•

During the quarter, the Company was primarily focused on balance sheet improvements, and therefore completed no new Eagle Ford Shale wells during the third quarter of 2016.  Consequently, the Company experienced a 10% decrease in net oil and gas production to 5,921 Boe/d during 3Q16, compared to 6,614 Boe/d during the three months ended September 30, 2015 (“3Q15”).  In the third quarter of 2016, 75% of the Company’s production was crude oil and NGLs.  The Company production from its focus, the Eagle Ford Shale play of south Texas, fell by 8% in 3Q16 versus 3Q15 results, to 5,485 Boe/d primarily due to the lack of new wells added during the quarter. The sale of the Company’s Morgan’s Bluff property also contributed to lower volumes.

•

Lonestar reported a net loss of $11.3 million for 3Q16 versus a net income of $6.6 million in 3Q15.  This loss in 3Q16 includes $5.2 million associated with non-cash, mark-to-market revaluation of Lonestar’s crude oil hedge portfolio and equity warrants and a $29.4 million gain on the disposal of bonds largely offset by a $29.1 million impairment on our Conventional assets.

•

Adjusted EBITDAX for the third quarter of 2016 was $14.6 million compared to $21.3 million for 3Q15, primarily due to a 10% decrease in production volumes coupled with a 26% decrease in revenues due to a sharp decline in West Texas Intermediate oil prices and Henry Hub gas prices compared to 3Q15. 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.

•

As of September 30, 2016, in a series of open-market transactions, Lonestar had purchased $68.2 million of its 8.750% Senior Unsecured Notes due April 15, 2019, leaving $151.8 million of these Notes outstanding.  

•

Lonestar funded the repurchases of its Senior Unsecured Notes through the incurrence of debt on its 12% Second Lien facility. As of September 30, 2016, the Company had drawn $38.0 million on this facility. The facility had remaining availability of $11.9 million as of that date.

•

As of September 30, 2016, Lonestar’s borrowings under its Senior Secured Credit Facility were $94.5 million.

•

Lonestar completed no new Eagle Ford Shale wells during the third quarter of 2016, and consequently reported a 10% decrease in total company production in the third quarter of 2016 and an 8% decrease in its Eagle Ford Shale production. Third quarter 2016 volumes of 5,921 Boe/d consisted of 3,175 barrels of oil per day, 1,238 barrels of NGLs per day, and 9,041 Mcf of natural gas per day.  The Company’s production mix for the third quarter of 2016 was 75% liquid hydrocarbons.  The Company produced 6,348 Boe/d through the first nine months of 2016, an increase of 6% over the comparable period in 2015.  

•

Lonestar’s lease operating expenses for the third quarter of 2016 were $4.0 million, representing a 6% decrease over 3Q15 lease operating expenses of $4.2 million. On a per unit basis, Lonestar’s lease operating expenses per BOE was reduced 5% from $6.97 per BOE in 3Q15 to $7.36 per BOE in 3Q16.  

•

The sale of the Company’s Conventional assets is expected to not only further sharpen the focus of its management and technical teams towards its core Eagle Ford Shale assets, but also to improve the Company’s operating cost structure.  To illustrate, in the third quarter of 2016, the Company’s total lease operating expenses were $7.36 per BOE.  Giving effect to the sale of the Conventional assets, lease operating expenses would have been $6.64 per BOE during the period.

•

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, and augments the Company’s borrowing base.  For 2016, the Company has West Texas Intermediate (“WTI”) swaps covering 2,528 barrels of oil per day for October 2016 through December 2016 at an average strike price of $70.41 per barrel.  As previously announced, the Company has three-way collars covering 1,000 bbls/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.   In October 2016, we entered into additional WTI crude oil swaps covering a total of 1,000 bbls/d for the period of January 2017 through December 2017 at an average strike price of $52.90 per barrel. The

addition of these swaps increased our total 2017 crude oil hedge position coverage to a total of approximately 2,500 barrels of oil per day at an average strike price of $53.43 per barrel. Also in October 2016, we entered into WTI crude oil swaps covering a total of 1,000 bbls/d for the period of January 2018 through December 2018 at an average strike price of $54.18 per barrel. Lastly we entered into Henry Hub natural gas swaps covering a total of 7,000 mcf/d for the period of January 2017 through December 2017 at an average strike price of $3.36 per million British Thermal Unit “MMBTU”.

•

Effective August 1, 2016, 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. On August 1, 2016, Lonestar assumed 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.  Since assuming operations of the property, Lonestar has made a number of operational improvements that have improved productivity of the two producing wells while substantially reducing operating costs.  As a result, Lonestar’s internal reserves estimates for proved and probable reserves have increased from 1.1 million barrels of oil equivalent (“MMBOE”) at closing to its current estimate of 1.6 MMBOE.

•

Asherton – In central Dimmit County, no new wells were completed during the three months ended September 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 continues to operate the Beall Ranch #20H - #22H, completed in the first quarter of 2016 and 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 225 days onstream are encouraging, as the average cumulative production from these wells of 64,000 barrels of oil is 11% 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 42% 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 58% improvement in cumulative oil production per lateral foot.  Lonestar is encouraged by the results of the GECA to date, and has been applying them across its portfolio during 2016.

•

Burns Ranch Area –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 engineered totaling 152,000 lateral feet. Following the lease swap, Lonestar has 18 gross/16.1 net laterals totaling 151,000 lateral feet. Lonestar recently completed drilling operations on the Burns Ranch Eagle Ford #8H, #9H and #10H wells with lateral lengths of approximately 9,620, 9,440 and 8,460 feet, respectively.  These wells were drilled to an average measured depth of 18,007 feet and were drilled from spud to total depth in an average of 13.3 days.  These results compare favorably with the wells that Lonestar drilled in 2015 on the Burns Ranch property, which were drilled to an average measured depth of 16,617 feet and were drilled from spud to total depth in an average of 24.3 days.  Lonestar’s recently drilled Burns Ranch Eagle Ford wells achieved a 97% improvement in rates of penetration, with the 2016 wells improving to 1,351 feet per day compared to the Burns Ranch Eagle Ford wells drilled in 2015, which averaged 683 feet per day. Lonestar plans to utilize BroadBand diverters on the #8H, #9H and #10H, which will allow Lonestar to set stage spacing at 300 foot increments, reducing the number of frac stages and associated costs while achieving a designed proppant concentration of up to 2,000 pounds per foot, which would be the highest in the Company’s history.  Based on availability of frac crews capable of conducting pressure pumping operations with BroadBand proppant diverter, Lonestar anticipates that it will commence fracture stimulation operations in mid-November 2016. Production from these three wells is expected to increase the leasehold that is held by production at Burns Ranch from 2,712 net acres to 3,279 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 September 30, 2016. Lonestar does not plan drilling activity on the Horned Frog property in the remainder of 2016, having held on the leasehold by production with our drilling activity during 2015.

•

Southern Gonzales County –Lonestar continues to operate its Cyclone #9H and #10H wells, which were placed onstream on May 12, 2016.  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 wells were fracture-stimulated with an average proppant concentration of 1,518 pounds per foot, utilizing BroadBand diverters, which allowed us to frac on 300-foot stage spacing.  The Cyclone #9H tested 543 bbl/d and 239 Mcf/d, or 598 Boe/d on an 18/64” choke and achieved a 30-day production rate of 486 Boe/d.  The Cyclone #10H tested 576 bbl/d and 239 Mcf/d, or 631 Boe/d on an 18/64” choke and achieved a 30-day production rate of 521 Boe/d.  After being placed on jet pump during the quarter, the wells are outperforming the Company’s prior internal expectations. The #9H has produced cumulative production of 56,900 bbls of oil in 180 days. Meanwhile, the #10H has produced cumulative production of 59,600 bbls of oil in 180 days.  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 are expected to increase Lonestar’s total leasehold in its Cyclone project to 2,906 gross / 2,656 net acres which is expected to accommodate 29

additional laterals with an average lateral length exceeding 7,000 feet. At December 31, 2015, Lonestar had no proved reserves booked to the Cyclone property.

•

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.  Based on its current drilling schedule, Lonestar currently plans to drill these wells in the first quarter of 2017.  

September 30,

2016

(unaudited)

December 31,

2015

Assets

Current assets

Cash and cash equivalents

$

5,990

$

4,322

Accounts receivable:

Oil, natural gas liquid and natural gas sales

4,879

5,043

Joint interest owners and other

884

1,305

Related parties

—

279

Derivative financial instruments

8,538

33,219

Prepaid expenses and other

1,749

724

Total current assets

22,040

44,892

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

432,169

488,100

Oil and gas properties held for sale

18,120

—

Other property and equipment, net

1,963

2,223

Derivative financial instruments

315

2,864

Other noncurrent assets

2,185

1,580

Restricted certificates of deposit

78

77

Total assets

$

476,870

$

539,736

September 30,

2016

(unaudited)

December 31,

2015

Liabilities and Stockholders’ Equity

Current liabilities

Accounts payable

$

9,410

$

18,027

Accounts payable – related parties

175

45

Oil, natural gas liquid and natural gas sales payable

3,475

3,870

Accrued liabilities

12,450

8,276

Accrued liabilities – related parties

356

125

Current income tax payable

5,581

—

Derivative financial instruments

420

—

Total current liabilities

31,867

30,343

Long-term debt

277,688

301,926

Deferred tax liability

—

16,013

Other non-current liabilities

1,000

1,000

Equity warrant liability

5,738

—

Asset retirement obligations

2,636

7,488

Asset retirement obligations - Held for sale

4,505

—

Derivative financial instruments

78

—

Total liabilities

323,512

356,770

Commitments and contingencies

Stockholders’ equity

Class A voting common stock, $0.001 par value, 15,000,000 shares authorized, 8,022,015 and 7,521,788 issued and outstanding at September 30, 2016 and December 31, 2015, respectively

142,638

142,638

Class B non-voting common stock, $0.001 par value, 5,000 shares authorized, 2,500 and 0 issued and outstanding at September 30, 2016 and December 31, 2015, respectively

—

—

Additional paid-in capital

15,303

10,270

Accumulated other comprehensive loss

—

(760

)

Retained (deficit) earnings

(4,583

)

30,818

Total stockholders’ equity

153,358

182,966

Total liabilities and stockholders’ equity

$

476,870

$

539,736

Three months ended

Nine months ended

September 30,

September 30,

2016

2015

2016

2015

Revenues

Oil sales

$

12,285

$

18,849

$

36,404

$

56,408

Natural gas sales

2,190

1,612

5,448

4,091

Natural gas liquid sales

1,063

416

2,685

1,538

Total revenues

15,538

20,877

44,537

62,037

Costs and expenses

Lease operating and gas gathering

4,006

4,616

12,764

12,666

Production, ad valorem, and severance taxes

907

1,376

3,046

4,203

Rig standby expense

364

10

2,261

10

Depletion, depreciation, and amortization

10,665

13,823

38,301

39,861

Accretion of asset retirement obligations

53

53

160

160

Loss (gain) on sale of oil and gas properties

53

—

(1,478

)

625

Impairment of oil and gas properties

29,144

—

31,082

—

Stock-based compensation

122

880

313

1,746

General and administrative

2,870

2,399

8,501

7,095

Other expense

1

18

1,045

53

Total costs and expenses

48,185

23,175

95,995

66,419

Loss from operations

(32,647

)

(2,298

)

(51,458

)

(4,382

)

Other income (expense)

Interest expense

(7,345

)

(6,666

)

(19,644

)

(18,485

)

Gain on disposal of bonds

29,363

—

29,363

—

Unrealized loss on warrants

(611

)

—

(611

)

—

Gain (loss) on derivative financial instruments

1,664

19,481

(3,405

)

18,956

Total other income, net

23,071

12,815

5,703

471

(Loss) income before income taxes

(9,576

)

10,517

(45,755

)

(3,911

)

Income tax (expense) benefit

(1,684

)

(3,931

)

10,354

1,419

Net (loss) income

$

(11,260

)

$

6,586

$

(35,401

)

$

(2,492

)

Net (loss) income per common share-basic and diluted

$

(1.44

)

$

0.88

$

(4.64

)

$

(0.33

)

Weighted average common shares outstanding–basic and diluted

7,842,586

7,522,025

7,629,896

7,522,025

Other comprehensive (loss) income:

Net (loss) income

$

(11,260

)

$

6,586

$

(35,401

)

$

(2,492

)

Foreign currency translation adjustments

(13

)

(30

)

(29

)

(29

)

Comprehensive (loss) income

$

(11,273

)

$

6,556

$

(35,430

)

$

(2,521

)

Nine months ended September 30,

2016

2015

Operating activities

Net loss

$

(35,401

)

$

(2,492

)

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

(Gain) loss on disposal of oil and gas properties

(866

)

629

Accretion of asset retirement obligations

160

160

Depreciation, depletion, and amortization

38,301

39,861

Stock-based compensation

313

1,746

Deferred taxes

(10,432

)

(1,418

)

Loss (gain) on derivative financial instruments

3,405

(18,956

)

Settlements of derivative financial instruments

24,322

26,497

Impairment of oil and gas properties

31,082

—

Non-cash interest expense

1,677

825

Changes in operating assets and liabilities:

Accounts receivable

865

8,526

Prepaid expenses and other assets

(1,961

)

(896

)

Accounts payable and accrued expenses

(4,479

)

(4,453

)

Net cash provided by operating activities

46,986

50,029

Investing activities

Acquisition of oil and gas properties

(3,115

)

(7,032

)

Development of oil and gas properties

(24,856

)

(77,735

)

Proceeds from sales of oil and gas properties

2,720

—

Purchases of other property and equipment

(202

)

(191

)

Net cash used in investing activities

(25,453

)

(84,958

)

Financing activities

Proceeds from borrowings

64,325

123,514

Payments on borrowings

(84,152

)

(93,514

)

Payments on other note payable

(9

)

(9

)

Net cash (used in) provided by financing activities

(19,836

)

29,991

Effect of exchange rate changes on cash and cash equivalents

(29

)

(29

)

Increase (decrease) in cash and cash equivalents

1,668

(4,967

)

Cash and cash equivalents, beginning of the period

4,322

9,992

Cash and cash equivalents, end of the period

$

5,990

$

5,025

Supplemental information

Cash paid for interest expense

$

14,095

$

11,020

Common stock issued for asset acquisition

$

5,500

$

—

Three Months Ended September 30,

Nine Months Ended September 30,

($ in thousands)

2016

2015

2016

2015

Net Income (Loss)

$

(11,260

)

$

6,586

$

(35,401

)

$

(2,492

)

Income tax expense (benefit)

1,684

3,931

(10,354

)

(1,419

)

Interest expense

7,345

6,666

19,644

18,485

Exploration expense

10

—

11

51

Depletion, depreciation, amortization and accretion

10,718

13,876

38,461

40,021

EBITDAX

8,497

31,059

12,361

54,646

Rig Standby Expense⁽¹⁾

364

10

2,261

10

Non-recurring costs⁽²⁾

607

25

1,252

44

Stock based compensation

122

880

313

1,746

(Gain) loss on sale of properties

53

—

(1,478

)

625

Impairment of oil and gas properties

29,144

—

31,082

—

Unrealized (gain) loss on derivative financial instruments

4,600

(10,668

)

26,205

8,009

Unrealized (gain) loss on warrants

611

—

611

—

Other income (expense) ⁽³⁾

(29,362

)

18

(28,315

)

53

Adjusted EBITDAX

$

14,636

$

21,325

$

44,292

$

65,134

For the three months

ended September 30,

For the nine months

ended September 30,

2016

2015

2016

2015

Daily production volumes by product -

Crude oil (MBbls)

3,175

4,631

3,522

4,284

NGLs (MBbls)

1,238

840

1,227

679

Natural gas (MMcf)

9,041

6,863

9,595

6,191

Total barrels of oil equivalent (Boe/d)

5,921

6,614

6,348

5,995

Daily production volumes by region (Boe/d) -

Eagle Ford Shale

5,485

5,969

5,810

5,309

Conventional

436

645

538

686

Total barrels of oil equivalent (Boe/d)

5,921

6,614

6,348

5,995

Average realized prices -

Crude oil ($ per Bbl)

$

42.05

$

44.25

$

37.73

$

48.23

NGLs ($ per Bbl)

9.33

6.36

7.99

8.74

Natural gas ($ per Mcf)

2.63

2.36

2.07

2.32

Total Oil Equivalent, excluding the effect from hedging

$

28.53

$

34.24

$

25.61

$

37.85

Total Oil Equivalent, including the effect from hedging

$

40.03

$

48.72

$

38.72

$

54.33

Operating Expenses per BOE:

Lease operating and gas gathering

$

7.36

$

6.97

$

7.34

$

7.74

Production, ad valorem, and severance taxes

1.67

2.26

1.75

2.57

General and administrative

5.27

3.94

4.89

4.34