Lonestar Announces First Quarter 2019 Financial Results And Provides Operational Update

HIGHLIGHTS

• Lonestar reported a 46% increase in net oil and gas production to 11,372 BOE/d during the three months ended March 31, 2019 (“1Q19”), compared to 7,777 BOE/d for the three months ended March 31, 2018(“1Q18”). The production volumes were within Company guidance of 11,200 – 12,000 BOE/d and were comprised of 79% crude oil and NGL’s on an equivalent basis. With the addition of six new wells, current net oil and gas production has climbed to 14,000 BOE/d.
• During 1Q19, Lonestar experienced an unusually high number of instances in which its producing wells were hit by frac operations conducted by third parties. In total, 9 of the Company’s pads were affected, and a total of 23 of our wells in the Western and Central regions experienced production curtailments related to these ‘frac hits’. These offset frac hits resulted in an aggregated reduction of 330 BOE/d in our 1Q19 production, reducing quarterly revenue by $1.4 million and increasing Lease Operating Expenses (“LOE”) by $0.6 million. Notably, all wells have since been returned to production equal to or above their third-party type curves.
• Lonestar reported a net loss attributable to its common stockholders of $60.6 million during 1Q19 compared to a net loss of $18.4 million during 1Q18, or a net loss of $2.45 and $0.75 per share, respectively. Our first quarter net loss included a $32.9 million loss attributable to the sale of our Pirate properties in March 2019, while our 2018 net loss included an $8.6 million loss on extinguishment of debt. Excluding, on a tax-adjusted basis, certain items that the Company does not view as either recurring or indicative of its ongoing financial performance, Lonestar’s adjusted net loss for 1Q19 was $3.4 million, or $0.14 per share. Most notable among these items include: $35.5 million of unrealized hedging gains/losses on financial derivatives related to mark-to-market accounting on our hedge book and $0.9 millionassociated with stock-based compensation. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted Net Income (Loss) to adjusted net income (loss), a reconciliation of net income before taxes to adjusted net income(loss), and the reasons for its use.
• Lonestar reported a 15% increase in Adjusted EBITDAX for the three months ended March 31, 2019 of $27.0 million compared to $23.4 million for 1Q18. This improvement was driven by a 46% increase in production coupled with an 11% reduction in unit cash operating expenses. Please see Non-GAAP Financial Measures at the end of this release for the definition of Adjusted EBITDAX, a reconciliation of net loss to Adjusted EBITDAX, and the reasons for its use.

Lonestar’s Chief Executive Officer, Frank D. Bracken, III, commented, “While our first quarter 2019 results represented significant improvement over the year prior, it represented a temporary pause in what the market has come to expect in terms of our ongoing financial growth and maturation. In fact, very little of our planned completion activity contributed to our first quarter results. Just 3 of our planned 20 completions for the year added to first quarter production, and those completions represented just 11% of the total perforated interval we plan to bring onstream over the course of 2019. The quarter was also impacted by an unprecedented number of frac hits from offset wells. I am pleased to report that Lonestar’s wells not only weathered those hits but now have been restored to full rate. In the second quarter, completion activity has accelerated significantly, with 6.0 gross / 5.2 net wells commencing flowback in May. These wells represent total perforated interval of 47,600 feet, or 27% of our anticipated total for 2019. Current net production is a record 14,000 BOE/d, and accordingly, we expect the second quarter to reflect significant sequential growth in production and Adjusted EBITDAX, which will accelerate in the third quarter, when we expect to set an all-time record for both.”

OPERATIONAL UPDATE

• Lonestar reported net oil and gas production of 11,372 BOE/d during the three months ended March 31, 2019, an increase of 46% compared to 7,777 BOE/d during the three months ended March 31, 2018. 1Q19 production volumes consisted of 6,557 barrels of oil per day (58%), 2,417 barrels of NGLs per day (21%), and 14,391 Mcf of natural gas per day (21%). The Company’s production mix for the three months ended March 31, 2019 was 79% liquid hydrocarbons.
• Lonestar’s Eagle Ford Shale assets continued to deliver outstanding wellhead realizations in 1Q19. Lonestar’s wellhead crude oil price realization was $56.90 per barrel, which reflects a premium of $2.00/bbl vs. West Texas Intermediate. Lonestar’s realized NGL price was $15.60 per barrel, or 28% of WTI. This was largely driven by a drop in Propane and other heavy liquids pricing which fell as much as 23% from 1Q18 prices. Lonestar’s realized wellhead natural gas price was $2.91 per Mcf, reflecting a $0.01/Mcf discount to Henry Hub.
• Operating revenues increased by $4.0 million to $40.7 million, or 11%, between the two quarters, primarily driven by a 46% increase in production partially offset with a 35% decrease in commodity prices.
• In 1Q19, Lonestar demonstrated continued progress in scaling its business to make it more competitive, delivering an 11% reduction in per BOE cash operating costs (outlined below). Total cash expenses, which includes the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administrative, and interest expenses were $23.4 million for the three months ended March 31, 2019. While cash operating costs rose 30% compared to $17.9 million in the three months ended March 31, 2018, Lonestar’s 46% increase in production yielded an 11% reduction in cash operating costs per unit, reducing total cash expenses from $25.61 per BOE in 1Q18 to $22.76 per BOE in 1Q19.
  • Lease Operating Expenses, excluding rig standby costs of $0.1 million, were $6.7 million for the three months ended March 31, 2019, which was 62% higher than LOE of $4.1 million in the three months ended March 31, 2018. During 1Q19, Lonestar was hit by third party fracs across 9 of its pads, a total of 23 wells in its Western and Central regions. These offset frac hits resulted in an additional $0.6 million of LOE or $0.54 on a per BOE basis. These unplanned lease operating expenses were almost exclusively responsible for the 11% increase in LOE to $6.57 per BOE for the three months ended March 31, 2019.
  • Gathering, Processing & Transportation Expenses (“G, P&T”) for the three months ended March 31, 2019 were $0.9 million, which was 99% higher than the G, P&T of $0.4 million in the three months ended March 31, 2018, related to a 124% increase in gas production. On a unit-of-production basis, G, P&T increased 36% to $0.86 per BOE for the three months ended March 31, 2019.
  • Production taxes for the three months ended March 31, 2019 were $2.3 million, which was 6% higher than production taxes of $2.2 million in the three months ended March 31, 2018. On a unit-of-production basis, production taxes decreased 28% to $2.24 per BOE for the three months ended March 31, 2019.
  • General & Administrative Expenses in the three months ended March 31, 2018 were $3.4 million vs. $4.4 million in the three months ended March 31, 2019. General & Administrative Expenses, excluding stock-based compensation of $0.5 million in the three months ended March 31, 2018 and $0.9 million in the three months ended March 31, 2019 (“G&A”), increased from $3.0 million to $3.5 million, respectively. On a unit-of-production basis, G&A per BOE fell 21% year over year, from $4.24per BOE in 2018 to $3.37 per BOE in 2019.
  • Interest Expense was $9.3 million in the three months ended March 31, 2018 vs. $10.7 million in the three months ended March 31, 2019. Interest Expense excluding amortization of debt issuance cost, premiums, and discounts, increased year over year from $8.2 million in 1Q18 to $10.0 million in 1Q19. On a unit-of-production basis, interest per BOE decreased 17% year over year from $11.72 per BOE in 2018 to $9.73 per BOE in 2019.
• Lonestar is committed to managing its liquidity and high-grading its portfolio. On March 22, 2019, we completed the divestiture of our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private third-party. The assets were comprised of 3,400 net undeveloped acres and held 7 proved undeveloped locations as of the closing date, and were producing approximately 200 BOE/d.

GUIDANCE

• Lonestar responded to low oil prices in 4Q18 by deferring drilling and completion activities. Consequently, in 1Q19, the Company only completed 3 gross / 2.9 short laterals in La Salle County that began producing in March. However, Lonestar has ramped up to its activity and expects to continue to increase production organically during the second quarter, and through the remainder of 2019. The Company anticipates placing 6.0 gross / 5.2 net wells online during 2Q19. In April, 2 gross / 2.0 net wells at Horned Frog NW were placed into flowback. In May, 4 gross / 3.2 net wells in Karnes County have been placed into flowback operations. The Company has recently completed drilling operations on 2 gross / 2.0 net wells at Horned Frog with projected completed intervals exceeding 12,000 feet, with completion operations expected to commence before the end of May. Flowback operations for these two wells are expected to commence on or around July 1, 2019, and these wells are expected to contribute materially to the third quarter production volumes.
• Lonestar issued production guidance of 12,400 to 12,800 BOE/d for the second quarter of 2019, a 12% increase over 2Q18 results at the midpoint. The primary sources for production growth in the second quarter will be 2.0 net wells at Horned Frog NW, which will contribute volumes for essentially the whole quarter, and 3.2 net wells in Karnes County, which are expected to contribute volumes for roughly half of the second quarter.
• Lonestar issued Adjusted EBITDAX guidance of $30 to $32 million for the second quarter of 2019, a 15% sequential increase over 1Q19 results. During the quarter, the Company anticipates oil realizations of +$2.10/bbl to WTI and lease operating expenses of $6.00/BOE.

EAGLE FORD SHALE TREND- WESTERN REGION

In our Western Region, production for the first quarter of 2019 averaged approximately 5,722 BOE per day, a 74% increase over the prior year.  During 1Q19, Lonestar was hit by third party fracs across 9 of its pads, a total of 23 wells in its Western and Central regions. These offset frac hits led to curtailed production of approximately 330 BOE/d during the quarter and will also modestly impact sales in April.  In aggregate, these wells have since recovered and returned to their third-party type curves. After completing 3 gross / 2.9 net wells at Burns Ranch during the first quarter, the Company focused its Western Region drilling activities to its Horned Frog region, which has some of the highest internal rate of returns (“IRR”) in the Company’s profile.

In April, the Company began flowback operations on the Horned Frog NW #4H and #5H. The Company holds a 100% working interest (“WI”) / 75% net revenue interest (“NRI”) in these wells. These wells were drilled to an average total measured depth of 19,716 and 19,672 feet and were fracture-stimulated using diverters with an average proppant concentration of 2,030 pounds per foot over 33 stages. Perforations and test rates for the for wells are:

• Horned Frog NW #4H – 9,771 perforated feet tested 823 Bbls/d oil & 2,825 Mcf/d or 1,489 BOE/d (three-stream) on a 26/64″ choke
• Horned Frog NW #5H – 9,645 perforated feet tested 797 Bbls/d oil & 2,872 Mcf/d or 1,475 BOE/d (three-stream) on a 26/64″ choke

These wells are our second set at our Horned Frog NW property and immediately offset the Horned Frog NW #2H and #3H, which were placed onstream last year. Early indications are that we have demonstrated two important technical achievements. First, we believe we have demonstrated the Company’s capability to maximize lateral length while maintaining productivity per foot (these wells are 50% longer than our first pair).  On a per foot basis, the new wells are producing at nearly identical rates compared to the ‘parent’ wells drilled last year. Additionally, we believe that we have demonstrated our ability to not damage productivity and recovery of the parent wells. After shut-in for fracture stimulation of our new #4H and #5H wells, the #2H and #3H have reestablished rates of production that exceed rates prior to shut-in.

In late April, the Company completed drilling operations on the Horned Frog F #1H and #2H. These wells were drilled to total measured depths of 22,675 and 22,520 feet, respectively, and are expected to have perforated intervals averaging 12,350 feet.  Fracture stimulation operations are expected to begin in May with an average proppant concentration exceeding 2,000 pounds per foot.  These wells are expected to begin flowback operations on or around July 1. Lonestar holds a 100% WI / 78% NRI in these wells.

EAGLE FORD SHALE TREND- CENTRAL REGION

In our Central Region, 1Q19 production averaged approximately 5,391 BOE per day, a 33% increase over the prior year.  On March 22, 2019, we completed the divestiture of our Pirate assets in Wilson County for $12.3 million, before closing adjustments, to a private operator.  This asset contributed approximately 200 BOE/d.  Despite this sale, the continued growth of the region was largely driven by the Sooner acquisition which occurred in November 2018.

The Company did not place any new wells onstream in the Central Region during the first quarter of 2019 but did complete drilling operations on the Georg #3H, Georg #4H, Georg #5H, and Georg #6H.  These wells were drilled to average total measured depths ranging from 16,396 feet and 16,475 feet.  Completion operations finished last week. The wells were fracture-stimulated using diverters with an average proppant concentration of 2,000 pounds per foot over 25 stages with average perforated intervals of 7,210 feet.  Lonestar has an 80% WI / 61% NRI in these wells.

Completion operations on this four-well pad concluded last week.  The wells were fracture-stimulated using diverters with an average proppant concentration of 2,000 pounds per foot over 25 stages.  In the past week, these four wells were placed into flowback operations.  Perforations and test rates for the for wells are:

• Georg #3H – 7,156 perforated feet tested 1,129 Bbls/d oil & 693 Mcf/d or 1,290 BOE/d (three-stream) on a 26/64″ choke
• Georg #4H – 7,230 perforated feet tested 1,113 Bbls/d oil & 589 Mcf/d or 1,250 BOE/d (three-stream) on a 25/64″ choke
• Georg #5H – 7,227 perforated feet tested 1,276 Bbls/d oil & 737 Mcf/d or 1,447 BOE/d (three-stream) on a 26/64″ choke
• Georg #6H – 7,236 perforated feet tested 1,294 Bbls/d oil & 783 Mcf/d or 1,476 BOE/d (three-stream) on a 26/64″ choke

At the end of the first quarter, the Company commenced drilling 3 gross / 3.0 net wells at its Sooner property, the Buchhorn #4H, Buchhorn #5H and Buchhorn #6H.  These wells, our first at Sooner, have planned total measured depths of approximately 20,300 feet and expected perforated intervals of 6,000 feet. Lonestar expects to commence flowback operations on these wells in August 2019. Lonestar has a 100% WI / 78% NRI in these wells.

Lonestar is also currently drilling 2 gross / 2.0 net wells on assets in Fayette County acquired from Sanchez Energy in 2017.  These wells, the Five Mile Creek E&B #A1H and the Five Mile Creek E&B #B2H are projected to be the longest laterals drilled by the Company to date, with projected perforated intervals of 13,000 feet.

EAGLE FORD SHALE TREND- EASTERN REGION

In our Eastern Region, production for the first quarter of 2019 averaged approximately 259 BOE per day, a 41% decrease over the prior year. The Company did not complete any wells in this region in the first quarter.  However, Lonestar has permitted a horizontal well intended to have a 10,000′ perorated interval in western Brazos County. This well is on-strike with its Wildcat B#1H wells, which has produced a cumulative 460,000 BOE in 24 months of production.  Lonestar plans to spud the well in June and expects to have a 50% WI / 38% NRI in the well.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Monday, May 13, 2019 at 9:00 AM CDT to discuss the first quarter 2019 results and operational highlights.

To access the conference call, participants should dial:

USA: 1-800-925-4693
International: +1-303-223-0113
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately May 14, 2019.

ABOUT LONESTAR RESOURCES US INC.

Lonestar is an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas, where we accumulated approximately 74,253 gross (53,448 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of March 31, 2019. 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 Annual Report on Form 10-K filed with the Securities and Exchange Commission, or the SEC, on March 13, 2019, as well as other documents that we may file from time to time with the SEC. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Actual results or events could differ materially from the plans, intentions and expectations disclosed in the forward-looking statements we make. The forward-looking statements in this press release represent our views as of the date of this press release. We anticipate that subsequent events and developments will cause our views to change. However, while we may elect to update these forward-looking statements at some point in the future, we have no current intention of doing so except to the extent required by applicable law. You should, therefore, not rely on these forward-looking statements as representing our views as of any date subsequent to the date of this press release.

(Financial Statements to Follow)

NON-GAAP FINANCIAL MEASURES (Unaudited)

Reconciliation of Non-GAAP Financial Measures

Adjusted EBITDAX

Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock-based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense), 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 (loss) 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 Net Income (Loss)

Adjusted net income (loss) 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 (loss) 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 (loss) comparable to analysts’ estimates on a diluted per share basis.

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

SOURCE Lonestar Resources US Inc.