.

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended September 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  ☐

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  ☐    No  ☒

As of November 7, 2016, the registrant had 8,022,015 shares of Class A voting common stock, par value $0.001 per share, outstanding.

 

 

 

 

 

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Table of Contents

 

 

 

 

 

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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 voting 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.

 

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

Lonestar Resources US Inc.

Consolidated Balance Sheets

(In thousands, except share and per share data)

 

 

See accompanying notes to unaudited consolidated financial statements.

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Lonestar Resources US Inc.

Consolidated Balance Sheets (continued)

(In thousands, except share and per share data)

 

 

See accompanying notes to unaudited consolidated financial statements.

 

 

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Lonestar Resources US Inc.

Consolidated Statements of Operations & Comprehensive (Loss) Income

(In thousands, except share and per share data)

(Unaudited)

 

See accompanying notes to unaudited consolidated financial statements.

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Lonestar Resources US Inc.

Consolidated Statement of Changes in Stockholders’ Equity

(In thousands, except share data)

(Unaudited)

 

 

 

See accompanying notes to unaudited consolidated financial statements.

 

 

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Lonestar Resources US Inc.

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

 

 

See accompanying notes to unaudited consolidated financial statements.

 

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Lonestar Resources US Inc.

Notes to Consolidated Financial Statements

(Unaudited)

 

1. Nature of Business and Presentation

 

Lonestar Resources US Inc. (the “Successor”) was incorporated in Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed on July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Successor and Lonestar Resources Limited (the “Predecessor”), an Australian company. Prior to the Reorganization, our business was owned and operated under our Predecessor, whose ordinary shares were listed on the Australian Securities Exchange (“ASX”). Pursuant to the Scheme, the Successor acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s shareholders received one share of our Class A voting common stock for every two ordinary shares of our Predecessor such shareholder held. 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. The reorganization was treated as a transaction among parties under common control and no gain or loss was recorded.  

Lonestar Resources America, Inc. (“LRAI”) is a Delaware registered U.S. holding company formed on 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. 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 and regulations of the Securities and Exchange Commission.  The results of operations and the cash flows for the nine months ended September 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”),

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

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

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 August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)" in order, to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The update addresses eight different transaction types and clarifies how to classify each in the statement of cash flows, where previously there was unclear or no specific guidance. For public entities, this ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2018. The impact is not expected to be material.

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments", which introduces new guidance for estimating credit losses on certain types of financial instruments based on expected losses and the timing of the recognition of such losses. For public entities, this ASU is effective for annual periods beginning after December 15, 2019, and interim periods within those years and early adoption is permitted in the year prior to the effective date. We expect to adopt this guidance in the first quarter of 2020. The impact is not expected to be material.

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. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements.

In February 2016, the FASB issued 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 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 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 became effective for the Company as of 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.

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

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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.

 

 

3. Acquisitions and Divestitures

On September 26, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. entered into a purchase and sale agreement with AVAD Energy Partners, LLC and Vendera Resources II, LLC to sell their remaining interest in producing wells and related oil and gas leases in its conventional properties located in multiple counties in Texas, effective as of July 1, 2016.  Aggregate production related to the properties was 436 Boe/d during the third quarter of 2016.  The sale price approximated $14,000,000.  The transaction closed on October 31, 2016.  As of September 30, 2016, the Company reported an impairment charge of approximately $29.1 million, representing carrying value in excess of fair value, less the cost to sell the properties.

On August 2, 2016 the Company entered into a purchase and sale agreement with Juneau Energy, LLC (“Juneau”) whereby the Company 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 the Company was $5,500,000 payable in 500,227 shares of the Company’s Class A voting common stock.

On June 15, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. sold their entire interest in producing wells and related oil and gas leases in its Morgan’s Bluff property located in Orange County, Texas, effective as of July 1, 2016.  Production related to the property was 86 Boe/d during the second quarter of 2016.  The sale price approximated $2,200,000 and resulted in a gain of approximately $1,900,000. 

From 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.  From 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 Certificate of Deposit

The Company is required to maintain a certificate of deposit (“CD”) issued by a municipality in Montana, in which certain of our 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 September 30, 2016, the Company had no open physical delivery obligations.

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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 September 30, 2016, the following derivative transactions were outstanding:

 

 

 

The above derivative contracts aggregate to 232,550 barrels or 2,528 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.

As of September 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 contain credit-risk related contingent features.

 

 

6. Fair Value Measurements

Non-recurring fair value measurements include certain nonfinancial assets and liabilities as may be acquired in a business combination and thereby measured at fair value; impaired oil and natural gas property assessments; warrants issued in equity offerings and the initial recognition of asset retirement obligations for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these estimates as Level 3.

The Company periodically reviews for impairment its long-lived assets, including proved oil and natural gas properties accounted for under the successful efforts method of accounting. Based upon a purchase and sale agreement for the sale of the Company’s conventional oil and natural gas properties located in Texas, the Company reviewed the carrying value of the remaining acreage in this area and recorded an impairment of approximately $29.1 million during the three months ended September 30, 2016.

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.

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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 September 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 the “8.750% Senior Notes” (as defined in Note 9 below) approximates $96.8 million as of September 30, 2016, and the notes are considered a Level 3 liability, as they are based on market transactions that occur infrequently as well as internally generated inputs.  The Company’s other Level 3 financial liabilities measured at fair value consist of the warrant liability as of September 30, 2016. Significant unobservable inputs used in the fair value measurement of the warrants include the estimated term. Significant decreases in the estimated remaining period to exercise would result in a significantly lower fair value measurement.

  

 

 

7. Oil and Gas Properties

A summary of oil and gas properties follows:

 

 

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On September 26, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. entered into a purchase and sale agreement with AVAD Energy Partners, LLC and Vendera Resources II, LLC to sell their remaining interest in producing wells and related oil and gas leases in its conventional properties located in multiple counties in Texas, effective as of July 1, 2016.  Aggregate production related to the properties was 436 Boe/d during the third quarter of 2016.  The sale price approximated $14,000,000.  The transaction closed on October 31, 2016.  As of September 30, 2016, the Company reported an impairment charge of approximately $29.1 million, representing the carrying value in excess of fair value, less the cost to sell the properties.  Asset retirement costs of $4 million and the related asset retirement liability of $4.5 million have been included in the carrying value of the properties as well as the impairment charge calculation.  The table above provides separate amounts for the carrying value of the assets held for sale and the related accumulated depletion and impairment allowances.

 

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 an approximate $1.9 million 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 September 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 Secured Credit Facility

On July 28, 2015, LRAI closed a new $500,000,000 Senior Secured Credit Facility (the “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 featured 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 October 16, 2018, which represents a seven month extension over the Wells Fargo-

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led facility.  The financial covenants contained in this new facility are substantially the same as the previous facility.  Effective as of May 19, 2016, the borrowing base was reduced from $180,000,000 to $120,000,000.  As of September 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 Senior Secured Credit Facility.  As of September 30, 2016 and December 31, 2015, $94,500,000 and $87,000,000 was borrowed, respectively, under the Senior Secured Credit Facility.

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

Borrowings under the Senior Secured 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 Senior Secured 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 Senior Secured 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 Senior Secured Credit Facility, LRAI and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangements, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the Senior Secured 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 quarterly periods ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarterly periods ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarterly periods 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.

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 (the “8.750% Senior 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 Senior Secured 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 8.750% Senior 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 8.750% Senior Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

 

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In addition, upon a change of control of LRAI, holders of the 8.750% Senior Notes will have the right to require LRAI to repurchase all or any part of their 8.750% Senior Notes for cash at a price equal to 101% of the aggregate principal amount of the 8.750% Senior Notes repurchased, plus any accrued and unpaid interest. The 8.750% Senior 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 September 30, 2016 and December 2015, the Company had approximately $1,300,000 and $1,100,000, respectively, of debt issuance costs associated with issuance of the Senior Secured Credit Facility 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.

Securities Purchase Agreement and Second Lien Notes

On August 2, 2016, the Company entered into a Securities Purchase Agreement with Juneau Energy, LLC, as initial purchaser (“Juneau”), Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto 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 Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”).

The Second Lien 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 Senior Secured Credit Facility.

 

As of September 30, 2016, LRAI has issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company has issued Warrants to purchase 760,000 shares of its Class A voting common stock. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes, and to pay related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $29.4 million.

Repurchase Facilitation Agreement

On October 26, 2016, effective September 29, 2016, Lonestar Resources US, Inc. (the “Company”), by and on behalf of itself and certain of its subsidiaries, entered into an Amended and Restated Repurchase Facilitation Agreement (the “Amended and Restated Agreement”) with Seaport Global Securities LLC, a Delaware limited liability company (“Seaport Global”).  Pursuant to the Amended and Restated Agreement, Seaport Global has agreed to provide the Company with financing (“Gap Financing”) from time to time in connection with the repurchase of the 8.750% Senior Notes, to be acquired by Seaport Global on the Company’s behalf in one or more open market purchases.  

The Amended and Restated Agreement amends and restates that certain Facilitation Agreement entered into on September 29, 2016 (the “Original Agreement”), between the Company and Seaport Global, which was previously disclosed in a Current Report on Form 8-K filed with the Securities and Exchange Commission (the “Commission”) on October 5, 2016.  Other than as provided below, the terms of the Amended and Restated Agreement are substantially the same as those set forth in the Original Agreement.

Under the Amended and Restated Agreement, the Company has agreed to repay Seaport Global for Gap Financing, concurrently with the consummation of a public equity offering by the Company of its Class A voting common stock , in an amount of cash (the “Cash Payment Amount”) equal to (i) one hundred five percent (105%) of the amount of the Gap Financing if paid before December 31, 2016 and (ii) one hundred eleven and one tenth percent (111.1%) of the amount of Gap Financing if paid on or after January 1, 2017.  

To the extent that the Company is unwilling or otherwise unable to consummate such public equity offering, the Company has agreed to issue up to the Share Cap (as defined below) in shares of Class A voting common stock in an amount equal to the purchase price of any 8.750% Senior Notes the repurchase of which is financed by Seaport Global, divided by (i) with respect to any financing prior to the approval of any such issuance by holders of a majority of the issued and outstanding shares of Class A voting common stock (“Stockholder Approval”), 90% of the closing price of the Class A voting common stock on September 28, 2016 and (ii) with respect

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to any financing subsequent to the Stockholder Approval of shares, 90% of the closing price of the Class A voting common stock on the most recently completed trading date prior to the date that shares of Class A voting common stock are delivered to Seaport Global.  The number of shares of Class A voting common stock that the Company may issue to Seaport Global under the Facilitation Agreement (the “Share Cap”) is limited to the lesser of (a) 460,000 shares of Class A voting common stock and (b) a number of shares of Class A voting common stock that would, as a result of the issuance thereof to Seaport Global, cause EFR Guernsey Holding Limited, the Company’s majority stockholder (the “EFR Guernsey”), to hold less than a majority of the issued and outstanding shares of Class A voting common stock.

As of September 30, 2016, the Company recorded $2,063,320 as long-term debt on its balance sheet as a result of this Gap Financing.

 

 

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 and the Successor have 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 nine months ended September 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 and the Lonestar Resources US Inc. 2016 Incentive Plan, which replaced the Lonestar Resources Limited 2012 Employee Share Option Plan following the Reorganization:

 

 

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Stock-Based Compensation Expense

For the three and nine month periods ended September 30, 2016, the Company recorded stock-based compensation expense for stock options granted using the fair-value method of $121,986 and $312,638, 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 Class A voting 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 nine months ended September 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 September 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.

The following table presents unaudited 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 nine month periods ended September 30, 2016 and 2015:

Unaudited Earnings Per Share (After Reorganization)

 

 

 

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.

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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 $78,000 and $149,000 for the three months ended September 30, 2016 and 2015, respectively and approximately $465,000 and $763,000 in the nine months ended September 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 $24,000 and $36,000 for the three months ended September 30, 2016 and 2015, respectively and approximately $95,000 and $107,000 for the nine months ended September 30, 2016 and 2015, respectively. He has not received any additional compensation for his service as a Director.

 

 

13.  Equity Backstop Commitment

Pursuant to the Securities Purchase Agreement discussed in Note 9 above with Juneau and Leucadia, in the event that the Company elects to pursue an equity offering prior to December 31, 2016, Leucadia has agreed to purchase the number of shares of Class A voting common stock equal to (a) $20,000,000 (or such lesser amount as the Company requests) divided by (b) the offering price to investors in a registered public offering of securities that is completed on or before December 31, 2016. Leucadia’s agreement to purchase the Class A voting common stock is conditioned on, among other things, the Company (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 such offering is no less than $40,000,000, excluding Leucadia’s commitment.

In connection with Leucadia’s commitment, the Company has agreed to pay Leucadia a fee equal to $1,000,000, payable whether such an offering is launched or consummated, upon the earlier of (i) the closing of such offering, (ii) the termination of such offering and (iii) December 31, 2016. This amount is recorded as prepaid expenses and other and accrued liabilities in the consolidated balance sheet.

In the event Leucadia purchases not less than their commitment amount, the Company agreed to use commercially reasonable efforts to enter into arrangements to provide Leucadia with the right to appoint one director to the board of directors of the Company, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Class A voting common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering.

 

14. 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.

Board Representation Agreement

On October 26, 2016, the Company entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation Company Limited (“EF Realisation”). Under the Board Representation Agreement, as long as EFR Guernsey, a wholly-owned subsidiary of EF Realisation and the direct holder of the majority of the Company’s Class A voting common stock, owns 15% or more of the issued and outstanding shares of Class A voting common stock, it has the right to designate up to, but no more than, two directors (each, a “Designee”) to serve on the board of directors of the Company (the “Board”), and for as long as EFR Guernsey owns at least 10% but less than 15% of the issued and outstanding Class A voting common stock, it has the right to designate up to, but no more than, one Designee to serve on the Board.  One Designee, as directed by EF Realisation, must serve on each committee of the Board provided that such appointment would not contravene any applicable rules and regulations of the NASDAQ Stock Market or the Securities and Exchange Commission.

 

Registration Rights Agreement

On October 26, 2016, the Company entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with EF Realisation. Pursuant to the Registration Rights Agreement, subject to certain limitations, the Company agreed to register for resale of the Class A voting common stock held by EFR Guernsey (“EF Realisation Stock”).  The Company agreed to file a registration statement (the “Registration Statement”) providing for the resale of EF Realisation Stock no later than the earlier of (the “Filing

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Deadline”): (i) October 26, 2017, and (ii) 30 days after the date the Company first becomes eligible to file a registration statement on Form S-3.  The Company agreed to cause the Registration Statement to become effective no later than 120 days after the Filing Deadline.

If a Registration Statement is not effective on or prior to the Filing Deadline, EF Realisation will have certain demand registration rights. Subject to certain exceptions, if at any time the Company proposes to register an offering of equity securities or conduct an underwritten offering of its Class A voting common stock, whether or not for its own account, then the Company must notify EF Realisation of such proposal to allow them to include a specified number of their shares of Class A voting common stock in that registration statement or underwritten offering, as applicable.

The registration rights provided under the Registration Rights Agreement are subject to certain conditions and limitations. The Company agreed to generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether a registration statement is filed or becomes effective.

 

 

 

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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 have accumulated approximately 43,314 gross (36,785 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of September 30, 2016. As of September 30, 2016, 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 September 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 voting 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 voting 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.

Deleveraging Initiative

On August 2, 2016, Lonestar Resources America, Inc. (“LRAI”) and the Company entered into a Securities Purchase Agreement with Juneau Energy, LLC, as initial purchaser (“Juneau”), Leucadia National Corporation (“Leucadia”), as guarantor of Juneau’s obligations, the other purchasers party thereto 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 Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants”). The initial sale of $10,000,000 aggregate principal amount of Second Lien Notes closed on August 4, 2016.

 

As of September 30, 2016, LRAI has issued $38.0 million in aggregate principal amount of Second Lien Notes, a $2 million Gap Financing to be settled in cash concurrently with the consummation of a public equity offering by the Company, and the Company has issued Warrants to purchase 760,000 shares of its Class A voting common stock resulting in a debt discount of approximately $5.1 million. Proceeds from the Second Lien Notes issuance were used to repurchase approximately $68.2 million in aggregate principal amount of LRAI’s 8.750% Senior Notes due 2019 (the “8.750% Senior Notes”) in privately negotiated open market repurchases with holders of such notes and related fees and expenses related to the foregoing. The repurchase amounts paid were approximately $36.2 million in cash. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $29.8 million.

On October 26, 2016, effective September 29, 2016, the Company, by and on behalf of itself and certain of its subsidiaries, entered into an Amended and Restated Facilitation Agreement (the “Amended and Restated Agreement”) with Seaport Global Securities LLC, a Delaware limited liability company (“Seaport Global”).  Pursuant to the Amended and Restated Agreement, Seaport Global has agreed to provide the Company with financing (“Gap Financing”) from time to time in connection with the repurchase of 8.750% Senior Notes from time to time, to be acquired by Seaport Global on the Company’s behalf in one or more open market purchases.  

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The Company intends to, from time to time, evaluate opportunistically accessing the equity or debt capital markets, selling non-core assets, and engaging in prudent liability or capital structure management transactions in order to continue to achieve its goal of reducing outstanding indebtedness. Ultimate terms and the successful pursuit of these transactions will be, however, dependent in part on prevailing economic conditions and other factors, including factors beyond the Company’s control.

 

Third Quarter 2016 Operational Summary

 

During the third quarter of 2016, the Company was primarily focused on balance sheet improvement and therefore completed no new Eagle Ford Shale wells.  Consequently, the Company experienced a 10% decrease in net oil and gas production to 5,921 Boe/d during the three months ended September 30, 2016, compared to 6,614 Boe/d during the three months ended September 30, 2015.  In the third quarter of 2016, 75% of the Company’s production was crude oil and NGLs.  The Company production from its focus, the Eagle Ford Shale play of south Texas, fell by 8% during the three months ended September 30, 2016 over the three months ended September 30, 2015, to 5,485 BOE/D. Lonestar did not place any new wells onstream during the third quarter 2016.  However, Lonestar added 2.0 gross / 1.0 net wells effective August 1, 2016 through the acquisition of a 50% working interest in two wells from Juneau.

 

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 September 30, 2016.  Production rates from the four producing wells continued to outperform the third-party engineering projections.  The Asherton leasehold is held by production, and Lonestar does not plan drilling activity here in 2016.

 

Beall Ranch

 

In Dimmit County, Lonestar continues to operate the Beall Ranch #20H - #22H, completed in the first quarter of 2016 and the first three wells completed in partnership with Schlumberger as part of the companies’ Geo-Engineered Completion Alliance (“GECA”). While still preliminary, the production results during the first 225 days onstream are encouraging, as the average cumulative production from these wells of 64,000 barrels of oil is 11% higher than that of the #26H - #28H wells, drilled 12 months prior, when compared on a barrel-per-lateral-foot basis for the same period of time. The #26H-#28H wells utilized certain elements of the GECA, which Lonestar believes were significant contributors to the 42% outperformance as compared to the offsets, the #32H-#34H, which were completed in July, 2015.  In total, through two iterations of technology improvements, Lonestar has achieved a 58% improvement in cumulative oil production per lateral foot.  Lonestar is encouraged by the results of the GECA to date, and has been applying them across its portfolio during 2016.

 

Burns Ranch Area

 

In August 2016, Lonestar executed a lease swap agreement with another operator and consolidated Lonestar’s leasehold position so that we can now drill at our own discretion.  Within the leasehold associated with this trade prior to this lease swap, Lonestar had 19 gross/15.1 net laterals engineered totaling 152,000 lateral feet. Following the lease swap, Lonestar has 18 gross/16.1 net laterals totaling 151,000 lateral feet. Lonestar recently completed drilling operations on the Burns Ranch Eagle Ford #8H, #9H and #10H wells with lateral lengths of approximately 9,620, 9,440 and 8,460 feet respectively. These wells were drilled to an average measured depth of 18,007 feet and were drilled from spud to total depth in an average of 13.3 days.  These results compare favorably with the wells that Lonestar drilled in 2015 on the Burns Ranch property, which were drilled to an average measured depth of 16,617 feet and were drilled from spud to total depth in an average of 24.3 days.  Lonestar’s recently drilled Burns Ranch Eagle Ford wells achieved a 97% improvement in rates of penetration, with the 2016 wells improving to 1,351 feet per day compared to the Burns Ranch Eagle Ford wells drilled in 2015, which averaged 683 feet per day. Lonestar plans to utilize BroadBand diverters on the #8H, #9H and #10H, which are expected to allow Lonestar to set stage spacing at 300 foot increments, reduce the number of frac stages and associated costs and achieve a designed proppant concentration of up to 2,000 pounds per foot, which would be the highest in the Company’s history. Based on availability of frac crews capable of conducting pressure pumping operations with BroadBand proppant diverter, Lonestar anticipates that it will commence fracture stimulation operations in mid-November 2016.  

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Production from these three wells is expected to increase the leasehold that is held by production at Burns Ranch from 2,712 net acres to 3,279 net acres, which equates to 86% of our total net leasehold at Burns Ranch.

 

Horned Frog

 

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

 

Eagle Ford Shale Trend - Central Region

 

Southern Gonzales County

 

Lonestar continues to operate its Cyclone #9H and #10H wells which were placed onstream on May 12, 2016.  Lonestar drilled and completed the Cyclone #9H & #10H with an average perforated interval of 6,685 feet. Lonestar holds a 42% WI / 33% NRI in these wells. The wells were fracture-stimulated with an average proppant concentration of 1,518 pounds per foot, utilizing BroadBand diverters, which allowed us to frac on 300-foot stage spacing.  The Cyclone #9H tested 543 bbl/d and 239 Mcf/d, or 598 Boe/d on an 18/64” choke and achieved a 30-day production rate of 486 Boe/d.  The Cyclone #10H tested 576 bbl/d and 239 Mcf/d, or 631 Boe/d on an 18/64” choke and achieved a 30-day production rate of 521 Boe/d. After being placed on jet pump during the quarter, the wells are outperforming the Company’s prior internal expectations. The #9H has produced cumulative production of 56,900 bbls of oil in 180 days. Meanwhile, the #10H has produced cumulative production of 59,600 bbls of oil in 180 days.  Based on the results of its initial wells on the Cyclone project, Lonestar has executed agreements to lease an additional 1,456 gross / 1,322 net acres that directly offset the Cyclone #9H and #10H wells. These additions are expected to increase Lonestar’s total leasehold in its Cyclone project to 2,906 gross / 2,656 net acres which is expected to accommodate 29 additional laterals with an average lateral length exceeding 7,000 feet. At December 31, 2015, Lonestar had no proved reserves booked to the Cyclone property.

 

Eagle Ford Shale Trend - Eastern Region

 

Brazos & Robertson Counties

 

In central Brazos County, Lonestar has permitted two 8,000-foot laterals with the Texas Railroad Commission and on March 8^th, 2016 Lonestar was granted operations permits with the City of College Station. The Company is encouraged by the results of offset drilling by a leading operator, who recently announced 30-day production rates on four wells immediately offsetting Lonestar’s leasehold, which have ranged from 1,587 to 1,973 BOE per day.  Based on its current drilling schedule, Lonestar currently plans to drill these wells in the first quarter of 2017. During the quarter Lonestar added 2.0 gross / 1.0 net wells effective August 1, 2016 through the acquisition of a 50% working interest in two wells from Juneau. On August 1, 2016, Lonestar assumed operatorship of this leasehold.  In the month of July, these two wells produced 650 Boe/d gross / 254 Boe/d net.  The acreage has the potential for 11 horizontal wells.  Since assuming operations of the property, Lonestar has made a number of operational improvements that have improved productivity of the two producing wells while substantially reducing operating costs.  As a result, Lonestar’s internal reserves estimates for proved and probable reserves have increased from 1.1 million barrels of oil equivalent (“MMBOE”) at closing to its current estimate of 1.6 MMBOE.

 

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.

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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.

EUR. Gross estimated ultimate recoveries for a single well.

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 September 30, 2016 compared to the three months ended September 30, 2015

Net Production

 

 

Our production decreased 10% from an average of 6,614 Boe/d during the three months ended September 30, 2015 to an average of 5,921 Boe/d during the three months ended September 30, 2016. The decrease in our average daily production is the result of not placing any new wells onstream during the quarter. For the three months ended September 30, 2016, approximately 54% of our production was crude oil, 21% was NGLs and 25% was natural gas.

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Average Sales Price

 

 

The average wellhead price for our production in the three months ended September 30, 2016 was $28.53 per Boe, which was 17% 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 $21.68 per barrel of oil or $11.50 per barrel of oil equivalent.

Revenues

 

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While wellhead revenues declined $5.3 million (-26%) in the three months ended September 30, 2016 to $15.5 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 $6.3 million in gains on commodity derivatives for the three months ended September 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.

Our total lease operating expenses decreased $0.2 million (-6%) in the three months ended September 30, 2016 to $4.0 million from the comparable period in 2015.  On a unit-of-production basis, our lease operating expenses increased 5% from $6.97 per Boe in the three months ended September 30, 2015 to $7.36 per Boe in the three months ended September 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 $0.5 million (-34%) in the three months ended September 30, 2016 to $0.9 million from the comparable period in 2015 principally due to the  26% decline in wellhead revenues.

Rig Standby Expense

During the three months ended September 30, 2016, we incurred rig standby expense of $0.4 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

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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 $3.2 million (23%) in the three months ended September 30, 2016 to $10.7 million from the comparable period in 2015 primarily due to a 10% decrease in production.

 

Impairment of oil and gas properties

 

On September 26, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. entered into a purchase and sale agreement to sell their remaining interest in producing wells and related oil and gas leases in its Conventional properties located in multiple counties in Texas, effective as of July 1, 2016.  The sale price approximated $14.0 million.  The transaction closed on October 31, 2016.  As of September 30, 2016, the Company reported an impairment charge of approximately $29.1 million, representing the carrying value in excess of fair value, less the cost to sell the 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 the Company recorded a $1.9 million 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 September 30, 2016. 

General and Administrative (G&A) Expenses

G&A expense increased $0.5 million (20%) in the three months ended September 30, 2016 to $2.9 million from the comparable period in 2015. 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.     

Interest Expense

Our interest expense increased $0.7 million (10%) in the three months ended September 30, 2016 to $7.3 million from the comparable period in 2015 primarily due  to an increase in average borrowings and a moderate increase in the average interest rate.

 

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Gains (Losses) on Derivative Financial Instruments

In the three months ended September 30, 2016, we recognized a non-cash $4.6 million loss on our commodity derivative contracts related to the change in mark to market of our derivative contracts and a $6.3 million realized gain on settlement of our commodity derivative contracts. Settlement of the crude oil hedge positions added $21.68 per barrel to crude oil price realization.

Income Taxes

As a result of the net loss before income tax of $9.6 million in the three months ended September 30, 2016 and net gain before income tax of $10.5 million in three months ended September 30, 2015, we recorded an income tax expense of $1.7 million in 2016 and an income tax expense of $3.9 million in 2015.

Net Income (Loss) Before Taxes

As a result of the $5.3 million (-26%) decrease in revenue caused by the decline in crude oil and natural gas benchmark prices, as well as a decrease in gain on derivative of $17.8 million, we recorded a net loss before income tax of $9.6 million in the three months ended September 30, 2016 compared to net gain before income tax of $10.5 million in the three months ended September 30, 2015.

Results of operations for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015

Net Production

 

 

Our production increased 6% from an average of 5,995 Boe/d during the nine months ended September 30, 2015 to an average of 6,348 Boe/d during the nine months ended September 30, 2016. The increase in our average daily production is the result of an effective drilling program. For the nine months ended September 30, 2016, approximately 55% of our production was crude oil, 19% was NGLs and 25% was natural gas.

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Average Sales Price

 

 

The average wellhead price for our production in the nine months ended September 30, 2016 was $25.61 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 (approximately 18%) in both the crude oil and natural gas benchmarks between the periods. While benchmark prices fell sharply, our crude oil hedge positions added $35.57 per barrel of oil or $13.11 per barrel of oil equivalent.

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Revenues

 

 

While wellhead revenue declined $17.5 million (-28%) in the nine months ended September 30, 2016 to $44.5 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 $22.8 million in gains on commodity derivatives for the nine months ended September 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.

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Our total lease operating expenses increased 1% in the nine months ended September 30, 2016 to $12.8 million from the comparable period in 2015 largely due to a 6% increase in production.  On a unit-of-production basis, our lease operating expenses declined 5% from $7.74 per Boe in the nine months ended September 30, 2015 to $7.34 per Boe in the nine months ended September 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 $1.2 million (-28%) in the nine months ended September 30, 2016 to $3.0 million from the comparable period in 2015 principally due to the 28% decline in wellhead revenues.

Rig Standby Expense

During the nine months ended September 30, 2016, we incurred rig standby expense of $2.3 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 $1.6 million (-4%) in the nine months ended September 30, 2016 to $38.5 million from the comparable period in 2015 primarily due to a 10% increase in estimated proved reserves in the nine months ended September 30, 2016.

Impairment of Oil and Gas Properties

 

On September 26, 2016, Amadeus Petroleum, Inc. and T-N-T Engineering, Inc. entered into a purchase and sale agreement to sell their remaining interest in producing wells and related oil and gas leases in its Conventional properties located in multiple counties in Texas, effective as of July 1, 2016.  The sale price approximated $14.0 million.  The transaction closed on October 31, 2016.  As of September 30, 2016, the Company reported an impairment charge of approximately $29.1 million, representing the carrying value in excess of fair value, less the cost to sell the 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 September 30, 2016. 

General and Administrative (G&A) Expenses

G&A expense increased $1.4 million (20%) in the nine months ended September 30, 2016 to $8.5 million from the comparable period in 2015 primarily due to the general and administrative expenses necessary to support higher production. Also included in the

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2016 G&A expense was approximately $1.2 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.

Interest Expense

Our interest expense increased $1.2 million (6%) in the nine months ended September 30, 2016 to $19.6 million from the comparable period in 2015 primarily due  to an increase in average borrowing and a moderate increase in the average interest rate.

 

Gains (Losses) on Derivative Financial Instruments

In the nine months ended September 30, 2016, we recognized a non-cash $26.2 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $22.8 million realized gain on settlement of our commodity derivative contracts. Settlement of the crude oil hedge positions added $35.57 per barrel to crude oil price realization.

Income Taxes

As a result of the net loss before income tax of $45.7 million in the nine months ended September 30, 2016 and net loss before income tax of $3.9 million from the comparable period in 2015, we recorded income tax benefit of $10.4 million and $1.4 million in the nine months ended September 30, 2016 and 2015, respectively.

Net Income (Loss) Before Taxes

As a result of the above factors, and particularly the $17.5  million (-28% ) decrease in revenue resulting from the decline in crude oil and natural gas benchmark prices, we recorded a net loss before income tax of $45.7 million in the nine months ended September 30, 2016 compared to net loss before income tax of $3.9 million in the nine months ended September 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 new $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit Facility”).

We have historically financed our acquisition and development activity through cash flows generated by operating activities, borrowings under our Senior Secured Credit Facility, and the issuance of bonds.

At September 30, 2016, we had $6.0 million in cash and cash equivalents and approximately $25 million of additional availability under our Senior Secured 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 Senior Secured Credit Facility will be sufficient to meet our liquidity requirements, anticipated capital expenditures and payments due under our existing credit facility and notes outstanding for at least the next 12 months.

On August 2, 2016 Lonestar Resources US Inc. and Eagleford Gas 5, LLC (collectively, “Buyer”) entered into a purchase and sale agreement with Juneau Energy, LLC (“Seller”) whereby 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. 

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Senior Secured Credit Facility

Effective as of July 27, 2016, LRAI, a subsidiary of the Company, 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 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 quarterly periods ending June 30, 2016, (ii) 4.50 to 1.0 for the four quarterly periods ending September 30, 2016, (iii) 4.25 to 1.0 for the four quarterly periods 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 and Second Lien Notes

On August 2, 2016, LRAI and the Company 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 Company’s Class A voting common stock at a price equal to $5.00 per share (the “Warrants” and, together with the Second Lien 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 September 30, 2016, LRAI has issued $38,000,000 in Second Lien Notes with the Company issuing Warrants to purchase 760,000 shares of the Company’s Class A voting common stock.  Proceeds from the Second Lien Notes issuance were used to repurchase $68,152,000 in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes and related fees and expenses related to the foregoing.

 

Historical Cash Flows

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

 

 

Net Cash Provided By Operating Activities

Net cash provided by operating activities decreased $3.0 million from $50.0 million in the nine months ended September 30, 2015 to $47.0 million in the nine months ended September 30, 2016. This decrease is primarily due to a $32.9 million increase in net loss, an $8.8 million decrease in net operating assets and liabilities and a $9 million dollar decrease in deferred taxes, offset by a $22.4 million increase in loss on derivative financial instruments and impairment charge of $31.1 million during the nine months ended September 30, 2016.

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Net Cash Used In Investing Activities

Net cash used in investing activities decreased $59.5 million from $85.0 million in the nine months ended September 30, 2015 to $25.5 million in the nine months ended September 30, 2016. This decrease is primarily due to (i) a $3.9 million decrease in the acquisition of oil and gas properties and (ii) a $52.9 million decrease in the development of oil and gas properties.

Net Cash Provided By Financing Activities

Net cash provided by (used in) financing activities decreased $49.8 million from $30.0 million provided during the nine months ended September 30, 2015 to $19.8 million used in the nine months ended September 30, 2016. The decrease was due to payments on bank borrowings exceeding the proceeds from such bank borrowings by $19.8 million in the nine months ended September 30, 2016.  During the nine months ended September 30, 2015 the Company reported borrowings  of approximately $64.3 million.

 

Hedging

 

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

 

 

For the remainder of 2016, our crude oil swap coverage totals approximately 2,528 barrels per day at an average swap price of $70.41. We have in place three-way collars covering 1,000 Bbls/d for calendar year 2017, which provide an effective floor of $55.25 per Bbl with WTI prices between $40.00 per Bbl and $60.00 per Bbl, and also gives upside to $80.25 per Bbl. In addition to the three-way collar, we had in place hedges covering approximately 500 Bbls/d for the calendar year 2017 at a volume weighted average of approximately $50.87 per Bbl.

In October 2016, we entered into additional WTI crude oil swaps covering a total of 365,000 barrels for the period of January 2017 through December 2017at an average strike price of $52.90. The addition of these swaps increased our total 2017 crude oil hedge position coverage to a total of approximately 2,500 barrels of oil per day at an average strike price of $53.43 per barrel. Also in October 2016, we entered into WTI crude oil swaps covering a total of 365,000 barrels for the period of January 2018 through December 2018 at an average strike price of $54.18. Lastly we entered into Henry Hub natural gas swaps covering a total of 2,555,000 Mcf for the period of January 2017 through December 2017 at an average strike price of $3.36.

Debt

As of September 30, 2016, we had an aggregate of $277.7 million of indebtedness, including $94.5 million drawn on our Senior Secured Credit Facility, $35.1 million  (less debt issuance costs of $1.2 million) on our Second Lien Notes, $151.8 million (less an unamortized discount of $1.9 million and debt issuance costs of $0.9 million) on our 8.750% Senior Notes and $0.3 million of other long-term notes.

Senior Secured Credit Facility

As of September 30, 2016, LRAI had outstanding borrowings of approximately $94.5 million under the Senior Secured Credit Facility, which was subject to an average interest rate of approximately 3.75% and 3.15% during the three and nine months ended September 30, 2016, respectively. Additionally, the Senior Secured Credit Facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. LRAI has $300,000 of advances on the letter of credit as of September 30, 2016. The borrowing base under

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the Senior Secured 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

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

The 8.750% Senior 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 8.750% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each subsidiary of LRAI.

During the third quarter of 2016, the Company repurchased $68,152,000 in aggregate principal amount of the 8.750% Senior Notes resulting in approximately $29,363,000 discount on disposal.

Securities Purchase Agreement and Second Lien Notes

On August 2, 2016, LRAI and the Company 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 the Second Lien Notes and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share.

As of September 30, 2016, LRAI has issued $38,000,000 in Second Lien Notes with the Company issuing Warrants to purchase 760,000 shares of the Company’s Class A voting common stock.  Proceeds from the Second Lien Notes issuance were used to repurchase $68,152,000 in aggregate principal amount of the 8.750% Senior Notes in privately negotiated open market repurchases with holders of such notes and related fees and expenses related to the foregoing.

Contractual Obligations

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

 

 

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Capital Expenditures

Historical capital expenditures

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

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 September 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;

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•         drilling, completion, and performance of wells;

 

•         competition;

 

•         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 facility;

 

•                                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.

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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.

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

 

There have been no material changes in our market risks as of September 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 September 30, 2016.

 

Changes in Internal Controls

There was no change in our internal control over financial reporting during the quarter ended September 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 position, 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.

Unregistered Sale of Equity Securities

On July 5, 2016, the Company acquired all of the issued and outstanding ordinary shares of the Predecessor as part of the Reorganization and pursuant to a scheme of arrangement under Australian law. The Company issued to the stockholders of the Predecessor one share of Class A voting common stock for every two ordinary shares of the Predecessor that were issued and outstanding.

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In connection with the Reorganization, the company adopted the Lonestar Resources US Inc. 2016 Incentive Plan (the “2016 Plan”) to replace the existing incentive plans of the Predecessor. Options issued under the prior incentive plans were cancelled and replaced with option awards under the 2016 Plan for 1,027,941 shares of the Company’s Class A voting common stock.

The issuances of shares and options in connection with our Reorganization were made in reliance of the exemption from the registration under Section 3(a)(10) of the Securities Act.

On August 2, 2016, LRAI and the Company entered into the Purchase Agreement with Juneau, as initial purchaser, Leucadia, as guarantor of Juneau’s obligations, the other purchasers party thereto 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 the Second Lien Notes and (ii) five-year Warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A voting common stock at a price equal to $5.00 per share. Pursuant to the Purchase Agreement, LRAI has issued $38 million aggregate principal worth of Second Lien Notes at par and the Company has issued Warrants for the purchase of 760,000 shares of Class A voting common stock. The date and amount of each issuance is detailed below:

 

On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau pursuant to which the Company issued 500,227 shares of Class A voting common stock in exchange for an undivided 50% 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 issuances of shares of Class A common stock to Juneau were made in reliance of the exemption from registration under Section 4(a)(2) of the Securities Act.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

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Item 6. Exhibits.

The exhibits in the accompanying Exhibit Index following the signature page are filed or furnished as a part of this report and are incorporated herein by reference.

 

 

 

 

 

 

 

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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.

 

 

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Exhibit Index

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