Market Overview

Lonestar Announces Second Quarter 2019 Financial Results And Increases 2019 Guidance

Share:

Lonestar Resources US Inc. (NASDAQ:LONE) (including its subsidiaries, "Lonestar," "we," "us," "our" or the "Company") today reported financial and operating results for the three months ended June 30, 2019.

HIGHLIGHTS

  • Production Increases 22%- Lonestar reported a 22% increase in net oil and gas production to 13,630 BOE/d during the three months ended June 30, 2019 ("2Q19"), compared to 11,140 BOE/d for the three months ended June 30, 2018 ("2Q18"). Reported production volumes exceeded the Company's guidance of 12,400 - 12,800 BOE/d and also exceeded our preliminary estimated result of 13,500 Boe/d announced on July 8, 2019. Production was comprised of 78% crude oil and NGL's on an equivalent basis. As Lonestar brings new wells onstream at rates that exceed third-party type curves, production continues to climb rapidly. For the month of July, net oil and gas production exceeded 16,000 BOE/d.
  • Outstanding Drilling Results- Lonestar's 2019 drilling program continues to deliver outstanding results. In Karnes County, our Georg 3H-6H wells, which delivered average Max-30 IP's of 1,045 BOE/d, are outperforming our third-party type curves by 19%. At Horned Frog, the F #A1H and F #B1H wells delivered average Max-30 IP's of nearly 2,500 BOE/d, a record for the Company. Additionally, the Horned Frog NW #4H and #5H have produced an average of 114,000 BOE through their first 90 days of production, a 27% improvement over their offsets over the same time period. Our first three wells in DeWitt County have recently been placed on production on our Sooner property and are averaging over 3,460 BOE/d per well (53% liquids) in their first week of production.
  • Net Income Rises- Lonestar reported net income attributable to its common stockholders of $11.2 million during 2Q19 compared to a net loss of $23.5 million during 2Q18, or a net income of $0.28 and a net loss of $0.96 per basic and diluted share, respectively.
  • EBITDAX Increases 15%- Lonestar reported a 15% increase in Adjusted EBITDAX for 2Q19 of $33.5 million compared to $29.2 million for 2Q18. This improvement was driven by a 22% increase in production, partially offset by a 2% increase 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.
  • Robust Hedging Program- Lonestar continues to utilize commodity derivatives to create a higher degree of certainty in our cash flows and returns while mitigating financial risk. During 2Q19, Lonestar added hedges which bring total swap volumes to 7,305 Bbls/d for the remainder of 2019 ("Bal ‘19") at an average WTI price of $54.60/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 3,000 Bbls/d for Cal '21 at an average WTI price of $54.68/bbl. Additionally, Lonestar has LLS/WTI Basis Swaps covering 6,000 bbls/d at a weighted-average price of $5.05/bbl for Cal ‘19. By locking in these swaps, it should allow the Company to realize a premium to WTI after marketing, regardless of market conditions. Lonestar also has Henry Hub natural gas swaps covering 15,000 Mcf/d at a weighted-average price of $2.82 per MMBTU for Bal '19 and added 15,000 Mcf/d of Henry Hub natural gas swaps for Cal '20 at an average price of $2.59 per MMBTU, further insulating Lonestar from fluctuations in the commodity markets.
  • 2019 And 2020 Guidance Increased- Given its outstanding drilling and completion results, deep drilling inventory and strong hedging position, Lonestar has materially enhanced its financial outlook. For 2019, production guidance was increased from 13,700-14,700 BOE/d to 14,800-15,000 BOE/d, and guides to $135-$140 million of EBITDAX. For 2020, Lonestar now believes it can achieve its previously issued production target of 17,000-18,300 BOE/d while drilling 20-25% fewer wells in 2020, and therefore, materially less capital. Lonestar's 2020 target yields a range of cash flow outcomes that generates $5-$20 million of free cash flow.

Lonestar's Chief Executive Officer, Frank D. Bracken, III, commented, "Our technologically focused smart completions continue to deliver differential results that exceed our third-party type curves and our budget. In the second quarter, those well results are beginning to show up in our financial results. The third quarter is set to deliver even more impressive results, with July's production having exceeded 16,000 BOE/d, as our new Horned Frog and Sooner wells are delivering impressive daily rates and were placed onstream ahead of schedule. Looking ahead, we see record production results in the third and fourth quarters of 2019, and strong growth in EBITDAX. Given the progress we made in 2019 we have the potential to achieve our previously issued production targets while drilling 20-25% fewer wells. With production anticipated to rise 19% and generate a substantial increase in EBITDAX, free cash flow generation of $5-$20 million is on the horizon. We have positioned Lonestar to thrive in the current environment and continue to build shareholder value."

OPERATIONAL UPDATE

  • Lonestar reported net oil and gas production of 13,630 BOE/d during the three months ended June 30, 2019, an increase of 20% sequentially compared to 11,372 BOE/d during 1Q19. 2Q19 production volumes consisted of 7,795 barrels of oil per day (57%), 2,901 barrels of NGLs per day (21%), and 17,601 Mcf of natural gas per day (22%).
  • Lonestar's Eagle Ford Shale assets continued to deliver outstanding wellhead realizations in 2Q19. Lonestar's wellhead crude oil price realization was $63.05/bbl, which reflects a premium of $3.24/bbl vs. West Texas Intermediate. Lonestar's realized NGL price was $13.44/bbl, or 22% of WTI. This was largely driven by a drop in Ethane which fell as much as 47% from 1Q19 prices and Propane and other heavy liquids pricing which fell as much as 38% from 1Q19 prices. Lonestar's realized wellhead natural gas price was $2.46 per Mcf, reflecting a $0.10 discount to Henry Hub. This discount to Henry Hub was largely driven by increase in gas sales at the end of the quarter with the additions of the new Horned Frog F #A1H and #B1H when the gas prices were at their lowest levels in the quarter.
  • Operating revenues increased sequentially by $11.5 million to $52.2 million, or 28%, compared to 1Q19, primarily driven by a 20% increase in production coupled with a 6% increase in commodity price realizations.
  • Total cash expenses, which include the cash portions of lease operating, gathering, processing, transportation, production taxes, general & administrative, and interest expenses were $25.3 million for 2Q19. While 2Q19 cash operating costs rose 9% compared to $23.3 million in 1Q19, strong volume growth yielded a 10% reduction on a per-unit basis to $20.43 per BOE in 2Q19.
    • Lease Operating Expenses ("LOE"), excluding rig standby costs of $0.3 million, were $7.9 million for 2Q19, which was 17% higher than LOE of $6.7 million in 1Q19. However, on a unit-of-production basis, LOE per BOE were reduced 3% sequentially to $6.35 per in 2Q19.
    • Gathering, Processing & Transportation Expenses ("GP&T") for 2Q19 were $0.7 million, which was 15% lower than the GP&T of $0.9 million in the three months ended 1Q19. On a unit-of-production basis, GP&T decreased 30% sequentially from $0.86 per BOE in 1Q19 to $0.60 per BOE in 2Q19.
    • Production taxes for 2Q19 were $2.8 million, which was 23% higher than production taxes of $2.3 million in 1Q19. On a unit-of-production basis, production taxes increased 2% sequentially from $2.24 in 1Q19 to $2.27 per BOE in 2Q19.
    • General & Administrative Expenses ("G&A") in 2Q19 were $3.8 million vs. $4.4 million in 1Q19. G&A Expenses, excluding stock-based compensation of $0.9 million in 1Q19 and $0.1 million in 2Q19, increased from $3.5 million to $3.7 million, respectively. However, on a unit-of-production basis, G&A per BOE decreased 10% sequentially from $3.37 per BOE in 1Q19 to $3.02 per BOE in 2Q19.
    • Interest Expense was $10.8 million for 2Q19 vs. $10.7 million for 1Q19. Interest Expense excluding amortization of debt issuance cost, premiums, and discounts, increased 2% sequentially from $10.0 million in 1Q19 to $10.2 million in 2Q19. Lonestar's robust production growth generated a 16% sequential decrease in Interest Expense per BOE, from $9.73 per BOE in 1Q19 to $8.19 per BOE in 2Q19.

GUIDANCE

  • 2019 Activity- The Company has executed on its 2019 drilling plan with great success through the first six months. By mid-year, Lonestar had placed 11 of its planned 20 wells into production and had concluded drilling operations on its 3 Sooner wells, which commenced flowback operations in July. Despite fluctuations in oil and gas prices over the quarter, Lonestar expects little impact to guidance for the remainder of the year as the Company has hedged 89% of oil at $54.60/bbl and approximately 50% of gas as an average price of $2.83 per MMBTU. Lonestar anticipates placing 3 gross / 3.0 net wells online during 3Q19. In July, these 3 gross / 3.0 net wells at Sooner were placed into flowback. Lonestar recently completed drilling operations on 1 gross / 0.5 net wells in Brazos County with a projected completion interval of 10,000', which it anticipates bringing online in September. The Company has recently finished drilling operations on 2 gross / 2.0 net wells on its Marquis property. These two wells are anticipated to begin flowback operations in October 2019.
  • 3Q19 Production- Based on the continued success of its 2019 capital program, Lonestar issued production guidance of 17,000 to 17,500 BOE/d for the third quarter of 2019, a 27% increase over 2Q19 results at the midpoint. The primary sources for production growth in the third quarter of 2019 will be a full quarter's contribution from its 2 gross / 2.0 net wells at Horned Frog that began flowback in June, and partial contribution from 3 gross / 3.0 net wells at Sooner, which commenced flowback in late July.
  • 3Q19 EBITDAX- Lonestar issued Adjusted EBITDAX guidance of $36.0 to $37.5 million for the third quarter of 2019, a 9% sequential increase over 2Q19 results. During the quarter, the Company anticipates oil realizations of +$2.00/bbl to WTI, NGL realizations which are 25% of WTI, and gas price realizations of -$0.10/Mcf to Henry Hub, and lease operating expenses of $5.35-$5.45/BOE.
  • 2019 Production- In aggregate, Lonestar's completion results have been outperforming their third-party type curves, which is the basis for Lonestar's budget and guidance. While the Company still only plans to drill 20 gross wells in 2019, visibility on production is sufficiently positive that it is raising its 2019 production guidance from 13,700-14,700 BOE/d to 14,800-15,000 BOE/d.
  • 2020 Targets- Previously, as part of its two-year forecasts and based on drilling 20 wells in 2020, Lonestar provided a 2020 production target of 17,000-18,300 BOE/d, which equates to production growth of 19% over its increased 2019 guidance (at their midpoints). Based on the production outperformance associated with the 2019 capital program and our current plans to focus our 2020 capital plan at Horned Frog, Karnes County, Cyclone/Hawkeye and Sooner, Lonestar reiterates its 2020 production target of 17,000-18,300 Boe/d, but now believes that this target can be achieved with fewer wells and less capital spending. Lonestar believes that it can achieve its 2020 production target by drilling and completing 15-16 wells at a cost of $115 to $120 million. At assumed pricing of $55.00 per barrel for West Texas Intermediate crude oil and $2.50 per MMBTU for Henry Hub natural gas prices, Lonestar's EBITDAX target is $165-$185 million. Lonestar's 2020 target yields a range of cash flow outcomes that generates $5-$20 million of free cash flow.

EAGLE FORD SHALE TREND - WESTERN REGION

In our Western Region, production for 2Q19 averaged approximately 7,717 BOE per day, a 24% sequential increase in production. This region accounted for 57% of the Company's production during the quarter. During the second quarter, Lonestar placed 2 wells onstream at both its Horned Frog and Horned Frog NW properties, respectively, where it has some of the highest internal rates of return ("IRR") in the Company's asset base.

In April, Lonestar began flowback operations on 2 gross / 2.0 net wells, the Horned Frog NW #4H and #5H. These wells recorded Max-30 production rates of 1,453 BOE/d, within 1% of their direct offsets on a per foot basis. Now, through the first 90 days, these wells have produced an average of 114,000 BOE, which is 2% better than the parent wells drilled in 2018 and 5% better than the third-party type curve. The Company holds a 100% working interest ("WI") / 75% net revenue interest ("NRI") in these wells.

In June, the Company began flowback operations on a second pair of wells in its Western Region. At Horned Frog South, Lonestar previously announced initial test results averaging 2,497 BOE/d. These new wells have since cleaned up after flowback and registered the following maximum rates over a 30-day period ("Max-30" rates) which average 2,493 BOE/d:

  • Horned Frog F #A1H – With a 12,461' perforated interval, the F #A1H recorded a Max-30 production rate of 549 Bbls/d oil, 674 Bbls/d of NGLs, 7,283 Mcf/d, or 2,436 BOE/d on a three-stream basis.
  • Horned Frog F #B1H – With a 12,170 perforated interval, the F #B1H recorded a Max-30 production rate of 578 Bbls/d oil, 704 Bbls/d of NGLs, 7,605 Mcf/d, or 2,550 BOE/d on a three-stream basis.

Lonestar's newest wells on its 4,975-acre Horned Frog South property represent continued progress in the advancement of its Geo-Engineered completion practices. On a per-foot basis through the first 30-days, our 2019 wells have recorded production rates that are 20% higher than our initial pad at Horned Frog, the Horned Frog #A1H and #B1H (completed in 2015) and 7% higher than our most recent Horned Frog wells, the Horned Frog #G1H and Horned Frog #H1H (completed in 2018). Our 2019 Horned Frog wells recorded Max-30 day rates that eclipsed 200 BOE/d per-foot, and importantly, are registering oil production rates that are 17% better than our 2018 completions, on a per-foot basis. Lastly, to date, our 2019 Horned Frog completions are outperforming the projections of our third-party engineers by 25% thus far. Lonestar holds a 100% WI / 78% NRI in these wells.

EAGLE FORD SHALE TREND - CENTRAL REGION

In our Central Region, 2Q19 production averaged approximately 5,652 BOE/d, a 69% increase over 1Q19 rates. The Company's second quarter results were positively impacted by 4 gross / 3.2 net wells placed onstream in Karnes County. The Company's third quarter results will be positively impacted by 3 gross / 3.0 net wells it has recently placed onstream on its Sooner property in DeWitt County.

In May 2019, the Company began flowback operations on the Georg #3H, Georg #4H, Georg #5H, and Georg #6H. These wells have some of the highest oil profiles (87%) in the Company's portfolio and have registered the following Max-30 rates:

  • Georg #3H – 7,156' perforated interval, 893 Bbls/d oil, 70 Bbls/d of NGLs, 369 Mcf/d, or 1,025 BOE/d (three-stream) on a 32/64" choke.
  • Georg #4H – 7,230' perforated interval, 804 Bbls/d oil, 62 Bbls/d of NGLs, 325 Mcf/d, or 920 BOE/d (three-stream) on a 32/64" choke.
  • Georg #5H – 7,227' perforated interval, 881 Bbls/d oil, 68 Bbls/d of NGLs, 359 Mcf/d, or 1,009 BOE/d (three-stream) on a 32/64" choke.
  • Georg #6H – 7,236' perforated interval, 1,056 Bbls/d oil, 90 Bbls/d of NGLs, 474 Mcf/d, or 1,225 BOE/d (three-stream) on a 32/64" choke.

Our 2019 wells in Karnes County follow 6 wells we placed onstream in 2018, and the Company has been able to continue to improve on prior results. By acquiring offsetting acreage contiguous to our existing leasehold, Lonestar was able to increase lateral lengths by 18% compared to 2018 wells but continues to exhibit modestly better productivity on a per-foot basis through 60 days of production, yielding superior well economics. Our 2019 wells have outperformed the type curve by 19% thus far. Lonestar has an 80% WI / 61% NRI in these wells.

In late July, Lonestar began flowback operations on 3.0 gross / 3.0 net wells on its Sooner property, which was acquired in November 2018, known as the Buchhorn #4H, Buchhorn #5H, and Buchhorn #6H. These wells are the first wells Lonestar has drilled on its Sooner property and were drilled to total measured depths of 20,327', 20,238', and 20,260', respectively. Lonestar fracture-stimulated these wells with an average proppant concentration of approximately 2,000 pounds per foot over 21 stages, using diverters. Test rates have averaged 3,460 BOE/d. Perforations and test rates for the wells are:

  • Buchhorn #4H – 6,157 perforated feet tested 542 Bbls/d oil, 1,311 Bbls/d of NGLs, 9,857 Mcf/d, or 3,496 BOE/d (three-stream) on a 24/64" choke.
  • Buchhorn #5H – 5,981 perforated feet tested 514 Bbls/d oil, 1,252 Bbls/d of NGLs, 9,407 Mcf/d, or 3,333 BOE/d (three-stream) on a 22/64" choke.
  • Buchhorn #6H – 6,021 perforated feet tested 545 Bbls/d oil, 1,334 Bbls/d of NGLs, 10,023 Mcf/d, or 3,549 BOE/d (three-stream) on a 22/64" choke.

Lonestar has 100% WI / 78% NRI in these wells.

EAGLE FORD SHALE TREND - EASTERN REGION

In our Eastern Region, production for the second quarter of 2019 averaged approximately 261 BOE/d, a 24% decrease compared to 1Q19 rates. The Company did not complete any wells in this region in the second quarter. However, Lonestar recently completed drilling operations on the Smith Family Ranch #1H, reaching a total measured depth of 22,025 feet. Lonestar expects to complete the well with a perforated interval of approximately 10,300 feet, stimulate the well in August, and place this well into flowback operations in September 2019. Lonestar has a 50% WI / 38% NRI in the well. Lonestar has engaged Intrepid Financial Partners, LLC to represent the Company in marketing its Eagle Ford Shale assets in Brazos and Robertson Counties for sale, with a target of concluding a transaction before year-end.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Tuesday, August 6, 2019 at 9:00 AM CDT to discuss the second quarter 2019 results and operational highlights.

To access the conference call, participants should dial:

USA: 1-888-221-1875

International: +1-303-223-4396

A playback of the conference call will be available on the Investor Relations section of Company's website beginning approximately August 7, 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 have accumulated approximately 72,178 gross (52,419 net) acres in what we believe to be the formation's crude oil and condensate windows, as of June 30, 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.

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Balance Sheets

(In thousands, except par value and share data)

 

June 30,

2019

 

December 31,

2018

Assets

Current assets

 

 

 

Cash and cash equivalents

$

3,340

 

 

$

5,355

 

Accounts receivable

 

 

 

Oil, natural gas liquid and natural gas sales

18,074

 

 

15,103

 

Joint interest owners and others, net

3,774

 

 

4,541

 

Related parties

24

 

 

301

 

Derivative financial instruments

7,143

 

 

15,841

 

Prepaid expenses and other

2,751

 

 

1,966

 

Total current assets

35,106

 

 

43,107

 

Property and equipment

 

 

 

Oil and gas properties, using the successful efforts method of accounting

 

 

 

Proved properties

976,638

 

 

960,711

 

Unproved properties

78,872

 

 

81,850

 

Other property and equipment

21,150

 

 

17,727

 

Less accumulated depreciation, depletion and amortization

(368,117

)

 

(369,529

)

Property and equipment, net

708,543

 

 

690,759

 

Derivative financial instruments

5,457

 

 

7,302

 

Other non-current assets

2,421

 

 

2,944

 

Total assets

$

751,527

 

 

$

744,112

 

Liabilities and Stockholders' Equity

Current liabilities

 

 

 

Accounts payable

$

30,021

 

 

$

18,260

 

Accounts payable – related parties

195

 

 

181

 

Oil, natural gas liquid and natural gas sales payable

13,339

 

 

13,022

 

Accrued liabilities

47,019

 

 

28,128

 

Derivative financial instruments

10,176

 

 

430

 

Total current liabilities

100,750

 

 

60,021

 

Long-term liabilities

 

 

 

Long-term debt

459,466

 

 

436,882

 

Asset retirement obligations

6,897

 

 

7,195

 

Deferred tax liabilities, net

682

 

 

12,370

 

Warrant liability

127

 

 

366

 

Warrant liability – related parties

234

 

 

689

 

Derivative financial instruments

1,726

 

 

21

 

Other non-current liabilities

3,043

 

 

4,021

 

Total long-term liabilities

472,175

 

 

461,544

 

Commitments and contingencies

 

 

 

Stockholders' Equity

 

 

 

Class A voting common stock, $0.001 par value, 100,000,000 shares authorized, 24,933,853 and 24,645,825 issued and outstanding, respectively

142,655

 

 

142,655

 

Series A-1 convertible participating preferred stock, $0.001 par value, 95,961 and 91,784 shares issued and outstanding, respectively

 

 

 

Additional paid-in capital

175,709

 

 

174,379

 

Accumulated deficit

(139,762

)

 

(94,487

)

Total stockholders' equity

178,602

 

 

222,547

 

Total liabilities and stockholders' equity

$

751,527

 

 

$

744,112

 

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

2019

 

2018

 

2019

 

2018

Revenues

 

 

 

 

 

 

 

Oil sales

$

44,726

 

 

$

39,707

 

 

$

78,310

 

 

$

72,859

 

Natural gas liquid sales

3,549

 

 

4,410

 

 

6,942

 

 

6,143

 

Natural gas sales

3,940

 

 

3,735

 

 

7,704

 

 

5,542

 

Total revenues

52,215

 

 

47,852

 

 

92,956

 

 

84,544

 

Expenses

 

 

 

 

 

 

 

Lease operating and gas gathering

8,929

 

 

6,490

 

 

16,638

 

 

11,074

 

Production and ad valorem taxes

2,818

 

 

2,761

 

 

5,109

 

 

4,927

 

Depreciation, depletion and amortization

21,515

 

 

20,737

 

 

39,486

 

 

36,162

 

Loss on sale of oil and gas properties

155

 

 

 

 

33,046

 

 

1,568

 

General and administrative

3,841

 

 

5,305

 

 

8,221

 

 

8,724

 

Acquisition costs and other

 

 

(3

)

 

(2

)

 

(13

)

Total expenses

37,258

 

 

35,290

 

 

102,498

 

 

62,442

 

Income (loss) from operations

14,957

 

 

12,562

 

 

(9,542

)

 

22,102

 

Other expense

 

 

 

 

 

 

 

Interest expense

(10,778

)

 

(9,298

)

 

(21,434

)

 

(18,555

)

Change in fair value of warrants

796

 

 

(2,462

)

 

694

 

 

(2,615

)

Gain (loss) on derivative financial instruments

9,514

 

 

(25,498

)

 

(26,724

)

 

(36,654

)

Loss on extinguishment of debt

 

 

 

 

 

 

(8,619

)

Total other expense

(468

)

 

(37,258

)

 

(47,464

)

 

(66,443

)

Income (loss) before income taxes

14,489

 

 

(24,696

)

 

(57,006

)

 

(44,341

)

Income tax (expense) benefit

(1,200

)

 

3,103

 

 

11,732

 

 

6,211

 

Net income (loss)

13,289

 

 

(21,593

)

 

(45,274

)

 

(38,130

)

Preferred stock dividends

(2,112

)

 

(1,932

)

 

(4,177

)

 

(3,821

)

Net income (loss) attributable to common stockholders

$

11,177

 

 

$

(23,525

)

 

$

(49,451

)

 

$

(41,951

)

 

 

 

 

 

 

 

 

Net income (loss) per common share

 

 

 

 

 

 

 

Basic

0.28

 

 

(0.96

)

 

(1.99

)

 

$

(1.71

)

Diluted

0.28

 

 

(0.96

)

 

(1.99

)

 

$

(1.71

)

 

 

 

 

 

 

 

 

Weighted average common shares outstanding

 

 

 

 

 

 

 

Basic

24,924,169

 

 

24,599,744

 

 

24,811,895

 

 

24,598,345

 

Diluted

24,924,169

 

 

24,599,744

 

 

24,811,895

 

 

24,598,345

 

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

2019

 

2018

 

2019

 

2018

Cash flows from operating activities

 

 

 

 

 

 

 

Net income (loss)

$

13,289

 

 

$

(21,593

)

 

$

(45,274

)

 

$

(38,130

)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation, depletion and amortization

21,515

 

 

20,737

 

 

39,486

 

 

36,162

 

Stock-based compensation

(181

)

 

2,263

 

 

352

 

 

2,713

 

Share-based payments

 

 

9

 

 

 

 

(601

)

Deferred taxes

1,234

 

 

(3,241

)

 

(11,688

)

 

(6,432

)

(Gain) loss on derivative financial instruments

(9,514

)

 

25,464

 

 

26,724

 

 

36,620

 

Settlements of derivative financial instruments

(4,888

)

 

(5,560

)

 

(3,579

)

 

(8,676

)

Gain on disposal of property and equipment

 

 

 

 

(17

)

 

 

Loss on abandoned property and equipment

 

 

 

 

 

 

170

 

Loss on sale of oil and gas properties

155

 

 

 

 

33,046

 

 

 

Non-cash interest expense

483

 

 

1,067

 

 

1,182

 

 

3,544

 

Change in fair value of warrants

(796

)

 

2,463

 

 

(694

)

 

2,615

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

(1,363

)

 

(122

)

 

(3,379

)

 

(254

)

Prepaid expenses and other assets

(996

)

 

(450

)

 

(692

)

 

(1,159

)

Accounts payable and accrued expenses

9,424

 

 

7,869

 

 

2,720

 

 

12,179

 

Net cash provided by operating activities

28,362

 

 

28,906

 

 

38,187

 

 

38,751

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

 

 

Acquisition of oil and gas properties

(673

)

 

(1,257

)

 

(3,025

)

 

(2,862

)

Development of oil and gas properties

(38,559

)

 

(35,238

)

 

(67,696

)

 

(66,761

)

Proceeds from sale of oil and gas properties

(154

)

 

 

 

11,953

 

 

 

Purchases of other property and equipment

(351

)

 

(150

)

 

(3,267

)

 

(1,498

)

Net cash used in investing activities

(39,737

)

 

(36,645

)

 

(62,035

)

 

(71,121

)

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

Proceeds from borrowings

24,000

 

 

26,178

 

 

54,000

 

 

290,744

 

Payments on borrowings

(13,052

)

 

(15,017

)

 

(32,167

)

 

(255,452

)

Net cash provided by financing activities

10,948

 

 

11,161

 

 

21,833

 

 

35,292

 

Net (decrease) increase in cash and cash equivalents

(427

)

 

3,422

 

 

(2,015

)

 

2,922

 

Cash and cash equivalents, beginning of the period

3,767

 

 

2,038

 

 

5,355

 

 

2,538

 

Cash and cash equivalents, end of the period

$

3,340

 

 

$

5,460

 

 

$

3,340

 

 

$

5,460

 

 

 

 

 

 

 

 

 

Supplemental information:

 

 

 

 

 

 

 

Cash paid for taxes

$

 

 

$

 

 

$

 

 

$

1,147

 

Cash paid for interest

3,027

 

 

2,173

 

 

19,770

 

 

6,143

 

Non-cash investing and financing activities:

 

 

 

 

 

 

 

Change in asset retirement obligation

$ 67

 

 

$ 151

 

 

$ (455

)

 

$ 183

 

Change in liabilities for capital expenditures

27,654

 

 

12,019

 

 

28,384

 

 

12,425

 

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 income (loss) before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, loss (gain) 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.

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

($ in thousands)

 

2019

 

2018

 

2019

 

2018

Net Income (Loss)

 

$

11,177

 

 

$

(23,525

)

 

$

(49,451

)

 

$

(41,951

)

Income tax expense (benefit)

 

1,200

 

 

(3,103

)

 

(11,732

)

 

(6,211

)

Interest expense (1)

 

12,890

 

 

11,230

 

 

25,611

 

 

22,376

 

Exploration expense

 

 

 

 

 

190

 

 

 

Depreciation, depletion and amortization

 

21,515

 

 

20,737

 

 

39,486

 

 

36,162

 

EBITDAX

 

46,782

 

 

5,339

 

 

4,104

 

 

10,376

 

Rig standby expense

 

310

 

 

 

 

416

 

 

 

Stock-based compensation

 

98

 

 

2,281

 

 

1,027

 

 

2,731

 

Loss on sale of oil and gas properties

 

155

 

 

 

 

33,046

 

 

 

Office lease write-off

 

 

 

 

 

 

 

1,568

 

Loss on extinguishment of debt

 

 

 

 

 

 

 

8,619

 

Unrealized (gain) loss on derivative financial instruments

 

(13,760

)

 

18,896

 

 

21,749

 

 

26,489

 

Change in fair value of warrants

 

(796

)

 

2,463

 

 

(694

)

 

2,615

 

Other expense

 

678

 

 

231

 

 

861

 

 

226

 

Adjusted EBITDAX

 

$

33,467

 

 

$

29,210

 

 

$

60,509

 

 

$

52,624

 

1 Interest expense also includes dividends paid on Series A Preferred Stock

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.

Lonestar Resources US Inc.

Unaudited Reconciliation of Income (Loss) Before Taxes As Reported To Income (Loss) Before Taxes Excluding Certain Items, a non-GAAP measure (Adjusted Net Income (Loss))

 

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

($ in thousands)

 

2019

 

2018

 

2019

 

2018

 

 

(In thousands)

 

(In thousands)

Income (loss) before income taxes, as reported

 

$

14,489

 

 

$

(24,696

)

 

$

(57,006

)

 

$

(44,341

)

Adjustments for special items:

 

 

 

 

 

 

 

 

General & administrative non-recurring costs

 

7

 

 

1

 

 

382

 

 

8

 

Rig standby expense

 

310

 

 

 

 

416

 

 

 

Non-recurring legal expense

 

670

 

 

233

 

 

670

 

 

233

 

Loss on extinguishment of debt

 

 

 

 

 

 

 

8,619

 

Unrealized hedging (gain) loss

 

(13,760

)

 

18,896

 

 

21,749

 

 

26,489

 

Lease write-off

 

 

 

 

 

 

 

1,568

 

Loss on sale of oil and gas properties

 

155

 

 

 

 

33,046

 

 

 

Stock based compensation

 

98

 

 

2,281

 

 

1,027

 

 

2,731

 

Income (loss) before income taxes, as adjusted

 

1,969

 

 

(3,285

)

 

284

 

 

(4,693

)

 

 

 

 

 

 

 

 

 

Income tax benefit (expense), as adjusted

 

 

 

 

 

 

 

 

Deferred (a)

 

(425

)

 

633

 

 

(61

)

 

904

 

Net income (loss) excluding certain items, a non-GAAP measure

 

1,543

 

 

(2,652

)

 

223

 

 

(3,789

)

 

 

 

 

 

 

 

 

 

Preferred stock dividends

 

(2,112

)

 

(1,932

)

 

(4,177

)

 

(3,821

)

Net loss excluding certain items, a non-GAAP measure

 

$ (569

)

 

$ (4,584

)

 

$ (3,954

)

 

$ (7,610

)

 

 

 

 

 

 

 

 

 

Non-GAAP loss per common share

 

 

 

 

 

 

 

 

Basic

 

$

(0.02

)

 

$

(0.19

)

 

$

(0.16

)

 

$

(0.31

)

Diluted

 

$

(0.02

)

 

$

(0.19

)

 

$

(0.16

)

 

$

(0.31

)

 

 

 

 

 

 

 

 

 

Non-GAAP basic shares outstanding

 

24,924,169

 

 

24,559,744

 

 

24,811,895

 

 

24,598,345

 

Non-GAAP diluted shares outstanding, if dilutive

 

24,924,169

 

 

24,559,744

 

 

24,811,895

 

 

24,598,345

 

(a)

Effective tax rate for 2019 and 2018 is estimated to be approximately 22% and 19%, respectively.

Lonestar Resources US Inc.

Unaudited Operating Results

 

In thousands, except per share and unit data

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

2019

 

2018

 

2019

 

2018

Operating Results

 

 

 

 

 

 

 

 

Net income (loss) attributable to common stockholders

 

$

11,177

 

 

$

(23,525

)

 

$

(49,451

)

 

$

(41,951

)

Net income (loss) per common share – basic

 

0.28

 

 

(0.96

)

 

(1.99

)

 

(1.71

)

Net income (loss) per common share – diluted

 

0.28

 

 

(0.96

)

 

(1.99

)

 

(1.71

)

Net cash provided by operating activities

 

28,362

 

 

28,906

 

 

38,187

 

 

38,751

 

Revenues

 

 

 

 

 

 

 

 

Oil

 

$

44,726

 

 

$

39,707

 

 

$

78,310

 

 

$

72,859

 

NGLs

 

3,549

 

 

4,410

 

 

6,942

 

 

6,143

 

Natural gas

 

3,940

 

 

3,735

 

 

7,704

 

 

5,542

 

Total revenues

 

$

52,215

 

 

$

47,852

 

 

$

92,956

 

 

$

84,544

 

Total production volumes by product

 

 

 

 

 

 

 

 

Oil (Bbls)

 

709,361

 

 

580,398

 

 

1,299,457

 

 

1,097,041

 

NGLs (Bbls)

 

263,994

 

 

221,858

 

 

481,555

 

 

308,786

 

Natural gas (Mcf)

 

1,601,656

 

 

1,268,813

 

 

2,896,860

 

 

1,848,010

 

Total barrels of oil equivalent (6:1)

 

1,240,298

 

 

1,013,740

 

 

2,263,822

 

 

1,713,708

 

Daily production volumes by product

 

 

 

 

 

 

 

 

Oil (Bbls/d)

 

7,795

 

 

6,378

 

 

7,179

 

 

6,061

 

NGLs (Bbls/d)

 

2,901

 

 

2,438

 

 

2,661

 

 

1,706

 

Natural gas (Mcf/d)

 

17,601

 

 

13,943

 

 

16,005

 

 

10,210

 

Total barrels of oil equivalent (BOE/d)

 

13,630

 

 

11,140

 

 

12,507

 

 

9,468

 

Average realized prices

 

 

 

 

 

 

 

 

Oil ($ per Bbl)

 

$

63.05

 

 

$

68.41

 

 

$

60.26

 

 

$

66.41

 

NGLs ($ per Bbl)

 

13.44

 

 

19.88

 

 

14.42

 

 

19.89

 

Natural gas ($ per Mcf)

 

2.46

 

 

2.94

 

 

2.66

 

 

3.00

 

Total oil equivalent, excluding the effect from commodity derivatives ($ per BOE)

 

42.10

 

 

47.20

 

 

41.06

 

 

49.33

 

Total oil equivalent, including the effect from commodity derivatives ($ per BOE)

 

38.63

 

 

40.69

 

 

38.86

 

 

43.40

 

Operating and other expenses

 

 

 

 

 

 

 

 

Lease operating and gas gathering

 

$

8,929

 

 

$

6,490

 

 

$

16,638

 

 

$

11,074

 

Production and ad valorem taxes

 

2,818

 

 

2,761

 

 

5,109

 

 

4,927

 

Depreciation, depletion and amortization

 

21,515

 

 

20,737

 

 

39,486

 

 

36,162

 

General and administrative (1)

 

3,841

 

 

5,305

 

 

8,221

 

 

8,724

 

Interest expense (2)

 

10,778

 

 

9,298

 

 

21,434

 

 

18,555

 

Operating and other expenses per BOE

 

 

 

 

 

 

 

 

Lease operating and gas gathering

 

$

7.20

 

 

$

6.40

 

 

$

7.35

 

 

$

6.46

 

Production and ad valorem taxes

 

2.27

 

 

2.72

 

 

2.26

 

 

2.88

 

Depreciation, depletion and amortization

 

17.35

 

 

20.46

 

 

17.44

 

 

21.10

 

General and administrative

 

3.10

 

 

5.23

 

 

3.63

 

 

5.09

 

Interest expense

 

8.69

 

 

9.17

 

 

9.47

 

 

10.83

 

(1)

General and administrative expenses include stock-based compensation

(2)

Interest expense includes amortization of debt issuance cost, premiums, and discounts

 

View Comments and Join the Discussion!