UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended March 31, 2017

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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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 May 11, 2017, the registrant had 21,822,015 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 Select Market on July 5, 2016 under the ticker symbol “LONE”.

 

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, including Lonestar Resources America, Inc. (“LRAI”), the operating company for the Lonestar group of companies, 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.

 

 

Glossary of Certain Defined Terms

The terms defined in this section are used throughout this Quarterly Report on Form 10-Q:

Bbl – Barrel of oil.

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

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

Boe/d.  Barrels of oil equivalent per day.

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.

 

 

 

 

 

 

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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 Income (Loss)

(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 above.  The majority of the activities of the Predecessor were 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 three months ended March 31, 2017 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”),

Lonestar Resources Intermediate, Inc. (“LRII”),

LNR America, Inc. (“LNRA”)

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”),

Eagleford Gas 9, LLC (“Eagleford Gas 9”),

Lonestar Operating, LLC (“LNO”),

Lonestar BR Disposal, LLC (“LBRD”),

La Salle Eagle Ford Gathering Line, LLC (“LSGL”),

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 January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-01, "Business Combinations (Topic 805): Clarifying the Definition of a Business" in order to clarify the definition of a business as it relates to whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. 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 under certain circumstances. The Company adopted ASU 2017-01 effective January 1, 2017.  There was no retrospective adjustment as the Company does not believe it has a material effect on our consolidated results of operations, financial position or cash flows.

In March 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (“Update 2016-09”), which seeks to simplify several aspects of the accounting for share-based payment award transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, Update 2016-09 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. The Company adopted ASU 2016-09 effective January 1, 2017.  The Company has elected to record the impact of forfeitures on compensation cost as they occur.  The Company is also permitted to withhold income taxes upon settlement of equity-classified awards at up to the maximum statutory rates.  There was no retrospective adjustment as the Company does not believe it has a material effect on our consolidated results of operations, financial position or cash flows.

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 beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated results of operations, financial position or cash flows and anticipates adopting the guidance on the effective date of January 1, 2019.

In May 2014, August 2015 and May 2016, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers”, ASU 2015-14, “Revenue from Contracts with Customers, Deferral of the Effective Date”, ASU 2016-12, “Revenue from Contracts with Customers, Narrow-Scope Improvements and Practical Expedients”, and ASU 2016-20, “Revenue from Contracts with Customers, Technical Corrections and Improvements”, respectively, as a new Topic, Accounting Standards Codification Topic 606. The new revenue recognition standard provides a five-step analysis of transactions to determine when and how revenue is recognized. The core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. It also requires entities to disclose both quantitative and qualitative information that enable financial statements users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. This guidance is effective for annual periods beginning after December 15, 2017 with early adoption permitted on January 1, 2017 and shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. As we are in the process of evaluating the impact of the standard, we have not yet quantified the impact of adoption or determined the method of adoption. During 2017, we will perform the remainder of our implementation process, which will include quantification of impact, selection of adoption method and development of policies. The Company plans to adopt this guidance in the first quarter of 2018.

 

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3. Acquisitions and Divestitures

From January to March 2017 the Company paid approximately $1,397,000 to acquire a total of 1,067 net acres in the Eagle Ford Shale play.  The amount paid included $400,000 for leases consummated in 2016 for 332 net acres in Gonzales County. During 2017, the Company entered into new primary term leases, including: i) paying approximately $700,000 to acquire approximately 526 net acres in Gonzales County, TX surrounding Company developed areas and new undeveloped areas classified by the Company as Cyclone; and ii) paying approximately $297,000 to acquire approximately 267 net acres in La Salle County, TX for new well development offsetting our Horned Frog property.

 

 

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, 2018, 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 cash collateral from any of its counterparties nor does its counterparties require cash collateral from the Company.  At March 31, 2017, the Company had no open physical delivery obligations.

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

As of March 31, 2017, the following derivative transactions were outstanding:

 

 

 

The above derivative contracts aggregate to 817,400 barrels or 2,970 barrels of oil per day for the remainder of 2017 and 912,500 barrels or 2,500 barrels of oil per day for 2018. The above natural gas derivative contract equates to 1,925,000 MMBtu or 7,000

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MMBtu 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 March 31, 2017 and December 31, 2016, 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.

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

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

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

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

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The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2017 and December 31, 2016, for each fair value hierarchy level:

 

  

Level 3 Gains and Losses

 

The table below sets forth a summary of changes in the fair value of the Company’s Level 3 liabilities for the quarter ended March 31, 2017, in thousands.

 

 

The derivative asset and liability fair values reported in the consolidated balance sheets are as of the balance sheet date and subsequently change as a result of changes in commodity prices, market conditions and other factors. The Company typically has numerous hedge positions that span several time periods and often result in both derivative assets and liabilities with the same counterparty, which positions are all offset to a single derivative asset or liability in the consolidated balance sheets, including the deferred premiums associated with its hedge positions. The Company nets the fair values of its derivative assets and liabilities associated with derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract.

 

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

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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 $128.6 million as of March 31, 2017, 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.  

  

 

7. Oil and Gas Properties

A summary of oil and gas properties is as follows:

 

 

If pricing declines, the Company may have to record impairment of its oil and gas properties subsequent to March 31, 2017.     

 

 

8. Accrued Liabilities

The accrued liabilities consisted of the following:

 

 

9. Long-Term Debt

The long-term debt consisted of the following:

 

 

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Senior Secured Credit Facility

On July 28, 2015, LRAI closed a $500,000,000 Senior Secured Credit Facility (the “Senior Secured Credit Facility”) which replaced a $400,000,000 Wells Fargo-led syndicated facility (the “Previous Senior Secured Credit 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-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.  Effective as of November 23, 2016, the borrowing base was reduced from $120,000,000 to $112,000,000.  As of March 31, 2017 and December 31, 2016 (giving effect to the amended covenant ratio discussed below), LRAI was in compliance with all covenants including all financial ratios under the Senior Secured Credit Facility.  As of March 31, 2017 and December 31, 2016, $50,000,000 and $43,500,000 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 (4.12% at March 31, 2017).

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 selling, 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 the Previous Senior Secured Credit Facility and a 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

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facility was terminated upon repayment.  During 2016, LRAI repurchased approximately $68.2 million in aggregate principle amount of the 8.750% Senior Notes leaving a remaining balance of approximately $151.8 million.

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:

 

 

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 March 31, 2017 and December 31, 2016, the Company had approximately $1,000,000 and $1,200,000, 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 balance of these notes and warrants is reflected in the Company’s long-term debt – related parties and equity warrant liability – related parties on the face of the balance sheet.

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.

 

During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of its Class A voting common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance.  The warrants were adjusted to fair value at March 31, 2017 which resulted in an unrealized gain on warrants of approximately $2.3 million for the three months ended March 31, 2017. 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 $28.5 million.

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the offering of the Company’s Class A voting common stock that was completed on December 22, 2016 pursuant to a Registration Statement on Form S-1 (File No. 333-214265), which was declared effective on December 15, 2016 (the “2016 Common Stock Offering”).  Under the terms of its Securities Purchase Agreement, the Company has the right to repurchase $13.3 million of the $17.0 million outstanding Second Lien Notes at a price equal to 106% of par.

  

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10. Stock-Based Compensation

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 three months ended March 31, 2017, no stock options were issued or 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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Restricted Stock Units

In February 2017, the Company granted awards of restricted stock units (“RSUs”) covering 612,000 shares to certain of its employees.  The awards vest over a three-year period as follows:  40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the RSU’s will be fully vested on the third anniversary of issuance.  The Company determines the fair value of granted RSU’s based on the market price of the Class A voting common stock of the Company on the date of grant.  RSUs will be paid in Class A voting common stock or cash at the Company’s option after the vesting of the applicable RSU.  Compensation expense for granted RSUs is recognized over the vesting period.  

 

 

 

 

 

Stock Appreciation Rights

In February 2017, the Company granted awards of stock appreciation rights (“SARs”) covering 700,000 shares to certain of its employees and its non-employee directors.  The awards vest over a three-year period as follows:  40% on the first anniversary of issuance and 30% on each of the second and third anniversaries of issuance, such that the SAR’s will be fully vested on the third anniversary of issuance.  The SARs will expire five-years after the date of issuance.  The exercise price of the SAR is the fair market value of the Company’s Class A voting common stock on the date of the grant.  The SAR entitles the holder to receive from the Company upon exercise of the exercisable portion of the SAR an amount determined by multiplying the excess of the fair market value of one share on the date of exercise over the exercise price per share by the number of shares with respect to which the SAR is exercised.  SARs will be paid in cash or common stock at holder’s election once the SAR is vested, with the provision that the Company possesses sufficient liquidity to allow for cash settlement of the SAR.

 

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Stock-Based Compensation Expense

For the three-month periods ended March 31, 2017 and 2016, the Company recorded stock-based compensation expenses of approximately $178,000 and $95,000, respectively, related to stock options, restricted stock units and stock appreciation rights.  As of March 31, 2017, the total unrecognized stock-based compensation cost is approximately $5,195,000.

 

 

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 months ended March 31, 2016 as the Company reported losses from operations for the period.  Although the Company had net income from operations for the three months ended March 31, 2017, as the options and SARs 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 612,000 RSUs granted during the period are considered dilutive and are included in the diluted weighted average common shares outstanding for the three months ended March 31, 2017.  The 760,000 warrants granted during the second half of 2016 are considered dilutive and are included in the diluted weighted average common shares outstanding for the three months ended March 31, 2017.

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 month period ended March 31, 2016:

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Unaudited Earnings Per Share (After Reorganization)

 

 

12. Related Party Activities

LEUCADIA

On August 2, 2016, Lonestar Resources America, Inc. (“LRAI”) and the Company entered into a Securities Purchase Agreement (the “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 $49.9 million aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (“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”). During 2016, LRAI issued $25 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 500,000 shares of its Class A voting common stock to Juneau. In December 2016, LRAI repaid to Juneau $21 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.

In connection with entering into the Purchase Agreement, the Company also entered into a registration rights agreement and an equity commitment agreement, both dated as of August 2, 2016. Pursuant to the registration rights agreement, the Company has agreed to register for resale certain Class A voting common stock issued or issuable to Juneau and Leucadia, including those issuable upon exercise of the Warrants. Leucadia agreed, pursuant to the equity commitment agreement, to purchase a certain number of Class A voting common stock in case the Company elected to pursue an equity offering prior to December 31, 2016. Pursuant to the equity commitment agreement, Leucadia purchased 3,478,261 shares of Class A voting common stock (costing $20 million) through the 2016 Common Stock Offering, which closed on December 22, 2016. In connection with Leucadia’s equity commitment, the Company paid Leucadia on January 3, 2017 a $1 million fee. In the event Leucadia purchased not less than its 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 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. Leucadia has elected to take an observer position on the board of directors, with no voting rights.

 EF REALISATION

On October 26, 2016, the Company entered into a Board Representation Agreement (the “Board Representation Agreement”) with EF Realisation Company Limited (“EF Realisation”). Under the Board Representation Agreement, for as long as EF Realisation, together with its affiliates, beneficially owns 15% or more of the issued and outstanding shares of the Company’s Class A voting common stock, it has the right to nominate up to, but no more than, two directors to serve on the Board and for as long as EF Realisation, together with its affiliates, beneficially owns at least 10% but less than 15% of the Company’s issued and outstanding shares of Class A voting common stock, it has the right to nominate up to, but no more than, one director to serve on the Board.

On October 26, 2016, the Company entered into a Registration Rights Agreement with EF Realisation, pursuant to which the Company agreed to register for resale Class A voting common stock indirectly owned by EF Realisation. The Company has agreed to file a registration statement providing for the resale of Class A voting common stock held by EF Realisation no later than the earlier of (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 has also granted EF Realisation certain piggyback and demand registration rights.

OTHER RELATED PARTY TRANSACTIONS 

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

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approximately $25,000 per quarter.  The consulting arrangement terminated effective December 31, 2016.  At March 31, 2017 the Company had a payable of $100,000 to Butterfly Flaps, Ltd representing consultancy services provided through December 31, 2016.

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 $232,000 and $229,000 for the three months ended March 31, 2017 and 2016, respectively.

 

 

13. Subsequent Events

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

Purchase and Sale Agreement

On March 13, 2017 Eagleford Gas 8, LLC (“Buyer”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement with Modern Exploration, Inc. (“Seller”) whereby the Buyer obtained an undivided 33.5% working interest / 26.8% net revenue interest of Seller’s interest in six producing wells and each well’s respective oil and gas leases located in southern Gonzales County, Texas.  The total purchase price paid by Buyer was approximately $7,600,000.  Closing occurred on April 3, 2017, with the effective date of the acquisition being April 1, 2017.

 

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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 43,246 gross (36,069 net) acres in what we believe to be the formation’s crude oil and condensate windows, as of March 31, 2017. As of March 31, 2017, we also held approximately 44,084 gross (28,655 net) acres in the West Poplar area in Roosevelt County, Montana, where we are currently conducting resource evaluation. 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 March 31, 2017, we had no long lived assets located outside the United States.

First Quarter 2017 Operational Summary

 

Having lowered long-term debt by more than $100 million from its peak of $319.5 million, the Company jumpstarted its production, bringing online 5 gross/4.9 net wells in the first quarter of 2017.  Sequentially, Lonestar reported a 15% increase in net oil and gas production, increasing production to 5,266 Boe/d during the three months ended March 31, 2017 compared to 4,560 Boe/d during the three months ended December 31, 2016.   In the first quarter of 2017, 79% of the Company’s production was crude oil and NGLs.  

 

Recent Developments Regarding Lonestar Properties

 

Eagle Ford Shale Trend - Western Region

 

Asherton

 

In Dimmit County, no new wells were completed during the three months ended March 31, 2017.  The Asherton leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2017.  

 

Beall Ranch

 

In Dimmit County, no new wells were completed during the three months ended March 31, 2017.  The Beall Ranch leasehold is held by production, and Lonestar does not currently plan any drilling activity here in 2017.  

 

Burns Ranch Area

 

Lonestar holds 4,830 gross / 4,013 net acres in the Burns Ranch.  Lonestar has drilled 6 extended reach laterals in Burns Ranch, and has 20 gross/18.4 net laterals remaining in its inventory which average 8,200 lateral feet.  On January 5, 2017, Lonestar completed fracture stimulation 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.  Lonestar utilized BroadBand diverters on the #8H, #9H and #10H, which allowed Lonestar to set stage spacing at 300 foot increments, compared to 250-foot spacing on previous wells at Burns Ranch, reducing the number of fracture stages and associated costs while achieving a designed proppant concentration of up to 2,000 pounds per foot in two of these wells, the highest in the Company’s history.  

 

Lonestar is pleased to report continued excellent performance out of its three new wells drilled at Burns Ranch.  Lonestar is highly focused on maintaining lower Gas-Oil-Ratios (“GOR”) in our Generation 5 wells, as we believe that the rapid increase in GOR that we experienced in our Generation 3 wells impaired oil EUR’s. As a result, we have been more stringent in our choke management techniques on our Generation 4 and Generation 5 wells.  Lonestar is encouraged with the results of our Generation 5 wells thus far. At 45% pressure drawdown, our Generation 3 wells had recovered 28,250 barrels of oil.  By contrast, our Generation 5 wells have achieved over 50,000 barrels of oil recovery with 45% pressure drawdown, an improvement of 79%.  We believe this improvement to date is the result of the increased effectiveness of the Generation 5 well completions in contacting additional

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reservoir rock volume that allows for a more complex fracture volume in the same fracture half-length, resulting in better fracture and drainage efficiency.

 

Horned Frog

 

In southern La Salle County, no new wells were completed during the three months ended March 31, 2017.  Lonestar continues to expand its leasehold position in the Horned Frog area, having closed during the three months ended March 31, 2017 on previously announced transactions to consummate primary term lease acquisitions and a farm-in which expanded Lonestar’s leasehold position in the Horned Frog area by 1,426 gross / 657 net acres, for a total cost of $0.3 million. In addition, as of March 31, 2017 Lonestar commercially agreed to lease terms on an additional 414 net acres for $0.6 million within the same lease block that is anticipated to close in the second quarter of 2017. With these additions, Lonestar’s total position in the Horned Frog area will be at 5,828 gross / 4,642 net acres.  Our leasehold provides Lonestar with an inventory of a minimum of 24 extended reach laterals with lateral lengths 7,400 to 10,000 feet.  Lonestar currently plans to drill two wells in the Horned Frog in the second half of 2017.  

 

Eagle Ford Shale Trend - Central Region

 

Southern Gonzales County

 

After acquiring an additional 526 net acres contiguous to our Cyclone leasehold at a cost of $0.7 million during the first quarter of 2017, Lonestar had a total of 3,064 gross / 2,860 net acres on its Cyclone property as of March 31, 2017, which can accommodate a total 33 laterals with average lateral lengths exceeding 8,100 feet.  The Company plans to drill 4 extended reach laterals at Cyclone in the second quarter of 2017.  The Cyclone #4H has reached total depth of 19,136 feet, has been logged and cased.  The Cyclone #5H has reached total depth of 19,100 feet and is undergoing completion operations.  Fracture stimulation operations on the Cyclone #4H and #5H are scheduled to commence on May 29, 2017, with flowback operations anticipated in the late second quarter of 2017.  Lonestar has an 86.5% working interest (“WI”) in these wells.  Following completion of the Cyclone #5H, Lonestar plans to mobilize the rig to drill the Cyclone #26H and #27H, with planned total depths of 18,000 feet and anticipated perforated intervals of 9,000 feet.  Lonestar has a 100% WI in these wells. None of these locations had Proved reserves assigned to them as of December 31, 2016.

 

Pirate

 

In southwest Wilson County, Lonestar took advantage of an open frac slot with its vendor and improved crude oil pricing, and elected to complete the Pirate #M1H and Pirate #N1H wells, which were previously drilled-uncompleted (“DUC’s”). The wells were completed with an average perforated interval of 7,101 feet.  Lonestar holds a 100% WI / 76.4% net revenue interest (“NRI”) in these wells.  The wells were fracture-stimulated with an average proppant concentration of 1,450 pounds per foot over 23 stages per well, utilizing BroadBand diverters, which allowed us to fracture on 300-foot stage spacing.  The Pirate #M1H tested 311 bbl/d and 120 Mcf/d, or 331 Boe/d on a 28/64” choke.  The Pirate #N1H tested 482 bbl/d and 215 Mcf/d, or 518 Boe/d on a 24/64”.  After being place on jet pump,  the 25 days of production leading up to May 11, 2017, the two wells averaged 394 bbl/d and 210 Mcf/d, or 429 Boe/d.

 

Eagle Ford Shale Trend - Eastern Region

 

Brazos & Robertson Counties

 

In February, 2017, Lonestar took advantage of an open frac slot with its vendor and improved crude oil pricing, and elected to complete drilling operations on the Wildcat B# 1H well in Brazos County, Texas and cased the well to a total depth of 19,800 feet.  Lonestar owns a 50% working interest in the Wildcat #B1H well.  The well has been fracture stimulated with a total of 16,556,700 lbs of proppant over a perforated interval of 8,166 feet (2,028 pounds per foot) in 41 stages.  On May 9, 2017, Lonestar commenced flowback operations on the Wildcat B#1H well.  The well has been placed in preliminary flowback operations as Lonestar is awaiting the results of PVT analysis to determine optimum production methodology.  The Wildcat B1H is currently flowing back on an 18/64” choke, and with 1.8% of its load recovered, current wellhead production rates are 1,119 BOE per day with a flowing tubing pressure of 4,000 psi, consisting of 648 barrels of oil per day and 2,824 Mcf of natural gas per day, with

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crude oil gravity averaging 48.8^o API and BTU content of 1,332 for the gas stream.  After gas processing, current rates equate to sales volumes of 1,475 BOE per day, consisting of 648 barrels of oil per day (45%), 510 barrels of natural gas liquids (34%) and 1,881 Mcf per day of natural gas (21%).  While preliminary, the results of the Wildcat B1H are encouraging, as Lonestar has a sizable leasehold position in the Wildcat Area, and notably, has not booked any Proved reserves to the area.  Lonestar has 9,555 gross / 6,420 net acres in the Wildcat area, which holds 38 extended-reach drilling locations, based on 800-foot spacing.

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.

Results of operations for the three months ended March 31, 2017 compared to the three months ended March 31, 2016

Net Production

 

 

Production volumes during the three months ended March 31, 2017 were 5,266 Boe/d, a decrease of 20% from 6,553 Boe/d during the three months ended March 31, 2016. The decrease in our average daily production is primarily the result of two principal factors. First, the Company sold virtually all of its Conventional assets in the second half of 2016, which had contributed 599 Boe/d for the three months ended March 31, 2016.  Second, the Company did not place any new Eagle Ford Shale wells onstream in the second half of 2016, which led to natural production declines.  

The Company has reinstated its Eagle Ford Shale drilling and completion program, and placed 5.0 gross / 4.9 net wells onstream over the course of the three months ended March 31, 2017. Sequentially, Lonestar reported a 15% increase in net oil and gas production, increasing production to 5,266 Boe/d during the three months ended March 31, 2017 compared to 4,560 Boe/d during the three months ended December 31, 2016. For the three months ended March 31, 2017, approximately 62% of our production was crude oil, 17% was NGLs and 21% was natural gas.

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Average Sales Price

 

 

The average wellhead price for our production in the three months ended March 31, 2017 was $37.18 per Boe, a 98% increase compared to the average price in the comparable period in 2016. Reported wellhead realizations were driven higher by significant increases in both the crude oil and natural gas benchmark prices between the periods, as well as improvements in differentials to those benchmarks which we were successful in negotiating with our hydrocarbon purchasers.  In addition to the significant increases in benchmark prices, our crude oil hedge positions added $1.39 per barrel of oil sold or $0.86 per barrel of oil equivalent. By comparison, during the three months ended March 31, 2016, our crude oil hedge positions added $32.66 per barrel of oil sold, $17.01 per barrel of oil equivalent.

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Revenues

 

Wellhead revenues in the three months ended March 31, 2017 were $17.6 million, a 57% increase from $11.2 million from the comparable period in 2016. These increases in revenue were a result of a significant increase in benchmark prices. We also realized favorable crude oil hedge cash settlements, which added $0.4 million in gains on commodity derivatives for the three months ended March 31, 2017.

Costs and Expenses

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

 

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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, ad valorem, or severance taxes.

Our lease operating expenses decreased $1.4 million (-32%) in the three months ended March 31, 2017 to $3.0 million from $4.4 million in the comparable period in 2016.  On a unit-of-production basis, our lease operating expenses decreased 15% from $7.32 per Boe in the three months ended March 31, 2016 to $6.24 per Boe in the three months ended March 31, 2017.

Sequentially, we reduced lease operating expenses by 15%, or $0.5 million to $4.0 million in the three months ended March 31, 2017 from $4.5 million in the three months ended December 31, 2016.  On a unit of production basis, our lease operating expenses decreased 25% sequentially to $6.24 per Boe in the three months ended March 31, 2017 from $8.37 per Boe in the three months ended December 31, 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 in the three months ended March 31, 2017 were $1.0 million, an increase of $0.1 million (13%) to $0.9 million from the comparable period in 2016 primarily due to the  57% increase in wellhead revenues.

Rig Standby Expense

The Company did not incur rig standby expense for the three months ended March 31, 2017, compared to $0.3 million in the three months ended March 31, 2016.

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 in the three months ended March 31, 2017 was $12.1 million, a 20% decrease from $15.2 million from the comparable period in 2016 primarily due to a 20% decrease in net production. On a unit of production basis, DD&A increased 1% from $25.48 in the three months ended March 31, 2016 to $25.62 in the three months ended March 31, 2017.

Impairment of Oil and Gas Properties

 

During the three months ended March 31, 2017, the Company did not record any impairment charge, compared to an immaterial impairment charge of $23,000 during the three months ended March 31, 2016.  

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If pricing declines, the Company may have to record impairment of its oil and gas properties subsequent to March 31, 2017.

General and Administrative (G&A) Expenses

G&A expenses decreased 10% to $2.5 million in the three months ended March 31, 2017 from $2.8 million from the comparable period in 2016 due to $0.3 million of expenses associated to the re-domiciliation of the Company to the United States during 2016, which did not recur in 2017.

Interest Expense

Our interest expense in the three months ended March 31, 2017 was $5.0 million, a decrease of 18% from $6.1 million from the comparable period in 2016 due to a combination of the retirement of $68.2 million of 8.75% Senior Notes and reduced balances on our Senior Secured Credit Facility. On a unit of production basis, interest expense increased 3% from $10.27 in the three months ended March 31, 2016 to $10.62 in the three months ended March 31, 2017.

 

Gains (Losses) on Derivative Financial Instruments

In the three months ended March 31, 2017, we recognized a non-cash gain of $8.3 million on our commodity derivative contracts related to the change in mark-to-market value of our derivative contracts and a $0.4 million realized gain on settlement of our commodity derivative contracts during the quarter. Settlement of the crude oil hedge positions added $1.39 per barrel to crude oil price realization during the three months ended March 31, 2017.

Income Taxes

As a result of the net income before income tax of $4.7 million in the three months ended March 31, 2017 and net loss before income tax of $17.1 million in three months ended March 31, 2016, we recorded an income tax expense of $1.6 million in the 2017 period and an income tax benefit of $5.8 million in the 2016 period.

Net Income (Loss) Before Taxes

As a result of the $6.4 million (57%) increase in revenue caused by the increase in crude oil and natural gas benchmark prices, as well as an increase in gain on derivative of $7.0 million, we recorded a net income before income tax of $4.7 million in the three months ended March 31, 2017 compared to net loss before income tax of $17.1 million in the three months ended March 31, 2016.

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 $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. As circumstances warrant, we may access the capital markets and issue equity or debt from time to time on an opportunistic basis in a continued effort to optimize our balance sheet and to fund our operations and capital expenditures in the future, dependent upon market conditions and available pricing. Such uses of proceeds may include repayment of our debt, development or acquisition of additional acreage, and general corporate purposes. There

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can be no assurance that future funding transactions will be available on favorable terms, or at all, and we therefore cannot guarantee the outcome of any such transactions.

At March 31, 2017, we had $3.9 million in cash and cash equivalents and approximately $62 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.

 

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 $4.7 million from $17.7 million in the three months ended March 31, 2016 to $13.0 million in the three months ended March 31, 2017. This decrease is primarily due to a $5.5 million decrease in net operating assets and liabilities, a $9.1 million dollar decrease in settlements of derivative financial instruments, a $7.0 million increase in non-cash gain on derivative financial instruments, and a decrease in DD&A of $3.0 million, offset by a $14.4 million increase in net income, and a $7.5 million increase in deferred taxes during the three months ended March 31, 2017.

Net Cash Used In Investing Activities

Net cash used in investing activities increased $3.8 million from $16.8 million in the three months ended March 31, 2016 to $20.7 million in the three months ended March 31, 2017. This increase is primarily due to (i) a $4.5 million increase in the development of oil and gas properties and (ii) a $0.5 million decrease in the acquisition of oil and gas properties.

Net Cash Provided By Financing Activities

Net cash provided by financing activities increased $6.5 million from $1.0 million used during the three months ended March 31, 2016 to $5.5 million provided in the three months ended March 31, 2017. The increase was due to increased borrowings of $2.0 million, cost to issue equity of $1.0 million, and decreased payments on bank borrowings of $5.5 million in the three months ended March 31, 2017. 

 

 

 

 

 

 

 

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Hedging

The following table provides a summary of our derivative contracts as of March 31, 2017:

 

 

The above derivative contracts aggregate to 817,400 barrels or 2,970 barrels of oil per day for the remainder of 2017 and 912,500 barrels or 2,500 barrels of oil per day for 2018. Our 2017 derivative contracts consist of 2,000 Bbls/day swaps at a volume weighted average price of $53.17 and three-way collars covering 970 Bbls/d, 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. Our 2018 derivative contracts consist of 2,000 Bbls/day swaps at a volume weighted average price of $54.88 and two-way collars covering 500 Bbls/day with a price ceiling of $59.45.

The above natural gas derivative contract equates to 1,925,000 MMBtu or 7,000 MMBtu per day for 2017 at a fixed price of $3.36 per MMBtu.

Debt

As of March 31, 2017, we had an aggregate of $214.5 million of indebtedness, including $50.0 million drawn on our Senior Secured Credit Facility, $14.9 million ($17.0 million of principal less $2.1 million of unamortized discount) on our Second Lien Notes less debt issuance costs of $0.3 million, $151.8 million (less an unamortized discount of $1.5 million and debt issuance costs of  $0.8 million) on our 8.750% Senior Notes and $0.3 million of other long-term notes.

Senior Secured Credit Facility

As of March 31, 2017 LRAI had outstanding borrowings of approximately $50.0 million under the Senior Secured Credit Facility, which was subject to an average interest rate of approximately 4.12% and 2.75% during the three months ended March 31, 2017 and 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 March 31, 2017. The borrowing base under 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 as of May 19, 2016, the borrowing base was reduced to $120 million. Effective as of November 23, 2016, the borrowing base was reduced from $120 million to $112 million. Also, redeterminations are now scheduled semi-annually to occur during May and November of each year. The next borrowing base redetermination is scheduled for May 2017.

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.

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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.

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.

During 2016, LRAI issued $38.0 million in aggregate principal amount of Second Lien Notes and the Company issued Warrants to purchase 760,000 shares of its Class A voting common stock. The Company recorded an equity warrant liability of approximately $5.1 million which was the fair value amount at the date of issuance.  The warrants were adjusted to fair value at March 31, 2017 which resulted in an unrealized gain on warrants of approximately $2.3 million for the three months ended March 31, 2017. 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 $28.5 million.

In December 2016, LRAI repaid $21.0 million principal of the Second Lien Notes with proceeds from the 2016 Common Stock Offering.

Capital Expenditures

Historical capital expenditures

The table below summarizes our capital expenditures incurred for the three months ended March 31, 2017.  Future drilling in 2017 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 Annual Report on Form 10-K as reported and filed with the SEC on March 23, 2017 (our “2016 10-K”). As of March 31, 2017, there were no significant changes to any of our critical accounting policies and estimates.

 

 

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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 known and unknown risks, uncertainties, and other important factors, many of which are beyond our control. We intend such forward-looking statements to be covered by the safe harbor provisions for forward-looking statements contained in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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;

 

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

 

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

 

•         availability and terms of capital;

 

•         drilling, completion, and performance of wells;

 

•         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; 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 8 (Financial Statements and Supplementary Data) and elsewhere in our 2016 10-K, 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 to fund our operations;

 

•                                borrowing capacity under our credit facility;

 

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•                                general economic and business conditions;

 

•                                failure to realize expected value creation from property acquisitions;

 

•                               uncertainties about our ability to find, develop or acquire additional oil and natural gas resources;

 

•                                uncertainties with regards to our drilling schedules;

 

•                                risks related to expiration of leases on our undeveloped leasehold assets;

 

•                                our dependence upon several significant customers for the sale of most of our crude oil, natural gas and NGL production;

 

•                                counterparty credit risks;

 

•                                competitive within the crude oil and natural gas industry;

 

•                                technology risks;

 

•                                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;

 

•                                our ability to satisfy future cash obligations and environmental costs; and

 

•                                the other factors set forth under “Risk Factors” in Item 1A of Part I of our 2016 10-K.

 

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 March 31, 2017 from those disclosed in our 2016 10-K.

 

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

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Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2017.

 

Changes in Internal Controls

There was no change in our internal control over financial reporting during the quarter ended March 31, 2017 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 Item 1A of Part I of “Risk Factors” in our 2016 10-K.  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.  There have been no material changes to our risk factors affecting the Company since the filing of our 2016 10-K.

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

None. 

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

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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