•

Lonestar Resources registered a 13% increase in net oil and gas production to 6,573 Boe/d in 2Q16, compared to 5,804 Boe/d in the second quarter of 2015 (“2Q15”). In the second quarter of 2016, 76% of the Company’s production was crude oil and NGL’s.  The Company’s second quarter 2016 production results also represent a modest sequential increase over production results in the first quarter of 2016 (“1Q16”). However, crude oil production rose 17% sequentially as Lonestar’s 2016 completions have all been in the crude oil window.

•

The Company continues to focus its technical and capital resources on the Eagle Ford Shale play of south Texas, where it generated a 17% increase in net oil and gas production in 2Q16 over 2Q15 results, to 5,991 BOE/D.

•

Lonestar reported a net loss of $12.8 million for 2Q16 versus a net loss of $8.4 million in 2Q15.  This loss in 2Q16 includes $13.2 million associated with a non-cash, mark-to-market revaluation of Lonestar’s crude oil hedge portfolio.

•

Adjusted EBITDAX for the second quarter of 2016 was $16.0 million compared to $22.0 million for 2Q15, as a 13% increase in production volumes partially offset a 21% decrease in revenues due to a sharp decline in West Texas Intermediate oil prices and Henry Hub gas prices compared to 2Q15. Please see “Non-GAAP Financial Measures” at the end of this release for the definition of EBITDAX, a reconciliation of EBITDAX to net income (loss), and the reasons for its use.

•

Effective July 5^th, 2016, Lonestar successfully completed its efforts to re-domicile from the Australian Stock Exchange to the United States, listing on the NASDAQ Global Market under the ticker “LONE”.

•

At June 30, 2016, $99.5 million was outstanding on the $120 million Senior Secured Credit Facility, leaving $20.5 million undrawn and available.  

•

As of August 18, 2016, the Company executed open-market purchases of its 8 ¾% Senior Unsecured Notes due April 15, 2019 totaling $48.4 million.  These purchases were funded by the

Company’s 12.0% Second Lien Notes.  As of August 19, 2016, Lonestar has issued $25.0 million on its Second Lien Notes, and has $24.9 million remaining available for additional issuance. The net effect of these transactions is a $23.4 million reduction in total debt outstanding as of August 19, 2016, which the Company estimates would yield approximately $1.4 million of net interest expense savings on an annualized basis.

•

On August 2, 2016, Lonestar entered into an agreement with subsidiaries of Leucadia National Corporation, which allows for the issuance of up to $49.9 million of Second Lien Notes, which are secured by second-priority liens on substantially all of the Company’s assets, pursuant to an intercreditor agreement with the lenders in the Company’s Senior Secured Revolving Credit Facility. As of August 18^th, 2016, Lonestar had issued $25.0 million of Second Lien Notes, leaving $24.9 million available for additional issuances.

•

As of August 18^th, 2016, in a series of open-market transactions, Lonestar had purchased $48.4 million of its 8 ¾% Senior Unsecured Notes due April 15, 2019, leaving $171.6 million of these Notes outstanding. The net effect of these transactions has been to reduce Lonestar’s long-term debt from $319.5 million to $294.7 million, as if these transactions had occurred at June 30, 2016.

•

Lonestar reported a 13% increase in total company production in the second quarter of 2016 and a 17% increase in its Eagle Ford Shale production. Second quarter 2016 volumes  of 6,573 Boe/d were comprised of 3,979 barrels of oil per day,  1,039 barrels of NGL’s per day, and 9,332 Mcf of natural gas per day.  The Company produced 6,564 Boe/d through the first six months of 2016, an increase of 16% over the comparable period in 2015.   The Company’s production rates rose modestly sequentially, as new Eagle Ford Shale wells were placed onstream at a slower rate than in past quarters. During the second quarter of 2016, Lonestar placed 2 new Eagle Ford Shale wells onstream during May, 2016.  Lonestar holds a 42% working interest and a 33% net

revenue interest in these wells, meaning that Lonestar added 2.0 gross / 0.8 net wells in the second quarter of 2016, as compared to 3.0 gross / 2.9 net wells in the first quarter of 2016 and 4.0 gross / 2.3 net wells in the fourth quarter of 2015.  However, crude oil production rose 17% sequentially from 3,414 Bo/d for the three months ended March 31, 2016 as Lonestar’s 2016 completions have all been in the crude oil window.

•

Lonestar’s lease operating expenses for the second quarter of 2016 were $4.4 million, representing a 4% decrease over 2Q15 lease operating expenses of $4.6 million. Notably, lease operating expenses on a dollar basis were reduced in spite of a 13% increase in production volumes. The factors combined yield an 15% reduction in total field operating expenses on a unit of production basis from 2Q15’s levels of $8.68 per BOE to $7.35 per BOE in the current quarter.

•

Crude oil hedging continues to be an important element of Lonestar’s strategy. We believe crude oil hedging provides increased visibility to cash flow streams and associated liquidity in the current crude oil price environment, as well as augmenting the Company’s borrowing base.  For 2016, the Company has West Texas Intermediate (“WTI”) swaps covering 2,692 barrels of oil per day for July 2016 through December 2016 at an average strike price of $69.57 per barrel.  As previously announced, the Company has three-way collars covering 1,000 bop/d for calendar 2017, which provide an effective floor of $55.25 per barrel with WTI prices between $40.00 per barrel and $60.00 per barrel but also gives upside to $80.25 per barrel. During the second quarter of 2016, the Company added 500 barrels of oil per day of NYMEX crude oil swaps for January 2017 through December 2017 at a volume weighted average strike price of $50.87 per barrel.  In total for 2017 the Company has 1,500 barrels of oil per day hedged at an average strike price of $53.79 per barrel. At June 30, 2016, the mark-to-market value of Lonestar’s hedge portfolio was $12.7 million.

•

Lonestar added to its Eagle Ford Shale leasehold and reserves position by issuing 500,227 shares of its Class A common stock to Juneau Energy, LLC (98% owned by Leucadia National Corp.) in exchange for 2,567 gross / 1,284 net acres in Brazos County, which includes the purchase of a 50.0% Working Interest (“WI”)/ 39% Net Revenue Interest (“NRI”) in two wells which hold all of the acreage by production.  Lonestar will assume operatorship of this leasehold. In the month of July, these two wells produced 650 Boe/d gross / 254 Boe/d net. The acreage has the potential for 11 horizontal wells.  Lonestar’s initial internal reserves estimates include Proved and Probable Reserves of 1.1 Million Barrels of Oil Equivalent (“MMBOE”).

•

Asherton – In central Dimmit County, no new wells were completed during the three months ended June 30, 2016.  Production rates from the four producing wells continued to outperform the third-party engineering projections.  The Asherton leasehold is held by production, and Lonestar does not plan drilling activity here in 2016.

•

Beall Ranch – In Dimmit County, Lonestar drilled and completed the Beall Ranch #20H - #22H with an average perforated interval of 6,075 feet in in the first quarter of 2016. The three new wells were fracture stimulated with an average proppant concentration of 1,520 pounds per foot, and commenced flowback in late first quarter of 2016. These were the first three wells completed in partnership with Schlumberger as part of the companies’ Geo-Engineered Completion Alliance (“GECA”). While still preliminary, the production results during the first 150 days onstream are encouraging, as the cumulative production is 14% higher than that of the #26H - #28H wells, drilled 12 months prior, when compared on a barrel-per-lateral-foot basis for the same period of time. The #26H-#28H wells utilized certain elements of the GECA, which Lonestar believes were significant contributors to the 43% outperformance as compared to the offsets, the #32H-#34H, which were completed in July, 2015.  In total, through two iterations of technology improvements, Lonestar has achieved a 63% improvement in cumulative oil production per lateral foot.  Lonestar is encouraged by the results of the GECA to date, and will seek to apply them across its portfolio.

•

Burns Ranch Area – Burns Ranch production was curtailed during the first quarter of 2016 by a severe fire at Southcross Energy, L.P.’s Lancaster gas processing plant, which rendered all of the Company’s natural gas and natural gas liquids unsaleable in the months of February and March 2016. The same issue partially affected April 2016, which reduced sales by approximately 26 Boe/d in the three months ended June 30, 2016. The Lancaster plant resumed normal operations mid-April 2016 and Burns Ranch sales volumes have recovered. Drilling activity at Burns Ranch has been delayed by protracted negotiations related to a lease swap on certain of Lonestar’s leasehold on the property. In August 2016, Lonestar executed a lease swap agreement with another operator and consolidated Lonestar’s leasehold position so that we can now drill at our own discretion.  Within the leasehold associated with this trade prior to this lease swap, Lonestar had 19 gross/15.1 net laterals booked totaling 152,000 lateral feet. Following the lease swap, Lonestar has 18 gross/16.1 net laterals totaling 151,000 lateral feet. Lonestar commenced drilling operations on the Burns Ranch Eagleford B Unit #8H, #9H and #10H wells with a planned average lateral length of 9,000 feet.  Lonestar anticipates that completion of these three wells will increase the leasehold that is held by production at Burns Ranch from 2,712 net acres to 3,328 net acres, which equates to 86% of our total net leasehold at Burns Ranch.  

•

Horned Frog – In southern La Salle County, no new wells were completed during the three months ended June 30, 2016. Lonestar does not plan drilling activity on the Horned Frog property in 2016, having held on the leasehold by production with our drilling activity during 2015.

•

Southern Gonzales County – Encouraged by the results of the initial six wells on our Harvey Johnson lease in southern Gonzales County, Lonestar leased a total of 1,450 gross / 1,450 net acres in our Cyclone project area through June 30, 2016, just west of Harvey Johnson.  Lonestar

drilled and completed the Cyclone #9H and #10H wells on this leasehold, and placed these two wells onstream on May 12, 2016.  After drilling a pilot hole and running logs to gather information on rock properties and petro-physics , Lonestar drilled and completed the Cyclone #9H & #10H with an average perforated interval of 6,685 feet. Lonestar holds a 42% WI / 33% NRI in these wells. The two new wells were fracture stimulated with an average proppant concentration of 1,518 pounds per foot. The Cyclone #9H tested 543 Bopd and 239 Mcfg/d, or 598 Boe/d on a processed three-stream basis on an 18/64” choke and registered a 30-day production rate of 486 Boe/d. The Cyclone #10H tested 576 Bopd and 239 Mcfg/d, or 631 Boe/d on a processed three-stream basis on an 18/64” choke and registered a 30-day production rate of 521 Boe/d.  Originally estimated to cost an average of $5.2 million, these wells have been drilled and completed at an average cost of $4.7 million.  Based on the results of its initial wells on the Cyclone project, Lonestar has executed agreements to lease an additional 1,456 gross / 1,322 net acres that directly offset the Cyclone #9H and #10H wells. These additions increase Lonestar’s total leasehold in its Cyclone project to 2,906 gross / 2,656 net acres as of August 15^th, 2016, which is expected to accommodate 29 additional laterals with an average lateral length exceeding 7,000 feet.

•

Brazos & Robertson Counties – In central Brazos County, Lonestar has permitted two 8,000-foot laterals with the Texas Railroad Commission and on March 8^th, 2016 Lonestar was granted operations permits with the City of College Station. The Company is encouraged by the results of offset drilling by a leading operator, who recently announced 30-day production rates on four wells immediately offsetting Lonestar’s leasehold, which have ranged from 1,587 to 1,973 BOE per day.  Lonestar currently plans to drill these wells in the fourth quarter of 2016.  

June 30,

2016

(unaudited)

December 31,

2015

Assets

Current assets

Cash and cash equivalents

$

5,147

$

4,322

Accounts receivable:

Oil, natural gas liquid and natural gas sales

6,402

5,043

Joint interest owners and other

1,044

1,305

Related parties

—

279

Derivative financial instruments

13,182

33,219

Prepaid expenses and other

703

724

Total current assets

26,478

44,892

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

478,363

488,100

Other property and equipment, net

2,106

2,223

Derivative financial instruments

681

2,864

Other noncurrent assets

1,609

1,580

Restricted certificates of deposit

77

77

Total assets

$

509,314

$

539,736

June 30,

2016

(unaudited)

December 31,

2015

Liabilities and Stockholders’ Equity

Current liabilities

Accounts payable

$

9,156

$

18,027

Accounts payable – related parties

160

45

Oil, natural gas liquid and natural gas sales payable

3,995

3,870

Accrued liabilities

8,311

8,276

Accrued liabilities – related parties

243

125

Derivative financial instruments

968

—

Total current liabilities

22,833

30,343

Long-term debt

315,197

301,926

Deferred tax liability

3,885

16,013

Other non-current liabilities

1,000

1,000

Asset retirement obligations

7,218

7,488

Derivative financial instruments

182

—

Total liabilities

350,315

356,770

Commitments and contingencies

Stockholders’ equity

Common stock, $0.20 par value, 500,000,000 shares authorized, 15,044,051 shares

   issued and outstanding  at June 30, 2016 and December 31, 2015

142,638

142,638

Additional paid-in capital

10,461

10,270

Accumulated other comprehensive loss

(776

)

(760

)

Retained earnings

6,676

30,818

Total stockholders’ equity

158,999

182,966

Total liabilities and stockholders’ equity

$

509,314

$

539,736

Three months ended

Six months ended

June 30,

June 30,

2016

2015

2016

2015

Revenues

Oil sales

$

15,168

$

21,338

$

24,119

$

37,559

Natural gas sales

1,636

1,151

3,257

2,479

Natural gas liquid sales

999

609

1,623

1,122

Total revenues

17,803

23,098

28,999

41,160

Costs and expenses

Lease operating and gas gathering

4,398

4,589

8,758

8,050

Production, ad valorem, and severance taxes

1,223

1,476

2,139

2,827

Rig standby expense

1,584

—

1,897

—

Depletion, depreciation, and amortization

12,498

13,253

27,636

26,039

Accretion of asset retirement obligations

51

54

107

106

(Gain) loss on sale of oil and gas properties

(1,531

)

—

(1,531

)

625

Impairment of oil and gas properties

1,938

—

1,938

—

Stock-based compensation

95

433

191

866

General and administrative

2,858

2,408

5,631

4,696

Other (income) expense

819

(4

)

1,047

35

Total costs and expenses

23,933

22,209

47,813

43,244

Income (loss) from operations

(6,130

)

889

(18,814

)

(2,084

)

Other income (expense)

Interest expense

(6,174

)

(5,972

)

(12,299

)

(11,819

)

Losses on derivative financial instruments

(6,785

)

(7,500

)

(5,069

)

(525

)

Total other expense, net

(12,959

)

(13,472

)

(17,368

)

(12,344

)

Loss before income taxes

(19,089

)

(12,583

)

(36,182

)

(14,428

)

Income tax benefit

6,245

4,230

12,040

5,350

Net loss

$

(12,844

)

$

(8,353

)

$

(24,142

)

$

(9,078

)

Net loss per common share-basic and diluted

$

(0.85

)

$

(0.56

)

$

(1.60

)

$

(0.60

)

Weighted average common shares outstanding–basic and diluted

15,044,051

15,044,051

15,044,051

15,044,051

Other comprehensive loss:

Net loss

$

(12,844

)

$

(8,353

)

$

(24,142

)

$

(9,078

)

Foreign currency translation adjustments

(17

)

(13

)

(16

)

1

Comprehensive loss

$

(12,861

)

$

(8,366

)

$

(24,158

)

$

(9,077

)

Six months ended June 30,

2016

2015

Operating activities

Net loss

$

(24,142

)

$

(9,078

)

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

(Gain) loss on disposal of oil and gas properties

(919

)

625

Accretion of asset retirement obligations

107

106

Depreciation, depletion, and amortization

27,636

26,039

Stock-based compensation

191

866

Deferred taxes

(12,129

)

(5,357

)

Loss on derivative financial instruments

5,069

525

Settlements of derivative financial instruments

18,300

18,376

Impairment of oil and gas properties

1,938

-

Non-cash interest expense

550

550

Changes in operating assets and liabilities:

Accounts receivable

(818

)

1,415

Prepaid expenses and other assets

229

(213

)

Accounts payable and accrued expenses

(8,479

)

(8,226

)

Net cash provided by operating activities

7,533

25,628

Investing activities

Acquisition of oil and gas properties

(2,717

)

(3,470

)

Development of oil and gas properties

(19,003

)

(54,585

)

Proceeds from sales of oil and gas properties

2,720

-

Purchases of other property and equipment

(177

)

(135

)

Net cash used in investing activities

(19,177

)

(58,190

)

Financing activities

Proceeds from bank borrowings

23,500

32,000

Payments on bank borrowings

(11,000

)

(5,000

)

Payments on other note payable

(15

)

(15

)

Net cash provided by financing activities

12,485

26,985

Effect of exchange rate changes on cash and cash equivalents

(16

)

1

Increase (decrease) in cash and cash equivalents

825

(5,576

)

Cash and cash equivalents, beginning of the period

4,322

9,992

Cash and cash equivalents, end of the period

$

5,147

$

4,416

Supplemental information

Cash paid for interest expense

$

11,082

$

10,672

Three Months Ended June 30,

Six Months Ended June 30,

($ in thousands)

2016

2015

2016

2015

Net Income (Loss)

$

(12,844

)

$

(8,353

)

$

(24,142

)

$

(9,078

)

Income tax expense (benefit)

(6,245

)

(4,230

)

(12,040

)

(5,350

)

Interest expense

6,174

5,972

12,299

11,819

Exploration expense

1

51

1

51

Depletion, depreciation, amortization and accretion

12,549

13,307

27,743

26,145

EBITDAX

(365

)

6,747

3,861

23,587

Rig Standby Expense

1,584

—

1,897

—

Non-recurring costs⁽¹⁾

321

19

645

19

Stock based compensation

95

433

191

865

(Gain) loss on sale of properties

(1,531

)

—

(1,531

)

625

Impairment of oil and gas properties

1,938

—

1,938

—

Unrealized (gain) loss on derivative financial instruments

13,176

14,908

21,605

18,677

Other income (expense)

819

(4

)

1,047

34

Adjusted EBITDAX

$

16,037

$

22,103

$

29,653

$

43,807

For the three months

ended June 30,

For the six months

ended June 30,

2016

2015

2016

2015

Daily production volumes by product -

Crude oil (MBbls)

3,979

4,175

3,696

4,110

NGLs (MBbls)

1,039

644

1,222

593

Natrual gas (MMcf)

9,332

5,909

9,874

5,839

Total barrels of oil equivalent (Boe/d)

6,573

6,573

6,564

5,676

Daily production volumes by region (Boe/d) -

Eagle Ford Shale

5,991

5,113

5,974

4,971

Conventional

582

691

590

705

Total barrels of oil equivalent (Boe/d)

6,573

5,804

6,564

5,676

Average realized prices -

Crude oil ($ per Bbl)

$

41.89

$

56.16

$

35.85

$

50.52

NGLs ($ per Bbl)

10.58

10.38

7.30

10.38

Natural gas ($ per Mcf)

1.93

2.16

1.81

2.34

Total Oil Equivalent, excluding the effect from hedging

$

29.77

$

43.76

$

24.28

$

40.03

Total Oil Equivalent, including the effect from hedging

$

40.45

$

57.79

$

38.12

$

57.69

Operating Expenses per BOE:

Lease operating and gas gathering

$

7.35

$

8.68

$

7.33

$

7.83

Production, ad valorem, and severance taxes

2.04

2.79

1.79

2.75

General and administrative

4.78

4.56

4.71

4.57