8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 10, 2016

Lonestar Resources US Inc.

(Exact name of Registrant as Specified in Its Charter)

Delaware	001-37670	81-0874035
(Stateorotherjurisdictionof incorporationororganization)	(Commission File Number)	(I.R.S.Employer IdentificationNo.)

Registrant’s telephone number, including area code: (817) 921-1889

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instructions A.2. below):

☐ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

☐ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition.

On November 10,2016,LonestarResourcesUS,Inc.(the ”Company”)issuedapressreleaseannouncingits financialresults forthe three monthsended September30,2016.Acopyofthe pressreleaseisfurnishedasExhibit99.1tothis Current Report on Form 8-K.  The information contained in this Current Report on Form 8-K, including Exhibit 99.1, shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as expressly provided by specific reference in such a filing.

Item 7.01 Regulation FD Disclosure

Note Regarding Non-GAAP Financial Measures

The Company Presentation attached as an exhibit hereto contains certain references to Adjusted EBITDAX, which is a non-GAAP financial measure, as defined under Regulation G of the rules and regulations of the SEC.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

The following exhibits relating to Item 2.02 and Item 7.01 shall be deemed to be furnished, and not filed:

Exhibit Number	Description
99.1	PressReleasedated November 10,2016announcingfinancialresults of the Company forthethree months ended September 30, 2016.
99.2	Company Presentation

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	LONESTAR RESOURCES US, INC. (Registrant)
Date:  November 10, 2016	By:	/s/ Frank D. Bracken III
		Frank D. Bracken, III
		Chief Executive Officer

EXHIBIT INDEX

Exhibit No.	Description
99.1	PressReleasedated November10,2016announcingfinancialresults of the Company forthethree months ended September 30, 2016

99.2   Company Presentation

EX-99.1

EX-99.1

Lonestar Resources US, Inc. Announces Third Quarter 2016 Results

Fort Worth, Texas, November 10, 2016 (PRNewswire) - Lonestar Resources U.S., Inc. (NASDAQ: LONE) (including its subsidiaries, “Lonestar,” “we,” “us,” “our” or the “Company”) reported today its financial and operating results for the three months ended September 30, 2016 (“3Q16”).

THIRD QUARTER HIGHLIGHTS

• 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 pricesand 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.

CORPORATE UPDATE

Corporate

During the third quarter of 2016, Lonestar was primarily focused on improving its balance sheet, liquidity profile and cost structure.  The Company consummated a series of transactions during the quarter to achieve these goals:

• 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.

Subsequent to the end of the quarter, on October 31, 2016, Lonestar concluded a sale of certain of its non-core Conventional assets.  In total, the Company has received a total of $15.8 million in proceeds from the sale of these assets which carried substantially higher operating costs than its core Eagle Ford Shale assets.

Operational

• 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 $6.97per BOE in 3Q15 to $7.36per 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 $7.36per BOE.  Giving effect to the sale of the Conventional assets, lease operating expenses would have been $6.64per 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.

EAGLE FORD SHALE TREND- WESTERN REGION

• 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 225daysonstream 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 approximately9,620, 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.

EAGLE FORD SHALE TREND- CENTRAL REGION

• 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.

EAGLE FORD SHALE TREND- EASTERN REGION

• 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.

CONFERENCE CALL DETAILS

Lonestar will host a live conference call on Friday, November 11, 2016 at 8:00 AM CST to discuss the third quarter 2016 results and operational highlights.

To access the conference call, participants should dial:

USA: 877-221-2749

International: 212-271-4657

A playback of the conference call will be available on the Investor Relations section of Company’s website beginning approximately November 11, 2016.  The playback will be available for approximately 2 weeks.

ABOUT LONESTAR RESOURCES US, INC.

Lonestar is an independent oil and natural gas company, focused on the development, production and acquisition of unconventional oil, natural gas liquids (“NGLs”) and natural gas properties in the Eagle Ford Shale in Texas, where we accumulated approximately 38,242 gross (33,951 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of December 31, 2015. As of December 31, 2015, we also held a portfolio of conventional, long-lived, crude oil-weighted onshore assets in Texas and are conducting resource evaluation on approximately 44,084 gross (28,655 net) acres in the West Poplar area of the Bakken-Three Forks trend in Roosevelt County, Montana.For more information, please visit www.lonestarresources.com.

FORWARD-LOOKING STATEMENTS

This press release contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements contained in this press release that do not relate to matters of historical fact should be considered forward-looking statements, including, without limitation, beliefs and expectations with respect to: discovery and development of crude oil, NGLs and natural gas reserves; drilling and completion of wells and the size of Lonestar’s leasehold; cash flows and liquidity, including statements regarding the expected benefits of the Company’s crude oil hedging;  availability and terms of capital; timing, amount and rate of future production of crude oil, NGLs and natural gas; Lonestar’s business strategy, including its partnership with Schlumberger and the GECA; and the expected benefits from the GECA.

These forward-looking statements are based on management's current expectations. These statements are neither promises nor guarantees, but involve known and unknown risks, uncertainties and other important factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements, including, but 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; ability to successfully replace proved producing reserves; substantial capital expenditures required 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, which could increase costs and materially alter the occurrence or timing of their drilling; 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, which could materially adversely affect Lonestar’s crude oil, natural gas and NGLs reserves and future production; inaccuracies in assumptions made in estimating proved reserves; Lonestar’s limited control over activities in properties Lonestar does not operate; customer concentration risk; potential inconsistency between the present value of future net revenues from Lonestar’s proved reserves and the current market value of Lonestar’s estimated oil and natural gas reserves; risks related to derivative activities; covenant restrictions related to the revolving credit facility and the indenture that governs 8.75% Senior Notes due 2019; losses resulting from title deficiencies; risks related to health, safety and environmental laws and regulations; additional regulation of hydraulic fracturing, which has recently come under increased scrutiny; 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; recent federal legislation that may have adverse impact on ability to use derivative instruments to reduce the

effects of commodity prices, interest rates and other risks associated with the business;  and risks in connection with acquisitions and integration. These and other important factors discussed under the caption "Risk Factors" in the Company's Registration Statement on Form 10, as amended and filed with the Securities and Exchange Commission, or the SEC, on June 9, 2016, along with our other reports filed with the SEC could cause actual results to differ materially from those indicated by the forward-looking statements made in this press release. Any such forward-looking statements represent management's estimates as of the date of this press release. While we may elect to update such forward-looking statements at some point in the future, we disclaim any obligation to do so, even if subsequent events cause our views to change. These forward-looking statements should not be relied upon as representing our views as of any date subsequent to the date of this press release.

(Financial Statements to Follow)

Lonestar Resources US Inc.

Consolidated Balance Sheets

(In thousands, except share and per share data)

	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

Lonestar Resources US Inc.

Consolidated Balance Sheets (continued)

(In thousands, except share and per share data)

	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

Lonestar Resources US Inc.

Consolidated Statements of Operations & Comprehensive Loss

(In thousands, except share and per share data)

(Unaudited)

	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	)

Lonestar Resources US Inc.

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

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		$	—

NON-GAAP FINANCIAL MEASURES

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

¹ Represents a non-recurring cost associated with a rig contract that expired in July 2016

² Non-recurring costs consist of General and Administrative Expenses related to the re-domiciliation to the NASDAQ.

³ For 3Q16, this represents a gain on disposal of bonds due to repurchase at a discount

Lonestar Resources US Inc.

Operating Results

	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

EX-99.2

Lonestar Resources US, Inc. Third Quarter Conference Call November 11, 2016 Ex-99.2

Forward-Looking Statements Safe Harbor & Disclaimer Lonestar Resources US, Inc. cautions that this presentation (including oral commentary that accompanies this presentation) contains forward-looking statements, including, but not limited to, statements about our business strategy and operations; discovery and development of crude oil, natural gas liquid (“NGL”) and natural gas reserves; drilling and completion of wells; and cash flows, liquidity, and availability and terms of capital. 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 Registration Statement on Form 10, as amended and filed with the Securities and Exchange Commission, or the SEC, on June 9, 2016, 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 presentation represent our views as of the date of this presentation. 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 presentation. This presentation also contains estimates and other statistical data made by independent parties and by us relating to well performance, finding and development costs, recycle ratio and other data about our industry. This data involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such estimates. In addition, projections, assumptions and estimates of our future performance and the future performance of the markets in which we operate are necessarily subject to a high degree of uncertainty and risk. Lonestar Resources US, Inc. cautions that this presentation (including oral commentary that accompanies this presentation) contains forward-looking statements, including, but not limited to, statements about performance expectations related to our assets and technical improvements made thereto; drilling and completion of wells; and other statements regarding our business strategy and operations. 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 Registration Statement on Form 10, as amended and filed with the Securities and Exchange Commission, or the SEC, on June 9, 2016, as well as other documents that we have filed and 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 presentation represent our views as of the date of this presentation. 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 presentation. This presentation also contains estimates and other statistical data made by independent parties and by us relating to well performance, finding and development costs, recycle ratio and other data about our industry. This data involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such estimates. In addition, projections, assumptions and estimates of our future performance and the future performance of the markets in which we operate are necessarily subject to a high degree of uncertainty and risk.

3Q16 Headlines- Focus On The Balance Sheet 3Q16 Production by Product Production Averaged 5,921 Boe/d Eagle Ford Shale Production Down 8% vs. 3Q15 No New Completions During 3Q16 & Yields Volume Decrease 4Q15 Eagle Ford Wells- Horned Frog (La Salle County) – Placed on stream November, 2016 (2.0 gross/0.3 net wells) 1Q16 Eagle Ford Wells- Beall Ranch (Dimmit County) - Placed onstream March, 2016 (3.0 gross / 2.9 net wells) 2Q16 New Wells- Cyclone (Gonzales County) - Placed onstream May, 2016 (2.0 gross / 0.8 net wells). New Well Additions Expected to Resume 4Q16 Eagle Ford Wells- Burns Ranch (La Salle County) – Fracture stimulation scheduled November, 2016 (3.0 gross/2.8 net wells) Lonestar Has Reduced Long-Term Debt by ~$50 MM… *Reflects application of net proceeds from sale of Conventional Assets to outstanding Revolver balance. …And Improved Liquidity Closed Sale of Conventional Assets on October 31, 2016 Total Proceeds $15.8 MM; $13.3 MM to be applied to Revolver balance Product Volume Crude Oil 3,175 bbl/d NGL’s 1,238 bbl/d Natural Gas 9,041 Mcf/d Total 5,921 Boe/d Issue June 30 2016 Sept. 30 2016 Sept. 30, 2016 Proforma Sale of Conventional Assets* Revolver $99.5 $94.5 $81.2 Second Lien $0.0 $38.0 $38.0 Unsecured Notes $220.0 $151.2 $151.2 Total Debt $319.5 $283.7 $270.4

Quarterly Financial Summary Quarterly Production – Total Company Quarterly Production – Total Company Net Income Adjusted EBITDAX1 Note- All 2013, 2014 , 2015 and 2016 figures are unaudited 1 Please see “Non-GAAP Financial Reconciliation” in the Appendix for the definition of Adjusted EBITDAX, a reconciliation of Net Income (loss) to Adjusted EBITDAX, and the reasons for its use.

Quarterly Production Summary Quarterly Production – Total Eagle Ford Quarterly Production – Western Eagle Ford Quarterly Production – Eastern Eagle Ford Quarterly Production – Central Eagle Ford

Dimmit County Performance Update- Beall Ranch Beall Ranch Locator Map Beall Ranch Eagle Ford Well Costs Per Foot Beall Ranch Eagle Ford Offset – Cumulative to Date Beall Ranch Technical Improvements 26-28H 32-34H 20-22H Lonestar has drilled three 3-well pads in the last 24 months, implementing increasing levels of leading edge technologies, intended to improve recoveries and mitigate interference from offset well depletion. Geo-targeting- Using petrophysical & rock properties analysis obtained from pilot hole logs to refine its geo-target to a 22-foot target in an effort to improve recoveries Thru-bit Logging- Increasingly utilized to design non-geometric, engineered frac stages. BroadBand Diverter- Pumping diverter mid-stage to fracture higher-stress rock with a goal of improving perforation efficiency while actually expanding stage spacing. Superior Production Performance Continues- #26H-#28H wells have cum’d 64,000 bbls/well through 480 days online (or 21,350 bbls / perforated foot),which is 42% better than the offsetting #32H-#34H wells. Through 225 days, newest generation wells are outperforming #26H-#28H by 11% and #32H-#34H by 58%.

Gonzales County Performance Update - Cyclone Cyclone Area Summary Cyclone Leasehold – September 30, 2016 Cyclone #9H Production Performance Cyclone #10H Production Performance Drilled and completed the Cyclone #9H and #10H wells with an average perforated interval of 6,685 feet, placed onstream on May 12, 2016. 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. Cyclone #9H- tested 543 bbl/d and 239 Mcf/d, or 598 Boe/d1 on an 18/64” choke and a 30-day production rate of 486 BOEPD. #9H has cum’d 56,900 bbls of oil in 180 days. Cyclone #10H- tested 576 bbl/d and 239 Mcf/d, or 631 Boe/d1 on an 18/64” choke and a 30-day production rate of 521 BOEPD. #10H has cum’d 59,600 bbls of oil in 180 days. AFE’d for $5.2 million, Cyclone #9H a& #10H were drilled and completed for an average of $4.7 million, including a pilot hole. Lonestar’s leasehold in its Cyclone project now totals 2,906 gross / 2,656 net acres, setting up 29 additional laterals with an average lateral length exceeding 7,000 feet. At current NYMEX Strip prices, 7,800’ laterals would generate 47% IRR’s, based on our internal engineering forecasts. At December 31, 2015, Lonestar had no Proved reserves booked to the Cyclone property. 1 well results are on a processed, three-stream basis Leased Top Leased Cyclone #10H Cyclone #9H

LaSalle County Performance Update – Burns Ranch Burns Ranch Leasehold Acquisitions Burns Ranch Area Summary Burns Ranch Leasehold Totals Burns Ranch Drilling Performance After concluding its lease swap, Lonestar commenced drilling operations on three extended reach laterals on August 28, 2016 Burns Ranch #8H- drilled to a total depth of 18,420 feet with a designed perforated interval of 9,620’. Reached total depth (TD) in 12 days. Burns Ranch #9H- drilled to a total depth of 18,290 feet with a designed perforated interval of 9,440’. Reached total depth (TD) in 13 days. Burns Ranch #10H- drilled to a total depth of 17,310 feet with a designed perforated interval of 8,460’. Reached total depth (TD) in 15 days. Lonestar achieved 97% faster drilling rates with its 2016 wells vs. its 2015 wells. 2015 wells- reached avg. TD of 16,617’ in 24.3 days (683 ft/day) 2016 wells- reached avg. TD of 18,007’ in 13.3 days (1,351 ft/day) Lonestar expects to commence fracture stimulation operations on November 20, 2016 Implementing BroadBand diverters as part of Schlumberger Alliance which allows for 300-foot spacing to reduce frac stages and costs Frac designed for up to 2,000 lbs/foot of proppant (highest in company history) YE 2013 2013 & 2014 YE 2014 YE15 2014 & 2015 2016 Current Position Undrilled Locations EF Well 2015 Wells 2016 Wells LONE has increased its leasehold position from 800 net acres in 2013 to current levels of 4,013 net acres #1H #2H #3H #8H #9H #10H

Lonestar Resources, Ltd. Appendix

Geo-Engineered Completion Alliance Vertical Pilot Logs Used To Select Geo-target to Optimize Both Reservoir & Mechanical Properties Reservoir Properties- Porosity, Total Organic Content, Clay Volume Mechanical Properties- Young’s Modulus, Poisson’s Ratio, Minimum In-situ Stress Results of Analysis Determine Geosteering Target Azimuthal Gamma Ray LWD Tool to Assist in Geosteering Multi-planar Gamma ray data determines dip angle and direction in real time Lateral “Thru-Bit” Logs Run to TD for Detailed Rock Properties Analysis Triple Combo Log with Spectral Gamma Ray and Dipole Sonic Logs Mangrove Stimulation Design Utilize Thru-Bit Log Data For Reservoir Characterization Models Key Mechanical Properties To Optimize Stimulation Vertical and lateral rock heterogeneity Planar and Non-planar fractures Account for multi-well stress shadows to optimize zipper fracs Facilitates Design of Engineered (Non-Geometric) Completion BroadbandTM Sequence Diverter Engineered fibrous pill designed to create near-wellbore isolation to augment frac efficacy across all perforations, maximizing wellbore coverage Increase efficiency through fewer pumped stages, coiled tubing plug drill outs Engineered Flowback Analysis Lonestar has been a longstanding proponent of controlled flowbacks Implement SLB solids and fluids analysis to avoid negative impact of hydraulic fractures and assess success of completion strategies Integrated Approach to Drilling, Completion, Stimulation & Production of Eagle Ford Laterals Technical Process Application Experience Horned Frog Beall Ranch Horned Frog Beall Ranch Horned Frog Beall Ranch New to Lonestar New to Lonestar New to Lonestar

Lonestar Eagle Ford Shale Operating Expenses

Lonestar’s Inventory of Extended Reach Drilling Locations Engineered Locations by Lateral Length (perforated interval in feet)

Non-GAAP Reconciliation 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 (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss 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) and 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 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. (1) Represents a non-recurring cost associated with a rig contract that expired in July 2016. (2) Non-recurring costs consist of General and Administrative Expenses related to the re-domiciliation to the NASDAQ. (3) For 3Q16, this represents a gain on disposal of bonds due to repurchase at a discount.

Glossary •“bbl” means barrel of oil. • bbls/d means the number of one stock tank barrel, or 42 US gallons liquid volume of oil or other liquid hydrocarbons per day. “Boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil. •Boe/d means barrels of oil equivalent per day. “scf” means standard cubic feet. •“btu” means British thermal units. •“M” prefix means thousand. •“MM” prefix means million. •“B” prefix means billion. •“NGL” means Natural Gas Liquids– these products are stripped from the gas stream at 3rd party facilities remote to the field. •“TEV” means total enterprise value •“LTM” means last twelve months •“NTM” means next twelve months •“HBP” means held by production •“EPS” means earnings per share • “Mcf/d” means thousand cubic feet of natural gas per day • “IRR” means our internal rate of return, calculates the interest rate at which the net present value of all the cash flows (both positive and negative) from a project or investment equal zero • “EUR” means gross estimated ultimate recoveries for a single well Note: One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.