.

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended June 30, 2016

OR

For the transition period from       to

Commission File Number: 001-37670

 

Lonestar Resources US Inc.

(Exact Name of Registrant as Specified in its Charter)

 

 

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☐    No  ☒

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  ☒

As of August 18, 2016, the registrant had 8,022,015 shares of Class A Voting Common Stock, par value $0.001 per share, outstanding.

 

 

 

 

 

---

 

Table of Contents

 

 

 

 

 

i

---

 

 

Presentation of Information

 

On July 5, 2016, Lonestar Resources US Inc., a Delaware corporation, acquired all of the issued and outstanding ordinary shares of Lonestar Resources Limited, the former parent company of the Lonestar group of companies, pursuant to a Scheme of Arrangement under Australian law that was approved by the Federal Court of Australia on June 28, 2016, and by Lonestar Resources Limited’s shareholders at a meeting of shareholders, which approval was obtained in March 2016 (the “Reorganization”).  The purpose of the Reorganization was to reorganize the operations of Lonestar Resources Limited, an Australian corporation, into a structure whereby the ultimate parent company of the Lonestar group of companies would be a Delaware corporation.  In connection with the Reorganization, the ordinary shares of Lonestar Resources Limited were delisted from the Australian Securities Exchange, and the Class A common stock of Lonestar Resources US Inc. began trading on the NASDAQ Global Market on July 5, 2016 under the ticker symbol “LONE”.

 

Lonestar Resources America, Inc. (“LRAI”), a subsidiary of Lonestar Resources Limited prior to the Reorganization, has been the U.S. operating company for the Lonestar group of companies since February 2013.  Following the Reorganization, LRAI will continue in the role of U.S. operating company for Lonestar Resources US Inc.

 

Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q to “Lonestar,” “we,” “us”, “our” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable.

 

General information about us can be found on our website at www.lonestarresources.com. The information available on or through our website, or about us on any other website, is neither incorporated into, nor part of, this report. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings that we make with the U.S. Securities and Exchange Commission (“SEC”), as well as any amendments and exhibits to those reports, will be available free of charge through our website as soon as reasonably practicable after we file or furnish them to the SEC. Information is also available on the SEC website at www.sec.gov for our U.S. filings.

 

ii

---

 

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

Lonestar Resources Limited

Consolidated Balance Sheets

(In thousands, except share and per share data)

 

 

See accompanying notes to unaudited consolidated financial statements.

1

---

 

Lonestar Resources Limited

Consolidated Balance Sheets (continued)

(In thousands, except share and per share data)

 

 

See accompanying notes to unaudited consolidated financial statements.

 

 

2

---

 

Lonestar Resources Limited

Consolidated Statements of Operations & Comprehensive Loss

(In thousands, except share and per share data)

(Unaudited)

 

 

See accompanying notes to unaudited consolidated financial statements.

3

---

 

Lonestar Resources Limited

Consolidated Statement of Changes in Stockholders’ Equity

(In thousands, except share data)

(Unaudited)

 

 

 

See accompanying notes to unaudited consolidated financial statements.

 

 

4

---

 

Lonestar Resources Limited

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

 

 

See accompanying notes to unaudited consolidated financial statements.

 

 

5

---

 

Lonestar Resources Limited

Notes to Consolidated Financial Statements

(Unaudited)

 

1. Nature of Business and Presentation

As of June 30, 2016, Lonestar Resources Limited (the “Predecessor”) was a company limited by shares incorporated in Australia, whose shares had publicly traded on the Australian Securities Exchange (“ASX”) and the OTCQX.

Lonestar Resources America, Inc. (“LRAI”) is a Delaware registered U.S. holding company formed January 31, 2013, which is engaged in the exploration, development, production, acquisition, and sale of oil, natural gas liquid (“NGL”) and natural gas primarily in the Eagle Ford Shale Play in South Texas, Conventional properties in North Texas and Bakken properties in Montana through its wholly owned subsidiaries, Lonestar Resources, Inc. and Amadeus Petroleum, Inc.. Its executive offices are located in Fort Worth, Texas. LRAI was a wholly owned subsidiary of the Predecessor, prior to the reorganization described below.  The majority of the activities of the Predecessor was carried out through LRAI.

On July 5, 2016, Lonestar Resources US Inc. (the “Successor”), a Delaware corporation, acquired all of the issued and outstanding ordinary shares of the Predecessor pursuant to a Scheme of Arrangement under Australian law (the “Reorganization”).  Pursuant to the Reorganization, the Successor issued to the shareholders of the Predecessor one share of Successor Class A common stock for every two ordinary shares of the Predecessor that were issued and outstanding.  Prior to the Reorganization, the Successor had no business or operations, and following the Reorganization, the business and the operations of the Successor consist solely of the business and operations of the subsidiaries of the Predecessor.

Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable.

Basis of Presentation

The accompanying interim consolidated financial statements have not been audited by independent public accountants, but in the opinion of management, reflect all adjustments necessary for a fair presentation of the financial position and results of operations.  Any and all adjustments are of a normal and recurring nature.  Although management believes the unaudited interim-related disclosures in these consolidated financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules of the Securities and Exchange Commission.  The results of operations and the cash flows for the six months ended June 30, 2016 are not necessarily indicative of the results to be expected for the full year.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company’s wholly owned subsidiaries:

Lonestar Resources America, Inc. (“LRAI”),

Lonestar Resources, Inc. (“LRI”),

Barnett Gas, LLC (“Barnett Gas”),

Eagleford Gas, LLC (“Eagleford Gas”),

Poplar Energy, LLC (“Poplar”),

Eagleford Gas 2, LLC (“Eagleford Gas 2”),

Eagleford Gas 3, LLC (“Eagleford Gas 3”),

Eagleford Gas 4, LLC (“Eagleford Gas 4”),

Eagleford Gas 5, LLC (“Eagleford Gas 5”),

Eagleford Gas 6, LLC (“Eagleford Gas 6”),

Eagleford Gas 7, LLC (“Eagleford Gas 7”),

Eagleford Gas 8, LLC (“Eagleford Gas 8”),

6

---

 

Lonestar Operating, LLC (“LNO”),

Amadeus Petroleum, Inc. (“API”),

T-N-T Engineering, Inc. (“TNT”) and

Albany Services, LLC (“Albany”).

All significant intercompany balances and transactions have been eliminated in consolidation.

 

 

2. Recently Issued Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2016-02, Leases (Topic 842) which will require organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by those leases. This ASU is effective for the annual period ending after December 15, 2018, and for annual interim periods thereafter. Early adoption is permitted. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“Update 2016-09”), which seeks to simplify several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, Update 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. The Company is currently evaluating the impact of the adoption of Update 2016-09 on its consolidated financial statements.

In November 2015, the FASB issued ASU No. 2015-17 to simplify income tax accounting. The update requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. This update is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, and may be adopted earlier on a voluntary basis. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, "Presentation of Financial Statements — Going Concern" (Subtopic 205-40). This ASU provides guidance on management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. Management does not expect the adoption of this guidance to have a material impact on our consolidated financial statements.

In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption.

In April 2015, the FASB issued updated guidance regarding simplification of the presentation of debt issuance costs. The updated guidance requires debt issuance costs related to a recognized debt liability, other than those costs related to line of credit arrangements, be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, similar to the presentation for debt discounts and premiums, instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. This guidance was effective for the Company on January 1, 2016. The Company’s adoption of this guidance was applied retrospectively and did not have a material impact on the Company’s consolidated financial statements.

 

 

3. Acquisitions and Divestitures

On June 15, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. sold its entire interest in producing wells and related oil and gas leases in its Morgan’s Bluff property located in Orange County, Texas.  Production related to the property was 86 BOE/Day

7

---

 

during the second quarter of 2016.  The sale price approximated $2,200,000 and resulted in a gain of approximately $1,900,000.  The transaction carried an effective date of July 1, 2016.

.During January to March 2016 the Company paid approximately $770,000 to acquire approximately 220 net acres in La Salle County, TX surrounding Company developed areas and new undeveloped areas classified by the Company as Burns Ranch.  During January to June 2016 the Company paid approximately $1,600,000 to acquire approximately 1,088 net acres in Gonzales County, TX for new well development in the Cyclone area.

In January 2015 the Company exchanged its working interest in two non-operated wells and the underlying leasehold acreage for increased working interests in currently owned and operated property. The exchange resulted in a loss of $629,000. Additionally, the Company acquired 159 net acres in the Eagle Ford Shale trend in La Salle County, TX for $500,000 as a further component of the exchange.

 

 

4. Restricted Certificates of Deposit

The Company is required to maintain certain certificates of deposit (“CDs”) by a municipality in which drilling operations are located. This CD is pledged as collateral for a letter of credit issued by the Company’s bank to the municipality. The CD has a maturity date of March 8, 2017, and bears an interest rate of 0.25%. As this CD is expected to be renewed upon maturity and is not available for use in operations, it is classified as a noncurrent asset.

 

 

5. Commodity Price Risk Activities

The Company has implemented a strategy to reduce the effects of volatility of oil and natural gas prices on the Company’s results of operations by securing fixed price contracts for a portion of its expected sales volumes.

Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor does its counterparties require collateral from the Company.  At June 30, 2016, the Company had no open physical delivery obligations.

The Company enters into certain commodity derivative instruments to mitigate commodity price risk associated with a portion of its future oil, NGL and natural gas production and related cash flows. The oil, NGL and natural gas revenues and cash flows are affected by changes in commodity product prices, which are volatile and cannot be accurately predicted. The objective for holding these commodity derivatives is to protect the operating revenues and cash flows related to a portion of the future oil, NGL and natural gas sales from the risk of significant declines in commodity prices, which helps ensure the Company’s ability to fund the capital budget. The Company has not designated any of the commodity derivatives as hedges under the applicable accounting standards.  Consequently, all changes in fair value of these derivatives (realized and unrealized) are included in the consolidated statement of operations.

As of June 30, 2016, the following derivative transactions were outstanding:

 

 

 

The above derivative contracts aggregate to 495,250 barrels or 2,692 barrels of oil per day for the remainder of 2016 and 547,600 barrels or 1,500 barrels of oil per day for 2017. All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in gain or loss on derivative financial instruments.

8

---

 

As of June 30, 2016 and December 31, 2015, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions.  The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties.  None of the Company’s derivative instruments contains credit-risk related contingent features.

 

 

6. Fair Value Measurements

In accordance with ASC 820, Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. ASC 820 prioritizes the inputs used in measuring fair value into the following fair value hierarchy:

Level 1 – Quoted prices for identical assets or liabilities in active markets.

Level 2 – Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs derived principally from or corroborated by observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability. The fair value input hierarchy level to which an asset or liability measurement falls in its entirety is determined based on the lowest level input that is significant to the measurement in its entirety.

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of June 30, 2016 and December 31, 2015, for each fair value hierarchy level:

 

 

The book values of cash and cash equivalents, receivables for oil, NGL and natural gas sales, joint interest billings, notes and other receivables, accounts payable, and accrued liabilities approximate fair value due to the short-term nature of these instruments. The carrying value of debt approximates fair value since it is subject to a short-term floating interest rate that approximates the rate available to the Company , except for bonds, which are recorded at amortized cost less debt issuance costs.

  The fair value of our 8.750% Senior Unsecured Notes approximates $107,000,000, and are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs.

 

 

9

---

 

7. Oil and Gas Properties

A summary of oil and gas properties follows:

 

 

In the second quarter of 2016, the Company recorded impairment of oil and gas properties of $1,938,000, which is included in accumulated depreciation, depletion, and amortization.

 

During 2016, certain leased acreage was set to expire in Montana as part of the Bakken, Three Forks, and Lower Lodgepole formations (the “Poplar Properties”).  Based on our decision to defer drilling on the Poplar Properties during the three months ended June 30, 2016, we recorded a $1,938,000 impairment charge related to leased acreage expiring during 2016.  This was calculated through the allocation of our current carrying value of the properties across our proportionate share of the acreage.  

 

If pricing continues to decline, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to June 30, 2016.

 

 

8. Accrued Liabilities

The accrued liabilities consist of the following:

 

 

 

9. Long-Term Debt

The Company’s debt consists of the following:

 

 

Senior Revolving Credit Facility

On July 28, 2015, LRAI closed a new $500,000,000 Senior Secured Credit Facility which replaced a $400,000,000 Wells Fargo-led syndicated facility.  The new facility was arranged by Citibank, N.A. and features an expanded borrowing base of $180,000,000 as of December 31, 2015.  The new facility provides additional liquidity for the Company and a lower interest rate.  The new rate is a 25 basis point improvement over the LIBOR interest rate spread.  The new facility provides for an extension in the maturity date to

10

---

 

October 16, 2018, which represents a seven month extension over the Wells Fargo-led facility.  The financial covenants contained in this new facility are substantially the same as the previous facility.  As of June 30, 2016 (giving effect to the amended covenant ratio discussed below) and December 31, 2015, LRAI was in compliance with all covenants including all financial ratios under the Citibank-led facility.  As of June 30, 2016 and December 31, 2015, $99,500,000 and $87,000,000 was borrowed, respectively, under the Citibank-led revolving credit facility.

The revolving credit facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit.  The revolving credit facility provides for a commitment fee of 0.375% to 0.5% based on the unused portion of the borrowing base under the revolving credit facility.

Borrowings under the revolving credit facility, at LRAI’s election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period on such day plus 1.0%; or (ii) the adjusted LIBO rate, which is the rate stated on Reuters screen LIBOR01 page, for one, two, three, six or twelve months, as adjusted for statutory reserve requirements for Eurocurrency liabilities, plus, in each of the cases described in clauses (i) and (ii) above, an applicable margin ranging from 0.75% to 1.75% for ABR loans and from 1.75% to 2.75% for adjusted LIBO rate loans.

The revolving credit facility requires LRAI to maintain certain financial ratios and limits the amount of indebtedness LRAI can incur.  Subject to certain permitted liens, LRAI’s obligations under the revolving credit facility have been secured by the grant of a first priority lien on no less than 80% of the value of the proved oil and gas properties of the Company and its subsidiaries.

In connection with the revolving credit facility, LRAI and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangement, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the revolving credit facility are unconditionally guaranteed by such subsidiaries.

Effective as of July 27, 2016, LRAI, the several banks and other financial institutions party thereto (collectively, the “Consenting Lenders”) and Citibank, N.A., in its capacity as administrative agent for the lenders (the “Administrative Agent”) entered into the Third Amendment to Credit Agreement and Limited Waiver (the “Amendment”) to that certain Credit Agreement dated as of July 28, 2015, by and among LRAI, the Consenting Lenders (together with the other banks and financial institutions party thereto, the “Lenders”) and the Administrative Agent (as amended, supplemented and modified, the “Credit Agreement”) to (a) permit LRAI to incur the second lien obligations contemplated by the Securities Purchase Agreement with Leucadia National Corporation and others (as described below) and LRAI’s contemplated use of proceeds thereof, (b) increase the applicable margin for Eurodollar and ABR loans and letter of credit fees by 0.75% across all levels of the previously applicable pricing grid, (c) modify the fee payable on the actual daily unused amount of the aggregate commitments to a flat 0.50% across all levels of the pricing grid, (d) increase the minimum percentage of the value of LRAI’s oil and gas properties that must be mortgaged as collateral for the obligations under the Credit Agreement and the other loan documents from 80% to 90%, (e) modify the maximum leverage ratio thresholds from 4.0 to 1.0 to (i) 4.75 to 1.0 for the four quarter period ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarter period ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarter period ending December 31, 2016 and (iv) 4.00 to 1.0 for all periods thereafter, (f) prohibit distributions to the Predecessor or the Successor, as applicable, for general and administrative expenses after September 30, 2016 and (g) amend certain other provisions of the Credit Agreement as more specifically set forth in the Amendment.

8.750% Senior Notes

On April 4, 2014, LRAI issued at par $220,000,000 of 8.750% Senior Unsecured Notes due April 15, 2019 (“Notes”) to U.S. based institutional investors. The net proceeds from the offering of approximately $212,000,000 (after deducting purchasers’ discounts and offering expenses) were used to repay LRAI’s revolving credit facility and 2nd lien facility, and for general corporate purposes. Under the 2nd lien term loan agreement, LRAI was required to pay a prepayment fee of $1,100,000 in connection with the early prepayment of the facility equal to 2.0% of the principal balance that was prepaid. This facility was terminated upon repayment.

On or after April 15, 2016, LRAI may redeem the Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, on the Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

 

 

11

---

 

In addition, upon a change of control of LRAI, holders of the Notes will have the right to require LRAI to repurchase all or any part of their Notes for cash at a price equal to 101% of the aggregate principal amount of the Notes repurchased, plus any accrued and unpaid interest. The Notes were issued under and governed by an Indenture dated April 4, 2014, between LRAI, Wells Fargo Bank, National Association, as trustee and LRAI’s subsidiaries named therein as guarantors (the “Indenture”). The Indenture contains covenants that, among other things, limit the ability of LRAI and its subsidiaries to: incur indebtedness; pay dividends or make other distributions on stock; purchase or redeem stock or subordinated indebtedness; make investments; create liens; enter into transactions with affiliates; sell assets; refinance certain indebtedness; and merge with or into other companies or transfer substantially all of LRAI’s assets.

Debt Issuance Costs

The Company capitalizes certain direct costs associated with the issuance of long-term debt and amortizes such costs over the lives of the respective debt. At June 30, 2016 and December 2015, the Company had approximately $900,000 and $1,100,000, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt which are recorded as other non-current assets in the consolidated balance sheets.

 

 

10. Stock Options

Determining Fair Value of Stock Options

In determining the fair value of stock option grants, the Company utilized the following assumptions:

Valuation and Amortization Method. The Company estimates the fair value of stock option awards on the date of grant using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method.”

Expected Life. The expected life of stock options granted represents the period of time that stock options are expected, on average, to be outstanding.  The Company determined the expected life to be 3.5 years, for all stock options issued with three-year vesting periods and four-year grant expirations.

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of Predecessor’s common shares at the beginning of the quarter in which the stock option is granted. The volatility of 58.6% is based on weighted average historical movements of Predecessor’s common share price on the ASX over a period that approximates the expected life.

Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.

Expected Dividend Yield. The Predecessor has not paid any cash dividends on its common shares, and the Successor does not anticipate paying any cash dividends in the foreseeable future.  Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.

Expected Forfeitures. The Company has experienced limited forfeitures and therefore has not discounted expenses for forfeitures at the reporting date.

Stock Option Activity

For the six months ended June 30, 2016, no stock options were exercised.  The following tables summarize certain information related to outstanding stock options under the Lonestar Resources Limited 2012 Employee Share Option Plan:

 

12

---

 

 

 

Stock-Based Compensation Expense

For the three and six month periods ended June 30, 2016, the Company recorded stock-based compensation expense for stock options granted using the fair-value method of $95,326 and $190,652, respectively.

 

 

11. Earnings Per Share

In accordance with the provisions of current authoritative guidance, basic earnings or loss per share shown on the Consolidated Statements of Operations is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities.  The Company includes the number of stock options in the calculation of diluted weighted average shares outstanding when the grant date or exercise prices are less than the average market prices of the Company’s common stock for the period. When a loss from operations exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding.  There is no dilutive effect for the three and six months ended June 30, 2016 as the Company reported a loss from operations for those periods.  The Company had net income from operations at the three months ended June 30, 2015, however, as the options were considered to be out of the money, the potentially dilutive common shares outstanding are treated as anti-dilutive and therefore, excluded from the calculation of diluted weighted average shares outstanding.

In connection with the Reorganization, discussed in Note 1, Lonestar Resources US Inc., immediately prior to the Reorganization, will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting policies have been adopted in these financial statements as if the Company were a public company. The following table presents unaudited pro forma earnings per share of Lonestar Resources US Inc., assuming that the 1 for 2 reverse stock split upon Reorganization had occurred at the beginning of the three and six month periods ended June 30, 2016 and 2015:

Unaudited Pro Forma Earnings Per Share (After Reorganization)

 

 

 

 

13

---

 

12. Related Party Activities

In April 2014, the Company loaned $539,000 in total to Frank D. Bracken, III and Thomas H. Olle to assist with their tax obligations as a result of stock compensation awarded to them in 2013.  The loans were on arms-length commercial terms and were settled in full in January 2016.

Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of the Company) owns an interest, has performed consultancy work for the Company since 2013 covering various strategic, tax structuring and investor matters at a cost of approximately $25,000 per quarter.

New Tech Global Ventures, LLC, a company in which Daniel R. Lockwood (a director of the Company) owns a limited partnership interest, has provided field engineering staff and consultancy services for the Company since 2013. The total cost for such services was approximately $149,000 and $276,000 for the three months ended June 30, 2016 and 2015, respectively and approximately $387,000 and $614,000 in the six months ended June 30, 2016 and 2015, respectively.

Mitchell Wells, who has been a director of the Company since December 2014, has provided consultancy services as its Company Secretary since January 2013. These services have been provided through BlueSkye Pty Ltd, for which Mr. Wells is the sole Director and shareholder. BlueSkye Pty Ltd was paid approximately $36,000 and $36,000 for the three months ended June 30, 2016 and 2015, respectively and approximately $71,000 and $71,000 for the six months ended June 30, 2016 and 2015, respectively. He has not received any additional compensation for his service as a Director.

 

 

13. Subsequent Events

In preparing the consolidated financial statements, management has evaluated all subsequent events and transactions for potential recognition or disclosure through the date the accompanying consolidated financial statements were issued.

Securities Purchase Agreement

On August 2, 2016, LRAI and Successor entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Successor’s common stock at a price equal to $5.00 per share (the “Warrants” and, together with the Notes, the “Securities”). The initial sale of $10,000,000 aggregate principal amount of Securities closed on August 4, 2016 (the “Closing Date”).

The Notes are secured by second-priority liens on substantially all of LRAI’s and its subsidiaries’ assets to the extent such assets secure obligations under the Credit Agreement. Pursuant to the terms of an intercreditor agreement, the security interest in those assets that secure the Notes and the related guarantees are contractually subordinated to liens that secure borrowings under the Credit Agreement and certain other permitted indebtedness. Consequently, the Notes and the guarantees will be effectively subordinated to the borrowings under the Credit Agreement and such other indebtedness to the extent of the value of such assets.

As of August 15, 2016, LRAI has issued $25,000,000 Second Lien Notes with the Successor issuing Warrants to purchase 500,000 of the Successor’s common stock.  Proceeds from the Second Lien Notes issuance were used to repurchase $48,414,000 in aggregate principal amount of its 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes and related fees and expenses related to the foregoing.

Registration Rights Agreement

In connection with entering into the Purchase Agreement, the Successor entered into a Registration Rights Agreement, dated as of August 2, 2016 (the “Registration Rights Agreement”), by and among the Successor, Leucadia and the Initial Purchaser (together with Leucadia and their permitted transferees, the “Holders”). Pursuant to the Registration Rights Agreement, the Successor has agreed to register for resale certain restricted shares of the Successor (the “Registrable Securities”) issued or issuable to the Holders, including those issuable upon exercise of the Warrants or pursuant to Leucadia’s commitment (the “Equity Commitment”) to purchase shares of the Successor’s Class A Voting Common Stock (the “Common Stock”). The Successor has agreed to file a registration statement providing for resale of the Registrable Securities as permitted by Rule 415 of the Securities Act of 1933, as amended (the “Securities Act”) no later than the earlier of (i) the one year anniversary of the consummation of the Offering (as defined below) and (ii) 30 days after the date the Successor first becomes eligible to file a registration statement on Form S-3. The Successor has also agreed, subject to certain limitations, to allow the Holders to sell Registrable Securities in connection with certain registered offerings that the

14

---

 

Successor may conduct in the future and to provide holders of a specified number of Registrable Securities the right to demand that the Successor conduct an underwritten public offering of Registrable Securities under certain circumstances. The Registration Rights Agreement contains representations, warranties, covenants and indemnities that are customary for private placements by public companies.

In the event that the Successor elects to pursue an equity offering prior to December 31, 2016, Leucadia agreed pursuant to the Equity Commitment to purchase the number of shares of Common Stock equal to (such amount, the “Commitment Amount”) (a) $20,000,000 (or such lesser amount as the Successor requests) divided by (b) the offering price to investors in a registered public offering of securities (the “Offering”) that is completed on or before December 31, 2016 (the “Outside Date”). Leucadia’s agreement to purchase the Common Stock is conditioned on, amongst other things, the Successor (i) selecting a lead underwriter approved by Leucadia, (ii) having, together with its subsidiaries, no more than $295,000,000 of long-term debt outstanding (net of cash and cash equivalents), and (iii) the equity order book in the Offering is no less than $40,000,000, excluding the Commitment Amount.

In connection with the Equity Commitment, the Successor will pay Leucadia a fee equal to $1,000,000, payable whether an Offering is launched or consummated, upon the earlier of (i) the closing of the Offering, (ii) the termination of the Offering and (iii) the Outside Date.

In the event Leucadia purchases not less than the Commitment Amount in an Offering, the Successor has agreed to use commercially reasonable efforts to enter into arrangements that provide Leucadia will have the right to appoint one director to the board of directors of the Successor, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Common Stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in the Offering.

Purchase and Sale Agreement

On August 2, 2016 Eagleford Gas 5, LLC and the Sucessor (“Buyer”) entered into a purchase and sale agreement with Juneau Energy, LLC (“Seller”) whereby the Buyer obtained an undivided 50% of Seller’s interest in two producing wells and each well’s respective  oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas.  The total purchase paid by Buyer was $5,500,000 payable in 500,227 shares of the Successor’s Class A Voting Common Stock.  

 

 

 

 

15

---

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

We are 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.

We operate in one industry segment, which is the exploration, development and production of oil, NGLs and natural gas. Our current operational activities and consolidated revenues are generated from markets exclusively in the United States, and, as of June 30, 2016, we had no long lived assets located outside the United States.

Reorganization

On July 5, 2016, Lonestar Resources US Inc. (the “Successor”) acquired all of the issued and outstanding ordinary shares of Lonestar Resources Limited (the “Predecessor”) pursuant to a Scheme of Arrangement under Australian law (the “Reorganization”). Pursuant to the Reorganization, the Successor issued to the shareholders of the Predecessor one share of the Successor’s Class A common stock for every two ordinary shares of the Predecessor that were issued and outstanding. Prior to the Reorganization, the Successor had no business or operations, and following the Reorganization, the business and operations of the Successor consist solely of the business and operations of the subsidiaries of the Predecessor. On July 5. 2016, the Class A common stock of the Successor began trading on the NASDAQ Global Market under the ticker symbol “LONE.”  

The historical results of operations discussed in this “Management's Discussion and Analysis of Financial Condition and Results of Operations” includes the results of the Predecessor and its consolidated subsidiaries prior to the Reorganization.  Unless the context otherwise requires, references in this Quarterly Report on Form 10-Q to “Lonestar,” “we,” “us,” “our” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable.

Second Quarter 2016 Operational Summary

 

Lonestar reported a 13% increase in total company production in the second quarter of 2016 and a 17% increase in its Eagle Ford Shale production. Second quarter 2016 volumes  of 6,573 Boe/d were comprised of 3,979 barrels of oil per day,  1,039 barrels of NGL’s per day, and 9,332 Mcf of natural gas per day.  The Company produced 6,564 Boe/d through the first six months of 2016, an increase of 16% over the comparable period in 2015.   The Company’s production rates rose modestly sequentially, as new Eagle Ford Shale wells were placed onstream at a slower rate than in past quarters. During the second quarter of 2016, Lonestar placed 2 new Eagle Ford Shale wells onstream during May, 2016.  Lonestar holds a 42% working interest and a 33% net revenue interest in these wells, meaning that Lonestar added 2.0 gross / 0.8 net wells in the second quarter of 2016, as compared to 3.0 gross / 2.9 net wells in the first quarter of 2016 and 4.0 gross / 2.3 net wells in the fourth quarter of 2015.  However, crude oil production rose 17% sequentially from 3,414 Bo/d for the three months ended March 31, 2016 as Lonestar’s 2016 completions have all been in the crude oil window.

 

Recent Developments Regarding Lonestar Properties

 

Eagle Ford Shale Trend - Western Region

 

Asherton

 

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

 

Beall Ranch

16

---

 

 

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

 

Burns Ranch Area

 

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

 

Horned Frog

 

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

 

Eagle Ford Shale Trend - Central Region

 

Southern Gonzales County

 

Encouraged by the results of the initial six wells on our Harvey Johnson lease in southern Gonzales County, Lonestar leased a total of 1,450 gross / 1,450 net acres in our Cyclone project area through June 30, 2016, just west of Harvey Johnson.  Lonestar drilled and completed the Cyclone #9H and #10H wells on this leasehold, and placed these two wells onstream on May 12, 2016.  After drilling a pilot hole and running logs to gather information on rock properties and petro-physics , Lonestar drilled and completed the Cyclone #9H & #10H with an average perforated interval of 6,685 feet. Lonestar holds a 42% WI / 33% NRI in these wells. The two new wells were fracture stimulated with an average proppant concentration of 1,518 pounds per foot. The Cyclone #9H tested 543 Bo/d and 239 Mcfg/d, or 598 Boe/d on a processed three-stream basis on an 18/64” choke and registered a 30-day production rate of 486 Boe/d. The Cyclone #10H tested 576 Bo/d and 239 Mcfg/d, or 631 Boe/d on a processed three-stream basis on an 18/64” choke and registered a 30-day production rate of 521 Boe/d.  Originally estimated to cost an average of $5.2 million, these wells have been drilled and completed at an average cost of $4.7 million.  Based on the results of its initial wells on the Cyclone project, Lonestar has executed agreements to lease an additional 1,456 gross / 1,322 net acres that directly offset the Cyclone #9H and #10H wells. These additions increase Lonestar’s total leasehold in its Cyclone project to 2,906 gross / 2,656 net acres as of August 15^th, 2016, which is expected to accommodate 29 additional laterals with an average lateral length exceeding 7,000 feet.

 

Eagle Ford Shale Trend - Eastern Region

 

17

---

 

Brazos & Robertson Counties

 

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

Operating Results

The following discussion relates to our consolidated results of operations, financial condition and capital resources. You should read this discussion in conjunction with our consolidated financial statements and the notes thereto. Comparative results of operations for the period indicated are discussed below.

Definitions:

Bbl – Barrel of oil.

Bbls/d.  Number of one stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons per day.

Boe.  Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Boe/d.  Barrels of oil equivalent per day.

Mcf.  Thousand cubic feet of natural gas.

Mcf/d.  Thousand cubic feet of natural gas per day.

WTI. West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

Results of operations for the three months ended June 30, 2016 compared to the three months ended June 30, 2015

Net Production

 

18

---

 

 

Our production increased 13% from an average of 5,804 Boe/d during the three months ended June 30, 2015 to an average of 6,573 Boe/d during the three months ended June 30, 2016. The increase in our average daily production is the result of an effective drilling program. For the three months ended June 30, 2016, approximately 61% of our production was crude oil, 16% was NGLs and 24% was natural gas.

Average Sales Price

 

 

The average wellhead price for our production in the three months ended June 30, 2016 was $29.77 per Boe, which was 32% lower than the average price in the comparable period in 2015. Reported wellhead realizations were driven lower by significant declines in both the crude oil and natural gas benchmarks between the periods. While benchmark prices fell sharply, our crude oil hedge positions added $17.65 per barrel of oil or $10.68 per barrel of oil equivalent.

19

---

 

Revenues

 

While wellhead revenues declined $5.3 million (-23%) in the three months ended June 30, 2016 to $17.8 million from the comparable period in 2015 as a result of a significant decrease in benchmark prices, we realized favorable crude oil hedge cash settlements, which added $6.4 million in gains on commodity derivatives for the three months ended June 30, 2016.

Costs and Expenses

The table below presents a detail of costs and expenses for the periods indicated.

 

Lease Operating and Gas Gathering Expenses

Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production or ad valorem taxes.

20

---

 

Our total lease operating expenses decreased $0.2 million (-4%) in the three months ended June 30, 2016 to $4.4 million from the comparable period in 2015.  On a unit-of-production basis, our lease operating expenses decreased 15% from $8.68 per Boe in the three months ended June 30, 2015 to $7.35 per Boe in the three months ended June 30, 2016.

Production, Severance and Ad Valorem Taxes

Severance and ad valorem taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

Our total production, severance and ad valorem taxes declined $0.3 million (-17%) in the three months ended June 30, 2016 to $1.2 million from the comparable period in 2015 principally due to the 27% decline in wellhead revenues.

Rig Standby Expense

During the three months ended June 30, 2016, we incurred rig standby expense of $1.6 million related to the drilling rig we had under contract.

Depreciation, Depletion and Amortization (DD&A)

Capitalized costs attributed to our proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and natural gas properties is calculated using the unit-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.

DD&A decreased $0.8 million (5.7%) in the three months ended June 30, 2016 to $12.5 million from the comparable period in 2015 primarily due to an increase in estimated proved reserves.

 

Impairment of oil and gas properties

During 2016, certain leased acreage was set to expire located in Montana as part of the Bakken, Three Forks, and Lower Lodgepole formations (Poplar properties).  Based on our decision to defer drilling on the Poplar properties during 2016, for the three months ended June 30, 2016 we recorded a $1,938,000 impairment related to leased acreage expiring during 2016.  This was calculated through the allocation of our current carrying value of the properties across our proportionate share of the acreage. 

 

If pricing continues to decline, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to June 30, 2016. 

General and Administrative (G&A) Expenses

G&A increased $0.5 million (19%) in the three months ended June 30, 2016 to $2.9 million from the comparable period in 2015 primarily due to the general and administrative expenses necessary to support higher production. Included in the 2016 G&A expense was approximately $0.3 million of legal and audit expenses associated with the Company’s efforts to re-domicile to the United States, and list on the NASDAQ Global Market. Despite the $0.3 million of legal and audit expenses, we achieved only a 5% increase in G&A per Boe to $4.78 per Boe in the three months ended June 30, 2016 from $4.56 per Boe in the three months ended June 30, 2015.

21

---

 

Interest Expense

Our interest expense increased $0.2 million (3%) in the three months ended June 30, 2016 to $6.2 million from the comparable period in 2015 primarily due  to an increase in average borrowings and a moderate increase in the average interest rate.

 

Gains (Losses) on Derivative Financial Instruments

In the three months ended June 30, 2016, we recognized a non-cash $13.2 million loss on our commodity derivative contracts related to the change in mark to market of our derivative contracts and a $6.4 million realized gain on settlement of our commodity derivative contracts. Settlement of the crude oil hedge positions added $17.65 per barrel to crude oil price realization.

Income Taxes

As a result of the net loss before income tax of $19.1 million in the three months ended June 30, 2016 and net loss before income tax of $12.6 million in three months ended June 30, 2015, we recorded an income tax benefit of $6.2 million in 2016 and an income tax benefit of $4.2 million in 2015.

Net Income (Loss) Before Taxes

As a result of the above factors, and particularly the $5.3 million (-23%) decrease in revenue resulting from the decline in crude oil and natural gas benchmark prices, we recorded a net loss before income tax of $19.1 million in the three months ended June 30, 2016 compared to net loss before income tax of $12.6 million in the three months ended June 30, 2015.

Results of operations for the six months ended June 30, 2016 compared to the six months ended June 30, 2015

Net Production

 

22

---

 

 

Our production increased 16% from an average of 5,676 Boe/d during the six months ended June 30, 2015 to an average of 6,564 Boe/d during the six months ended June 30, 2016. The increase in our average daily production is the result of an effective drilling program. For the six months ended June 30, 2016, approximately 56% of our production was crude oil, 19% was NGLs and 25% was natural gas.

Average Sales Price

 

 

The average wellhead price for our production in the six months ended June 30, 2016 was $24.28 per Boe, which was 39% lower than the average price in the comparable period in 2015. Reported wellhead realizations were driven lower by significant declines (30 - 50%) in both the crude oil and natural gas benchmarks between the periods. While benchmark prices fell sharply, our crude oil hedge positions added $24.58 per barrel of oil or $13.84 per barrel of oil equivalent.

23

---

 

Revenues

 

 

While wellhead revenue declined $12.2 million (-30%) in the six months ended June 30, 2016 to $29.0 million compared to the comparable period in 2015 due to the significant decrease in benchmark prices, we realized favorable crude oil hedge cash settlements, which added $16.5 million in gains on commodity derivatives for the six months ended June 30, 2016.

Costs and Expenses

The table below presents a detail of costs and expenses for the periods indicated.

 

Lease Operating and Gas Gathering Expenses

Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water injection and disposal, utilities, materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production or ad valorem taxes.

24

---

 

Our total lease operating expenses increased 9% in the six months ended June 30, 2016 to $8.8 million from the comparable period in 2015 largely due to a 16% increase in production.  On a unit-of-production basis, our lease operating expenses declined 6% from $7.83 per Boe in the six months ended June 30, 2015 to $7.33 per Boe in the six months ended June 30, 2016.

Production, Severance and Ad Valorem Taxes

Severance and ad valorem taxes are paid on produced crude oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil and natural gas revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties.

Our total production, severance, and ad valorem taxes declined $0.7 million (-24%) in the six months ended June 30, 2016 to $2.1 million from the comparable period in 2015 principally due to the 30% decline in wellhead revenues.

Rig Standby Expense

During the six months ended June 30, 2016, we incurred rig standby expense of $1.6 million related to the drilling rig we had under contract.

Depreciation, Depletion and Amortization (DD&A)

Capitalized costs attributed to our proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and natural gas properties is calculated using the unit-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.

DD&A increased $1.6 million (6%) in the six months ended June 30, 2016 to $27.7 million from the comparable period in 2015 primarily due to the 16% increase in total oil equivalent produced in the six months ended June 30, 2016.

General and Administrative (G&A) Expenses

G&A increased $0.9 million (20%) in the six months ended June 30, 2016 to $5.6 million from the comparable period in 2015 primarily due to the general and administrative expenses necessary to support higher production. Included in the 2016 G&A expense was approximately $0.6 million of legal and audit expenses associated with the Company’s efforts to re-domicile to the United States, and list on the NASDAQ Global Market. Despite the $0.6 million of legal and audit expenses, we achieved only a 3% increase in G&A per Boe to $4.71 per Boe in the six months ended June 30, 2016 from $4.57 per Boe in the six months ended June 30, 2015.

Interest Expense

Our interest expense increased $0.5 million (4%) in the six months ended June 30, 2016 to $12.3 million from the comparable period in 2015 primarily due  to an increase in average borrowing and a moderate increase in the average interest rate.

 

25

---

 

Gains (Losses) on Derivative Financial Instruments

In the six months ended June 30, 2016, we recognized a non-cash $21.6 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $16.5 million realized gain on settlement of our commodity derivative contracts. Settlement of the crude oil hedge positions added $24.58 per barrel to crude oil price realization.

Income Taxes

As a result of the net loss before income tax of $36.2 million in the six months ended June 30, 2016 and net loss before income tax of $14.4 million from the comparable period in 2015, we recorded income tax benefit of $12.0 million in the six months ended 2016 and an income tax benefit of $5.4 million in the comparable period in 2015.

Net Income (Loss) Before Taxes

As a result of the above factors, and particularly the $12.2 million (-30%) decrease in revenue resulting from the decline in crude oil and natural gas benchmark prices, we recorded a net loss before income tax of $36.2 million in the six months ended June 30, 2016 compared to net loss before income tax of $14.4 million in the six months ended June 30, 2015.

Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources will be cash flows generated by operating activities and borrowings under our revolving credit facility.

We have historically financed our acquisition and development activity through cash flows generated by operating activities, borrowings under our revolving credit facility, and the issuance of bonds.

At June 30, 2016, we had $5.1 million in cash and cash equivalents and approximately $20 million of additional availability under our revolving credit facility.  We believe that our existing cash and cash equivalents, cash expected to be generated from operations and the availability of borrowing under our revolving credit facility will be sufficient to meet our liquidity requirements, anticipated capital expenditures and payments due under our existing credit facilities for at least the next 12 months.

On August 2, 2016 Lonestar Resources US Inc. and Eagleford Gas 5, LLC (“Buyer”) entered into a purchase and sale agreement with Juneau Energy, LLC (“Seller”) whereby the Buyer obtained an undivided 50% of Seller’s interest in two producing wells and each well’s respective  oil and gas leases covering approximately 1,300 net mineral acres located in Brazos County, Texas.  The total purchase paid by Buyer was $5,500,000 payable in 500,227 shares (post-restructuring) of Lonestar Resources US Inc. Class A Voting Common Stock. 

Senior Revolving Credit Facility

Effective as of July 27, 2016, LRAI, a subsidiary of the Successor, the several banks and other financial institutions party thereto (collectively, the “Consenting Lenders”) and Citibank, N.A., in its capacity as administrative agent for the lenders (the “Administrative Agent”) entered into the Third Amendment to Credit Agreement and Limited Waiver (the “Amendment”) to that certain Credit Agreement dated as of July 28, 2015, by and among LRAI, the Consenting Lenders (together with the other banks and financial institutions party thereto, the “Lenders”) and the Administrative Agent (as amended by that certain First Amendment to Credit Agreement dated as of April 29, 2016 and that certain Second Amendment to Credit Agreement dated as of May 19, 2016 and as further amended, supplemented and modified, the “Credit Agreement”) to (a) permit LRAI to incur the second lien obligations contemplated by the Purchase Agreement (as defined below) and LRAI’s contemplated use of proceeds thereof, (b) increase the applicable margin for Eurodollar and ABR loans and letter of credit fees by 0.75% across all levels of the previously applicable pricing grid, (c) modify the fee payable on the actual daily unused amount of the aggregate commitments to a flat 0.50% across all

26

---

 

levels of the pricing grid, (d) increase the minimum percentage of the value of our oil and gas properties that must be mortgaged as collateral for the obligations under the Credit Agreement and the other loan documents from 80% to 90%, (e) modify the maximum leverage ratio thresholds from 4.0 to 1.0 to (i) 4.75 to 1.0 for the four quarter period ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarter period ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarter period ending December 31, 2016 and (iv) 4.00 to 1.0 for all periods thereafter, (f) prohibit distributions to the Predecessor for general and administrative expenses after September 30, 2016 and (g) amend certain other provisions of the Credit Agreement as more specifically set forth in the Amendment.

Securities Purchase Agreement

On August 2, 2016, LRAI and the Successor entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Successor’s common stock at a price equal to $5.00 per share (the “Warrants” and, together with the Notes, the “Securities”). The initial sale of $10,000,000 aggregate principal amount of Securities closed on August 4, 2016 (the “Closing Date”).

As of August 15, 2016, LRAI has issued $25,000,000 in Second Lien Notes with the Successor issuing Warrants to purchase 500,000 shares of the Successor’s common stock.  Proceeds from the Second Lien Notes issuance were used to repurchase $48,414,000 in aggregate principal amount of its 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes and related fees and expenses related to the foregoing.

Registration Rights Agreement

In connection with entering into the Purchase Agreement, the Successor entered into a Registration Rights Agreement, dated as of August 2, 2016 (the “Registration Rights Agreement”), by and among the Successor, Leucadia and the Initial Purchaser (together with Leucadia and their permitted transferees, the “Holders”). Pursuant to the Registration Rights Agreement, the Successor has agreed to register for resale certain restricted shares of the Successor (the “Registrable Securities”) issued or issuable to the Holders, including those issuable upon exercise of the Warrants or pursuant to Leucadia’s commitment (the “Equity Commitment”) to purchase shares of the Successor’s Class A Voting Common Stock (the “Common Stock”). The Successor has agreed to file a registration statement providing for resale of the Registrable Securities as permitted by Rule 415 of the Securities Act of 1933, as amended (the “Securities Act”) no later than the earlier of (i) the one year anniversary of the consummation of the Offering (as defined below) and (ii) 30 days after the date the Successor first becomes eligible to file a registration statement on Form S-3. The Successor has also agreed, subject to certain limitations, to allow the Holders to sell Registrable Securities in connection with certain registered offerings that the Successor may conduct in the future and to provide holders of a specified number of Registrable Securities the right to demand that the Successor conduct an underwritten public offering of Registrable Securities under certain circumstances. The Registration Rights Agreement contains representations, warranties, covenants and indemnities that are customary for private placements by public companies.

In the event that the Successor elects to pursue an equity offering prior to December 31, 2016, Leucadia agreed pursuant to the Equity Commitment to purchase the number of shares of Common Stock equal to (such amount, the “Commitment Amount”) (a) $20,000,000 (or such lesser amount as the Successor requests) divided by (b) the offering price to investors in a registered public offering of securities (the “Offering”) that is completed on or before December 31, 2016 (the “Outside Date”). Leucadia’s agreement to purchase the Common Stock is conditioned on, amongst other things, the Successor (i) selecting a lead underwriter approved by Leucadia, (ii) having, together with its subsidiaries, no more than $295,000,000 of long-term debt outstanding (net of cash and cash equivalents), and (iii) the equity order book in the Offering is no less than $40,000,000, excluding the Commitment Amount.

In connection with the Equity Commitment, the Successor will pay Leucadia a fee equal to $1,000,000, payable whether an Offering is launched or consummated, upon the earlier of (i) the closing of the Offering, (ii) the termination of the Offering and (iii) the Outside Date.

In the event Leucadia purchases not less than the Commitment Amount in an Offering, the Successor has agreed to use commercially reasonable efforts to enter into arrangements that provide Leucadia will have the right to appoint one director to the board of directors of the Successor, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Common Stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in the Offering.

 

 

Historical Cash Flows

27

---

 

The following table summarizes our cash flows for the periods indicated:

 

 

Net Cash Provided By Operating Activities

Net cash provided by operating activities decreased $18.1 million from $25.6 million in the six months ended June 30, 2015 to $7.5 million in the six months ended June 30, 2016. This decrease is primarily due to a $19.6 million increase in net loss, a $0.9 million gain on sale of oil and gas properties, and a $2.1 million decrease in net operating assets and liabilities, offset by a $4.5 million increase in gain on derivative financial instruments during the six months ended June 30, 2016.

Net Cash Used In Investing Activities

Net cash used in investing activities decreased $39.0 million from $58.2 million in the six months ended June 30, 2015 to $19.2 million in the six months ended June 30, 2016. This decrease is primarily due to (i) a $0.8 million decrease in the acquisition of oil and gas properties and (ii) a $35.7 million decrease in the development of oil and gas properties.

Net Cash Provided By Financing Activities

Net cash provided by financing activities decreased $14.5 million from $27.0 million provided during the six months ended June 30, 2015 to $12.5 million provided in the six months ended June 30, 2016. The decrease was due to a decrease in borrowings of $8.5 million and a payment on bank borrowings exceeding proceeds from bank borrowings of $6.0 million in the six months ended June 30, 2016.  During the six months ended June 30, 2015 the Company reported borrowings of $23.5 million.

 

Hedging

 

The following table provides a summary of our derivative contracts as of June 30, 2016:

 

 

For the remainder of 2016, our crude oil swap coverage totals approximately 2,692 barrels per day at an average swap price of $69.57. During the quarter, we have entered into additional WTI crude oil swaps covering a total of 182,500 barrels for the period of January 2017 through December 2017. The addition of these swaps increased our crude oil hedge position coverage to a total of approximately 1,500 barrels of oil per day at an average strike price of $53.79 per barrel.

28

---

 

Debt

As of June 30, 2016, we had an aggregate of  $315.2 million of indebtedness, including $99.5 million drawn on our revolving credit facility and $220.0 million (less an unamortized discount of $3.0 million and debt issuance costs of $1.5 million) under our 8.750% Senior Notes due 2019.

Revolving Credit Facility

As of June 30, 2016, LRAI had outstanding borrowings of approximately $99.5 million under the revolving credit facility, which was subject to an average interest rate of approximately 2.75% during the three months ended June 30, 2016. Additionally, the revolving credit facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. LRAI have drawn $300,000 of advances on the letter of credit as of June 30, 2016. The borrowing base under the revolving credit facility can be redetermined up or down by the lenders based on, among other things, their evaluation of our oil and natural gas reserves. Effective May 19, 2016, LRAI received notification that the borrowing base was reduced to $120 million. Also, redeterminations are now scheduled semi-annually to occur on May 1 and November 1 of each year. The next borrowing base redetermination is scheduled for November 1, 2016.

8.750% Senior Notes due 2019

LRAI issued $220 million aggregate principal amount of 8.750% Senior Notes due 2019 (the “Notes”) in April 2014 under an indenture among LRAI, its subsidiary guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”).  The Successor is not a party to the indenture.

The Notes mature on April 15, 2019 and accrue interest at a rate of 8.750% per annum, payable semi-annually in arrears on April 15 and October 15 of each year until the maturity date.  The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each subsidiary of LRAI.

Contractual Obligations

A summary of our contractual obligations as of June 30, 2016 is provided in the following table.

 

 

Capital Expenditures

Historical capital expenditures

The table below summarizes our capital expenditures incurred for the three months ended March 31 and June 30, 2016 and six months ended June 30, 2016. Future drilling in 2016 will be dictated by cash flow.

29

---

 

Impairment of Oil and Gas Properties

During 2016, certain leased acreage was set to expire located in Montana as part of the Bakken, Three Forks, and Lower Lodgepole formations (Poplar properties).  Based on our decision to defer drilling on the Poplar properties during 2016, for the three months ended June 30, 2016 we recorded a $1,938,000 impairment related to leased acreage expiring during 2016.  This was calculated through the allocation of our current carrying value of the properties across our proportionate share of the acreage. 

 

If pricing continues to decline, it is reasonably likely that the Company may have to record impairment of its oil and gas properties subsequent to June 30, 2016. 

Critical Accounting Policies and Estimates

The preparation of our financial statements requires us to make estimates and judgments that can affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements. We analyze our estimates and judgments, including those related to oil, NGLs and natural gas revenues, oil and natural gas properties, impairment of long-lived assets, fair value of derivative instruments, asset and retirement obligations and income taxes, and we base our estimates and judgments on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may vary from our estimates. The policies of particular importance to the portrayal of our financial position and results of operations and that require the application of significant judgment or estimates by our management are summarized in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of our Registration Statement on Form 10 as amended and filed with the SEC on June 9, 2016 and declared effective by the Securities and Exchange Commission on July 5, 2016. As of June 30, 2016, there were no significant changes to any of our critical accounting policies and estimates.

 

Cautionary Note Regarding Forward-looking Statements

 

This Quarterly Report on Form 10-Q statement contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report on Form 10-Q, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

 

Forward-looking statements may include statements about our:

 

·         discovery and development of crude oil, NGLs and natural gas reserves;

 

·         cash flows and liquidity;

 

·         business and financial strategy, budget, projections and operating results;

 

·         crude oil, NGLs and natural gas realized prices;

 

·         timing and amount of future production of crude oil, NGLs and natural gas;

 

·         availability of drilling and production equipment;

 

·         availability of personnel;

 

·         amount, nature and timing of capital expenditures, including future development costs;

 

·         availability and terms of capital;

 

·         drilling and completion of wells;

 

·         competition;

 

30

---

 

·         marketing of crude oil, NGLs and natural gas;

 

·         timing, location and size of property acquisitions and divestitures;

 

·         costs of exploiting and developing our properties and conducting other operations;

 

·         general economic and business conditions;

 

·         effectiveness of our risk management activities;

 

·         environmental and other liabilities;

 

·         counterparty credit risk;

 

·         governmental regulation and taxation of the crude oil and natural gas industry; and

 

·         our plans, objectives, expectations and intentions.

 

All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, objectives, expectations or intentions will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Item 1A (Risk Factors), Item 2 (Financial Information) and elsewhere in our Registration Statement on Form 10, as amended and filed with the SEC on June 9, 2016, and Part I (Financial Information), Item 1A (Risk Factors) and elsewhere in this Quarterly Report on Form 10-Q.

 

These important factors include risks related to:

 

·                                variations in the market demand for, and prices of, crude oil, NGLs and natural gas;

 

·                                lack of proved reserves;

 

·                                estimates of crude oil, NGLs and natural gas data;

 

·                                the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing;

 

·                                borrowing capacity under our credit facilities;

 

·                                general economic and business conditions;

 

·                                failure to realize expected value creation from property acquisitions;

 

·         uncertainties about our ability to replace reserves and economically develop our reserves;

 

·                                risks related to the concentration of our operations;

 

·                                drilling results;

 

·                                potential financial losses or earnings reductions from our commodity price risk management programs;

 

·                                potential adoption of new governmental regulations; and

 

·                                our ability to satisfy future cash obligations and environmental costs.

 

The forward-looking statements relate only to events or information as of the date on which the statements are made in this Quarterly Report on Form 10-Q. Except as required by law, we undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, after the date on which the statements are made or to reflect the occurrence of unanticipated events.

31

---

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

 

There have been no material changes in our market risks as of June 30, 2016 from those disclosed in our Registration Statement on Form 10 initially filed with the SEC on December 31, 2015 and declared effective by the Securities and Exchange Commission on July 5, 2016.

 

Item 4. Controls and Procedures.

 

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

 

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated, as of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2016.

 

Changes in Internal Controls

There was no change in our internal control over financial reporting during the quarter ended June 30, 2016 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

 

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business.  Like other crude oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety, and other laws and regulations governing air emissions, wastewater discharges and solid and hazardous waste management activities.  We are not aware of any material pending or overtly threatened legal action against us.

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed under “Risk Factors” in our Form 10, as amended and filed with the SEC on June 9, 2016.  These factors could materially adversely affect our business, financial condition, liquidity, results of operations and capital postion, and could cause our actual results to differ materially from our historical results or the results contemplated by any forward-looking statements contained in this report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

32

---

 

Item 5. Other Information.

None.

33

---

 

Item 6. Exhibits.

The following exhibits are required by Item 601 of Regulation S-K and are filed as part of this report.

34

---

 

 

 

 

**Furnished herewith.

 

 

 

35

---

 

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.

 

 

36

---

 

Exhibit Index

37

---

 

 

 

 

 

 

38