Quarterly / Earnings Reports | Third Quarter (3Q) Update

Lonestar Resources Talks Q3 2019 Results

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Lonestar Resources US Inc. reported its Q3 2019 results.

Highlights:

• Production Increases 45%, Exceeds Guidance- Lonestar reported a 45% increase in net oil and gas production to a Company-record 18,097 BOE/d during the three months ended September 30, 2019 ("3Q19"), compared to 12,471 BOE/d for the three months ended September 30, 2018 ("3Q18"). Reported production volumes exceeded the Company's guidance of 17,000 - 17,500 BOE/d, and also represented a 33% sequential increase in production. Production was comprised of 67% crude oil and NGL's on an equivalent basis. Excellent execution of a large number of high-rate wells in our 2019 capital program fueled these results.
• More High-Rate Completions- Lonestar's 2019 drilling program continues to deliver outstanding results. In DeWitt County, our Buchhorn #4H-#6H wells, which delivered average Max-30 IP's of 2,494 BOE/d, are performing extremely well, in spite of a variety of temporary constraints. In Brazos County, the Smith Family Ranch well has delivered an IP of 1,258 BOE/d. Most recently, the Company brought the FMC EB #A1H and #B2H wells online in October which have exhibited promising productivity, averaging 1,179 BOE/d on a three-stream basis, 86% of which is crude oil.
• Net Income Rises- Lonestar reported net income attributable to its common stockholders of $14.1 million during 3Q19 compared to a net loss of $21.7 million during 3Q18, or a net income of $0.33 and a net loss of $0.88 per diluted common share, respectively.
• EBITDAX Increases 12%- Lonestar reported Adjusted EBITDAX for 3Q19 of $37.1 million. On a sequential basis, Adjusted EBITDAX increased 12%, as a 33% increase in production more than offset a 24% decrease in wellhead prices. 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.
• Robust Hedging Program Protects Prices- Lonestar continues to utilize commodity derivatives to create a higher degree of certainty in our cash flows and returns while mitigating financial risk. Lonestar has crude swap volumes of 7,212 Bbls/d for the remainder of 2019 ("Bal `19") at an average WTI price of $54.54/bbl and added hedges which bring total swap volumes to 7,480 bbls/d for Cal `20 at an average WTI price of $56.95/bbl, and 4,000 Bbls/d for Cal `21 at an average WTI price of $53.93/bbl. Lonestar also has Henry Hub natural gas swaps covering 15,000 MMBTU/d at a weighted-average price of $2.87 per MMBTU for Bal `19 and has 20,000 MMBTU/d of Henry Hub natural gas swaps for Cal `20 at an average price of $2.58 per MMBTU, significantly insulating Lonestar from fluctuations in the commodity markets.
• 4Q19 Guidance - Lonestar has issued production guidance of 17,200 to 17,600 BOE/d for 4Q19. Production rates remain relatively flat quarter over quarter as the pace of capital spending and completions is reduced for the fourth quarter (2 gross / 2.0 net new wells at Marquis) as the Company completes its 2019 program. Given current strip pricing for the oil and gas benchmarks, the Company has issued EBITDAX guidance of $32.0 to $34.0 million for 4Q19.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, commented, "The third quarter represented yet another outstanding result, with daily production setting a new record of over 18,000 Boe/d, again exceeding guidance as Lonestar continues to deliver better-than-expected well results. These results help ensure that the full-year results will exceed our already-increased guidance of 14,800-15,000 Boe/d for the year, which represents an increase in production of approximately 35% over 2018 levels. The underlying drivers to these results are that our 2018 and 2019 completions are continuing to outperform projections, and in the third quarter of 2019, we delivered new high-rate completions sooner than expected. While our production growth is impressive, growth is not as important as what that growth allows us to achieve in terms of other more strategic objectives: 1) In the gas condensate window, our technological advancements at Horned Frog and at Sooner are delivering meaningful outperformance versus their type curves with the most notable outperformance coming from oil production; 2) In the crude oil window, our 2019 wells at Georg are performing well, and recently, we placed onstream our first 2 wells at Marquis, and early average rates are exceeding 1,100 Boe/d. These areas, as well as Cyclone/Hawkeye, which are home to over 100 drilling locations, continue to deliver oil cuts at roughly 90%; 3) Production growth yielded a 30% improvement in the Company's cash cost structure- total cash costs have fallen from $22.76/Boe in 1Q19 to $16.09/Boe in 3Q19, giving Lonestar a more durable and competitive cost structure; 4) Most importantly, the underlying outperformance of our 2018 and 2019 completions means that we can achieve our 2020 production target of 17,000 to 18,000 Boe/d with fewer wells and less capital spending. Today, we believe that our 2020 production target can be achieved by drilling 13 to 19 gross wells / 12 - 16 net wells at a cost of between $90 and $115 million, both of which yield free cash flow generation. We have positioned Lonestar to thrive in the current environment and continue to build shareholder value."

Ops Update

• Production - Lonestar reported net oil and gas production of 18,097 BOE/d during the three months ended September 30, 2019, representing a 45% increase year-over-year and a 33% increase sequentially vs. 2Q19 production of 13,630 BOE/d. 3Q19 production volumes consisted of 7,885 barrels of oil per day (44%), 4,209 barrels of NGLs per day (23%), and 36,019 Mcf of natural gas per day (33%).
• Pricing - Lonestar's Eagle Ford Shale assets continued to deliver favorable wellhead realizations in 3Q19. Lonestar's wellhead crude oil price realization was $58.16/bbl, which reflects a premium of $1.71/bbl vs. West Texas Intermediate. Lonestar's realized NGL price was $8.88/bbl, or 16% of WTI. This was largely the result of a sharp drop in ethane, which fell as much as 70% from 1Q19 prices, and propane and other heavy liquids pricing, which fell as much as 44% from 1Q19 prices. Lonestar's realized wellhead natural gas price was $2.27 per Mcf, reflecting a $0.11 discount to Henry Hub. This discount to Henry Hub was largely driven by the increase in gas sales at the beginning of the quarter with the additions of our 5 highest producing gas wells beginning flowback operations in June and July, the Horned Frog F #A1H, Horned Frog F #B1H, Buchhorn #4H, Buchhorn #5H, and Buchhorn #6H.
• Revenues - Operating revenues increased sequentially by $0.9 million to $53.1 million, or 2%, compared to 2Q19, primarily driven by a 33% increase in production offset by a 24% decrease in commodity price realizations.
• Expenses -Lonestar's ramp-up in production has generated a powerful reduction in its cash unit-cost structure. Total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administrative, and interest expenses were $26.8 million for 3Q19. While 3Q19 cash operating costs rose 6% sequentially compared to $25.3 million in 2Q19, continued strong volume growth yielded a 21% reduction on a per-unit basis from $20.43 per BOE in 2Q19 to $16.09 per BOE in 3Q19.
  • Lease Operating Expenses ("LOE"), excluding rig standby costs of $0.1 million, were $8.8 million for 3Q19, which was 19% higher than LOE of $7.4 million in 2Q19. However, on a unit-of-production basis, LOE per BOE were reduced 11% sequentially to $5.29 per in 3Q19.
  • Gathering, Processing & Transportation Expenses ("GP&T") for 3Q19 were $1.1 million, which was 11% lower than the GP&T of $1.2 million in the three months ended 2Q19. On a unit-of-production basis, GP&T decreased 33% sequentially from $1.00 per BOE in 2Q19 to $0.66 per BOE in 3Q19.
  • Production and ad valorem taxes for 3Q19 were $3.0 million, which was 7% higher than production taxes of $2.8 million in 2Q19. On a unit-of-production basis, production and ad valorem taxes decreased 20% sequentially from $2.27 in 2Q19 to $1.81 per BOE in 3Q19.
  • General & Administrative Expenses ("G&A") in 3Q19 were $4.1 million vs. $3.8 million in 2Q19. G&A Expenses, excluding stock-based compensation of $0.1 million in 2Q19 and $0.9 million in 3Q19, decreased from $3.7 million to $3.2 million, respectively. Excluding stock-based compensation, on a unit-of-production basis G&A per BOE decreased 37% sequentially from $3.02 per BOE in 2Q19 to $1.91 per BOE in 3Q19.
  • Interest expense was $11.3 million for 3Q19 vs. $10.8 million for 2Q19. Interest expense excluding amortization of debt issuance cost, premiums, and discounts increased 5% sequentially from $10.2 million in 2Q19 to $10.7 million in 3Q19. Excluding these costs, Lonestar's robust production growth generated a 22% sequential decrease in interest expense per BOE, from $8.19 per BOE in 2Q19 to $6.40 per BOE in 3Q19.
• Capital Spending - The Company's drilling program has proceeded rapidly this year, with 17 of its planned 20 drill wells finished by August 2019. The Company ran a two-rig program from February to August 2019, resulting in a concentration of drilling and completion expenditures in the third quarter of 2019. The compressed intensity of activity resulted in a concentration of drilling and completion ("D&C") expenditures in the third quarter, totaling $46.2 million of D&C spending, compared to $25.9 million in 1Q19 and $37.2 million in 2Q19. The remaining $7.9 million of the reported capital spending of $54.1 million was on a combination of lease acquisitions in the Horned Frog and Cyclone Hawkeye areas and most significantly, on upgrades and expansions of centralized gathering, processing and treatment facilities, principally at Horned Frog and Sooner, which were required for both higher-than-expected rates on new wells and much higher anticipated volumes resulting from additional development in 2020 and beyond. Based on these considerations, Lonestar expects drilling and completions expenditures to range from between $15 and $18 million in 4Q19.

Guidance

• 2019 Activity - In the nine months ended September 30,2019, the Company had placed 15 of its 20 planned wells into production, and in October placed 2 gross / 2.0 net wells onstream on its Marquis property. These wells are our first wells drilled and completed at our Marquis acquisition that closed in June 2017. Flowback results are promising results, and at the present, Lonestar's recent Marquis completions are conclude expected flowback activity for 2019. Lonestar deferred the commencement of drilling operations on its 3-well Cyclone pad to await the upgrade of a new rig which it put under contract at favorable day rates. Consequently, Lonestar anticipates fracture stimulation operations to be deferred until December, with first production expected in early 2020.
• 4Q19 Production - In our second quarter earnings release, Lonestar increased its 2019 full-year production forecast from 13,700-14,700 BOE/d to current guidance of 14,800-15,000 BOE/d. With newly issued production guidance of 17,200-17,600 BOE/d for the fourth quarter of 2019, Lonestar is poised to exceed the upper end of its already-increased full-year guidance.
• 4Q19 EBITDAX - Based on the aforementioned factors, and current benchmark pricing, Lonestar issued Adjusted EBITDAX guidance of $32.0 to $34.0 million for the fourth quarter of 2019. This 11% sequential decrease from 3Q19 results is a result of only 2 gross / 2.0 net new wells beginning flowback operations in 4Q19 as the 2019 drilling and completions program comes to a close. The Company anticipates oil realizations of -$0.60 to -$1.20/Bbl to WTI, NGL realizations which are 17% to 19% of WTI, and gas price realizations of -$0.05 to -$0.10/Mcf to Henry Hub, and lease operating expenses of $5.50-$5.60/BOE.

Eagle Ford - West

In our Western Region, production for 3Q19 averaged approximately 9,470 BOE per day, a 23% sequential increase in production. Production consisted of 3,310 barrels of oil per day (35%), 2,544 barrels of NGL's per day (27%) and 21,699 Mcf of natural gas per day (38%). The Western region accounted for 52% of the Company's production during the quarter. The Company did not complete any wells in this region in the third quarter.

However, Lonestar had placed 2 wells onstream at Horned Frog South in June that materially contributed to the quarter, the Horned Frog F#A1H and F #B1H ("F pad wells"). Now, through their first 120 days of production, these wells have produced an average of 260,000 BOE, which is 86% better than our initial pad at Horned Frog, the Horned Frog #A1H and #B1H (completed in 2015). To date, the F pad wells have produced total volumes which exceed their Type Curve by 16%, and most importantly, have produced 42% more oil than originally projected. In terms of production mix, the wells have produced a mix of 32% oil / 24% NGL's / 43% gas versus third party projections of 12% oil / 44% NGL's / 43% gas, making them significantly more profitable.

Given the continued success in the region, The Company plans to kick off its 2020 capital program with 2 gross / 2.0 net wells at Horned Frog. Lonestar plans to drill these wells to average total measured depths of approximately 22,500 feet and expected perforated intervals of 12,000 feet. Lonestar expects to commence flowback operations on these wells in February 2020. Lonestar has a 100% WI / 78% NRI in these wells.

Eagle Ford - Central

In our Central Region, 3Q19 production averaged approximately 8,378 BOE/d, a 48% increase over 2Q19 rates. Production consisted of 4,409 barrels of oil per day (53%), 1,619 barrels of NGL's per day (19%), and 14,102 Mcf of natural gas per day (28%). The Company's third quarter results were positively impacted by 3 gross / 3.0 net wells it placed onstream on its Sooner property in DeWitt County.

In May, Lonestar began flowback operations on 4 gross / 3.2 net wells, the Georg #3H, Georg #4H, Georg #5H, and Georg #6H. These wells recorded maximum rates over a 30-day period ("Max-30 rates") of 1,045 BOE/d, 87% of which was crude oil. Now, through their first 150 days of production, these wells have produced an average of 98,000 BOE, which is in-line the 6 previous wells drilled in 2018. The Company holds an 80% working interest ("WI") / 61% net revenue interest ("NRI") in these wells.

In late July, Lonestar began flowback operations on 3 gross / 3.0 net wells on its Sooner property, which was acquired in November 2018. These new wells have since cleaned up after flowback and registered the following Max-30 rates which average 2,494 BOE/d:

• Buchhorn #4H - With a 6,157' perforated interval, the #4H recorded Max-30 rates of 360 Bbls/d oil, 880 Bbls/d of NGLs, and 6,614 Mcf/d, or 2,342 BOE/d on a three-stream basis. Currently, the 4H is producing 229 Bbls/d oil, 524 Bbls/d of NGLs, 3,935 Mcf/d gas, or 1,409 BOE/d on a three-stream basis.
• Buchhorn #5H - With a 5,981' perforated interval, the #5H recorded Max-30 rates 366 Bbls/d oil, 962 Bbls/d of NGLs, and 7,231 Mcf/d, or 2,533 BOE/d on a three-stream basis. Currently, the 5H is producing 266 Bbls/d oil, 679 Bbls/d of NGLs, 5,100 Mcf/d gas, or 1,795 BOE/d on a three-stream basis.
• Buchhorn #6H - With a 6,021' perforated interval, the #6H recorded Max-30 rates 328 Bbls/d oil, 1,012 Bbls/d of NGLs, and 7,606 Mcf/d, or 2,607 BOE/d on a three-stream basis. Currently, the 6H is producing 295 Bbls/d oil, 744 Bbls/d of NGLs, and 5,592 Mcf/d gas, or 1,971 BOE/d on a three-stream basis.

Through the first 100 days of production, these wells continue to flow up casing and are still producing on average 298 Bbls/d oil, 690 Bbls/d of NGLs, 5,187 Mcf/d, or 1,852 Boe/d on a three-stream basis. These impressive results have been registered in spite of: 1) the fact that these wells are still flowing up casing; 2) elective reductions in choke size and flow rates; and 3) excessive line pressures, which is expected to be mitigated with the imminent start-up of a new 24" third-party transportation line. Lonestar has 100% WI / 78% NRI in these wells.

In October, Lonestar began flowback operations on 2 gross / 2.0 net wells on its Marquis property, which was acquired in June 2017, known as the FMC EB #A1H and FMC EB #B2H. These wells are the first wells Lonestar has drilled on its Marquis property and were drilled to average total measured depths of 19,563'. Lonestar fracture-stimulated these wells with an average proppant concentration of approximately 1,470 pounds per foot and across average perforated intervals of 9,068 lateral feet, using diverters. Test rates have averaged 1,008 Bbls/d oil (85%), 90 Bbls/d of NGLs (8%), and 487 Mcf/d (7%), or 1,179 BOE/d (three-stream) on a 26/64" choke. Lonestar has a 100% WI / 73% NRI in these wells.

Eagle Ford - East

In our Eastern Region, production for the third quarter of 2019 averaged approximately 249 BOE/d, a 5% decrease compared to 2Q19 rates. Production consisted of 166 barrels of oil per day (67%), 46 barrels of NGL's per day (19%) and 218 Mcf of natural gas per day (15%). The Company completed 1 gross / 0.5 net well in this region in the third quarter. The Smith Family #1H was drilled to a total measured depth of 22,025 feet and fracture-stimulated with an average proppant concentration of 2,030 pounds per foot across a perforated interval of approximately 10,200 feet, with diverters. This well, which has encountered mechanical difficulties, registered a Max-IP of 463 Bbls/d oil, 391 Bbls/d of NGLs, 2,674 Mcf/d, or 1,258 BOE/d on a three-stream basis. To date, the maximum 30-day rate recorded has been 295 Bbls/d oil, 288 Bbls/d of NGLs, 1,789 Mcf/d, or 881 BOE/d on a three-stream basis. Lonestar has a 50% WI / 38% NRI in the well.