H and B #2H wells with lateral lengths of approximately 9,470 and 9,450 feet, respectively.  These wells were drilled to an average measured depth of 17,950 feet and were drilled from spud to total depth in an average of 19.5 days. Lonestar has a 92.4% WI and 69.3% NRI in these wells. These wells are tracking our type curves. With the additions of these wells, Lonestar has 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 Burns Ranch is now 100% HBP'd.

Horned Frog – In La Salle County, we recently completed the Horned Frog G #1H and H #1H. These wells were drilled to total measured depths of approximately 22,800 and 20,950 feet, respectively and were drilled from spud to total depth in an average of 12 days.  These wells 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.  Flowback operations commenced on March 20th and productivity is promising. With only 6 days since first production and 2% of load recovered, the Horned Frog G#1H, which has a perforated interval of 12,280 feet, is testing at three-stream rates of 1,944 Boe/d, consisting of 442 Bbls/d of oil, 518 Bbls/d of natural gas liquids and 5,900 Mcf/d on a 28/64'' choke. With only 2% of load recovered, the Horned Frog H #1H has been in flowback for 8 days. The H #1H has a perforated interval of 10,445 feet, and is testing at three-stream rates 1,938 Boe/d, consisting of 426 Bbls/d of oil, 522 Bbls/d of natural gas liquids and 5,943 Mcf/d, on a 26/64'' choke. 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 has a 100% WI and 80% NRI in these wells.  Additionally, Lonestar continues to expand its leasehold position via primary term leasing activity in the Horned Frog area at costs that are in-line with its historically low leasehold costs.  Ongoing leasing efforts prevent the Company from disclosing commercial terms at this time, but we believe that our efforts to date will allow Lonestar to replace 200% of our estimated 2018 production.  Lonestar has commenced drilling operations on the Horned Frog North West #2H and #3H, in which it holds a 100% WI.

EAGLE FORD SHALE TREND- CENTRAL REGION

Cyclone – 2017 was a significant year for Lonestar in Southern Gonzales County, Texas.  The Company increased its acreage from 3,488 gross / 2,798 net acres to 10,663 gross / 5,299 net acres, its total drilling locations from 26 to 46, and its average lateral length of its drilling locations from 7,800 to 8,100 year over year. In addition, with the drilling and completion of the Cyclone #4H, Cyclone #5H, Cyclone #26H, and Cyclone #27H, the Company increased its acreage which is Held By Production to approximately 86%. Our operations team was also able to make significant strides by further optimizing our fracture-stimulated engineered completions that utilize diverters and better refining our geo-targeting with each additional well we drill. Our first two wells, the Cyclone #9H and Cyclone #10H, drilled and completed in 2016, averaged 90-day initial production rates of 368 Bbls and 187 Mcf, or 411 Boe/d (three-stream). Our second set of wells, the Cyclone #4H and Cyclone #5H, drilled and completed in July 2017, averaged 90-day initial production rates of 469 Bbls and 281 Mcf, or 555 Boe/d (three-stream), an increase of 35% over the Cyclone #9H and Cyclone #10H.  Our most recent set of wells, the Cyclone #26H and Cyclone #27H, drilled and completed in September 2017, averaged 90-day initial production rates of 499 Bbls and 250 Mcf, or 576 Boe/d (three-stream), a 40% increase over the #9H and #10H. With these successes, the Company is planning to continue to develop this acreage in 2018 by drilling an additional 4 gross / 4.0 net wells in the Cyclone/Hawkeye area over the remainder of the year.

Hawkeye – The Hawkeye property was acquired by Lonestar in the fourth quarter of 2017 for $3.4 million and consists of 6,257 gross / 1,655 net acres in Gonzales County, Texas.  The Hawkeye leasehold contains 15 additional Eagle Ford Shale locations, most of which range in lateral length from 8,000 to 11,000 feet. Under Lonestar's operatorship, production from the existing producing wells has increased from 49 Boe per day to 219 Boe per day.  In January 2018, Lonestar completed its first two wells on the Hawkeye property.

• Hawkeye #1H- Lonestar has an 87.5% WI / 63.4% NRI. The well has a perforated lateral length of 10,910 feet and was fracture stimulated with 1,810 pounds of proppant per foot over 36 stages. The well tested initial rates of 1,071 Bbls/d and 601 Mcf/d, or 1,209 Boe/d (three-stream) on a 28/64'' choke. The Hawkeye #1H produced a 30-day production rate of 1,003 Boe/d, consisting of 889 barrels of oil per day (89%), 52 barrels of natural gas liquids (1%), and 372 Mcf per day of natural gas (6%). The Hawkeye #1H well continues to outperform our forecasts.
• Hawkeye #2H- Lonestar has an 87.5% WI / 63.4% NRI. The well has a perforated lateral length of 10,910 feet and was fracture stimulated with 1,867 pounds of proppant per foot over 28 stages. The well tested initial rates of 907 Bbls/d and 494 Mcf/d, or 1,020 Boe/d (three-stream) on a 22/64'' choke. The Hawkeye #1H produced a 30-day production rate of 872 Boe/d, consisting of 773 barrels of oil per day (89%), 45 barrels of natural gas liquids (5%), and 324 Mcf per day of natural gas (6%). The Hawkeye #2H well continues to outperform our forecasts.

Karnes County – In February 2018, the Company drilled the Georg EF #18H, Georg EF #19H, and Georg EF #20H to total measured depths of approximately 15,450 feet. We project that these wells will have perforated intervals of approximately 6,300 feet.  Lonestar owns an 80% WI and 61% NRI in these wells.  Fracture stimulation of these wells is scheduled for early April with our dedicated frac spread with flowback operations expected to begin in May.  These wells mark the first three development wells on properties we acquired in Karnes County in June, 2017, and are the first of 9 wells we plan to be drill and complete on the properties this year. 

Pirate – In Wilson County, no new wells were completed during the three months ended December 31, 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 10 months and the Company continues to be encouraged by the productivity of the well, with cumulative production having eclipsed 320,000 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 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.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Thursday, March 29, 2018 at 8:00 AM CDT to discuss the fourth quarter 2017 results and operational highlights.

To access the conference call, participants should dial:

USA: 800-908-9173
International: +1 212-231-2935

A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately March 30, 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 78,196 gross (58,262 net) acres in what we believe to be the formation's crude oil and condensate windows, as of December 31, 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.

RESERVES DISCLOSURES

Based on rules of the U.S. Securities and Exchange Commission, for the year ended December 31, 2017, Lonestar's proved reserves were estimated using the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month preceding the 12 months prior to the end of the reporting period. This methodology resulted in an average oil price of $51.34 per barrel and an average natural gas price of $2.96 per million British Thermal Units ("MMBTU"), an increase of 20% for both crude oil and natural gas, as compared to an average of oil price of $42.75 per barrel and an average natural gas price of $2.46 per MMBTU used to estimate Lonestar's proved reserves for the year ended December 31, 2016.

The average future prices for benchmark commodities used in determining our Strip Pricing for the year ended December 31, 2017 reserves were $59.55 for oil for 2018, $56.22 for 2019, $53.79 for 2020, $52.29 for 2021, $51.70 for 2022, $51.59 for 2023, $51.76 for 2024, $52.07 for 2025, $52.47 for 2026, and escalated 3% thereafter and $2.87/MMBtu for natural gas for 2018, $2.81 for 2019, $2.82 for 2020, $2.85 for 2021, $2.89 for 2022, $2.93 for 2023, $2.97 for 2024, $3.01 for 2025, $3.07 for 2026, and escalated 3% thereafter.

(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 Income

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.

Lonestar Resources US Inc.
Unaudited Reconciliation of Income Before Income Taxes As Reported To Income Before Income Taxes Excluding Certain Items, a non-GAAP measure (Adjusted Income)

PV-10

Certain of our oil and natural gas reserve disclosures included in this release are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows, less future development and production costs from our proved reserves before income taxes, discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the Standardized Measure. We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of a pre-tax PV-10 value provides greater comparability when evaluating oil and gas companies. The PV-10 value is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. The definition of PV-10 value, as defined above, may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value, as defined, may not be comparable to similar measures provided by other companies.

The following table provides a reconciliation of the Standardized Measure to PV-10: