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Lonestar Announces Record Third Quarter 2019 Production

FORT WORTH, Texas--(BUSINESS WIRE)--

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

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.”

OPERATIONAL 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 SHALE TREND - WESTERN REGION

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 SHALE TREND - CENTRAL REGION

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 SHALE TREND - EASTERN REGION

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.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Tuesday, November 12, 2019 at 9:00 AM CST to discuss the third quarter 2019 results and operational highlights.

To access the conference call, participants should dial:

USA: 1-800-671-2810
International: +1-303-223-4371
A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately November 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 have accumulated approximately 72,703 gross (53,833 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of September 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)

 

September 30,
2019

 

December 31,
2018

Assets

Current assets

 

 

 

Cash and cash equivalents

$

3,441

 

 

$

5,355

 

Accounts receivable

 

 

 

Oil, natural gas liquid and natural gas sales

16,594

 

 

15,103

 

Joint interest owners and others, net

5,159

 

 

4,541

 

Related parties

5,213

 

 

301

 

Derivative financial instruments

15,798

 

 

15,841

 

Prepaid expenses and other

2,844

 

 

1,966

 

Total current assets

49,049

 

 

43,107

 

Property and equipment

 

 

 

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

 

 

 

Proved properties

1,009,545

 

 

960,711

 

Unproved properties

80,565

 

 

81,850

 

Other property and equipment

21,344

 

 

17,727

 

Less accumulated depreciation, depletion and amortization

(392,604

)

 

(369,529

)

Property and equipment, net

718,850

 

 

690,759

 

Derivative financial instruments

9,857

 

 

7,302

 

Other non-current assets

2,457

 

 

2,944

 

Total assets

$

780,213

 

 

$

744,112

 

Liabilities and Stockholders' Equity

Current liabilities

 

 

 

Accounts payable

$

34,363

 

 

$

18,260

 

Accounts payable – related parties

251

 

 

181

 

Oil, natural gas liquid and natural gas sales payable

15,286

 

 

13,022

 

Accrued liabilities

16,100

 

 

28,128

 

Derivative financial instruments

3,271

 

 

430

 

Total current liabilities

69,271

 

 

60,021

 

Long-term liabilities

 

 

 

Long-term debt

499,772

 

 

436,882

 

Asset retirement obligations

7,139

 

 

7,195

 

Deferred tax liabilities, net

5,387

 

 

12,370

 

Warrant liability

162

 

 

366

 

Warrant liability – related parties

299

 

 

689

 

Derivative financial instruments

4

 

 

21

 

Other non-current liabilities

3,360

 

 

4,021

 

Total long-term liabilities

516,123

 

 

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, 98,120 and 91,784 shares issued and outstanding, respectively

 

 

 

Additional paid-in capital

175,709

 

 

174,379

 

Accumulated deficit

(123,545

)

 

(94,487

)

Total stockholders' equity

194,819

 

 

222,547

 

Total liabilities and stockholders' equity

$

780,213

 

 

$

744,112

 

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Operations

(In thousands, except per share data)

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

 

2019

 

2018

 

2019

 

2018

Revenues

 

 

 

 

 

 

 

Oil sales

$

42,187

 

 

$

47,846

 

 

$

120,496

 

 

$

120,705

 

Natural gas liquid sales

3,439

 

 

6,795

 

 

10,381

 

 

12,939

 

Natural gas sales

7,519

 

 

4,096

 

 

15,224

 

 

9,637

 

Total revenues

53,145

 

 

58,737

 

 

146,101

 

 

143,281

 

Expenses

 

 

 

 

 

 

 

Lease operating and gas gathering

10,055

 

 

6,687

 

 

26,695

 

 

17,761

 

Production and ad valorem taxes

3,017

 

 

3,218

 

 

8,126

 

 

8,145

 

Depreciation, depletion and amortization

24,635

 

 

23,775

 

 

64,120

 

 

59,937

 

Loss on sale of oil and gas properties

483

 

 

 

 

33,530

 

 

1,568

 

Impairment of oil and gas properties

 

 

12,169

 

 

 

 

12,169

 

General and administrative

4,124

 

 

4,661

 

 

12,345

 

 

13,385

 

Acquisition costs and other

(2

)

 

315

 

 

(4

)

 

302

 

Total expenses

42,312

 

 

50,825

 

 

144,812

 

 

113,267

 

Income from operations

10,833

 

 

7,912

 

 

1,289

 

 

30,014

 

Other expense

 

 

 

 

 

 

 

Interest expense

(11,295

)

 

(10,215

)

 

(32,730

)

 

(28,771

)

Change in fair value of warrants

(100

)

 

509

 

 

594

 

 

(2,105

)

Gain (loss) on derivative financial instruments

21,546

 

 

(18,198

)

 

(5,177

)

 

(54,852

)

Loss on extinguishment of debt

 

 

 

 

 

 

(8,619

)

Total other expense

10,151

 

 

(27,904

)

 

(37,313

)

 

(94,347

)

Income (loss) before income taxes

20,984

 

 

(19,992

)

 

(36,024

)

 

(64,333

)

Income tax (expense) benefit

(4,767

)

 

282

 

 

6,966

 

 

6,493

 

Net income (loss)

16,217

 

 

(19,710

)

 

(29,058

)

 

(57,840

)

Preferred stock dividends

(2,159

)

 

(1,975

)

 

(6,336

)

 

(5,796

)

Net income (loss) attributable to common stockholders

$

14,058

 

 

$

(21,685

)

 

$

(35,394

)

 

$

(63,636

)

 

 

 

 

 

 

 

 

Net income (loss) per common share

 

 

 

 

 

 

 

Basic

$

0.34

 

 

$

(0.88

)

 

$

(1.42

)

 

$

(2.59

)

Diluted

$

0.33

 

 

$

(0.88

)

 

$

(1.42

)

 

$

(2.59

)

 

 

 

 

 

 

 

 

Weighted average common shares outstanding

 

 

 

 

 

 

 

Basic

24,933,853

 

 

24,599,744

 

 

24,852,994

 

 

24,598,816

 

Diluted

25,331,810

 

 

24,599,744

 

 

24,852,994

 

 

24,598,816

 

Lonestar Resources US Inc.

Unaudited Condensed Consolidated Statements of Cash Flows

(In thousands)

Three Months Ended September 30,

 

Nine Months Ended September 30,

2019

 

2018

 

2019

 

2018

Cash flows from operating activities

 

 

 

 

 

 

 

Net income (loss)

$

16,216

 

 

$

(19,710

)

 

$

(29,058

)

 

$

(57,840

)

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

 

 

 

 

 

 

 

Depreciation, depletion and amortization

24,634

 

 

23,775

 

 

64,120

 

 

59,937

 

Stock-based compensation

942

 

 

924

 

 

1,294

 

 

3,637

 

Stock-based payments

 

 

 

 

 

 

(601

)

Deferred taxes

4,705

 

 

(714

)

 

(6,983

)

 

(7,145

)

(Gain) loss on derivative financial instruments

(21,547

)

 

18,198

 

 

5,177

 

 

54,852

 

Settlements of derivative financial instruments

(279

)

 

(7,647

)

 

(3,858

)

 

(16,323

)

Impairment of oil and gas properties

 

 

12,169

 

 

 

 

12,169

 

Gain on disposal of property and equipment

 

 

 

 

(17

)

 

 

Loss on abandoned property and equipment

 

 

 

 

 

 

171

 

Loss on sale of oil and gas properties

484

 

 

 

 

33,530

 

 

 

Non-cash interest expense

640

 

 

1,013

 

 

1,822

 

 

4,556

 

Changes in fair value of warrants

100

 

 

(509

)

 

(594

)

 

2,105

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

Accounts receivable

(4,951

)

 

(4,343

)

 

(8,330

)

 

(4,596

)

Prepaid expenses and other assets

(410

)

 

(676

)

 

(1,102

)

 

(1,835

)

Accounts payable and accrued expenses

(5,848

)

 

(5,410

)

 

(3,128

)

 

6,733

 

Net cash provided by operating activities

14,686

 

 

17,070

 

 

52,873

 

 

55,820

 

 

 

 

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

 

 

 

Acquisition of oil and gas properties

(2,214

)

 

(1,900

)

 

(5,239

)

 

(4,762

)

Development of oil and gas properties

(51,577

)

 

(55,931

)

 

(119,273

)

 

(122,691

)

Proceeds from sale of oil and gas properties

(483

)

 

 

 

11,470

 

 

 

Purchases of other property and equipment

(260

)

 

(133

)

 

(3,527

)

 

(1,631

)

Net cash used in investing activities

(54,534

)

 

(57,964

)

 

(116,569

)

 

(129,084

)

 

 

 

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

 

 

 

Proceeds from borrowings

60,000

 

 

58,000

 

 

114,000

 

 

348,744

 

Payments on borrowings

(20,051

)

 

(18,014

)

 

(52,218

)

 

(273,466

)

Repurchase and retire Class B Common Stock

 

 

(10

)

 

 

 

(10

)

Net cash provided by financing activities

39,949

 

 

39,976

 

 

61,782

 

 

75,268

 

Net increase (decrease) in cash and cash equivalents

101

 

 

(918

)

 

(1,914

)

 

2,004

 

Cash and cash equivalents, beginning of the period

3,340

 

 

5,460

 

 

5,355

 

 

2,538

 

Cash and cash equivalents, end of the period

$

3,441

 

 

$

4,542

 

 

$

3,441

 

 

$

4,542

 

 

 

 

 

 

 

 

 

Supplemental information:

 

 

 

 

 

 

 

Cash paid for taxes

$

 

 

$

 

 

$

 

 

$

1,147

 

Cash paid for interest

8,355

 

 

16,181

 

 

28,125

 

 

22,324

 

Non-cash investing and financing activities:

 

 

 

 

 

 

 

Change in asset retirement obligation

163

 

 

39

 

 

(292

)

 

222

 

Change in liabilities for capital expenditures

(19,286

)

 

4,563

 

 

9,098

 

 

16,988

 

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 September 30,

 

Nine Months Ended September 30,

($ in thousands)

 

2019

 

2018

 

2019

 

2018

Net Income (Loss)

 

$

14,058

 

 

$

(21,685

)

 

$

(35,394

)

 

$

(63,636

)

Income tax expense (benefit)

 

4,767

 

 

(282

)

 

(6,966

)

 

(6,493

)

Interest expense (1)

 

13,454

 

 

12,190

 

 

39,066

 

 

34,567

 

Exploration expense

 

 

 

109

 

 

190

 

 

109

 

Depreciation, depletion and amortization

 

24,635

 

 

23,775

 

 

64,120

 

 

59,937

 

EBITDAX

 

56,914

 

 

14,107

 

 

61,016

 

 

24,484

 

Rig standby expense

 

135

 

 

27

 

 

552

 

 

27

 

Stock-based compensation

 

942

 

 

924

 

 

1,970

 

 

3,637

 

Loss on sale of oil and gas properties

 

483

 

 

 

 

33,530

 

 

 

Office lease write-off

 

 

 

 

 

 

 

1,568

 

Loss on extinguishment of debt

 

 

 

 

 

 

 

8,619

 

Impairment of oil and gas properties

 

 

 

12,169

 

 

 

 

12,169

 

Unrealized (gain) loss on derivative financial instruments

 

(22,098

)

 

9,911

 

 

(349

)

 

36,401

 

Unrealized loss (gain) on warrants

 

100

 

 

(509

)

 

(593

)

 

2,105

 

Other expense

 

576

 

 

375

 

 

1,435

 

 

600

 

Adjusted EBITDAX

 

$

37,052

 

 

$

37,004

 

 

$

97,561

 

 

$

89,610

 

 

(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 September 30,

 

Nine Months Ended September 30,

($ in thousands)

 

2019

 

2018

 

2019

 

2018

 

 

 

 

 

Income (loss) before income taxes, as reported

 

$

20,984

 

 

$

(19,992

)

 

$

(36,024

)

 

$

(64,333

)

Adjustments for special items:

 

 

 

 

 

 

 

 

Impairment of oil and gas properties

 

 

 

12,169

 

 

 

 

12,169

 

General & administrative non-recurring costs

 

 

 

168

 

 

960

 

 

176

 

Rig standby expense

 

135

 

 

27

 

 

552

 

 

27

 

Non-recurring legal expense

 

 

 

 

 

670

 

 

233

 

Loss on extinguishment of debt

 

 

 

 

 

 

 

8,619

 

Unrealized hedging (gain) loss

 

(22,098

)

 

9,911

 

 

(349

)

 

36,401

 

Lease write-off

 

 

 

 

 

 

 

1,568

 

Loss on sale of oil and gas properties

 

483

 

 

 

 

33,530

 

 

 

Stock-based compensation

 

942

 

 

924

 

 

1,970

 

 

3,637

 

(Loss) Income before income taxes, as adjusted

 

446

 

 

3,207

 

 

1,309

 

 

(1,503

)

 

 

 

 

 

 

 

 

 

Income tax benefit (expense), as adjusted

 

 

 

 

 

 

 

 

Deferred (1)

 

(93

)

 

(655)

 

 

(273

)

 

307

 

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

 

353

 

 

2,552

 

 

1,036

 

 

(1,196

)

 

 

 

 

 

 

 

 

 

Preferred stock dividends

 

(2,159

)

 

(1,975

)

 

(6,336

)

 

(5,796

)

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

 

$

(1,806

)

 

$

577

 

 

$

(5,300

)

 

$

(6,992

)

 

(1) Effective tax rate for 2019 and 2018 is estimated to be approximately 21% and 20%, respectively.

 

Lonestar Resources US Inc.

Unaudited Operating Results

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

In thousands, except per share and unit data

 

2019

 

2018

 

2019

 

2018

Operating Results

 

 

 

 

 

 

 

 

Net income (loss) attributable to common stockholders

 

$

14,058

 

 

$

(21,685

)

 

$

(35,394

)

 

$

(63,636

)

Net income (loss) per common share – basic

 

0.34

 

 

(0.88

)

 

(1.42

)

 

(2.59

)

Net income (loss) per common share – diluted

 

0.33

 

 

(0.88

)

 

(1.42

)

 

(2.59

)

Net cash provided by operating activities

 

14,686

 

 

17,069

 

 

52,873

 

 

55,820

 

Revenues

 

 

 

 

 

 

 

 

Oil

 

$

42,187

 

 

$

47,846

 

 

$

120,496

 

 

$

120,705

 

NGLs

 

3,439

 

 

6,795

 

 

10,381

 

 

12,939

 

Natural gas

 

7,519

 

 

4,096

 

 

15,224

 

 

9,637

 

Total revenues

 

$

53,145

 

 

$

58,737

 

 

$

146,101

 

 

$

143,281

 

Total production volumes by product

 

 

 

 

 

 

 

 

Oil (Bbls)

 

725,405

 

 

660,836

 

 

2,024,862

 

 

1,758,393

 

NGLs (Bbls)

 

387,256

 

 

262,660

 

 

868,811

 

 

571,389

 

Natural gas (Mcf)

 

3,313,757

 

 

1,343,016

 

 

6,210,617

 

 

3,190,824

 

Total barrels of oil equivalent (6:1)

 

1,664,954

 

 

1,147,332

 

 

3,928,776

 

 

2,861,586

 

Daily production volumes by product

 

 

 

 

 

 

 

 

Oil (Bbls/d)

 

7,885

 

 

7,183

 

 

7,417

 

 

6,441

 

NGLs (Bbls/d)

 

4,209

 

 

2,855

 

 

3,182

 

 

2,093

 

Natural gas (Mcf/d)

 

36,019

 

 

14,600

 

 

22,750

 

 

11,689

 

Total barrels of oil equivalent (BOE/d)

 

18,097

 

 

12,471

 

 

14,391

 

 

10,482

 

Average realized prices

 

 

 

 

 

 

 

 

Oil ($ per Bbl)

 

$

58.16

 

 

$

72.40

 

 

$

59.51

 

 

$

68.65

 

NGLs ($ per Bbl)

 

8.88

 

 

25.87

 

 

11.95

 

 

22.64

 

Natural gas ($ per Mcf)

 

2.27

 

 

3.05

 

 

2.45

 

 

3.02

 

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

 

31.92

 

 

51.19

 

 

37.19

 

 

50.07

 

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

 

31.59

 

 

43.97

 

 

35.78

 

 

43.62

 

Operating and other expenses

 

 

 

 

 

 

 

 

Lease operating and gas gathering

 

$

10,055

 

 

$

6,687

 

 

$

26,695

 

 

$

17,761

 

Production and ad valorem taxes

 

3,017

 

 

3,218

 

 

8,126

 

 

8,145

 

Depreciation, depletion and amortization

 

24,635

 

 

23,775

 

 

64,120

 

 

59,937

 

General and administrative (1)

 

4,124

 

 

4,661

 

 

12,345

 

 

13,385

 

Interest expense (2)

 

11,295

 

 

10,215

 

 

32,730

 

 

28,771

 

Operating and other expenses per BOE

 

 

 

 

 

 

 

 

Lease operating and gas gathering

 

$

6.04

 

 

$

5.83

 

 

$

6.79

 

 

$

6.21

 

Production and ad valorem taxes

 

1.81

 

 

2.80

 

 

2.07

 

 

2.85

 

Depreciation, depletion and amortization

 

14.80

 

 

20.72

 

 

16.32

 

 

20.95

 

General and administrative

 

2.48

 

 

4.06

 

 

3.14

 

 

4.68

 

Interest expense

 

6.78

 

 

8.90

 

 

8.33

 

 

10.05

 

 

(1)   General and administrative expenses include stock-based compensation

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

 

View source version on businesswire.com: https://www.businesswire.com/news/home/20191111005638/en/