VIA EDGAR

February 16, 2016

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549

Attn: H. Roger Schwall

Assistant Director, Natural Resources

Re: Lonestar Resources US Inc.

SEC Comment Letter dated January 29, 2016

Draft Registration Statement on Form 10-12(b)

Filed December 31, 2015

File No. 001-37670

Dear Mr. Schwall:

Set forth below are the responses of Lonestar Resources US Inc. (the “Company,” “we,” “us” or “our”) to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated January 29, 2016, with respect to the Company’s registration statement on Form 10-12(b) filed with the Commission on December 31, 2015 (the “Registration Statement”).

Concurrently with the submission of this letter, we have filed through EDGAR Amendment No. 1 to the Registration Statement (the “Amendment No. 1” ). Five marked copies of Amendment No. 1 will be hand delivered to you to show all changes made to the Registration Statement.

For your convenience, each response below is prefaced by the exact text of the Staff’s corresponding comment in bold text. All references to page numbers and captions correspond to the Registration Statement, unless otherwise indicated.

Registration Statement on Form 10-12(b) Filed December 31, 2015

General

1. Please supplementally provide us with copies of all written communications, as defined in Rule 405 under the Securities Act, that you, or anyone authorized to do so on your behalf, present to potential investors in reliance on Section 5(d) of the Securities Act, whether or not they retain copies of the communications.

Response: We acknowledge the Staff’s comment and advise that in connection with the Reorganization described in the Registration Statement, we do not intend to undertake any written communications, as defined in Rule 405 of the Securities Act, in reliance on Section 5(d) of the Securities Act.

2. Tell us why you believe that you qualify as a smaller reporting company, as defined in Item 10(f)(1) of Regulation S-K, considering you were incorporated in December 2015, and the business you plan to acquire reports revenues in excess of $50 million for the most recently completed fiscal year.

Response: Item 10(f)(1) of Regulation S-K defines a “smaller reporting company” as an issuer that is not an investment company, an asset-backed issuer, or a majority-owned subsidiary of a parent that is not a smaller reporting company and that:

(i) Had a public float of less than $75 million as of the last business day of its most recently completed second fiscal quarter, computed by multiplying the aggregate worldwide number of shares of its voting and non-voting common equity held by non-affiliates by the price at which the common equity was last sold, or the average of the bid and asked prices of common equity, in the principal market for the common equity; or

(ii) In the case of an initial registration statement under the Securities Act or Exchange Act for shares of its common equity, had a public float of less than $75 million as of a date within 30 days of the date of the filing of the registration statement, computed by multiplying the aggregate worldwide number of such shares held by non-affiliates before the registration plus, in the case of a Securities Act registration statement, the number of such shares included in the registration statement by the estimated public offering price of the shares; or

(iii) In the case of an issuer whose public float as calculated under paragraph (i) or (ii) of this definition was zero, had annual revenues of less than $50 million during the most recently completed fiscal year for which audited financial statements are available.

For purposes of an initial Exchange Act registration, paragraph (ii) of Item 10(f)(1) provides that “public float” is computed by multiplying the aggregate worldwide number of such shares held by non-affiliates before the registration.

Item 10(f)(1) was adopted as part of significant changes made by the Commission to the disclosure and reporting requirements for small business issuers. In the Commission’s Adopting Release 33-8876 (Smaller Reporting Company Regulatory Relief and Simplification, the “Release”), the Commission described that one of the regulatory objectives behind the departure from the prior Regulation S-B test and system was to “expand the number of smaller companies eligible to use scaled disclosure requirements.” The Commission reasoned that “requiring only a public float test for most companies to qualify would provide additional simplicity, consistency and certainty.”

Item 10(f)(1) was a departure from the Regulation S-B test, which was dual eligibility test that required separate calculations for public float and annual revenues. Under the new rules, a company would be required to only look to its annual revenues if it had no common equity outstanding or no market price for its outstanding common equity existed at the time of its eligibility determination.

Consistent with the regulatory objectives behind Item 10(f)(1) of Regulation S-K and the guidance set forth in the Release, we believe that the Company qualifies as a “smaller reporting company” as we are able to calculate our public float based on the historical trading of the ordinary shares of Lonestar Resources Limited, an Australian corporation and current parent company of the Lonestar group of companies (“LNR”), which are traded on the Australian Securities Exchange (“ASX”). In addition, we will be able to calculate our public float after giving pro-forma effect to the issuance of our Class A common stock in connection with the Reorganization and the listing of those shares on The Nasdaq Stock Market LLC (“Nasdaq”).

As described in the Registration Statement, the Company was formed solely for the purpose of reorganizing the operations of LNR into a structure whereby the ultimate parent company of the Lonestar group of companies would be a Delaware corporation and a reporting domestic issuer. As a condition to the completion of the Reorganization, the Company’s Class A common stock must be approved for listing on Nasdaq. If the scheme of arrangement is not approved by shareholders or the Australian court, or the conditions to the completion of the scheme are not satisfied (including the Nasdaq listing condition), the Company intends to abandon the transaction and withdraw the Registration Statement prior to its effectiveness.

LNR’s ordinary shares have traded on the ASX since 1997, and will continue to trade on the ASX until immediately following the Reorganization. As the Reorganization will not result in a change to our historical operations or business, we expect that our Class A common stock will continue to trade on Nasdaq in substantially the same manner that LNR’s ordinary shares currently trade on the ASX. Immediately prior to the date of the filing of the Registration Statement, the public float of LNR was approximately $36.9 million. We expect that the Company’s public float will continue to be less than $75 million after giving pro-forma effect to the Reorganization, in which each outstanding ordinary share of LNR will be exchanged for shares of our Class A common stock on a one-for-two basis. Again, we believe that calculation of our public float on this basis is consistent with the regulatory objectives and the guidance provided for in the Release.

In addition to the foregoing, we respectfully note that a foreign private issuer is eligible to present its disclosure in Commission filings in compliance with alternative, scaled disclosure requirements if it qualifies as a smaller reporting company. If we had elected, in lieu of undertaking the Reorganization, to directly list LNR’s ordinary shares in the U.S. and file forms applicable to a domestic issuer, we believe we would have been eligible for scaled disclosure as a smaller reporting based on LNR’s public float as calculated above. Accordingly, we do not believe that an interpretation of Item 10(f)(1) that would cause the Company to be ineligible as a smaller reporting company simply because of the form of transaction in which it becomes a reporting domestic issuer would be consistent with the regulatory objectives described in the Release.

Business

Our Business Strategies, page 8

3. Please explain the differences between the well count figures here — 61 gross/56 net — and those on p. 17 — 57 gross/52 net — and amend, if necessary.

Response: Our disclosure has been revised to reflect the correct well count figures. Please see page 17 of Amendment No. 1.

Experienced management and a proven track record, page 9

4. Quantify the “proven track record” or revise the heading. We note the reference to managements’ “average 30 years of industry experience.”

Response: In light of the Staff’s comment we have revised the heading to remove reference to the “proven track record.” Please see page 9 of Amendment no. 1.

Development of Proved Undeveloped Reserves, page 14

5. Item 1203(b) of Regulation S-K requires that you “Disclose material changes in proved undeveloped reserves that occurred during the year, including proved undeveloped reserves converted into proved developed reserves.” It appears you have omitted the increases in PUD reserves due to drilling and completion activities and due to acquisitions. Please amend your document to disclose separately PUD reserve changes due to drilling/completion and due to acquisitions.

Response: We have revised our disclosure to disclose separately PUD reserve changes due to drilling/completion and due to acquisitions. Please see page 14 of Amendment No. 1.

6. Your realized 2014 unit PUD conversion cost appears to be about 25$/BOE (=$108.5 million/4.3 MMBOE) while the year-end 2014 standardized measure (page F-38) projects future unit development costs at about $17/BOE (=$320 million/18.6 MMBOE). Please explain the reasons that the projected unit development costs are significantly lower than those that you have incurred.

Response: We acknowledge the Staff’s comment and advise that we have revised our disclosure on page 14 of Amendment No. 1 to reflect $34.2 million in costs and 1.6 MMBOE associated with the drilling and completion costs of drilling locations designated as proved undeveloped at December 31, 2013 and subsequently categorized as proved developed producing properties at December 31, 2014. This equates to $21.71/BOE. During the course of 2014, WTI oil prices fell from $98.17 to $53.45. In accordance with this price decrease, we experienced significant declines in energy service costs, particularly during the second half of 2014. Forecasted capital spending on our PUD reserves reflects those well costs at year-end.

7. We note your statement, “Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe we can fund the drilling of our current inventory of proved undeveloped locations and our expansions and extensions in the next five years from our cash on hand combined with cash flow from operations and borrowings under our credit facilities.” Please explain to us the figures for those parameters (e.g. product prices, development and production costs) that are the basis for your “current expectations”. Address the minimum product prices that you require to continue these drilling/development programs.

Response: We acknowledge the Staff’s comment and have revised our disclosure. Please see page 14 of Amendment No. 1.

Internal Controls over Reserves Estimation Process, page 16

8. We note your statement, “Year-end reserve estimates are reviewed by our Senior Vice President-Operations, our Chief Executive Officer and other senior management, and revisions are communicated to our board of directors.” Please advise us whether these reviews include the drilling schedule for your proved undeveloped reserves. Tell us also whether your board of directors reviews/approves the PUD drilling schedule.

Response: We acknowledge the Staff’s comment and advise that our Senior Vice President-Operations, our Chief Executive Officer and other senior management review the drilling schedule for our proved undeveloped reserves. It has not been our practice for our Board of Directors to review the PUD drilling schedule, however, we anticipate that our Board of Directors will review our PUD drilling schedule following completion of the Reorganization, which we will disclose in our future Exchange Act filings.

Drilling Activities, page 17

9. We note that all of your wells drilled are categorized as development. For each period, please explain to us the number of locations drilled that also had booked PUD reserves at the time of drilling. For those wells/locations without PUD reserves, please explain why you have described them as development. Refer to Rule 4-10(a)(11) of Regulation S-X which defines a development well as “A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.”

Response: In 2013, we drilled a total of 12 Eagle Ford Shale wells, 10 of which were booked as proved undeveloped. The other two wells were drilled at our Gonzo property. The A3H and B1H wells were classified as development wells because they were offset by 24 producing Eagle Ford Shale wells, updip, downdip, and along strike, and were completed by six different operators. Three of these producing wells were within 3,000 feet of our Gonzo A3H and B1H wells.

In 2014, we drilled a total of 21 Eagle Ford Shale wells, 6 of which were booked as proved undeveloped. On several occasions, we acquired new leases during the calendar year, and drilled wells on those leases in the same year. Because the acreage was not owned by us as of the prior year-end, an engineering report was not available. During 2014, each of the 15 non-PUDs were drilled and completed as producers in locations where offset wells established oil and gas production in the immediate area within the Eagle Ford Shale. We drilled and completed the Pirate B1H well, which was offset by 14 Eagle Ford Shale producers updip, downdip and along strike. Two of these producers were within 2,000 feet of our Pirate B1H well. We drilled and completed the Asherton 9H and 10H wells, which was offset by more than 100 Eagle Ford Shale producers updip, downdip and along strike. Two of these producers were Lonestar-operated wells, located within 1,000 feet of our Asherton 9H and 10H wells. We drilled and completed the Gonzo E1H well, which was offset by 29 Eagle Ford Shale producers updip, downdip and along strike. Two of these producers were neighboring Lonestar-operated Gonzo A3H and B1H drilled in 2013. Lonestar drilled and completed the Pirate K1H well, which was offset by 30 Eagle Ford Shale producers updip, downdip and along strike. Two of these producers were within Lonestar-operated Eagle Ford Shale producers located within 2,000 feet of our Pirate K1H well. We drilled and completed the Meiners 1H, 2H and 3H, which were offset by 70 Eagle Ford Shale producers updip, downdip and along strike. Eight of these Eagle Ford Shale producers were within 3,000 feet of our Meiners wells. We drilled and completed the Ranger A4H and B1H wells, which was offset by 25 Eagle Ford Shale producers updip, downdip and along strike. Three of these Eagle Ford producers were located within 3,000 feet of our Ranger A4H and B1H producers. We drilled and completed the Dunn A1H and A2H wells, which was offset by 24 Eagle Ford Shale producers downdip and along strike, one of which was less than 2,000 feet away. All 15 of the wells we drilled without a PUD designation were completed as Eagle Ford Shale producers. Lastly, we drilled and completed the Harvey Johnson 1H, 2H and 3H. These wells were offset by 70 producing Eagle Ford Shale wells, updip, downdip and along strike. Four of these producers were on the adjacent lease less than 5,000 feet away.

As of September 30, 2015, we drilled a total of 16 Eagle Ford Shale wells, 12 of which were booked as proved undeveloped. The other two wells were drilled at our Horned Frog property, which we acquired via farm-in during 2015. The Horned Frog A1H and B1H wells were classified as development wells because they were offset by 107 producing Eagle Ford Shale wells, updip, downdip, and along strike, and were completed by six different operators. Five of these producing wells were within 5,000 feet of our Horned Frog A1H and B1H wells.

Developed and Undeveloped Acres, page 18

10. We note your statement “As of September 30, 2015, we had leases across the Eagle Ford Shale representing 3,011 net acres expiring in 2016, 4,519 net acres expiring in 2017 and 563 net acres expiring in 2018 and beyond. We anticipate that our current and future drilling plans together with selected lease extensions will address a significant portion of our leases expiring in the Eagle Ford Shale in 2016.” Please tell us the figures for year-end 2015 PUD reserves you have claimed that are scheduled for drilling after the expiration of the associated acreage.

Response: We acknowledge the Staff’s comment and advise that figures for year-end 2015 PUD reserves are not yet complete. We will provide that information and related reserve report via a subsequent amendment to the Registration Statement prior to requesting acceleration thereof.

Operations

Marketing and Major Customers, page 18

11. Reconcile your statement “we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time” with the risk factor on page 38 in which you indicate that you “depend upon several significant purchasers for the sale of most of our crude oil, natural gas and NGLs production.”

Response: We respectfully advise the Staff that our statement on page 18 of the Registration Statement is based on our past ability to attract new buyers of crude oil on the majority of our Eagle Ford Shale properties, and in many instances, we continue to change crude oil purchasers based on improved bids. We recognize the conflict of the statement on page 18 and have revised the risk factor. Please see page 38 of Amendment No. 1.

Financial Information, page 52

Outlook, page 55

12. We note your disclosure explaining that you have moderated drilling activity due to the decline in oil prices that began in 2014 and that you expect to continue such moderation as you believe oil and natural gas prices will remain volatile. You have similar and related disclosures on page 31, stating that you expect “a material reduction in the PV-10 valuation” of your reserves, and that if sustained as indicated, lower commodity prices “will have a material impact” on your revenues.

Please expand your disclosure to further clarify the nature and scope of your moderation efforts and to describe the reasonably likely impact on your proved reserves, development plans, and accounting. For example, describe any material changes that you have made to your proved reserve development schedules underlying your proved undeveloped reserves as of December 31, 2014, as well as the impact of any such changes on your ability to complete development of your proved undeveloped reserves within five years of booking. Additionally, given your disclosure on page 56, explaining that production during the recent interim period increased 48% as a result of an effective drilling program, clarify the extent to which this trend in production is expected to continue, in light of your moderation plan.

Response: We acknowledge the Staff’s comment and have revised our disclosure. Please see pages 55 and 56 of Amendment No. 1.

13. We understand that although you have used derivatives such as fixed-price swaps to insulate from price volatility and realize higher prices on production each period; you do not have significant coverage for settlements beyond 2016. Given your stated policy of hedging up to 85% of “forecasted proved developed producing production” on page 54, please disclose the percentages of actual production covered by derivatives for each period, and of forecasted production for the upcoming year, which you indicate is approximately 54% in the last paragraph on page 10.

Please also disclose the extent to which your hedging program has been successful in stabilizing cash flows for each period, relative to the prevailing market prices, and the reasonably likely implications of lower commodity prices on the continuation of this program, as may impact the availability and cost of entering into these arrangements. The extent to which your financial statements reflect derivative activity that you believe is indicative of your future operating results and financial condition should be clarified to comply with Instructions 2 and 3 to Item 303(a) of Regulation S-K.

If you have paid material amounts to acquire the derivatives utilized in your hedging efforts please clarify and indicate the manner by which outflows and inflows of any related cash are presented on pages F-6 and F-21.

Response: We have removed the wording regarding our current hedging policy, as that policy has been modified in the current commodity price environment. We have provided additional disclosures on pages 59 and 64 of Amendment No. 1 showing the percentage of actual production covered by derivatives for the nine months ended September 30, 2015 and 2014 and the years ended December 31, 2014 and 2013.

The effect of realized hedging gain or loss on our profit and loss for the years ended December 31, 2013 and 2014 was somewhat minimal with a loss of $1.8 million in 2013 versus a gain of $1.2 million in 2014. However, during the nine months ended September 30, 2015 realized hedging gains of $27 million have created a material positive effect on not only profit for the period but cash flow as well.

The hedging contracts that we have entered into have all been costless transactions in the form of swaps and collars, and there is no initial capital outlay associated with placing the hedge.

Sources of Liquidity and Capital Resources, page 65

14. We note that the operating and investing cash flows shown for the nine-month interim period ended September 30, 2015 do not agree with the corresponding figures presented in the Statement of Cash Flows on page F-6. Please revise accordingly.

Response: We acknowledge the Staff’s comment and have revised our disclosure. Please see page 65 of Amendment No. 1.

Debt, page 66

15. Tell us supplementally your current level of compliance with your debt covenants. It appears, for example, your current ratio has gone from 1.28 at December 31, 2014 to 1.09 at September 31, 2015.

Response: As of September 30, 2015, we are in compliance with our debt covenants and have added disclosure to acknowledge this. Please see page 66 of Amendment No. 1. As defined by our credit facility, the current ratio covenant is calculated as follows:

Consolidated current assets (including the unused amount of the borrowing base, but excluding non-cash assets) divided by consolidated current liabilities (excluding non-cash obligations and current maturities under the credit agreement). Such ratio cannot be less than 1.0 to 1.0. The ratios were 2.79 to 1.0 and 2.80 to 1.0 at December 31, 2014 and 2013, respectively.

While our December 31, 2015 audited financial statements are not available yet, we believe that we are in compliance with our debt covenants and will update the disclosure in the Registration Statement via a subsequent amendment prior to requesting acceleration.

Critical Accounting Estimates, page 68

16. We note you have identified various policies that you consider to be of particular importance to the portrayal of your financial position and results of operations and that require the application of significant judgment or estimates by management. However, it does not appear that you have addressed any specific assumptions or estimates or included information incremental to the corresponding accounting policies in the notes to your financial statements on pages F-23 and F-24.

The guidance in Item 303(a)(1) and (3)(ii) of Regulation S-K requires that you address the reasonably likely effects of trends and uncertainties that are relevant to an assessment of your financial condition and results of operations, while

Instructions 2 and 3 to paragraph 303(a) clarify the importance of this disclosure, particularly where reported financial information is not necessarily indicative of future operating results or future financial condition. The guidance in FRC §501.14 (Section V of SEC Release Nos. 33-8350; 34-48960; FR-72), indicates how disclosures of critical accounting estimates and assumptions may address these requirements.

Please expand your disclosure under this heading to address any material implications of the uncertainties associated with the methods, assumptions and estimates underlying your critical accounting measurements. This disclosure should provide greater insight into the quality and variability of information regarding your financial condition and operating performance. For example, you may discuss the extent to which your estimates and assumptions have been accurate or have changed in the past, and the extent to which these are reasonably likely to change in the future.

Response: We acknowledge the Staff’s comment and have revised our disclosure. Please see pages 69 and 70 of Amendment No. 1.

Quantitative and Qualitative Disclosures about Risk, page 71

17. We note that you have elected to provide an oil price sensitivity analysis related to your various derivative instruments for the 2014 fiscal year. Please expand your disclosure to describe the model, assumptions, and parameters underlying the range of figures you present, following Item 305(a)(ii)(B), and Instruction 1.B to paragraph 305(a) of Regulation S-K. For example, please clarify the number of periods within the year for which the analysis has been prepared, the population of instruments included and how you have handled derivatives settled prior to year-end.

Response: We acknowledge the Staff’s comment and advise that we have revised our disclosure on pages 71 and 72 of Amendment No. 1 to correctly reflect our sensitivity analysis. For purposes of our analysis, the major assumption used is the improvement or decline in oil price of $10 per Bbl. We applied this assumption to the production results of the year ended December 31, 2014 and also giving effect to the change in production/severance taxes based on the increase or decrease in oil revenues. Additionally, we considered the effect the $10 improvement or decline would have on our hedging revenues or expenses. The result of the analysis shows a positive change in profit of approximately $2.6 million with a $10 per Bbl improvement in oil price. The analysis also showed a decrease in profit of approximately $2.6 million with a $10 per Bbl decline in oil price.

Properties, page 73

Eagle Ford Shale Trend, page 73

18. It appears that you plan to drill 20 gross/19 net wells by year-end 2016: 8 gross/8 net wells in the Western Eagle Ford region (page 74) and 12 gross/11 net wells in the Eastern Eagle Ford region (page 76), beginning in the fourth quarter 2015 to the end of fiscal 2016. The table on page 76 presents total Eagle Ford locations to be drilled as 10 gross/10 net. Please amend your document to reconcile these figures. As of fiscal year-end 2015, explain to us the status of these wells.

Response: We acknowledge the Staff’s comment and have revised our disclosure. Please see pages 76 and 77 of Amendment No. 1. We also advise that as of December 31, 2015 we had begun drilling three wells in the Western Region and had permitted an additional three wells in the Western Region.

Security Ownership of Certain Beneficial Owners and Management, page 78

19. Please supplement your disclosure in footnote 2 to the table to also identify the natural person(s) that hold voting or dispositive power over the shares held by Ecofin Water & Power Opportunities PLC.

Response: We acknowledge the Staff’s comment and have revised our disclosure in footnote 2 of the table to identify the natural person that holds voting and dispositive power over the shares held by Ecofin Water & Power Opportunities PLC.

Directors and Executive Officers, page 80

20. Please revise each of your biographical disclosures for each of your named executives to include the principal occupation and employment for the periods that you discuss, providing the month, year and title. Refer to Item 401(e) of Regulation S-K.

Response: We acknowledge the Staff’s comment and have revised our disclosure. Please see pages 80 and 81 of Amendment No. 1., where we have expanded the biographical information for certain of our named executives consistent with the requirements of Item 401(e) of Regulation S-K.

Executive Compensation

Summary Compensation Table, page 88

21. We note that annual cash bonuses are discretionary and tied to achievement of certain performance objectives established by your board. In future Exchange Act periodic reports, please identify and quantify the performance criteria, both financial and non-financial, used to determine such awards.

Response: We acknowledge the Staff’s comment and confirm that in future Exchange Act periodic reports, that we will identify and quantify the performance criteria, both financial and non-financial, used to determine such awards.

Recent Sales of Unregistered Securities

Issuances by Lonestar Resources US Inc., page 92

22. We note your disclosure in this section that your common stock to be issued in connection with the reorganization will be issued pursuant to an exemption from the registration requirements provided by Section 3(a)(10) of the Securities Act. Please provide us with a more detailed factual and legal analysis setting forth why you believe you may properly rely on this exemption. Refer to Division of Corporation Finance Staff Legal Bulletin No. 3A (June 18, 2008).

Response: Section 3(a)(10) of the Securities Act provides an exemption from the registration requirements of the Securities Act for “any security which is issued in exchange for one or more bona fide outstanding securities, claims or property interests…where the terms and conditions of such issuance and exchange are approved, after a hearing upon the fairness of such terms and conditions at which all persons to whom it is proposed to issue securities in such exchange shall have the right to appear, by any court . . . expressly authorized by law to grant such approval.”

As set forth in SEC Staff Legal Bulletin No. 3A, the conditions for exemption from registration under Section 3(a)(10) of the Securities Act are as follows:

· securities must be issued in exchange for securities, claims or property interests (not cash);

· a court or authorised governmental entity must approve the fairness of the terms and conditions of the exchange;

· the reviewing court or authorised governmental entity must:

· find that the terms and conditions of the exchange are fair to those to whom securities will be issued; and

· be advised before the hearing that the issuer will rely on the Section 3(a)(10) exemption based on the court’s or authorised governmental entity’s approval of the transaction;

· the court or authorised governmental entity must hold a hearing before approving the fairness of the terms and conditions of the transaction;

· any governmental entity must be expressly authorised by law to hold the hearing;

· the fairness hearing must be open to everyone who is proposed to be issued securities in the exchange;

· adequate notice must be given to all those persons; and

· there cannot be any improper impediments to the appearance by those persons at the hearing.

In this instance:

· the Company has entered into a Scheme Implementation Agreement (which has been filed as Exhibit 2.1 to the Registration Statement) with LNR under which the Company will acquire all the shares and options in LNR by means of schemes of arrangement (the “Schemes”) under Australian law between LNR and its shareholders and option holders;

· under the Schemes, LNR shareholders will receive one share of common stock of the Company in exchange for every two ordinary shares of LNR that they hold and LNR option holders will similarly receive options in the Company in exchange for options in LNR on the same one-for-two basis;

· the Schemes are subject to approval by LNR shareholders and option holders as well as an Australian court; and

· LNR has issued an explanatory memorandum and notice of meeting (the “Scheme Booklet”) to LNR shareholders and option holders for their consideration in approving the Schemes.

The Scheme Booklet, which has been subject to review by the Australian Securities and Investments Commission, the ASX and the Australian Federal Court, has been sent to LNR shareholders and option holders and is publicly available on the websites of LNR and ASX.

As can be seen in the Scheme Booklet, meetings of LNR shareholders and option holders are scheduled for March 10, 2016 in Sydney, Australia. As required under Australian law, a second court hearing will be held before Justice Foster of the Federal Court of Australia on March 22, 2016. The Australian Court has been advised that the Company will rely on the Section 3(a)(10) exemption based on the court’s approval of the transaction.

In Staff Legal Bulletin No. 3A, the Staff notes that the term “court” in Section 3(a)(10) may include a foreign court. In particular, the Staff has indicated that an Australian court is a “court” for purposes of Section 3(a)(10). See Ashanti Goldfields Company Limited (Oct. 17, 1996); Cortecs International Limited (Oct. 8, 1997); ForBio Inc. (Sept. 23, 1998); Constellation Brands Inc. (Jan 29, 2003). We also note that ForBio Inc. involved the same fact pattern as the Company (i.e., the restructuring of an Australian company to the United States via a scheme of arrangement with a new Delaware holding company). We further note that, since the Staff first issued Staff Legal Bulletin No. 3 in 1997 partly in an effort to avoid unnecessary no-action letter requests, several other Australian companies have re-domiciled to the United States in the same manner in reliance on Section 3(a)(10) and Staff Legal Bulletin No. 3A.

Financial Statements and Exhibits, page 96

23. Please submit all exhibits as promptly as possible. Please note that we will not be in a position to declare your filing effective until we have had an opportunity to review such materials.

Response: We acknowledge the Staff’s comment and will file all exhibits with to the Registration Statement prior to requesting acceleration of the effectiveness of the Registration Statement.

24. We note that you have filed a “form of” employment agreement as an exhibit to the registration statement. Please confirm that you plan to file copies of each of your executed employment agreements as an exhibit in accordance with Item 601(b)(10) of Regulation S-K.

Response: We acknowledge the Staff’s comment and supplementally advise that each individual executive officer’s personal agreement was not renewed as contemplated at the time of the filing of the initial Registration Statement, and therefore each such agreement expired as of December 31, 2015. Accordingly, we have revised our disclosure (see page 87 of Amendment No. 1) and have removed reference to the form of employment agreement in the Exhibit Index.

Financial Statements

General

25. Given the $3.3 million loss before taxes for the nine-month interim period ended September 30, 2015, it appears you will need to update your filing to include audited financial statements for the 2015 fiscal year if the filing is not effective prior to February 17, 2016 as indicated in Rule 8-08(b) of Regulation S-X.

Response: We acknowledge the Staff’s comment and advise that we intend to update the Registration Statement to include financial statements for the 2015 fiscal year if the Registration Statement is not effective prior to February 17, 2016.

26. We understand from your disclosures on page 1 that in conjunction with your reorganization you plan to acquire Lonestar Resources Limited and all of its subsidiaries. Given the foregoing, tell us why you have only included financial statements of the Lonestar Resources America, Inc. subsidiary, and provide us descriptions and amounts of all accounts and activity that would be shown in the consolidated statements of its parent that are not reported by this entity.

Please also clarify the relevance of the pro forma earnings per share that you present in Note 14 on page F-36, which appears to be based on the capital structure of the subsidiary rather than the parent you identify as the party to the reorganization.

Response: For the years ended December 31, 2014 and 2013, LNR has acted solely as a holding company. Accounts and activity recorded on the books of LNR have generally consisted of consulting, accounting and tax fees, rent, compliance filing fees and other general and administrative expenses required to maintain our ASX listing and to otherwise comply with Australian law. We have set forth the amounts relating to these accounts and activities below, and have indicated those amounts that will be eliminated following the completion of the Schemes and liquidation of LNR.

Accounts/Activity	FY 2014		FY 2013
Board compensation	$	242,394	$	276,525
Contract labor*	185,202		171,474
Salaries & benefits*	—		125,772
D&O Insurance*	60,940		100,877
Legal*	133,040		12,517
Share registry costs*	366,495		97,741
Audit & tax fees*	110,955		185,920
Rent & office costs*	50,030		108,610
Travel & entertainment*	86,218		123,959
Other G&A*	8,568		17,138
Total	$	1,243,841	$	1,220,534
Total Eliminated Accounts/Activity	$	1,001,447	$	944,009

* Indicates an account/activity that will be eliminated following completion of the Schemes.

In addition, as LNR will be liquidated as soon as possible after completion of the Schemes, the future results reported by the Company are expected to consist solely of the operating results of Lonestar Resources America, Inc. Accordingly, the financial statements of LNR were not included because we believe that they are not material to the investors, and we further believe that including such financial statements would be confusing and misleading to investors in light of the liquidation of LNR.

The pro forma earnings per share that is being presented in Note 14 on page F-36 in the table labeled Unaudited Pro Forma Earnings Per Share (After Reorganization) is prepared with the capital structure of LNR, which will be the capital structure of the Company upon completion of the re-domiciliation process.

27. We understand from the Lonestar Resources Limited and Controlled Entities 2014 Annual Financial Report posted on its website that it paid $255,000 and $280,000 for the 2014 and 2013 financial statement audits to BDO Audit (WA) Pty Ltd and related entities, and it also paid these firms $321,000 and $163,000 for non-audit services. Please describe to us the non-audit services that were provided by such firms with details sufficient to understand how these would be considered relative to the various prohibited services outlined in Rule 2-01(c)(4) of Regulation S-X. Please include a schedule listing each non-audit service obtained and the related amounts comprising the totals.

Response: We acknowledge the Staff’s comment and have provided the table below to describe the non-audit services that were provided by such firms:

Non-Audit Services:	2014		2013
Taxation Services
Annual tax compliance & quarterly tax assistance	$	114,000	$	52,000
Other Services
Review and assurances services in connection with our 2014 Bond Offering	$	121,000	$	0
Consultations on the tax impact of the restructuring, liquidation and redomiciliation of our Parent	$	86,000	$	96,000
Accounting consultations regarding our reverse merger and other technical matters	$	0	$	15,000
TOTALS	$	321,000	$	163,000

Note 3 — Acquisitions and Divestitures, page F-25

28. We note that you acquired interests in proved and unproved oil and gas properties in March 2014, including working interests in producing properties, in exchange for $70.7 million. Please submit the analysis that you performed in determining that you would not include financial statements related to these properties for periods prior to acquisition to comply with Rule 8-04 of Regulation S-X.

Response: We acknowledge the Staff’s comment and advise that these properties were acquired in March 2014 with an effective date of January 1, 2014. We made our analysis based on the following information:

Financial Statement Area:	December 31, 2013
Total Assets	$	312,718,180
Transaction Value: $70,737,000	22		%
Total Revenue Less Direct Operating Expenses	$	62,350,212
Revenues Less Direct Operating Expenses From Acquired Properties: $18,057,597	29		%

Based on the above analysis and the requirement under Rule 8-04 of Regulation S-X if these percentages exceed 20% but none exceed 40%, financial statements shall be furnished for the most recent fiscal year and any interim periods specified. The company’s audited financial statements for the year ended December 31, 2014 included nine months of operations for the acquired assets, which also satisfies the financial statement filing requirement of Rule 3-06 of Regulation S-X.

29. We note your disclosure on page F-26 explaining that the value ascribed to oil and gas properties in your reverse merger accounting was based on “discounted future cash flows expected to be obtained from existing oil and gas reserves as determined by third party petroleum engineers.” Please describe to us the nature of the oil and gas properties acquired, including the proved vs. unproved, and developed vs. undeveloped status on the date of acquisition, and any key assumptions necessary to understand your basis for ascribing $96 million to the properties in your purchase price computation and $140 million in your standardized measure activity on page F-39. Please also submit a schedule showing your development plans for the PUD reserves acquired, including the quantities to be developed and related expenditures approved for each year, also covering subsequent progress and activity related to the properties acquired. Finally, please submit for review the report of the third party engineers which you reference as the basis for your fair value assessment.

Response: We acknowledge the Staff’s comment and advise that the oil and gas properties acquired in connection with our reverse merger consisted of conventional, vertical well oil and gas production throughout Texas, Louisiana and Oklahoma. At December 31, 2012 Amadeus Petroleum Inc. (“API”) had 14 PUD locations booked in its Year-End 2012 Reserve Report. There were 3 non-operated PUD’s in the Raccoon Bend Field scheduled in 2013 and 2014. There was 1 operated PUD in Central Texas scheduled in 2013. There was 1 operated PUD in East Texas scheduled in 2013. Lastly there were 9 PUD’s in West Texas scheduled in 2013 & 2014. This schedule was created by API’s management prior to the merger of Lonestar Resources and Amadeus Petroleum Inc.

Subsequently, as of December 31. 2014, the API assets had 10 PUD locations booked in its Year-End 2014 Reserve Report. The 3 non-operated PUD’s located at Raccoon Bend were excluded as the Raccoon Bend assets were sold in 2014. The remaining 10 locations were scheduled by Lonestar’s management. There was 1 operated PUD in Central Texas which was rescheduled for 2017 due the lower commodity price environment and Lonestar’s focus on the Eagle Ford Shale. There was 1 operated PUD in East Texas which was rescheduled for 2017 due the lower commodity price environment and Lonestar’s focus on the Eagle Ford Shale. Lastly there were 8 PUD’s in West Texas scheduled in 2016. Due to heavy rain and flooding in 2015, the West Texas locations are currently un-drillable and are expected to be rescheduled beyond 2016.

At YE12, there were 29 total PDNP’s. At YE14, there were 9 total PDNP’s. As compared to the YE12 Reserve Report, 11 were sold at Raccoon Bend, 4 were executed, 8 remain from the YE12 report, and 5 were deemed uneconomic after further evaluation.

Our independent third party reserve engineer, LaRoche Petroleum, performed a reserve report for the period ending December 31, 2012 for the acquired oil and gas assets of Amadeus Petroleum, Inc. This reserve report was prepared using the average price per year of futures contracts traded on the NYMEX for oil and gas prices. As the acquisition date has been determined to be January 2, 2013, LaRoche’s reserve report was used to fair value the oil and gas properties. We consider this report to be the most timely and reliable information available for the fair market value of the oil and gas properties acquired.

We are also submitting on a supplemental basis the report from our third party engineers for your review.

Regarding the $96 million value assigned to the oil and gas properties (see page F-26 of Amendment No. 1), as a part of the reverse merger with Amadeus Energy Limited, this amount is included in the line item titled “Standardized measure at beginning of period” and not in the $140 million line item titled “Purchase of minerals in place.” We included the amount in the beginning of period balance because we used the reserve report as of December 31, 2012. We considered the $96 million transaction as an end of 2012 year merger for this disclosure and not a purchase of minerals in place during 2013.

30. Your disclosures under this heading and on page 11 indicate that 460 million ordinary shares were issued to complete your reverse merger, representing 68.5% of the outstanding shares immediately following the transaction and that the quoted market price of the Amadeus Energy Limited stock was $0.22 per share on the transaction date. Please submit the computations that you performed in arriving at the $56.5 million valuation, and any explanations or details necessary to understand how your approach compares to the guidance in FASB ASC 805-40-30-2.

Response: We acknowledge the Staff’s comment and advise that this reverse acquisition involved only the exchange of equity. The accounting acquiree (Amadeus Energy Limited) issued 460 million equity shares to the accounting acquirer (LNR) in exchange for all of the accounting acquirer’s equity shares. The accounting acquiree’s shares are publicly traded on the ASX and are therefore reliably measured as quoted on a public exchange. As the accounting acquirer was a privately held company, fair value of its shares is not easily measured and less reliable.

We utilized the example given in ASC 805-40-55-8 to determine the acquisition-date fair value of the consideration transferred by the accounting acquirer for its interest in the accounting acquiree based on the number of equity interests the legal subsidiary would have had to issue to give the owners of the legal parent the same percentage equity interest in the combined entity that results from the reverse acquisition. Because this transaction involved only the exchange of equity, the number of shares the legal subsidiary would have had to issue to give the owners of the legal parent the same percentage ownership interest would be equivalent to the number of then outstanding shares of the legal parent. The calculation of this consideration is as follows:

Description		Amount
Existing outstanding shares		236,687,211
Share price (AUD)		x $.209
Total value of shares (AUD)		$49,467,627
AUD spot rate		x 1.03820
Total value of shares (US$)		$51,357,290
Cash assumed in merger		+ 5,265,337
Total consideration paid		$56,622,627

Note 5 — Commodity Price Risk Activities, page F-27

31. We note that amounts reported as Gains (losses) on derivative financial instruments on the income statement at page F-19 correspond to amounts utilized in your indirect reconciliation on the statements of cash flows at page F-21. Tell us whether you have taken a different approach in presenting this type of activity in your interim financial statements and your rationale. Please explain how you have accounted for periodic changes in value and settlements in each financial statement, with details sufficient to understand why the derivative related amounts on pages F-4 and F-6 do not agree.

Response: The amount shown in the September 30, 2015 interim statement of cash flows was a netted amount, as we considered this appropriate for the condensed financial statement format. The interim statements will be replaced by full year 2015 audited financial statements in a future amended Form 10, where such disclosure will conform with the 2014 audited financial statement presentation on pages F-19 and F-21.

Note 15 — Commodity Price Risk Activities, page F-36

32. Please revise your financial statements to separately present amounts arising from transactions with related parties to comply with FASB ASC 850-10-50-2.

Response: We acknowledge the Staff’s comments and have amended the balance sheets in the Registration Statement to provide these related party disclosures. See pages F-2, F-3, F-17 and F-18 of Amendment No. 1.

Supplemental Information on Oil and Natural Gas Exploration and Production Activities (unaudited), page F-36

33. It appears you have omitted the costs incurred for 2013 and 2014 as required by FASB 932-235-50-18. Please amend your document to comply with FASB 932.

Response: We acknowledge the Staff’s comments and have added a new table on page F-37 of Amendment No. 1.

Net Proved Reserve Summary, page F-37

34. Please amend your document to disclose figures for your total proved developed and for your total proved undeveloped reserves for the beginning and end of each year presented. Refer to FASB 932-235-50-4.

Response: We acknowledge the Staff’s comments and have revised our disclosure. Please see pages F-38 and F-39 of Amendment No. 1.

35. It appears you have included natural gas liquids with the crude oil proved reserves. FASB ASC 932-235-50-4(a) requires the disclosure of “Crude oil, including condensate and natural gas liquids (If significant, the reserve quantity information shall be disclosed separately for natural gas liquids.)” As the NGL proved reserves are about 10 percent of the total equivalent proved reserves and about 11 percent of the total liquid proved reserves, please amend your document to disclose separately the NGL proved reserves.

Response: We acknowledge the Staff’s comments and have revised our disclosure. Please see pages F-37 and F-38 of Amendment No. 1.

36. Your 2014 proved reserve acquisitions appear to be 10.7 MMBOE for $20.35 million (page F-8) or about $2/BOE. Please provide us with the petroleum engineering reports you used as the basis for the acquired proved reserves disclosed on page F-37. You may furnish these materials on digital media such as flash drive or compact disk.

The report should include:

a. One-line recaps in spread sheet format for each property sorted by field within each proved reserve category including the dates of first booking and estimated first production for your proved undeveloped properties;

b. Summary income forecast schedules for each proved reserve category with proved developed segregated into producing and non-producing properties;

c. Individual income forecasts for all the wells/locations in the proved developed and proved undeveloped categories;

d. Engineering exhibits (e.g. maps, rate/time plots, volumetric calculations, analogy well performance) for each of the five largest wells/locations in the proved developed and proved undeveloped categories (10 entities in all) as well as the AFE/capital cost inventory for each of the five PUD properties. Please ensure that the decline parameters (b-factor, initial/final production rates, initial/terminal decline rates), EURs and cumulative production figures are presented on the rate/time plots or another convenient location.

Response: We acknowledge the Staff’s comment and advise that our disclosure on page F-8 of Amendment No. 1 has been revised to be consistent with pages F-25 and F-26 which shows the approximate purchase price of $70.7 million as allocated $58.5 million to proved oil and gas properties and $12.2 million to unproved oil and gas properties. This calculates to approximately $5.47/BOE for the 10.7 MMBOE acquired. We are also providing, on a supplemental basis, the report requested by the Staff above.

As requested in your letter, we acknowledge that:

· the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

· Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

· the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

* * * * *

If you have any questions with respect to the foregoing responses or require further information, please contact the undersigned at (817) 921-1889 or William D. Davis II of Baker & McKenzie LLP at (713) 427-5000.

	Very truly yours,

	LONESTAR RESOURCES US INC.


	By:	/s/Frank D. Bracken, III
	Name:	Frank D. Bracken, III
	Title:	Chief Executive Officer

cc: Jerard Gibson (Securities and Exchange Commission)

Joseph Klinko (Securities and Exchange Commission)

Karl Hiller (Securities and Exchange Commission)

Doug Banister (Lonestar Resources US Inc.)

William D. Davis II (Baker & McKenzie LLP)

Andrew S. Reilly (Baker & McKenzie LLP)