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Table of Contents

As filed with the Securities and Exchange Commission on October 26, 2016

Registration No. 333-            

 

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Lonestar Resources US Inc.

(Exact name of Registrant as Specified in its Charter)

 

 

 

Delaware   1311   81-0874035

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

600 Bailey Avenue, Suite 200

Fort Worth, TX 76107

(817) 921-1889

(Address, including Zip Code, and Telephone Number, including Area Code, of Registrant’s Principal executive Offices)

 

 

Frank D. Bracken, III

Chief Executive Officer

Lonestar Resources US Inc.

600 Bailey Avenue, Suite 200

Fort Worth, TX 76107

(817) 921-1889

(Name, Address, including Zip Code, and Telephone Number, including Area Code, of Agent for Service)

 

 

Copies to:

 

J. Michael Chambers

David J. Miller

Latham & Watkins LLP

811 Main Street

Houston, Texas 77002

(713) 546-5400

 

Mark L. Jones

Allison Jones

Baker & Hostetler LLP

811 Main Street, Suite 1100

Houston, Texas 77002

(713) 751-1600

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ☐

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

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. (Check one):

 

Large accelerated filer      Accelerated filer  
Non-accelerated filer   ☐  (Do not check if a smaller reporting company)    Smaller reporting company  

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

 

Proposed

Maximum

Aggregate

Offering Price(1)(2)

 

Amount of

Registration Fee

Class A Common Stock, par value $0.001 per share

 

$50,000,000

  $5,795

 

 

(1) Includes shares of Class A Common Stock issuable upon exercise of the underwriters’ option to purchase additional shares of Class A Common Stock to cover over-allotments.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. We may not sell the securities described herein until the registration statement filed with the Securities and Exchange Commission is declared effective. This preliminary prospectus is not an offer to sell such securities, and it is not soliciting an offer to buy such securities in any state or jurisdiction where such offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED OCTOBER 26, 2016

            Shares

 

 

LOGO

 

Lonestar Resources US Inc.

Class A Common Stock

 

 

We are offering              shares of Class A common stock. Our Class A common stock is traded on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “LONE.” As of October 25, 2016, the last reported sales price of our Class A common stock was $9.70 per share.

In this offering, Leucadia National Corporation has agreed to purchase from the Underwriters              shares of Class A common stock at $        per share, which is the price per share paid by the public.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Prospectus Summary—Emerging Growth Company.”

 

 

Investing in our Class A common stock involves risks. See “Risk Factors” on page 20.

 

     Price to
Public
     Underwriting
Discounts and
Commissions
     Proceeds to
Issuer
 

Per Share

   $                    $                    $                

Total

   $         $         $     

Delivery of the shares of Class A common stock will be made on or about                     , 2016.

To the extent that the underwriters sell more than              shares of Class A common stock, the underwriters have the option to purchase up to an additional              shares from us to cover over-allotments at the public offering price less the underwriting discount and commissions.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

 

Seaport Global Securities    Johnson Rice & Company L.L.C.

The date of this prospectus is                     , 2016.


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     20   

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     45   

USE OF PROCEEDS

     47   

DIVIDEND POLICY

     48   

CAPITALIZATION

     49   

MARKET PRICE OF OUR CLASS A COMMON STOCK

     50   

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

     51   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     54   

BUSINESS

     79   

MANAGEMENT

     106   

EXECUTIVE COMPENSATION

     111   

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     118   

RECENT AND FORMATION TRANSACTIONS

     120   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     121   

DESCRIPTION OF CAPITAL STOCK

     123   

SHARES ELIGIBLE FOR FUTURE SALE

     126   

MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

     127   

UNDERWRITING

     131   

LEGAL MATTERS

     135   

EXPERTS

     135   

WHERE YOU CAN FIND MORE INFORMATION

     135   

INDEX TO FINANCIAL STATEMENTS

     F-1   

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or the information to which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of Class A common stock and seeking offers to buy shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

 

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Table of Contents

Until             (25 days after commencement of this offering), all dealers that effect transactions in our Class A common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

 

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Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply, a relationship with us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

 

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Table of Contents

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the information under the headings “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and the notes to those financial statements appearing elsewhere in this prospectus. Unless the context otherwise requires, references to “we,” “us,” “our” or the “Company” refer to (i) prior to July 5, 2016, the date of our reorganization, Lonestar Resources Limited (our “Predecessor”) and (ii) after July 5, 2016, Lonestar Resources US Inc. References to “LRAI” refer to Lonestar Resources America, Inc., our wholly owned subsidiary. References to “EF Realisation” refer to our majority stockholder, EF Realisation Company Limited, including its subsidiaries and affiliates who own shares of our Class A common stock.

This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus and in the “Glossary of Oil and Natural Gas Terms.”

Our Company

Overview

We are an independent oil and natural gas company, focused on the acquisition, development and production of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas, where we have accumulated approximately 40,271 gross (35,230 net) acres in what we believe to be the formation’s crude oil and condensate windows as of June 30, 2016.

Our primary operational focus is on our Eagle Ford Shale position in seven Texas counties. Our properties in the Eagle Ford Shale are divided into three distinct regions: Western Eagle Ford (comprised of Dimmit, La Salle and Frio Counties), Central Eagle Ford (comprised of Gonzales and Wilson Counties) and Eastern Eagle Ford (comprised of Brazos and Robertson Counties). As of June 30, 2016, we operated 100% of our Eagle Ford position and approximately 60% of our acreage was held by production, or HBP. We have identified 159 gross (143 net) horizontal drilling locations on our Eagle Ford Shale acreages. We also own 44,084 gross (28,655 net) undeveloped acres in the Bakken Three Forks formation in Roosevelt County, Montana, though we do not plan to make capital expenditures to develop this acreage in 2016.

We plan to invest substantially all of our 2016 capital budget for the horizontal development of our Eagle Ford Shale properties and have allocated between $35 million and $45 million to operate drilling and completion activities to develop these assets there. Our preliminary 2017 budget calls for us to spend between $62 million and $72 million to develop our Eagle Ford Shale properties of which up to $10 million is allocated for leasehold acquisition expenditures. We have historically grown our Eagle Ford leasehold position through acquisitions, organic leasing activities, farm-ins and other structures. We believe our management team’s extensive experience in the basin provides us with relationships and contacts that will provide us opportunities to grow our acreage footprint.

We seek to deploy advanced drilling, completion and production techniques across our unconventional acreage with a goal of minimizing completed well costs and maximizing per well hydrocarbon recoveries. Increasingly, we utilize 3-D seismic imaging to plan our lateral programs while utilizing log-based petrophysical analysis to optimize our drilling targets within distinct horizons within the Eagle Ford Shale section. We are also frequently drilling laterals in excess of 7,000 feet in an effort to maximize per-well recoveries. Further, we are utilizing thru-bit logging in our laterals to design non-geometric completions which allow for the use of diverters while increasing proppant concentrations in an effort to make our fracture stimulations more effective. Additionally, we employ active choke management to optimize pressure drawdowns in an effort to maximize liquid hydrocarbon recoveries.

 



 

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The following table presents summary data for each of our primary project areas as of June 30, 2016:

 

     Net
Acreage
     Average
Working
Interest
   

Identified

Drilling

Locations

(1)(2)(3)

    

Producing

Wells

    

Average

Daily

Production(4)

     Capex     Planned Wells
(Net)(2)(5)
 
          Gross      Net      Gross      Net      Boe/d      2016     2017     2016      2017  

Eagle Ford

                          

Western

     13,413         88     51         47         41         38         4,924         73     41 – 63     5.9         5.0 – 8.0   

Central

     12,211         96     76         66         19         15         735         9     24 – 46     0.8         3.0 – 6.0   

Eastern

     9,606         78     32         30         8         7.6         315         8     6     0.0         1.0   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Total

     35,230         87     159         143         68         60.6         5,974         90     93     6.7         12.0   

West Poplar

     28,655         65     —           —           —           —           —           —          —          —           —     
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

Total

     63,885         75     159         143         68         60.6         5,974         90     93     6.7         12.0   
  

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

    

 

 

 

 

(1) We identify these potential drilling locations based on our analysis of relevant geologic and engineering data. Our total identified drilling locations include 59 gross (54 net) locations that were associated with proved undeveloped reserves, or PUDs, as of June 30, 2016. The remaining drilling locations were not associated with proved reserves as of June 30, 2016, however, based on our analysis of our drilling results, the drilling results of offset operators and applicable geologic and engineering data, we believe locations are prospective for development.
(2) The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our adding additional proved reserves to our existing reserves. See “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Our identified drilling locations are subject to many uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.”
(3) We have estimated our drilling locations based on well spacing assumptions that we view as reasonable for the areas in which we operate and other criteria. Our identified drilling location count implies well spacing of (a) 500 feet in the crude oil window of our Western Eagle Ford region and 750 feet in the condensate window, with approximately 84% of these locations expected to be drilled with greater than 7,000 foot lateral lengths and approximately 98% expected to be drilled with greater than 5,000 foot lateral lengths and (b) between 500-750 feet depending on specific location in our Central and Eastern Eagle Ford regions, with well spacing with approximately 50% of these locations expected to be drilled with greater than 7,000 foot lateral lengths and approximately 99% of these locations expected to be drilled with greater than 5,000 foot lateral lengths. The ultimate spacing between wells may be less than these amounts, which would result in a higher location count, or greater than these amounts, which would result in a lower location count.
(4) Production for the six months ended June 30, 2016. Table excludes certain conventional assets that we agreed to sell in September 2016. Production associated with these assets averaged 590 Boe/d for the six months ended June 30, 2016.
(5) Planned Wells (Net) represents our optimal planned drilling results based on our currently budgeted capital expenditures for the remainder of 2016 and for 2017.

Our Eagle Ford Shale Properties

Our Eagle Ford Shale net production for the six months ended June 30, 2016 was 5,974 Boe/d, comprised of 3,338 Bbls/d of oil, 1,211 Bbls/d of NGLs and 8,548 Mcf/d of natural gas, from 68 gross (61 net) producing wells.

 



 

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As of December 31, 2015, according to our reserve report, our Eagle Ford Shale properties had proved reserves of 38.0 MMBoe, of which 76% is crude oil and NGLs and 29% is proved developed producing, or PDP. The PV-10 of our Eagle Ford proved reserves as of December 31, 2015 was $275.9 million using SEC pricing and $321.9 million using NYMEX strip pricing, and 50% of such PV-10 is PDP. See “Summary Historical Reserve and Operating Data.”

We have identified 159 gross (143 net) horizontal drilling locations on our acreage of which 61% are expected to be drilled using lateral lengths of or greater than 7,000 feet and 98% are expected to be drilled using lateral lengths of or greater than 5,000 feet.

Western Eagle Ford. As of June 30, 2016, our Western Eagle Ford region was comprised of 15,208 gross (13,413 net) acres in Dimmit, La Salle and Frio Counties. As of June 30, 2016, we operated 100% of this acreage. Approximately 90% of this net acreage is HBP.

As of December 31, 2015, according to our reserve report, single well gross estimated ultimate recoveries, or EURs, on our undeveloped locations range from 381 MBoe to 1,284 MBoe across our Western region wells, projected well costs currently range from $3.5 million to $5.8 million for wells with lateral lengths of 3,600 feet to 8,000 feet. In certain cases, we have the ability to extend lateral lengths beyond the lengths assumed in our 2015 reserve report. The most recent wells drilled in our Western Eagle Ford area had an average well cost of $4.1 million and average lateral length of 6,100 feet.

We plan on allocating approximately $17.8 million in the second half of 2016 and between $27.3 million to $42.3 million of our 2017 budget to our Western Eagle Ford acreage.

Central Eagle Ford. Our Central Eagle Ford region as of June 30, 2016 was comprised of 12,695 gross (12,211 net) acres in Wilson and Gonzales Counties. As of June 30, 2016, we operated 100% of this acreage. Approximately 44% of this net acreage was HBP.

As of December 31, 2015, according to our reserve report, single well gross EURs range from 309 MBoe to 475 MBoe across our Central region wells. Projected well costs range from $4.2 million to $5.1 million for wells with lateral lengths of 5,000 feet to 8,000 feet. The most recent wells drilled in our Central Eagle Ford area had an average well cost of $4.7 million and average lateral length of 6,700 feet. Based on our drilling experience and that of offset operators, we believe that success in the Central Eagle Ford area is related to a different set of factors than in other parts of the Eagle Ford Shale. The Eagle Ford Shale horizon in this area is thinner yet exhibits higher porosities, and is more prone to significant faulting than in our other leasehold positions. We employ 3-D seismic imaging to maximize the lateral’s interface with the Eagle Ford and avoid the Buda formation, which produces high rates of water locally. We also take care to design well paths so as to minimize intersecting large faults that may take the lateral well bore out of our target Eagle Ford zone.

We will not allocate any of our remaining 2016 capital budget to the development of our Central Eagle Ford acreage but we plan on allocating between $16.0 million to $31.0 million of our 2017 budget to this area.

Eastern Eagle Ford. Our Eastern Eagle Ford region as of June 30, 2016, was comprised of 12,367 gross (9,606 net) acres in Brazos and Robertson Counties. Approximately 38% of this net acreage is HBP. As of June 30, 2016, we operated 100% of this acreage. Our Eastern region includes 5,380 gross (4,651) net acres, which are located within the productive limits of the Aguila Vado Eagle Ford Shale Field, and an additional 6,987 gross (4,956) net acres that are under appraisal.

As of December 31, 2015, according to our reserve report, single well gross EURs range from 356 MBoe to 783 MBoe across our Eastern Eagle Ford region wells, and projected well costs range between $4.7 million and $6.5 million for wells with lateral lengths ranging from 5,000 feet to 7,000 feet. We believe current well costs are in the $5.1 to $6.4 million range.

 



 

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We plan on allocating approximately $3.2 million in the second half of 2016 and approximately $3.7 million of our 2017 budget to our Eastern Eagle Ford acreage.

Non-Core Properties

Conventional Texas Assets

In addition to our Eagle Ford Shale acreage, we have historically maintained conventional oil and natural gas properties located in 13 counties in Texas, including long-lived reserves in the Canyon, Delaware Sand, Hackberry, Caddo, Cockfield and Jackson formations. As of December 31, 2015, these properties contained approximately 2.2 MMBoe of estimated proved reserves, of which 79% is crude oil. For the six months ended June 30, 2016, production from our conventional assets was 590 Boe/d which represented 9% of our total net production for the year. Consistent with our plan to divest non-core assets and reduce our outstanding indebtedness, on June 15, 2016, we sold a portion of these assets for $2.2 million. On September 26, 2016, we entered into an agreement to sell the remaining assets for $14.0 million, and this transaction is scheduled to close, subject to customary closing conditions, on October 31, 2016.

Bakken Three Forks Assets

We also have 44,084 gross (28,655 net) undeveloped acres in the Poplar West area of the Bakken Three Forks formation in Roosevelt County, Montana. We expect to pursue a number of farm-in or other structured transactions to bring in a potential exploration partner in this area.

We currently do not plan on spending any of our remaining 2016 or preliminary 2017 budgets outside of the Eagle Ford.

Business Strategies

Our primary business objective is to increase reserves, production and cash flows at attractive rates of return on invested capital. We are focused on exploiting long-lived, unconventional oil, NGLs and natural gas reserves from the crude oil window of the Eagle Ford Shale. Key elements of our business strategy include:

 

  Develop our Eagle Ford Shale leasehold positions. We intend to develop our acreage position to maximize the value of our resource potential and generate returns for our stockholders through continuing to utilize best in class drilling and completion techniques at the lowest possible costs. Through the conversion of our resource base to developed reserves, we will seek to increase our production and cash flow, thereby increasing the value of our reserves. As of June 30, 2016, we were producing from 68 gross (61 net) Eagle Ford wells and we intend to deploy the large majority of our capital budget for 2016 and 2017 on the development of our Eagle Ford acreage.

 

 

Pursue strategic acquisitions, organic leasing and other structures to continue to develop and grow our production and leasehold position. We believe that we will be able to continue to identify and acquire additional acreage and producing assets in the Eagle Ford Shale. By leveraging our longstanding relationships in this area, we intend to expand our Eagle Ford shale acreage. We have increased our Eagle Ford Shale net acres by over eight times from 3,710 net acres in 2011 to 35,230 net acres as of June 30, 2016. We also intend to continue to find creative ways to fund our continued development while maintaining financial discipline and seeking to maximize returns from our projects. We have successfully used farm-ins and drilling commitments as means of adding prospective Eagle Ford Shale acreage by committing to drilling activity as opposed to deploying capital with lease acquisition costs. We also have a track record of executing on this strategy through our Joint Development Agreement with IOG Capital L.P., or IOG. This agreement allows for working interest level participation with IOG participating on a promoted

 



 

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basis for funding farm-ins. It is a wellbore only agreement that allows Lonestar to develop acreage or hold expiring acreage while maintaining some upside through a specified return hurdle earn-in and all of the upside associated with future development of offsetting wells.

 

  Leverage our extensive operational expertise and concentration of our operating areas to reduce costs and enhance returns. We are focused on continuously improving our operating measures. We intend to leverage the magnitude and concentration of our acreage within the Eagle Ford Shale in our operating areas, as well as our experience within our areas of operation to capture economies of scale, including by employing multiple-well pad drilling, and utilizing centralized production and fluid handling facilities. Our management and operating team has significant industry and operating experience, and it regularly evaluates our operating measures against those of other operators in our area in order to improve our performance and identify additional opportunities to optimize our drilling and completion techniques and make informed decisions about our capital expenditure program and drilling activity.

 

  Maintain operational control over our drilling and completion operations. We operate 100% of the Eagle Ford Shale wells in which we have a working interest and intend to maintain a high degree of operational control over substantially all of our producing locations. Moreover, we hold an average working interest of 87% in our Eagle Ford Shale leasehold. We believe this strategy allows us to manage the timing and levels of our development spending, while controlling the techniques used to drill and complete wells, as well as overall well costs and operating costs. We expect to operate the drilling and completion phase on approximately 100% of our identified drilling locations. Approximately 80% of our existing Eagle Ford net acreage that contains our Proved Reserves is HBP, and 60% of our existing Eagle Ford net acreage is HBP, and we anticipate that our current planned development program in 2016 and 2017 will be sufficient to maintain the majority of our acreage currently not HBP. We believe that continuing to exercise a high degree of control over our acreage position will provide us with flexibility to manage our drilling program and optimize our returns and profitability.

 

  Maintain and enhance financial liquidity and flexibility. We intend to use cash on hand and borrowings from our revolving credit facility, combined with our cash flow from operations, to continue executing a capital expenditure program that we believe will result in steady growth of production, cash flow and proved reserves. Upon completion of this offering and the use of proceeds therefrom we will have $        million in cash and $        million available under our $120 million revolving credit facility to execute on the remainder of our 2016 and our 2017 capital budgets. Furthermore, we intend to continue to employ a hedging strategy on our PDP production to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in oil, NGLs and natural gas prices. We regularly assess the futures markets for opportunities to enter into additional hedging contracts. Generally, we have entered into additional hedges when we believe that they are additive to our borrowing base and/or lock-in rates of return which exceed our hurdle rates. Based on our 2017 drilling plans, current NYMEX strip oil and gas prices and our current hedge positions, we expect cash flow from operations to cover 70% to 80% of our 2017 budget. Further, we have strived to enter into unique and strategically effective arrangements to reduce our outstanding indebtedness and improve our financial liquidity. See “Recent Developments.” We intend to continue to seek out such opportunity to improve our balance sheet and financial flexibility.

 

  Optimize our current position and maximize cost-saving opportunities in response to oil price declines. We have moderated our drilling activity plans for 2016 in response to oil price declines that began in late 2014, and our revised plan is to complete 9 gross (6.7 net) wells in 2016. We believe that we are in a good position to be flexible due to our financial position, a $100 million joint development agreement entered into with IOG in July 2015, the absence of material drilling obligations and strong operational capabilities. We estimate production will be between 6,000 to 6,300 Boe/d in 2016, including the impact from asset sales.

 



 

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Our Competitive Strengths

We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategy:

 

  Geographic focus in one of North America’s leading unconventional oil plays. We have assembled a leasehold position of approximately 35,230 net acres in the Eagle Ford Shale as of June 30, 2016. We believe this unconventional oil and natural gas formation has one of the higher rates of return among such formations in North America. In addition to leveraging our technical expertise in our project areas, our geographically-concentrated acreage position allows us to establish economies of scale with respect to drilling, production, operating and administrative costs. Based on our drilling and production results and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core operating areas in the Eagle Ford Shale where we have devoted almost all of our 2016 drilling capital budget.

 

  Experienced management team. Our top eight executives each average 30 years of industry experience. We have assembled what we believe to be a strong technical staff of geoscientists, field operations managers and engineers with significant experience drilling horizontal wells and with fracture stimulation of unconventional formations, which has resulted in reserve and production growth. In addition, our management team has extensive expertise and operational experience in the oil and natural gas industry with a proven track record of successfully negotiating, executing and integrating acquisitions. Members of our management team have previously held positions with major and large independent oil and natural gas companies.

 

  Demonstrated ability to increase acreage position and drive growth of oil production and reserves. We have increased our Eagle Ford Shale net acres by over eight times from 3,710 net acres in 2011 to 35,230 net acres as of June 30, 2016. We placed 16 gross (13 net) and 5 gross (4 net) Eagle Ford Shale wells onstream during 2015 and through June 30, 2016, respectively. We had a total of 68 gross (61 net) producing wells in the Eagle Ford, as of June 30, 2016. The resulting production rates achieved by this program increased Eagle Ford sales volumes by approximately 43% over 2014. Our average total production for 2015 was 6,407 Boe/d, of which 90% was from the Eagle Ford Shale. Moreover, between December 31, 2014 and December 31, 2015, our total proved reserves increased by approximately 30% from 31.0 MMBoe to 40.2 MMBoe, and our proved developed reserves increased by approximately 8% from 12.3 MMBoe to 13.3 MMBoe. Our three-year average reserve replacement ratio is approximately 400%, which we believe demonstrates our ability to grow reserves year over year. We believe the location and concentration of our project areas within the Eagle Ford provide us an opportunity to continue to increase production, lower costs and further delineate our proved reserves.

 

  Demonstrated ability to adapt and employ leading drilling and completion techniques. We are focused on enhancing our drilling, completion and production techniques to maximize recovery of hydrocarbons. Industry techniques with respect to drilling and completion have significantly evolved over the past several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of longer laterals and more tightly spaced fracture stimulation stages. We continuously evaluate industry results and methods and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques will continue to improve and evolve. We have demonstrated a track record of innovation and operational improvement through our partnership with Schlumberger, the Geo-Engineered Completion Alliance (“GECA”). This Alliance utilizes a variety of technologies intended to focus our wells in precise, optimal intervals of the Eagle Ford Shale and utilize analysis of advanced logs run through the laterals to assist in the design of non-geometric fracture stimulation stages, which in combination with diverters, are intended to stimulate a greater percentage of the lateral on a cost-effective basis.

 



 

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  Multi-year drilling inventory in existing and emerging resource plays. We have identified 159 gross (143 net) horizontal drilling locations on our Eagle Ford Shale acreage. As of June 30, 2016, these identified drilling locations included 59 gross (54 net) locations to which we have assigned proved undeveloped reserves. We have identified 9 gross (6.7 net) locations in the Eagle Ford Shale that we expect to drill in 2016, the completion of which would represent approximately 6% of our gross identified drilling locations in the Eagle Ford Shale at June 30, 2016. We believe our acreage is prospective for additional locations and plan to continue evaluating this acreage and monitoring industry activity in order to maximize our efficiency in developing this acreage. Furthermore, we are evaluating our acreage to identify and develop additional locations across our portfolio as we evaluate down-spacing in the Eagle Ford Shale and accessing other stratigraphic horizons that lie above and below the Eagle Ford Shale, such as the Austin Chalk, Buda, Georgetown, Woodbine and Wilcox formations. We believe our multi-year drilling inventory and exploration portfolio will provide near-term growth in our production and reserves and highlight the long-term resource potential across our asset base.

 

  Oil-weighted reserves and production. Our net proved reserves at December 31, 2015 were comprised of approximately 58.5% oil, and our net average daily production for the year ended December 31, 2015 and 2014 was comprised of 66% oil and 73% oil, respectively. Given the current commodity price environment and resulting disparity between oil and natural gas prices on a Boe basis, we believe our high percentage of oil reserves, compared to our overall reserve base, is a key strength.

 

  Low field operating expenses. Even in light of recent declines in oil prices, we expect to generate sufficient cash margins on the operation of our Eagle Ford Shale acreage due to our low cash operating costs. For the six months ended June 30, 2016, our total field operating expenses (including lease operating expenses and production taxes) totaled $9.12 per Boe around our project areas. We believe there are relatively low geologic risks and repeatable drilling opportunities across our core operating areas in the Eagle Ford Shale, where we have devoted almost all of our 2016 drilling capital budget.

 

  Hedging position. As of June 30, 2016, we had in place hedges covering approximately 2,692 bbls/d for calendar year 2016 at an average price of approximately $69.57 per bbl. We believe that these hedges help insulate us from oil price volatility on approximately 85% of our expected crude oil production in 2016. We also 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, but 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.

Recent Events

Deleveraging Initiative

Securities Purchase Agreement

On August 2, 2016, 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 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.

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 LRAI’s $500,000,000 Senior Secured Credit Facility, entered into on July 28, 2015 (our “revolving credit facility”).

 



 

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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 common stock. 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 “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 and approximately $2.0 million in Class A common stock. Net of related fees, such repurchases resulted in a gain on debt extinguishment of approximately $29.8 million.

Equity Commitment

In addition, pursuant to the Securities Purchase Agreement with Juneau and Leucadia, in the event that we elect to pursue an equity offering prior to December 31, 2016, Leucadia has agreed to purchase the number of shares of Class A 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 (the “Outside Date”). Leucadia’s agreement to purchase the Class A 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 will 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.

In the event Leucadia purchases not less than their commitment amount, we have 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 common stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in such offering.

Purchase and Sale Agreement

On August 2, 2016, the Company entered into a purchase and sale agreement with Juneau, whereby we obtained an undivided 50% of Juneau’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 was $5,500,000 payable in 500,227 shares of our Class A common stock.

Repurchase Facilitation Agreement

Effective September 29, 2016, we entered into an Amended and Restated Facilitation Agreement (the “Facilitation Agreement”) with Seaport Global Securities LLC, a Delaware limited liability company (“Seaport Global”), pursuant to which Seaport Global has agreed to provide us with financing from time to time in connection with the repurchase of Notes, to be acquired by Seaport Global on our behalf in one or more open market purchases. We anticipate that Seaport Global will receive a cash payment of $2,166,486 at the time of the closing of this offering as a repayment for principal and interest in connection with the repurchase of Notes under the Facilitation Agreement. To the extent we are unable to complete this offering, we anticipate issuing to Seaport Global shares of our Class A common stock in lieu of such cash payment.

Non-Core Asset Sale

We recently sold our non-core legacy assets including proved producing conventional properties in Texas. During June and September 2016 we entered into agreements to sell these assets for a total of $16.2 million.

 



 

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Formation Transactions

Lonestar Resources US Inc. was incorporated Delaware in December 2015 for purposes of effecting our corporate reorganization, which was completed in July 5, 2016 (the “Reorganization”), pursuant to a Scheme Implementation Agreement (the “Scheme”), dated December 28, 2015, between the Company and Lonestar Resources Limited (our “Predecessor”), an Australian company and our former parent 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 Company 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 common stock for every two ordinary shares of our Predecessor such shareholder held.

In connection with the Reorganization, we filed a registration statement on Form 10 (“Form 10”) to register our Class A common stock pursuant to Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Following the effectiveness of the registration statement and in connection with the completion of the Reorganization, the ordinary shares of our Predecessor were delisted from the ASX, and our Class A common stock was listed on the NASDAQ Global Select market (“NASDAQ”).

 



 

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Organizational Structure

The following diagram indicates our simplified ownership structure immediately following this offering (assuming the option to purchase additional shares is not exercise):

 

 

LOGO

 



 

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Risk Factors

Investing in our Class A common stock involves risks that include the speculative nature of oil and natural gas development and production, competition, volatile oil, natural gas and NGL prices and other material factors. You should read carefully the section of this prospectus entitled “Risk Factors” for an explanation of these risks before investing in our Class A common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our Class A common stock and a loss of all or part of your investment:

 

  Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

 

    Our future cash flows and results of operations are highly dependent on our ability to find, develop or acquire additional oil and natural gas reserves.

 

    Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity.

 

    Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities and substantial losses, which may not be fully covered by our insurance.

 

    Development of our estimated proved undeveloped reserves, or PUDs, may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

 

    Our producing properties are located primarily in the Eagle Ford Shale of South Texas, making us vulnerable to risks associated with operating in one geographic area.

 

    Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the actual quantities and present value of our reserves.

 

    We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGLs production. The loss of one or more of these customers could adversely affect our revenues in the short term.

 

    Our ability to manage growth will have an impact on our business, financial condition and results of operations.

 

    We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

 

    We are a “controlled company” within the meaning of NASDAQ listing standards and, as a result, qualify for, and rely on, exemptions from certain corporate governance requirements. You will not have the same protections afforded to stockholders of companies that are subject to such requirements.

Emerging Growth Company

As a company with less than $1.0 billion in revenue during our last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). An emerging growth company may avail itself of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. For example, we intend to rely on an exemption from the auditor attestation requirements of Section 404 of the Sarbanes Oxley Act of 2002 (the “Sarbanes Oxley Act”) relating to internal control over financial reporting, and we will not provide such an attestation from our

 



 

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auditors. In addition, we may also take advantage of certain other exemptions available under the JOBS Act, including an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies, an exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm rotation or a supplement to the auditors’ report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding advisory “say-on-pay” votes on executive compensation and stockholder advisory votes on golden parachute compensation not previously approved.

We will remain an emerging growth company until the earliest of the following:

 

    the end of the first fiscal year in which the market value of our Class A common stock held by non-affiliates exceeds $700 million as of the end of the second quarter of such fiscal year;

 

    the end of the first fiscal year in which we have total annual gross revenues of at least $1 billion; or

 

    the date on which we have issued more than $1 billion in non-convertible debt securities in any rolling three year period.

Once we cease to be an emerging growth company, we will not be entitled to the exemptions provided for by the JOBS Act.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 600 Bailey Avenue, Suite 200, Fort Worth, Texas 76107, and our telephone number at that address is (817) 921-1889.

Our website address is www.lonestarresources.com. We make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

 



 

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The Offering

 

Issuer

Lonestar Resources US, Inc.

 

Common stock offered by us

            shares of our Class A common stock.

 

  In this offering, Leucadia National Corporation has agreed to purchase from the Underwriters             shares of Class A common stock at $         per share, which is the price per share paid by the public.

 

Common stock outstanding after this offering

            shares of Class A common stock.

 

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to an aggregate of             additional shares of our Class A common stock to cover over-allotments, to the extent the underwriters sell more than                 shares of Class A common stock in this offering.

 

Use of proceeds

We expect to receive approximately $         million of net proceeds from the offering, after deducting underwriting discounts and estimated offering expenses (or approximately $         million if the underwriters’ option to purchase additional shares is exercised in full.

 

  We intend to use a portion of the net proceeds from this offering to repay Seaport Global in connection with the Facilitation Agreement, reduce amounts drawn under our revolving credit facility and for general corporate purposes. Please read “Use of Proceeds.”

 

Dividend policy

We do not anticipate paying any cash dividends on our Class A common stock. In addition, our revolving credit facility places certain restrictions on our ability to pay cash dividends. Please read “Dividend Policy.”

 

Listing and trading symbol

Our Class A common stock is traded on NASDAQ under the symbol “LONE.”

 

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A common stock.

 



 

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Summary Historical Financial Data

The following table presents summary historical consolidated financial data of our Predecessor as of the dates and for the periods indicated. The summary historical consolidated financial data as of and for the years ended December 31, 2015 and 2014 are derived from the audited financial statements appearing elsewhere in this prospectus. The summary historical consolidated interim financial data as of June 30, 2016 and for the six months ended June 30, 2016 and 2015 are derived from the unaudited interim financial statements appearing elsewhere in this prospectus. The unaudited consolidated financial statements have been prepared on the same basis as our audited financial statements and, in our opinion, include all adjustments, consisting of normal recurring adjustments, that are considered necessary for a fair presentation of the financial position, results of operations and cash flows for such periods. Historical results are not necessarily indicative of future results.

The summary historical consolidated data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes and other financial data included elsewhere in this prospectus.

 

     For the Six Months Ended
June 30,
    For the Twelve Months Ended
December 31,
 

($ in thousands except shares and per share amounts)

   2016     2015         2015                 2014          
     (unaudited)     (unaudited)              

Statement of Operations Data:

        

Revenues

        

Oil sales

   $ 24,119      $ 37,559      $ 70,739      $ 104,233   

Natural gas sales

     3,257        2,479        6,823        7,590   

Natural gas liquid sales

     1,623        1,122        1,928        3,804   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

     28,999        41,160        79,490        115,627   

Operating expenses

        

Lease operating and gas gathering

     8,758        8,050        17,190        16,632   

Production, ad valorem and severance taxes

     2,139        2,827        4,982        7,123   

Rig Standby expense

     1,897        —          663        —     

Depletion, depreciation and amortization

     27,636        26,039        58,828        40,522   

Accretion of asset retirement obligations

     107        106        214        201   

(Gain) loss on sale of oil and gas properties

     (1,531     625        —          —     

Impairment of oil and gas properties

     1,938        —          28,623        5,478   

Stock-based compensation

     191        866        2,585        1,938   

General and administrative

     5,631        4,696        10,825        8,913   

Other (income) expense

     1,047        35        —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     47,813        43,244        123,910        80,807   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     (18,814     (2,084     (44,420     34,820   

Other income (expense)

        

Interest expense

     (12,299     (11,819     (24,577     (19,949

Gains (losses) on commodity derivatives

     (5,069     (525     27,609        43,972   

Other income (expense)

     —          —          1,066        55   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     (17,368     (12,344     1,966        24,078   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before taxes

     (36,182     (14,428     (42,454     58,898   

Income tax benefit (expense)

     12,040        5,350        15,121        (22,432
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (24,142   $ (9,078   $ (27,333   $ 36,466   
  

 

 

   

 

 

   

 

 

   

 

 

 

 



 

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     For the Six Months Ended
June 30,
    For the Twelve Months Ended
December 31,
 

($ in thousands except shares and per share amounts)

   2016     2015         2015                 2014          
     (unaudited)     (unaudited)              

Pro forma weighted average number of common shares outstanding

        

Basic(1)

     7,522,025        7,522,025        7,522,025        7,330,602   

Diluted(1)

     7,522,025        7,522,025        7,522,025        7,534,805   

Pro forma net earnings per common share

        

Basic(1)

   $ (3.21   $ (1.21   $ (3.63   $ 4.97   

Diluted(1)

   $ (3.21   $ (1.21   $ (3.63   $ 4.84   

Balance Sheet Data:

        

Cash and cash equivalents

   $ 5,147      $ 3,596      $ 4,321      $ 9,992   

Oil and gas properties

     478,363        494,125        488,100        481,079   

Total assets

     509,314        555,450        541,521        559,069   

Long-term debt

     315,197        274,626        303,711        264,614   

Stockholders’ equity

     158,999        207,423        182,966        207,702   

 

(1) Gives effect to the Reorganization and the 50:1 share consolidation that our Predecessor effected in May 2015 as if they had occurred for the period indicated.

Non-GAAP Financial Measure

Adjusted EBITDAX

Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock-based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense) and unrealized (gain) loss on derivative financial instruments.

Management believes Adjusted EBITDAX provides useful information to investors because it assists investors in the evaluation of the Company’s operating performance and comparison of the results of the Company’s operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at Adjusted EBITDAX to eliminate the impact of certain non-cash items or because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. The Company’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

 



 

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The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated.

 

    

Six Months Ended

June 30,

    Twelve Months Ended
December 31,
 

($ in thousands)

   2016     2015         2015             2014      
     (unaudited)     (unaudited)              

Net Income (Loss)

   $ (24,142   $ (9,078   $ (27,333   $ 36,466   

Income tax expense (benefit)

     (12,040     (5,350     (15,121     22,432   

Interest expense

     12,299        11,819        24,577        19,949   

Exploration expense

     1        51        222        96   

Depletion, depreciation, amortization and accretion

     27,743        26,145        59,042        40,723   
  

 

 

   

 

 

   

 

 

   

 

 

 

EBITDAX

     3,861        23,587        41,387        119,666   

Rig Standby Expense

     1,897        —          663        —     

Non-recurring costs

     645        19        1,226        1,700   

Stock based compensation

     191        865        2,585        1,938   

(Gain) loss on sale of properties

     (1,531     625        —          —     

Impairment of oil and gas properties

     1,938        —          28,623        5,478   

Unrealized (gain) loss on derivative financial instruments

     21,605        18,677        8,728        (42,756

Other income (expense)

     1,047        34        1,066        (55
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX

   $ 29,653      $ 43,807      $ 84,278      $ 85,971   

 



 

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Summary Historical Reserve and Operating Data

The following table presents estimated net proved oil, NGLs and natural gas reserves attributable to our properties and the Standardized Measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2015, 2014 and 2013. We employ a technical staff of engineers and geoscientists that perform technical analysis of each producing well and undeveloped location. The staff uses industry accepted practices to estimate, with reasonable certainty, the economically producible oil and gas reserves. The practices for estimating hydrocarbons in place include, but are not limited to, mapping, seismic interpretation, core analysis, log analysis, mechanical properties of formations, thermal maturity, well testing and flowing bottom hole pressure analysis. We employ an independent petroleum engineer to estimate 100% of our proved reserves. The data below is based on our reserve report prepared by W.D. Von Gonten & Co. for our Eagle Ford Shale properties and on the reserve report prepared by LaRoche Petroleum Consultants, Ltd. for our conventional properties in the State of Texas. The Standardized Measure and PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. We do not currently have proved reserves on our acreage in the West Poplar Area of the Bakken-Three Forks trend in Montana. Reserves reported below for our Eagle Ford shale assets are owned by our subsidiary Lonestar Resources, Inc., and reserves reported below for our conventional assets are owned by our subsidiary Amadeus Petroleum, Inc.

 

     NYMEX(1)      SEC (2)  
     As of December 31,  
     2015      2015      2014      2013  

Estimated Proved Reserves(2)

           

Eagle Ford Shale:

           

Oil (MBbls)

     22,980         21,789         20,861         10,490   

NGLs (MBbls)

     7,453         7,154         3,044         1,841   

Natural Gas (MMcf)

     56,613         54,395         21,528         12,651   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford Shale (MBoe)(3)

     39,869         38,009         27,493         14,440   
  

 

 

    

 

 

    

 

 

    

 

 

 

Conventional Assets:

           

Oil (MBbls)

     2,355         1,727         2,749         2,994   

NGLs (MBbls)

     40         35         —           —     

Natural Gas (MMcf)

     3,867         2,586         4,441         4,722   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Conventional Assets (MBoe)(3)

     3,039         2,193         3,490         3,781   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Estimated Proved Reserves (MBoe)(3)

     42,907         40,201         30,983         18,221   
  

 

 

    

 

 

    

 

 

    

 

 

 

Estimated Proved Developed Reserves

           

Eagle Ford Shale:

           

Oil (MBbls)

     7,231         6,596         7,044         3,801   

NGLs (MBbls)

     2,159         2,020         1,212         639   

Natural Gas (MMcf)

     15,944         14,948         8,360         4,355   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford Shale (MBoe)(3)

     12,047         11,107         9,649         5,166   
  

 

 

    

 

 

    

 

 

    

 

 

 

Conventional Assets:

           

Oil (MBbls)

     1,957         1,727         2,140         2,394   

NGLs (MBbls)

     40         35         —           —     

Natural Gas (MMcf)

     3,357         2,586         3,631         3,933   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Conventional Assets (MBoe)(3)

     2,557         2,193         2,745         3,049   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Estimated Proved Developed Reserves (MBoe)(3)

     14,604         13,300         12,395         8,215   
  

 

 

    

 

 

    

 

 

    

 

 

 

 



 

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     NYMEX(1)      SEC (2)  
     As of December 31,  
     2015      2015      2014      2013  

Estimated Proved Undeveloped Reserves

           

Eagle Ford Shale:

           

Oil (MBbls)

     15,749         15,193         13,817         6,688   

NGLs (MBbls)

     5,294         5,134         1,833         1,203   

Natural Gas (MMcf)

     40,669         39,447         13,167         8,296   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford Shale (MBoe)(3)

     27,822         26,902         17,844         9,274   
  

 

 

    

 

 

    

 

 

    

 

 

 

Conventional Assets:

           

Oil (MBbls)

     397         —           609         600   

NGLs (MBbls)

     —           —           —           —     

Natural Gas (MMcf)

     510         —           810         789   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Conventional Assets (MBoe)(3)

     482         —           744         731   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Estimated Proved Undeveloped Reserves (MBoe)(3)

     28,304         26,902         18,588         10,005   
  

 

 

    

 

 

    

 

 

    

 

 

 

PV-10 (millions)(4)

   $ 344.2       $ 294.3       $ 705.8       $ 418.7   

Standardized Measure (millions)(5)

     —         $ 268.4       $ 549.0       $ 302.8   

Oil and Gas Prices Used(2):

           

Oil—NYMEX-WTI per Bbl

     N/A         50.28       $ 94.99       $ 96.94   

Natural Gas—NYMEX-Henry Hub per MMBtu

     N/A         2.59       $ 4.35       $ 3.67   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Our estimated net proved NYMEX reserves were prepared on the same basis as our SEC reserves, except for the use of pricing based on closing monthly futures prices as reported on the NYMEX for oil and natural gas on December 31, 2015 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Prices were in each case adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

Our NYMEX reserves were determined using index prices for oil and natural gas, without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our NYMEX reserves were $ 40.45/Bbl for oil for 2016, $46.06 for 2017, $49.36 for 2018, $51.96 for 2019, $53.64 for 2020, $54.66 for 2021, $55.24 for 2022, $55.67 for 2023, and escalated 3% thereafter and $2.49/MMBtu for natural gas for 2016, $2.79 for 2017, $2.91 for 2018, $3.03 for 2019, $3.26 for 2020, $3.31 for 2021, $3.46 for 2022, $3.61 for 2023 and escalated 3% thereafter. NGLs pricing used in determining our NYMEX reserves were approximately 30% of future crude oil prices.

We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. NYMEX futures prices are not necessarily a projection of future oil and natural gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves.

 

(2)

Our estimated net proved reserves and related Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The prices are based on the average prices during the 12-month period prior to the ending date of the period covered, determined as the unweighted arithmetic average of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual

 



 

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  arrangements, and are adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead.
(3) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.
(4) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes.
(5) Standardized Measure is calculated in accordance with Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities—Oil and Gas.

The data in the table above represent estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure amounts shown above should not be construed as the current market value of our estimated oil, NGLs and natural gas reserves. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

 



 

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RISK FACTORS

An investment in our Class A common stock involves significant risks. You should carefully consider the risks described below and the other information in this document before you decide to invest in our Class A common stock. If any of the following risks actually occurs, our business, prospects, financial condition and results of operations could be materially affected, the trading price of our Class A common stock could decline and you could lose all or part of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil, natural gas and NGL prices are volatile. A substantial or extended decline in the price of these commodities may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, profitability, liquidity, ability to access capital and future growth prospects are highly dependent on the prices we receive for our oil, natural gas and NGLs. The prices of these commodities are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas and NGLs have been volatile, and this volatility may continue in the future. The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

 

    worldwide and regional economic and political conditions;

 

    the domestic and global supply of, and demand for, oil, natural gas and NGLs;

 

    the cost of exploring for, developing, producing and marketing oil, natural gas and NGLs;

 

    the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities;

 

    the price and quantity of imports of foreign oil, natural gas and NGLs;

 

    the level of global oil, natural gas and NGL exploration and production;

 

    the level of global oil, natural gas and NGL inventories;

 

    weather conditions and natural disasters;

 

    domestic and foreign governmental laws, regulations and taxes;

 

    volatile trading patterns in commodities futures markets;

 

    price and availability of competitors’ supplies of oil, natural gas and NGLs;

 

    the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and the ability of OPEC and other producing nations to agree to and maintain production levels;

 

    technological advances affecting energy consumption; and

 

    the price and availability of alternative fuels.

Further, oil, natural gas and NGL prices do not necessarily fluctuate in direct relationship to each other. Because approximately 60% of our estimated proved reserves as of December 31, 2015 was attributed to oil, our financial results are more sensitive to movements in oil prices.

As of June 30, 2016, we had commodity price hedging agreements on approximately 85% of our expected production for 2016 or 2,692 bbls/d at an average swap price of $69.57 per bbl. To the extent we are unhedged, we have significant exposure to adverse changes in the prices of oil and natural gas that could materially and adversely affect our business and results of operations.

 

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The decline in the SEC mandated oil price for use in PV-10 calculations from $94.99 per bbl as of December 31, 2014 to $50.28 per bbl as of December 31, 2015 has had a material reduction in the PV-10 valuation of our proved reserves and may continue if oil and natural gas prices remain lower. We believe that PV-10 is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that PV-10 is widely used by securities analysts and investors when evaluating oil and gas companies.

WTI oil prices have declined from over $100 per bbl in September 2014 to $47.72 per bbl at September 30, 2016. Such a decline in oil price, if sustained, will have a material impact on our annual revenues and has caused us to take actions to reduce the costs of drilling and our operations. For example, we have moderated our 2016 drilling plan by reducing the number of wells planned for 2016, with an expected capital budget of between $35 million and $45 million, in order to ensure our drilling budget is broadly matched by our operating cash flows and the availability of capital under our financing arrangements.

Prolonged further sustained declines in oil, natural gas or NGL prices may act to reduce our cash flows further and adversely affect our financial condition. In the event of further sustained declines, our liquidity could be reduced, our access to equity or long-term debt might be restricted, and our ability to meet our capital expenditure obligations and financial commitments might be adversely affected. We may choose to defer drilling activity and/or production from existing wells for a number of reasons, including the following:

 

    drilling activity is sanctioned on the expectation of matching the drilling budget with operating cash flows and securing reasonable rates of returns based on the then prevailing oil, natural gas and NGL prices; if those prices decline and operating cash flows are reduced, there is a risk that drilling may be curtailed or postponed; and

 

    operating costs on our Eagle Ford properties are so low that production from these properties would likely continue to contribute to cash flows, but we may choose to defer production in the event that we consider there may be greater value in producing later.

Furthermore, prolonged sustained further declines in oil, natural gas or NGL prices may reduce the amount of oil, natural gas and NGLs we can produce economically and negatively impact the value of our estimated oil, natural gas and NGL reserves, the carrying value of our oil, natural gas and NGL reserves, the PV-10 valuations of our oil, natural gas and NGL reserves, and the standardized measure relating to oil, natural gas and NGL reserves.

Our future cash flows and results of operations are highly dependent on our ability to find, develop or acquire additional oil and natural gas resources.

Our business strategy is to generate profit through the acquisition, exploration, development and production of crude oil and natural gas reserves. Our future success therefore depends on our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable. Our proved reserves generally decline when produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves or both. We may not be able to find, develop or acquire additional reserves on an economically viable basis. Furthermore, if crude oil and natural gas prices increase, the cost of finding, developing or acquiring additional reserves could also increase.

Drilling for and producing oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Exploration and development activities involve numerous risks beyond our control, including the risk that no commercially productive oil or natural gas reservoirs will be discovered and that drilling will not result in commercially viable oil or natural gas production. In addition, the future cost and timing of drilling, completing and operating wells is often uncertain. Drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

 

    lack of prospective acreage available on acceptable terms;

 

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    unexpected or adverse drilling conditions;

 

    elevated pressure or irregularities in geologic formations;

 

    equipment failures or accidents;

 

    adverse weather conditions;

 

    title problems;

 

    limited availability of financing upon acceptable terms;

 

    limitations in the market for oil, gas and NGLs;

 

    reductions in oil, NGLs and natural gas prices;

 

    compliance with governmental requirements, laws and regulations; and

 

    shortages or delays in the availability of drilling rigs, equipment and personnel.

Even if our exploitation, development and drilling efforts are successful, our wells, once completed, may not produce reserves of crude oil, NGLs or natural gas that are economically viable or that meet our prior estimates of economically recoverable reserves. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially impact our operations and financial position by reducing our available cash and liquidity. In addition, the potential for production decline rates for our wells could be greater than we expect. Because of the risks and uncertainties inherent to our businesses, our future drilling results may not be comparable to our historical results.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves with resulting adverse effects on our cash flow and liquidity.

The oil and natural gas industry is capital intensive. We currently make, and expect to continue to make, substantial capital expenditures for the acquisition, development and exploration of oil, natural gas and NGL reserves. We currently expect to allocate between $35 million and $45 million under our 2016 capital program to drilling and completing 9 gross (6.7 net) wells across our properties in the Eagle Ford Shale. We expect to fund our 2016 capital expenditures with cash generated by operations, our undrawn capacity under our revolving credit facility and funding available under our Joint Development Agreement with IOG.

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, crude oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital are subject to a number of factors, including:

 

    our proved reserves;

 

    the amount of crude oil, natural gas and NGLs we are able to produce from existing wells;

 

    the prices at which our crude oil, natural gas and NGLs are sold;

 

    the costs at which our crude oil, natural gas and NGLs are extracted;

 

    global credit and securities markets;

 

    the ability and willingness of lenders and investors to provide capital and the cost of the capital; and

 

    our ability to acquire, locate and produce new reserves and the cost of such reserves.

 

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If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower crude oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, or we are unable to secure funding under our Joint Development Agreement with IOG, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. For a period of 90 days following the date of this prospectus, we will not be able to sell any shares of our Class A common stock, whether pursuant to a private or public offering, without the prior written consent of Seaport Global Securities, LLC. See “Underwriting” for more information. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually on May 1 and November 1 of each year. The borrowing base depends on, among other things, our lenders’ evaluation of our oil and natural gas reserves. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. Effective May 19, 2016, we received notification that the borrowing base for our revolving credit facility was reduced to $120 million. Our next scheduled borrowing base redetermination is scheduled for November 1, 2016.

In the future, we may not have access to adequate funding under our revolving credit facility as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of our lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover any defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans or make required repayments under our revolving credit facility, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities and substantial losses, which may not be fully covered by our insurance.

The oil and natural gas business involves significant operating hazards and risks such as:

 

    well blowouts;

 

    mechanical failures;

 

    fires and explosions;

 

    pipe or cement failures and casing collapses, which could release natural gas, oil, drilling fluids or hydraulic fracturing fluids;

 

    uncontrollable flows of oil, natural gas or well fluids;

 

    earthquakes and natural disasters;

 

    geologic formations with abnormal pressures;

 

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    handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;

 

    pipeline ruptures or spills;

 

    releases of toxic gases; and

 

    other environmental hazards and risks.

Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that our management believes to be prudent. However, we are not insured against all operational risks and such coverage is not available to us. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented.

We could sustain significant losses and substantial liability for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. We cannot assure investors that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Our planned exploratory drilling involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques, which are subject to risks. As a result, drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns.

Risks that we face while drilling include, but are not limited to:

 

    landing our well bore in the desired formation;

 

    staying in the desired formation while drilling horizontally through the formation;

 

    running our casing the entire length of the well bore; and

 

    being able to run tools and other equipment consistently through the well bore.

Risks that we face while completing our wells include, but are not limited to:

 

    being able to fracture and stimulate the planned number of stages;

 

    being able to run tools the entire length of the well bore during completion operations; and

 

    successfully cleaning out the well bore after completion of the final fracture stimulation stage.

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history, and, consequently, it is more difficult to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling does not meet our anticipated results or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and limited takeaway capacity and/or declines in crude oil and natural gas prices, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

 

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SEC rules could limit our ability to book additional PUDs in the future.

SEC rules only permit, subject to limited exceptions, us to book our PUDs if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement limits our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill those wells within the required five-year time frame.

Our identified drilling locations are subject to many uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

 

    the ongoing review and analysis of geologic and engineering data;

 

    the availability of sufficient capital resources to us and the other participants to drill and complete the prospects;

 

    the approval of the prospects by other participants once additional data has been compiled;

 

    economic and industry conditions at the time of drilling, including prevailing and anticipated prices for crude oil, natural gas and NGLs and the availability and prices of drilling rigs and personnel;

 

    the ability to maintain, extend or renew leases and permits on reasonable terms for the prospects;

 

    additional due diligence;

 

    regulatory requirements and restrictions; and

 

    the opportunity to divert our drilling budget to preferred prospects on acquired acreage or to secure other acreage by farming in.

Although we have identified or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells that are currently part of our capital plan may be based on results of drilling activities in other areas that we believe are geologically similar to a prospect rather than on analysis of seismic or other data in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from results in other areas. In addition, our drilling schedule may vary from our expectations because of future uncertainties. In addition, our ability to produce oil and natural gas may be significantly affected by the availability and prices of equipment and personnel.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in the addition of proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

 

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The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.

The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which the oil and gas industry has historically increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, and the costs for those items also increased. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services has subsided due to reduced activity. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for us to maintain or increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

Development of our estimated proved undeveloped reserves, or PUDs, may take longer than expected and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At December 31, 2015, approximately 67% of our total estimated proved reserves were classified as proved undeveloped reserves. Recovery of undeveloped reserves requires successful drilling and incurrence of significant capital expenditures. Our approximately 26.9 MMBoe of estimated proved undeveloped reserves will require an estimated $285 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves as unproved reserves.

Further, our reserves data assumes that we can and will make these expenditures and that these operations will be conducted successfully. These assumptions, however, may not prove correct. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write them off. Any such write-offs of our reserves could reduce our ability to borrow and adversely affect our liquidity and available capital.

Our producing properties are located primarily in the Eagle Ford Shale of South Texas, making us vulnerable to risks associated with operating in one geographic area.

Approximately 91% of our production during the six months ended June 30, 2016 was derived from our properties in the Eagle Ford Shale region of South Texas. As a result of this geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas. Additionally, we may be exposed to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in many or all of our wells within the Eagle Ford Shale.

 

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Approximately 77% of our net Eagle Ford Shale leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases and result in a material adverse effect on our crude oil, natural gas and NGLs reserves and future production and, therefore, our future cash flow and income.

As of December 31, 2015, approximately 77% of our net Eagle Ford Shale leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil, natural gas and NGLs regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future crude oil, natural gas and NGLs reserves and production and, therefore, our future cash flow and income, are highly dependent on successfully developing our undeveloped leasehold acreage and holding on to such leases.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate and any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the actual quantities and present value of such reserves.

There are uncertainties inherent in estimating crude oil and natural gas reserves and their estimated value, including many factors beyond our control. The reserve data in this registration statement represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner and is based on assumptions that may vary considerably from actual results. Reservoir engineering also requires economic assumptions about matters such as crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Accordingly, actual production, crude oil and natural gas prices, revenues, taxes, operating expenses, expenditures and quantities of recoverable crude oil and natural gas reserves will likely vary, possibly materially, from estimates. Any significant variance in our estimates or the accuracy of our assumptions could materially affect the estimated quantities and present value of reserves shown in this registration statement.

We depend upon several significant customers for the sale of most of our crude oil, natural gas and NGL production. The loss of one or more of these customers could adversely affect our revenues in the short term.

For the six months ended June 30, 2016, purchases by our largest four customers accounted for 38%, 20%, 18% and 11%, respectively, of our total sales revenues. While we believe that we can procure substitute or additional customers to offset the loss of one or more of our current customers, there is no assurance that we would be successful in doing so on terms acceptable to us or at all. The loss of one or more of such customers could limit our access to suitable markets for the crude oil, natural gas and NGLs we produce. The availability of a ready market for any crude oil, natural gas and/or NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of crude oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of crude oil and natural gas production and federal regulation of crude oil, natural gas and NGLs sold in interstate commerce. We cannot assure you that we will continue to have ready access to suitable markets for our future crude oil, natural gas and NGL production.

Our hedging transactions expose us to counterparty credit risk.

Currently, all of our hedging arrangements are concentrated with three counterparties, each of which are lenders under our revolving credit facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market for our crude oil, natural gas and NGLs.

 

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The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

The discounted future net cash flows in this registration statement are not necessarily the same as the current market value of our estimated crude oil and natural gas reserves. The current requirements for crude oil and natural gas reserve estimation and disclosures require the estimated discounted future net cash flows from proved reserves to be based on the average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by various factors, including:

 

    the actual prices we receive for crude oil and natural gas;

 

    our actual operating costs in producing crude oil and natural gas;

 

    the amount and timing of actual production;

 

    supply and demand for crude oil and natural gas;

 

    increases or decreases in consumption of crude oil and natural gas; and

 

    changes in governmental laws and regulations or taxation.

In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

We have incurred losses from operations for various periods since our inception and may continue to do so in the future.

We incurred a net loss of $27.3 million for the year ended December 31, 2015. Our development of and participation in an increasingly larger number of prospects has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to operate profitability and may not receive positive cash flows from operating activities in the future, which could adversely affect our business and the trading price of our Class A common stock.

Our derivative activities could result in financial losses or could reduce our income.

Because crude oil and natural gas prices are subject to volatility, we may periodically enter into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and natural gas production and thereby achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of crude oil and natural gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in crude oil and natural gas prices.

These arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase contracted quantities of crude oil and natural gas or a sudden, unexpected event materially impacts crude oil or natural gas prices. In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us.

 

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If crude oil and natural gas prices decrease, we may be required to write-down the carrying values of our crude oil and natural gas properties.

We review our proved crude oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our crude oil and natural gas properties, which may result in a decrease in the amount we can borrow under our credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our credit facility and adversely impact our results of operations and liquidity for the periods in which such charges are taken.

Our inability to market our crude oil and natural gas could adversely affect our business.

Market conditions or the unavailability of satisfactory crude oil and natural gas transportation arrangements may hinder our access to crude oil and natural gas markets or delay production. The availability of a ready market for our crude oil and natural gas production depends on a number of factors, including the demand for and supply of crude oil and natural gas and the proximity of reserves to pipelines and gathering facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on favorable terms could adversely impact our business and results of operations.

Our productive properties may be located in areas with limited or no access to pipelines, thereby requiring compression facilities or delivery by other means, such as trucking and train. Such restrictions on our ability to sell our crude oil or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended period of time, possibly causing us to lose leases due to the lack of commercially established production.

We generally deliver our crude oil and natural gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our crude oil and natural gas production may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system or for other reasons as dictated by the particular agreements. We may also enter into firm transportation arrangements for additional production in the future. Because we are obligated to pay fees on minimum volumes to our service providers under firm transportation agreements regardless of actual volume throughput, these firm transportation agreements may be significantly more costly than interruptible or short-term transportation agreements, which could adversely affect our business and results of operations.

A portion of our crude oil and natural gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, or field personnel issues or strikes. We may also voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted or curtailed, it could adversely affect our business and results of operations.

The terms of our revolving credit facility and the indenture that governs the Notes may restrict our operations, particularly our ability to respond to changes or to take certain actions.

The indenture that governs the Notes and our revolving credit facility contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, subject to satisfaction of certain conditions, to:

 

    incur additional indebtedness and guarantee indebtedness;

 

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    pay dividends or make other distributions or repurchase or redeem capital stock;

 

    prepay, redeem or repurchase certain debt;

 

    issue certain preferred stock or similar equity securities;

 

    make loans and investments;

 

    sell assets;

 

    incur liens;

 

    enter into transactions with affiliates;

 

    alter the businesses we conduct;

 

    enter into agreements restricting our subsidiaries’ ability to pay dividends; and

 

    consolidate, amalgamate, merge or sell all or substantially all of our assets.

In addition, the restrictive covenants in our revolving credit facility require us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we may be unable to meet them.

A breach of the covenants or restrictions under the indenture that governs the Notes or under our revolving credit facility could result in an event of default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related debt and may result in the acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In the event our lenders or holders of the Notes accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets to repay that indebtedness.

As a result of these restrictions contained in the Notes and our revolving credit facility, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities. These restrictions may further affect our ability to grow in accordance with our strategy. In addition, our financial results, our substantial indebtedness and our credit ratings could adversely affect the availability and terms of our current and future financing.

Our level of indebtedness may increase, reducing our financial flexibility.

We intend to fund our capital expenditures in 2016 through cash flow from operations, from borrowings under our revolving credit facility, funding available under our Joint Development Agreement with IOG and, if necessary, through debt or equity financings. Our ability to make the necessary capital investment to maintain or expand our asset base and develop oil and natural gas reserves will be impaired if cash flow from operations is reduced and external sources of capital become limited or unavailable. If we incur additional debt for these or other purposes, the related risks that we now face could intensify and we could face additional risks. Our level of debt could adversely affect our business and results of operations in several important ways, including the following:

 

    a portion of our cash flow from operations would be used to pay interest on borrowings;

 

    the covenants contained in our credit facilities limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in general business and economic conditions;

 

    a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes;

 

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    a leveraged financial position would make us more vulnerable to economic downturns and decreases in commodity prices and could limit our ability to withstand competitive pressures; and

 

    a debt that we incur under our credit facilities will be at variable rates, which could make us vulnerable to an increase in interest rates.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving credit facility and senior notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flow and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness which would have a material adverse effect on our business and operations.

Increased costs of capital could adversely affect our business.

Our business and operating results can be adversely affected by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Disruptions in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, which would impact our ability to finance our operations. We will require continued access to capital for the foreseeable future. A significant reduction in the availability of credit could materially and adversely affect our business, results of operations and financial condition.

The crude oil and natural gas industry is intensely competitive and many of our competitors have resources that are greater than ours.

The oil and natural gas industry is highly competitive. Public integrated and independent oil and gas companies, private equity backed and private operators are all active bidders for desirable crude oil and natural gas properties as well as the equipment and personnel required to operate those properties. Many of these companies have substantially greater financial resources, staff and facilities than we do. There is a risk that increased industry competition will adversely impact our ability to purchase assets or secure services at prices that will allow us to generate sufficient returns on investment in the future.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

 

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The loss of any of our key personnel could adversely affect our business, financial condition, the results of operations and future growth.

We are reliant on a number of key members of our executive management team, and we do not have employment agreements with any of them. Loss of such personnel may have an adverse effect on our performance. Certain areas in which we operate are highly competitive regions and competition for qualified personnel is intense. We may be unable to hire suitable field personnel for our technical team or there may be periods of time where a particular position remains vacant while a suitable replacement is identified and appointed. Our ability to manage our growth will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. We may not be successful in attracting and retaining the personnel required to grow and operate our business profitably.

Our ability to manage growth will have an impact on our business, financial condition and results of operations.

Our growth historically has been achieved through the acquisition of leaseholds and the expansion of our drilling programs. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, potentially adversely affecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

 

    our ability to obtain leases or options on properties;

 

    our ability to identify and acquire new exploratory prospects;

 

    our ability to develop existing prospects;

 

    our ability to continue to retain and attract skilled personnel;

 

    our ability to maintain or enter into new relationships with project partners and independent contractors;

 

    the results of our drilling programs;

 

    commodity prices; and

 

    our access to capital.

We may not be successful in upgrading our technical, operational and administrative resources or increasing our internal resources sufficiently to provide certain of the services currently provided by third parties, and we may not be able to maintain or enter into new relationships with project partners and independent contractors on financially attractive terms, if at all. If we are unable to achieve or manage growth, it may materially and adversely affect our business, results of operations and financial condition.

We may incur losses as a result of title deficiencies.

We may lose title to, or interests in, our leases and other properties if the conditions to which those interests are subject are not satisfied or if we do not have sufficient funds available to meet the commitments.

The existence of title differences with respect to our crude oil and natural gas properties could reduce their value or render such properties worthless, which would have a material adverse effect on our business and financial results. We do not obtain title insurance and have not obtained drilling title opinions on all of our crude oil and natural gas properties. As is customary in the industry in which we operate, we generally rely upon the judgment of crude oil and natural gas lease brokers or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract, and we generally make

 

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title investigations and receive title opinions of local counsel before we commence drilling operations. In some cases, we perform curative work to correct deficiencies in the marketability or adequacy of the title assigned to us. In cases involving more serious title problems, the amount paid for affected crude oil and natural gas leases can be lost, and the target area can become undrillable. While we undertake to cure all title deficiencies prior to drilling, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease, our investment in the well and the right to produce all or a portion of the minerals under the property. A significant portion of our acreage is undeveloped leasehold, which has a greater risk of title defects than developed acreage.

Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

The conduct of exploring for, and producing oil, natural gas and NGLs may expose our personnel and other third parties to potentially dangerous working environments. Occupational health and safety legislation and regulations differ in each jurisdiction. If any of our employees suffer injury or death, compensation payments or fines may have to be paid, and such circumstances could result in the loss of a license or permit required to carry on the business, or other legislative sanction, all of which have the potential to materially and adversely affect our business, results of operations and financial condition.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable, regardless of whether we were at fault, for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose us to significant liabilities that could have a material adverse effect on our financial condition and results of operations. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal and other private parties may be able to sue us to enforce compliance with environmental laws and regulations, as well as collect penalties for violations or obtain damages for any related personal injury or property damage. Some sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly material handling, emission, waste management or clean-up requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise materially and adversely affect our business, results of operations and financial condition. We may not be able to recover some or any of these costs from insurance.

In addition, our operations and financial performance may be adversely affected by governmental action, including delay, inaction, policy change or the introduction of new, or amendment of or changes in interpretation of existing legislation or regulations, particularly in relation to access to infrastructure, environmental regulation (including in respect of carbon emissions and management), royalties and production and exploration licensing. Federal and state regulators are increasingly targeting greenhouse gas emissions from oil and gas operations. While these regulatory efforts are evolving, they may require the installation of emission controls or mandate other action that may result in increased costs of operation, delay, uncertainty or exposure to liability.

Hydraulic fracturing has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Hydraulic fracturing is an important and commonly used process in the completion of unconventional crude oil and natural gas wells. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into deep rock formations to stimulate crude oil or natural gas production. Currently, hydraulic fracturing is

 

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primarily regulated in the United States at the state level, which generally focuses on regulation of well design, pressure testing and other operating practices. However, some states and local jurisdictions across the United States, including states in which we operate, have begun adopting more restrictive regulation, including measures such as:

 

    required disclosure of chemicals used during the hydraulic fracturing process;

 

    restrictions on wastewater disposal activities;

 

    required baseline and post-drilling sampling of water supplies in close proximity to hydraulic fracturing operations;

 

    new municipal or state land use regulations, such as changes in setback requirements, which may restrict drilling locations or related activities;

 

    financial assurance requirements, such as the posting of bonds, to secure site restoration obligations; and

 

    local moratoria or even bans on crude oil and natural gas development utilizing hydraulic fracturing in some communities.

The Texas Railroad Commission recently adopted rules and regulations requiring that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well also must be disclosed to the public and filed with the Texas Railroad Commission. Any increased federal, state, local, foreign, or international regulation of hydraulic fracturing could reduce the volume of reserves that we can economically recover, which could materially and adversely affect our revenues and results of operations.

At the U.S. federal level, hydraulic fracturing that does not involve the use of diesel fuels is exempt from regulation under the Safe Drinking Water Act (“SDWA”). However, the United States Congress (“Congress”) has considered and likely will continue to consider eliminating this regulatory exemption, which could subject hydraulic fracturing activities to regulation and permitting by the Environmental Protection Agency (“EPA”) under the SDWA. Congressional action will be informed by a study commenced in 2011 by the EPA on the impacts of hydraulic fracturing on drinking water resources, with final results anticipated in 2016. Despite the existing exemption, the EPA has begun utilizing other legal authorities in various ways to regulate portions of the hydraulic fracturing process, exemplified by its issuance of regulations under the Clean Air Act limiting emission of pollutants during the hydraulic fracturing process, as well as its recent initiation of a proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In addition, the United States Department of the Interior has issued comprehensive regulations governing the use of hydraulic fracturing on federally managed lands, though they are currently subject to litigation.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts on surface water, and groundwater and , the potential for the disposal of produced water in underground formations to trigger earthquakes, and effects on the environment generally. A number of lawsuits and enforcement actions have been initiated across the country relating to hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and

 

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potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act of 2005”), the Federal Energy Regulatory Commission (“FERC”) has civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act (“NGPA”) to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Natural Gas Industry.”

Conservation measures and technological advances could reduce demand for crude oil, natural gas and NGLs.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for crude oil, natural gas and NGLs. The impact of the changing demand for crude oil, natural gas and NGLs services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

Drilling activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of oil and natural gas from many reservoirs, including in the Eagle Ford, requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities due to drought conditions. Water must be obtained from other sources and transported to the drilling site. The effects of climate change may further exacerbate water scarcity in certain regions. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.

Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of crude oil and natural gas. In particular, regulatory focus on disposal of produced water and drilling waste through underground injection has increased because of alleged links between such injection and regional seismic impacts in disposal areas. For example, regulators in some states, including Texas, have responded to the potential concern that the injection of produced water (and other waste water from oil and gas operations) into underground disposal wells may trigger seismic activity.

 

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Compliance with environmental regulations and permit requirements governing the withdrawal, storage, use and discharge of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could materially and adversely affect our business, results of operations and financial condition.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

In connection with the EPA finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the Clean Air Act (“CAA”) that, among other things, require reduced GHG emissions from certain large stationary sources, and the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. In May 2016, the EPA released final regulations intended to reduce methane emissions from the oil and gas industry, including throughout the natural gas supply chain. The regulations could affect us indirectly by affecting our customer base or by directly regulating our operations. In either case, increased costs of operation and exposure to liability could result. The EPA has also announced that it intends to propose similar standards for existing sources. The EPA also finalized rules in 2016 that clarify when crude oil and natural gas sites should be aggregated for purposes of air permitting, which could increase our compliance and permitting costs.

In addition, Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane that are understood to contribute to global warming. While comprehensive climate legislation will likely not be passed by either house of Congress in the near future, energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. The U.S. is actively participating in international discussions that are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration. And in November 2014, President Obama announced that the U.S. would seek to cut net GHG emissions 26-28 percent below 2005 levels by 2025 in return for China’s commitment to seek to peak emissions around 2030, with concurrent increase in renewable energy. Most recently in December, the United States was one of 175 countries to adopt the Paris Agreement at the 21st Conference of Parties, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. On October 4, 2016, the E.U. ratified the Paris Agreement, thus meeting the threshold for the agreement to come into force. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions such as electric power plants, smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

 

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Acts of terrorism (including eco-terrorism and cyber-attacks) could have a material adverse effect on our financial condition, results of operations and cash flows.

Our assets and operations, and the assets and operations of our providers of gas gathering, processing, transportation and fractionation services, may be targets of terrorist activities (including eco-terrorist and cyber-terrorist activities) that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, market or distribute natural gas, NGLs and oil. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental and other repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, acts of terrorism, and the threat of such acts, could result in volatility in the prices for natural gas, NGLs and oil and could affect the markets for such commodities.

Our systems and IT infrastructure may be subject to security breaches and other cyber security incidents.

We seek to maintain the security of computers, computer networks and data storage resources, as security breaches could result in vulnerabilities and loss of and/or unauthorized access to proprietary information and could negatively impact our business. We may face attempts by experienced hackers, cybercriminals or others with authorized access to our systems to misappropriate our proprietary information and technology, interrupt our business and/or gain unauthorized access to confidential information.

Certain federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of future legislation.

We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. Certain legislation introduced in the Congress and certain proposals in the U.S. President’s Fiscal Year 2017 Budget Proposal, if enacted into law, would make significant changes to U.S. tax laws, including, but not limited to, the elimination of certain key federal income tax incentives currently available to crude oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (v) the imposition of a $10.25 per barrel fee on oil, to be paid by oil companies (but the budget does not describe where and how such a fee would be collected).

These or any other similar changes in federal tax laws could defer or eliminate certain tax deductions that are currently available to us with respect to our crude oil and natural gas exploration and development, and any such change could materially and adversely affect our business, results of operations and financial condition.

General economic conditions could adversely affect our business and future growth.

Instability in the global financial markets may have a material impact on our liquidity and financial condition, and we may ultimately face major challenges if conditions in the financial markets were to materially change or worsen. Our ability to access the capital markets or to borrow money may be restricted or may be more expensive at a time when we would need to raise capital, which could have an adverse effect on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. Such economic conditions could have an impact on our customers, causing them to fail to meet their obligations to us. In addition, such changes could have an impact on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments.

Also, market conditions could have an impact on our crude oil and natural gas derivative instruments if our counterparties are unable to perform their obligations or seek bankruptcy protection, which could lead to reductions in the demand for crude oil and natural gas, or reductions in the prices of oil and natural gas or both,

 

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which could have an adverse impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of changing economic conditions cannot be predicted, they may materially and adversely affect our business, results of operations and financial condition.

Changes in the differential between benchmark prices of crude oil and natural gas and the reference or regional index price used to price our actual crude oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we use to price our crude oil and natural gas sales reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict crude oil and natural gas differentials. Changes in differentials between the benchmark price for crude oil and natural gas and the reference or regional index price we reference in our sales contracts could materially and adversely affect our business, results of operations and financial condition.

Recent federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our crude oil and natural gas production. Under the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), the Commodity Futures Trading Commission (“CFTC”) issued regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are exempt from these limits. The position limits regulation was vacated by the United States District Court for the District of Columbia in September 2012. The CFTC has appealed the District Court’s decision and its Chairman has stated that the agency is working on developing a new proposed rulemaking to address position limits. The CFTC has finalized other regulations, including critical rulemakings on the “swap” and “swap dealer” definitions, swap dealer registration, swap data reporting and mandatory clearing, among others. The Dodd-Frank Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. The legislation may also require the counterparties to our derivative contracts to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The new legislation and any new regulations could:

 

    significantly increase the cost of some derivative contracts (including through requirements to post collateral that could adversely affect our available liquidity);

 

    materially alter the terms of some derivative contracts;

 

    reduce the availability of some derivatives to protect against risks we encounter;

 

    reduce our ability to monetize or restructure our existing derivative contracts; and

 

    potentially increase our exposure to less creditworthy counterparties.

If we reduce our use of derivatives as a result of the new legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. If the new legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our financial condition and results of operations.

 

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We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

In accordance with our business strategies, we periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

 

    recoverable reserves;

 

    future crude oil and natural gas prices and their appropriate differentials;

 

    development and operating costs; and

 

    potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems may not be observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may also involve other risks, including:

 

    diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

 

    the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

 

    difficulty associated with coordinating geographically separate organizations; and

 

    the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

In addition, even if we successfully integrate an acquisition, it may not be possible to realize the full benefits we may expect, including with respect to estimated proved reserves, production volume or cost savings from operating synergies, within our expected time frame. Anticipated benefits of an acquisition may also be offset by operating losses relating to changes in commodity prices in crude oil and natural gas industry conditions, risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. Failure to realize the benefits we anticipate from an acquisition may materially and adversely affect our business, results of operations and financial condition.

 

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Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Certain provisions in our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

    requiring advance notice of stockholder intention to put forth director nominees or bring up other business at a stockholders’ meeting;

 

    requiring the affirmative vote of 66 2/3% of the voting power of all then outstanding shares of Class A common stock entitled to vote in order for stockholders to adopt, amend or repeal any provision of our bylaws or certificate of incorporation; and

 

    providing that the number of directors shall be fixed from time to time by our board of directors pursuant to a resolution adopted by a majority of the total number of authorized directors (whether or not there exist any vacancies in previously authorized directorships) or by the stockholders. Newly created directorships resulting from any increase in our authorized number of directors will be filled only by a majority vote of our board of directors then in office, whether or not such directors number less than a quorum, and directors so chosen will serve for a term expiring at the annual meeting of stockholders at which the term of office to which they have been elected expires or until such director’s successor shall have been duly elected and qualified.

In addition, we entered into a Board Representation Agreement (“Board Representation Agreement”) with EF Realisation pursuant to which it is entitled to nominate a number of directors so long as certain ownership thresholds are maintained. Please read “Certain Relationships and Related Transactions—Related Transactions.”

Our bylaws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Certain of our oil producing properties are located on the Fort Peck Reservation, making us vulnerable to risks associated with tribal sovereignty laws and regulations pertaining to the operation of oil and gas properties on Native American tribal lands.

Certain of our oil and natural gas properties are located on the Fort Peck Reservation in Montana, or the “Reservation.” Operation of oil and natural gas interests on Native American tribal lands presents unique considerations and complexities that arise from the fact that Native American tribes are “dependent” sovereign nations located within states but are subject only to tribal laws and treaties with, and the laws and Constitution of,

 

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the United States. This creates an overlay of three jurisdictional regimes—Native American, federal and state. These considerations and complexities could impact various aspects of our operations, including real property considerations, permitting, employment practices, environmental matters and taxes.

Furthermore, because tribal property is considered to be held in trust by the federal government, before we can take actions such as drilling, pipeline installation or similar actions, we are required to obtain approvals from various federal agencies, including the Bureau of Indian Affairs and the Bureau of Land Management. We are also required to obtain approvals from the tribe for surface use access on certain of our properties. Gaining these approvals could result in delays in implementation of, or otherwise prevent us from implementing, our development program.

Risks Related to our Class A Common Stock

Future sales of our common stock in the public market could reduce our Class A common stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of Class A common stock in subsequent public offerings. We may also issue additional shares of Class A common stock or convertible securities. After the completion of this offering, we will have outstanding                  shares of Class A common stock. This number includes                  shares that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, assuming no exercise of the underwriters’ option to purchase additional shares, EF Realisation will own                  shares of our Class A common stock, or approximately     % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in “Underwriting,” but may be sold into the market in the future. Certain of our other existing stockholders are party to a registration rights agreement with us which will require us to effect the registration of their shares (and shares of certain of their affiliates) in certain circumstances no earlier than the expiration of the lock-up period contained in the underwriting agreement entered into in connection with this offering. Please see “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions—Related Transactions.”

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our Class A common stock.

We, all of our directors and executive officers, and EF Realisation, have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our Class A common stock for a period of 90 days following the date of this prospectus. Seaport Global Securities LLC, at any time and without notice, may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. See “Underwriting” for more information on these agreements. If any restrictions under the lock-up agreements are waived, then the Class A common stock, subject to compliance with the Securities Act of 1933, as amended (the “Securities Act”) or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital.

 

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The market price and trading volume of our Class A common stock may be volatile and may be affected by economic conditions beyond our control.

The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. The market prices of securities of oil and gas exploration and production companies have often experienced fluctuations that have been unrelated or disproportionate to the operating results of these companies. In addition, the trading volume of our Class A common stock may fluctuate and cause significant price variations to occur. If the market price of our Class A common stock declines significantly, you may be unable to resell your shares at or above the purchase price, if at all. We cannot assure you that the market price of our shares will not fluctuate or significantly decline in the future.

Some specific factors that could negatively affect the price of our Class A common stock or result in fluctuations in their price and trading volume include:

 

    actual or expected fluctuations in our operating results;

 

    actual or expected changes in our growth rates or our competitors’ growth rates;

 

    changes in commodity prices for hydrocarbons we produce;

 

    changes in market valuations of similar companies;

 

    changes in our key personnel;

 

    potential acquisitions and divestitures;

 

    changes in financial estimates or recommendations by securities analysts;

 

    changes or proposed changes in laws and regulations affecting the oil and natural gas industry;

 

    changes in trading volume of our Class A common stock on NASDAQ;

 

    sales of our Class A common stock by us, our executive officers or our stockholders in the future;

 

    conditions in the crude oil and natural gas industry in general; and

 

    conditions in the financial markets or changes in general economic conditions.

We are an emerging growth company and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies may make the Class A common stock less attractive to investors and, as a result, adversely affect the price of the Class A common stock and result in a less active trading market for the Class A common stock.

We are an emerging growth company as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. For example, we have elected to rely on an exemption from the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act relating to internal control over financial reporting, and we will not provide such an attestation from our auditors. We may also take advantage of an exemption from the adoption of new or revised financial accounting standards until they would apply to private companies, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding advisory “say-on-pay” votes on executive compensation and stockholder advisory votes on golden parachute compensation not previously approved.

We may avail ourselves of these disclosure exemptions until we are no longer an emerging growth company. We cannot predict whether investors will find the Class A common stock less attractive because of our reliance on some or all of these exemptions. If investors find the Class A common stock less attractive, it may adversely impact the price of the Class A common stock and there may be a less active trading market for the Class A common stock.

 

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We will cease to be able to take advantage of the disclosure exemptions as an emerging growth company upon the earliest of:

 

    the end of the fiscal year in which the fifth anniversary of completion of an initial public offering occurs;

 

    the end of the first fiscal year in which the market value of our Class A common stock held by non-affiliates exceeds $700 million as of the end of the second quarter of such fiscal year;

 

    the end of the fiscal year in which we have total annual gross revenues of at least $1 billion; and

 

    the date on which we have issued more than $1 billion in non-convertible debt securities in any rolling three-year period.

If we fail to establish and maintain proper internal controls, our ability to produce accurate financial statements or comply with applicable regulations could be impaired.

Section 404(a) of the Sarbanes-Oxley Act requires that, beginning with our annual report for the year ending December 31, 2017, our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Once we are no longer a smaller reporting company, Section 404(b) of the Sarbanes-Oxley Act will require our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal controls over financial reporting. We expect, however, to rely on the exemptions provided in the JOBS Act, and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

Our first Section 404(a) assessment will take place beginning with our annual report for the year ending December 31, 2017. In connection with the review of our unaudited condensed consolidated financial statements for the nine months ended September 30, 2015, management identified a material weakness in the financial close process relating to the failure to record certain balance sheet entries and balance sheet reclassification adjustments during the interim quarter end closing process. Though this deficiency has been remediated, the presence of further material weaknesses could result in financial statement errors which, in turn, could lead to errors in our financial reports and/or delays in our financial reporting, which could require us to restate our operating results or our auditors may be required to issue a qualified audit report.] We might not identify one or more material weaknesses in our internal controls in connection with evaluating our compliance with Section 404(a) of the Sarbanes-Oxley Act. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal controls over financial reporting, we will need to expend significant resources and provide significant management oversight. Implementing any appropriate changes to our internal controls may require specific compliance training of our directors and employees, entail substantial costs in order to modify our existing accounting systems, take a significant period of time to complete and divert management’s attention from other business concerns. These changes may not, however, be effective in maintaining the adequacy of our internal control.

If either we are unable to conclude that we have effective internal controls over financial reporting or, at the appropriate time, our independent auditors are unwilling or unable to provide us with an unqualified report on the effectiveness of our internal controls over financial reporting as required by Section 404(b) of the Sarbanes-Oxley Act, investors may lose confidence in our operating results, the price of our Class A common stock could decline and we may be subject to litigation or regulatory enforcement actions. In addition, if we are unable to meet the requirements of Section 404 of the Sarbanes-Oxley Act, we may not be able to remain listed on NASDAQ.

 

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We will continue to be controlled by our existing owners, whose interests may differ from those of our public stockholders.

As of September 30, 2016, EF Realisation controlled approximately 52.0 % of the combined voting power of our Class A common stock and its designees hold two of the seats on our board of directors. As a result, EF Realisation will have the ability to elect all of the members of our board of directors and to control our management and affairs. In addition, it may be able to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and are able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company and might ultimately affect the market price of our Class A common stock.

In addition, we entered into a Board Representation Agreement with EF Holdings whereas so long as it maintains certain beneficial ownership levels of our Class A common stock, then EF Holdings will have certain rights, including director nomination rights. Please read “Certain Relationships and Related Party Transactions—Related Transactions.”

We are a “controlled company” within the meaning of NASDAQ listing standards and, as a result, qualify for, and rely on, exemptions from certain corporate governance requirements. You will not have the same protections afforded to stockholders of companies that are subject to such requirements.

We are a “controlled company” within the meaning of NASDAQ listing standards. Under these rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements of NASDAQ, including (i) the requirement that a majority of the board of directors consist of independent directors, (ii) the requirement that we have a nominating and corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities and (iii) the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. We intend to rely on some or all of these exemptions. For example, we will not have a majority of independent directors and our compensation and nominating and corporate governance committees will not consist entirely of independent directors.

Accordingly, you will not have the same protections afforded to stockholders of companies subject to all of the corporate governance requirements of NASDAQ.

We do not anticipate paying dividends in the foreseeable future.

For the foreseeable future, we currently intend to retain all available funds and any future earnings to support our operations and to finance the growth and development of our business. Any future determination to declare cash dividends will be made at the discretion of our board of directors, subject to compliance with applicable laws and covenants under current or future credit facilities, which may restrict or limit our ability to pay dividends, and will depend on our financial condition, operating results, capital requirements, general business conditions and other factors that our board of directors may deem relevant. We do not anticipate paying any cash dividends on our Class A common stock in the foreseeable future. As a result, a return on your investment will only occur if our Class A common stock share price appreciates.

Additional stock offerings may dilute current stockholders.

Given our plans and our expectation that we may need additional capital and personnel, we may need to issue additional shares of our Class A common stock or securities convertible into or exercisable for shares of Class A common stock, including preferred stock, options or warrants. The issuance of additional Class A common stock may significantly dilute the ownership of our current stockholders.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This registration 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 registration statement, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this registration statement, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

 

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

 

    cash flows and liquidity;

 

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

 

    crude oil, NGLs and natural gas realized prices;

 

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

 

    availability of drilling and production equipment;

 

    availability of personnel;

 

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

 

    availability and terms of capital;

 

    drilling and completion of wells;

 

    competition;

 

    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 registration statement. 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 registration statement 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 “Risk Factors” and our financial information contained in this registration statement.

These factors include risks related to:

 

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

 

    lack of proved reserves;

 

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    estimates of crude oil, NGLs and natural gas data;

 

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

 

    borrowing capacity under our credit facilities;

 

    general economic and business conditions;

 

    failure to realize expected value creation from property acquisitions;

 

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

 

    risks related to the concentration of our operations;

 

    drilling results;

 

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

 

    potential adoption of new governmental regulations; and

 

    our ability to satisfy future cash obligations and environmental costs.

The forward-looking statements relate only to events or information as of the date on which the statements are made in this registration statement. 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.

 

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USE OF PROCEEDS

Based on our last reported sales price on NASDAQ on                     , 2016, we expect to receive approximately $            million of net proceeds from the sale of              shares of Class A common stock offered by us (or approximately $             if the underwriters exercise in full the option to purchase              additional shares of Class A common stock), in each case, after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this offering to repay Seaport Global in connection with the Facilitation Agreement, reduce amounts drawn under our revolving credit facility and for general corporate purposes.

Our revolving credit facility matures on October 16, 2018 and bears interest at an average rate of approximately 2.85%. We had $99.5 million outstanding under our revolving credit facility as of June 30, 2016. The borrowings were primarily incurred to fund ongoing operations. Amounts repaid under the revolving credit facility, if any, may be reborrowed, subject to the terms of our revolving credit facility.

 

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DIVIDEND POLICY

We currently intend to retain any earnings to fund the operation and expansion of our business and do not anticipate paying any cash dividends for the foreseeable future. The declaration and payment of any dividends in the future by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Moreover, if we determine to pay any dividend in the future, there can be no assurance that we will continue to pay such dividends. In addition, under our bank financing agreements, we are not permitted to pay cash dividends without the prior written consent of the lender.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2016:

 

    on an actual basis: and

 

    as adjusted to give effect to the sale of              shares of our Class A common stock in this offering and the application of the net proceeds from this offering as set forth under “Use of Proceeds.”

 

     As of June 30, 2016  
     Actual     As Adjusted  

Cash and cash equivalents

   $ 5,147      $                
  

 

 

   

 

 

 

Debt:

    

Revolving Credit Facility(1)

     99,500     

Note Payable

     220,000     
  

 

 

   

 

 

 

Total Debt

     319,500     

Stockholders’ equity

    

Common stock, $0.20 par value, 500,000,000 shares authorized, 15,044,051 shares issued and outstanding actual; and 500,000,000 shares authorized,              shares issued and outstanding as adjusted

     142,638     

Additional paid-in capital

     10,461     

Accumulated other comprehensive loss

     (776  

Retained earnings

     6,676     
  

 

 

   

 

 

 

Total stockholders’ equity

     158,999     
  

 

 

   

 

 

 

Total capitalization

   $ 478,499      $     
  

 

 

   

 

 

 

 

(1) We reduced borrowings outstanding under our revolving credit facility with the net proceeds from the offering.

 

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MARKET PRICE OF OUR CLASS A COMMON STOCK

Our Class A common stock is listed on NASDAQ under the ticker symbol “LONE” and began trading on July 5, 2016. The following table sets forth, for the periods indicated, the high and low sales prices per common share as reported on NASDAQ:

 

Period:

   High      Low  

Third Quarter 2016 (beginning July 5, 2016)

   $ 13.32       $ 6.65   

Fourth Quarter 2016 (through October 25, 2016)

   $ 10.27       $ 8.75   

As of September 30, 2016, we had approximately 1,612 stockholders of record for our Class A common stock. This number excludes owners for whom Class A common stock may be held in “street” name.

As of September 30, 2016, we had one stockholder of record for our Class B common stock.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following table presents selected historical consolidated financial data of our Predecessor as of the dates and for the periods indicated. The selected historical consolidated financial data as of and for the years ended December 31, 2015 and 2014 are derived from the audited financial statements appearing elsewhere in this prospectus. The selected historical consolidated interim financial data as of June 30, 2016 and for the six months ended June 30, 2016 and 2015 are derived from the unaudited interim financial statements appearing elsewhere in this prospectus. The unaudited consolidated financial statements have been prepared on the same basis as our audited financial statements and, in our opinion, include all adjustments, consisting of normal recurring adjustments, which are considered necessary for a fair presentation of the financial position, results of operations and cash flows for such periods. Historical results are not necessarily indicative of future results.

The selected historical consolidated financial data presented below should be read in conjunction with “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes and other financial data included elsewhere in this prospectus.

 

     For the Six Months Ended
June 30,
    For the Twelve Months Ended
December 31,
 

($ in thousands except shares and per share amounts)

   2016     2015     2015     2014  
     (unaudited)     (unaudited)              

Statement of Operations Data:

        

Revenues

        

Oil sales

   $ 24,119      $ 37,559      $ 70,739      $ 104,233   

Natural gas sales

     3,257        2,479        6,823        7,590   

Natural gas liquid sales

     1,623        1,122        1,928        3,804   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

     28,999        41,160        79,490        115,627   

Operating expenses

        

Lease operating and gas gathering

     8,758        8,050        17,190        16,632   

Production, ad valorem and severance taxes

     2,139        2,827        4,982        7,123   

Rig Standby expense

     1,897        —          663        —     

Depletion, depreciation and amortization

     27,636        26,039        58,828        40,522   

Accretion of asset retirement obligations

     107        106        214        201   

(Gain) loss on sale of oil and gas properties

     (1,531     625        —          —     

Impairment of oil and gas properties

     1,938        —          28,623        5,478   

Stock-based compensation

     191        866        2,585        1,938   

General and administrative

     5,631        4,696        10,825        8,913   

Other (income) expense

     1,047        35        —          —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses

     47,813        43,244        123,910        80,807   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     (18,814     (2,084     (44,420     34,820   

Other income (expense)

        

Interest expense

     (12,299     (11,819     (24,577     (19,949

Gains (losses) on commodity derivatives

     (5,069     (525     27,609        43,972   

Other income (expense)

     —          —          1,066        55   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     (17,368     (12,344     1,966        24,078   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before taxes

     (36,182     (14,428     (42,454     58,898   

Income tax benefit (expense)

     12,040        5,350        15,121        (22,432
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (24,142   $ (9,078   $ (27,333   $ 36,466   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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     For the Six Months Ended
June 30,
    For the Twelve Months Ended
December 31,
 

($ in thousands except shares and per share amounts)

   2016     2015     2015     2014  
     (unaudited)     (unaudited)              

Pro forma weighted average number of common shares outstanding

        

Basic(1)

     7,522,025        7,522,025        7,522,025        7,330,602   

Diluted(1)

     7,522,025        7,522,025        7,522,025        7,534,805   

Pro forma net earnings per common share

        

Basic(1)

   $ (3.21   $ (1.21   $ (3.63   $ 4.97   

Diluted(1)

   $ (3.21   $ (1.21   $ (3.63   $ 4.84   

Balance Sheet Data:

        

Cash and cash equivalents

   $ 5,147      $ 3,596      $ 4,321      $ 9,992   

Oil and gas properties

     478,363        494,125        488,100        481,079   

Total assets

     509,314        555,450        541,521        559,069   

Long-term debt

     315,197        274,626        303,711        264,614   

Stockholders’ equity

     158,999        207,423        182,966        207,702   

 

(1) Gives effect to the Reorganization and the 50:1 share consolidation that our Predecessor effected in May 2015 as if they had occurred for the period indicated.

Non-GAAP Financial Measure

Adjusted EBITDAX

Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non-recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock-based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense) and unrealized (gain) loss on derivative financial instruments.

Management believes Adjusted EBITDAX provides useful information to investors because it assists investors in the evaluation of the Company’s operating performance and comparison of the results of the Company’s operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at Adjusted EBITDAX to eliminate the impact of certain non-cash items or because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. The Company’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

 

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The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated.

 

     Six Months Ended June 30,     Twelve Months Ended December 31,  

($ in thousands)

           2016                     2015                     2015                     2014          
     (unaudited)     (unaudited)              

Net Income (Loss)

   $ (24,142   $ (9,078   $ (27,333   $ 36,466   

Income tax expense (benefit)

     (12,040     (5,350     (15,121     22,432   

Interest expense

     12,299        11,819        24,577        19,949   

Exploration expense

     1        51        222        96   

Depletion, depreciation, amortization and accretion

     27,743        26,145        59,042        40,723   
  

 

 

   

 

 

   

 

 

   

 

 

 

EBITDAX

     3,861        23,587        41,387        119,666   

Rig Standby Expense

     1,897        —          663        —     

Non-recurring costs

     645        19        1,226        1,700   

Stock based compensation

     191        865        2,585        1,938   

(Gain) loss on sale of properties

     (1,531     625        —          —     

Impairment of oil and gas properties

     1,938        —          28,623        5,478   

Unrealized (gain) loss on derivative financial instruments

     21,605        18,677        8,728        (42,756

Other income (expense)

     1,047        34        1,066        (55
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDAX(1)

   $ 29,653      $ 43,807      $ 84,278      $ 85,971   

 

(1) Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus Summary—Summary Historical Financial Data—Non-GAAP Financial Measure.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Our Predecessor and Reorganization

On July 5, 2016, the Company acquired all of the issued and outstanding ordinary shares of our Predecessor and former parent pursuant to a scheme of arrangement under Australian law, which we refer to as the Reorganization. Pursuant to the Reorganization, the Company issued to the stockholders of the Predecessor one share of the Company’s Class A common stock for every two ordinary shares of our Predecessor that were issued and outstanding. Prior to the Reorganization, the Company had no business or operations, and following the Reorganization, the business and operations of the Company consist solely of the business and operations of the subsidiaries of our Predecessor. On July 5, 2016, the Class A common stock of the Company began trading on NASDAQ 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 our Predecessor and its consolidated subsidiaries prior to the Reorganization. Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our” and “the Company” refer to (i) our Predecessor and its subsidiaries prior to the Reorganization and (ii) the Company and its subsidiaries upon completion of the Reorganization, as applicable.

Overview

We are an independent oil and natural gas company, focused on the acquisition, development and production of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas. As of June 30, 2016, we have accumulated approximately 40,271 gross (35,230 net) acres in what we believe to be the formation’s crude oil and condensate windows. We also own 44,084 gross (28,655 net) undeveloped acres in 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 we currently have no long lived assets located outside the United States.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the six months ended June 30, 2016 and the years ended December 31, 2015 and 2014, our revenues were derived 83%, 89% and 90%, respectively, from oil sales and 11%, 9% and 7%, respectively, from natural gas sales. Our revenues from NGL sales for the six months ended June 30, 2016 and the years ended December 31, 2015 and 2014, were 6%, 2% and 3%, respectively.

 

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Our revenues may vary significantly from period to period as a result of changes in volumes of production sold and changes in commodity prices.

Market Conditions

The oil and gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and thus far in 2016, the global oil supply has continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and have continued to be weak throughout 2015 and thus far in 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America. The duration and magnitude of the commodity price declines cannot be accurately predicted.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

 

    production volumes;

 

    realized prices on the sale of oil and natural gas, including the effect of our commodity derivative contracts;

 

    lease operating and production expenses;

 

    general and administrative expenses; and

 

    Adjusted EBITDAX.

Recent Developments Regarding Lonestar Properties

Eagle Ford Shale Trend—Western Region

Asherton

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

Beall Ranch

In Dimmit County, Lonestar drilled and completed the Beall Ranch #20H - #22H with an average perforated interval of 6,075 feet in the first quarter of 2016. The three new wells were fracture stimulated with an average proppant concentration of 1,520 pounds per foot, and commenced flowback in late first

 

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quarter of 2016. These were the first three wells completed in partnership with Schlumberger as part of the companies’ GECA. While still preliminary, the production results during the first 150 days onstream are encouraging, as the cumulative production is 14% higher than that of the #26H - #28H wells, drilled 12 months prior, when compared on a bbl-per-lateral-foot basis for the same period of time. The #26H-#28H wells utilized certain elements of the GECA, which Lonestar believes were significant contributors to the 43% outperformance as compared to the offsets, the #32H-#34H, which were completed in July, 2015. In total, through two iterations of technology improvements, Lonestar has achieved a 62% improvement in cumulative oil production per lateral foot. Lonestar is encouraged by the results of the GECA to date, and will seek to apply them across its portfolio.

Burns Ranch Area

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

Horned Frog

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

Eagle Ford Shale Trend—Central Region

Southern Gonzales County

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

 

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Eagle Ford Shale Trend—Eastern Region

Brazos & Robertson Counties

In central Brazos County, Lonestar permitted two 8,000-foot laterals with the Texas Railroad Commission and on March 8, 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/d. Lonestar currently plans to drill these wells in the fourth quarter of 2016.

Factors Affecting the Comparability of Our Financial Condition and Results of Operations

Our financial condition and results of operations may not be comparable to the historical financial condition and results of operations of our Predecessor for the periods presented, primarily for the reasons described below:

Recent Events and Formation Transactions

The Company was incorporated as a Delaware corporation in December 2015 and does not have historical financial operating results. As a result, our accounting predecessor for all periods presented herein is the Predecessor which is an Australian company. The historical results of our operations are based on the financial statements of our accounting Predecessor prior to our Reorganization as described in “Recent and Formation Transactions.”

U.S. Reporting Company Expenses

Prior to our Reorganization, the ordinary shares of our Predecessor were listed on the ASX. Upon effectiveness of our registration statement on Form 10, our Class A common stock was listed on NASDAQ and we became subject to the periodic reporting requirements of the Exchange Act. Although we have been listed on the ASX and have been required to file financial information and make certain other filings with the ASX, our status as a U.S. reporting company under the Exchange Act will cause us to incur additional legal, accounting and other expenses that we have not previously incurred, including costs related to compliance with the requirements of the Sarbanes-Oxley Act of 2002. These incremental legal and financial compliance expenses are not included in our historical results of operations; therefore, our results of operations for future periods may not be comparable to our results of operations for the periods under review.

EBITDAX

EBITDAX is a supplemental, non-GAAP measure and is defined as our earnings before interest expense, income taxes, depreciation, depletion and amortization, property impairments, gain (loss) on sale of non-current assets, exploration expense, share-based compensation and income and gains and losses on commodity hedging net of settlements of commodity hedging. We use this non-GAAP measure primarily to compare our results with other companies in the industry that make a similar disclosure. We note, however, because EBITDAX is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.

 

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Operating Results

The following discussion relates to our Predecessor’s 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.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

Net Production

 

     For the Six Months Ended
June 30,
        
         2016              2015          % Change  

Crude Oil (Bbls/d):

        

Eagle Ford Shale

     3,338         3,716         -10

Conventional

     358         394         -9
  

 

 

    

 

 

    

 

 

 

Total Crude Oil

     3,696         4,110         -10
  

 

 

    

 

 

    

 

 

 

Natural Gas Liquids (Bbls/d):

        

Eagle Ford Shale

     1,211         579         109

Conventional

     11         14         -21
  

 

 

    

 

 

    

 

 

 

Total NGLs

     1,222         593         106
  

 

 

    

 

 

    

 

 

 

Natural Gas (Mcf/d):

        

Eagle Ford Shale

     8,548         4,052         111

Conventional

     1,326         1,787         -26
  

 

 

    

 

 

    

 

 

 

Total Natural Gas

     9,874         5,839         69
  

 

 

    

 

 

    

 

 

 

Oil Equivalent (Boe/d):

        

Eagle Ford Shale

     5,974         4,971         20

Conventional

     590         705         -16
  

 

 

    

 

 

    

 

 

 

Total Oil Equivalent

     6,564         5,676         16
  

 

 

    

 

 

    

 

 

 

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

 

    Net production from our Eagle Ford Shale assets averaged approximately 5,974 Boe/d in the six months ended June 30, 2016, a 20% increase over the approximate 4,971 Boe/d in the six months ended June 30, 2015. Approximately 76% of our Eagle Ford production in the six months ended June 30, 2016 was liquid hydrocarbons.

 

    Net production from our Conventional properties decreased 16% from 705 Boe/d in the six months ended June 30, 2015 to 590 Boe/d in the six months ended June 30, 2016 due to natural declines and curtailment of gas sales in the West Texas and East Texas areas. Approximately 63% of our production from our Conventional properties during the six months ended June 30, 2016 was liquid hydrocarbons.

 

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Average Sales Price

 

     For the Six Months Ended
June 30,
        
             2016                      2015              % Change  

Crude Oil ($/Bbls):

        

Eagle Ford Shale

   $ 35.91       $ 50.61         -29

Conventional

     35.30         49.66         -29
  

 

 

    

 

 

    

 

 

 

Total Crude Oil

   $ 35.85       $ 50.52         -29
  

 

 

    

 

 

    

 

 

 

Natural Gas Liquids ($/Bbls):

        

Eagle Ford Shale

   $ 7.31       $ 10.24         -29

Conventional

     5.98         15.38         -61
  

 

 

    

 

 

    

 

 

 

Total NGLs

   $ 7.30       $ 10.38         -30
  

 

 

    

 

 

    

 

 

 

Natural Gas ($/Mcf):

        

Eagle Ford Shale

   $ 1.79       $ 2.24         -20

Conventional

     1.95         2.57         -24
  

 

 

    

 

 

    

 

 

 

Total Natural Gas

   $ 1.81       $ 2.34         -23
  

 

 

    

 

 

    

 

 

 

Oil Equivalent ($/Boe):

        

Eagle Ford Shale

   $ 24.11       $ 40.82         -41

Conventional

     25.92         34.51         -25
  

 

 

    

 

 

    

 

 

 

Total Oil Equivalent, excluding the effect from hedging

   $ 24.28       $ 40.03         -39
  

 

 

    

 

 

    

 

 

 

Total Oil Equivalent, including the effect from hedging

   $ 38.12       $ 57.69         -34
  

 

 

    

 

 

    

 

 

 

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

 

    The average wellhead price for our Eagle Ford Shale production in the six months ended June 30, 2016 was $24.11 per Boe, which was 41% lower than the average price in the comparable period in 2015 due to the significant decline in the crude oil and natural gas benchmarks.

 

    The average wellhead price for our Conventional properties in the six months ended June 30, 2016 was $25.92 per Boe, which was 25% lower than the average price in the comparable period in 2015 due to the significant decline in WTI pricing.

 

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Revenues

 

     For the Six Months Ended
June 30,
        

($ in thousands)

           2016                      2015              % Change  

Oil Revenues:

        

Eagle Ford Shale

   $ 21,817       $ 34,018         -36

Conventional

     2,302         3,541         -35
  

 

 

    

 

 

    

 

 

 

Total Oil Revenues

   $ 24,119       $ 37,559         -36

NGLs Revenues:

        

Eagle Ford Shale

   $ 1,611       $ 1,078         49

Conventional

     12         44         -73
  

 

 

    

 

 

    

 

 

 

Total NGLs Revenues

   $ 1,623       $ 1,122         45

Natural Gas Revenues:

        

Eagle Ford Shale

   $ 2,787       $ 1,649         69

Conventional

     470         830         -43
  

 

 

    

 

 

    

 

 

 

Total Natural Gas Revenues

   $ 3,257         2,479         31

Total Wellhead Revenues:

        

Eagle Ford Shale

   $ 26,215       $ 36,745         -29

Conventional

     2,784         4,415         -37
  

 

 

    

 

 

    

 

 

 

Total Wellhead Revenues

   $ 28,999       $ 41,160         -30
  

 

 

    

 

 

    

 

 

 

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

 

    Wellhead revenues for our Eagle Ford Shale assets decreased $10.5 million (-29%) in the six months ended June 30, 2016 to $26.2 million from the comparable period in 2015 as a result of a 41% decrease in wellhead price realizations but partially offset by a 20% increase in production in the six months ended June 30, 2016.

 

    Wellhead revenues for our Conventional properties decreased $1.6 million (-37%) in the six months ended June 30, 2016 to $2.8 million from the comparable period in 2015 as a result of a 25% decrease in wellhead price realizations and a -16% decrease in production.

Costs and Expenses

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

 

     For the Six Months Ended
June 30,
        
(In thousands, except expense per BOE)            2016                      2015              % Change  

Operating Expenses:

        

Lease operating and gas gathering

   $ 8,758       $ 8,050         9

Production, ad valorem, and severance taxes

     2,139         2,827         -24

Depreciation, depletion and amortization

     27,743         26,145         6

General and administrative

     5,631         4,696         20

Rig standby expense

     1,897         —           —     

Operating Expenses per BOE:

        

Lease operating and gas gathering

   $ 7.33       $ 7.83         -6

Production, ad valorem, and severance taxes

     1.79         2.75         -35

General and administrative

     4.71         4.57         3

 

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

Severance and Ad Valorem Taxes.

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

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

Rig Standby Expense.

During the six months ended June 30, 2016, we incurred rig standby expense of $1.9 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 units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.

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

 

     For the Six Months Ended
June 30,
 
           2016                  2015        
     (In thousands)  

DD&A of proved oil and gas properties

   $ 27,341       $ 25,822   

Depreciation of other property and equipment

     295         217   

Accretion of asset retirement obligations

     107         106   
  

 

 

    

 

 

 

Depreciation, Depletion and Amortization

   $ 27,743       $ 26,145   
  

 

 

    

 

 

 

 

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General and Administrative (G&A) Expenses.

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

Interest Expense.

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

 

     For the Six Months Ended
June 30,
 
         2016              2015      
     (In thousands)  

Interest expense on Senior Notes

   $ 9,625       $ 9,625   

Interest expense on revolving credit facility

     1,566         1,140   

Amortization of debt issuance cost, premiums, and discounts

     1,089         1,038   

Other interest expense

     19         16   
  

 

 

    

 

 

 

Interest expense, net

   $ 12,299       $ 11,819   
  

 

 

    

 

 

 

Gains (Losses) on Derivative Financial Instruments.

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

Income Taxes.

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

Net Income (Loss) Before Taxes.

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

 

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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Net Production

 

     For the Year Ended
December 31,
        
         2015              2014          % Change  

Crude Oil (Bbls/d):

        

Eagle Ford Shale

     3,843         2,833         36

Conventional

     373         434         -14
  

 

 

    

 

 

    

 

 

 

Total Crude Oil

     4,216         3,267         29
  

 

 

    

 

 

    

 

 

 

Natural Gas Liquids (Bbls/d):

  

  

Eagle Ford Shale

     864         423         104

Conventional

     13         13         3
  

 

 

    

 

 

    

 

 

 

Total NGLs

     877         436         101
  

 

 

    

 

 

    

 

 

 

Natural Gas (Mcf/d):

        

Eagle Ford Shale

     6,224         3,277         90

Conventional

     1,663         1,387         20
  

 

 

    

 

 

    

 

 

 

Total Natural Gas

     7,887         4,664         69
  

 

 

    

 

 

    

 

 

 

Oil Equivalent (Boe/d):

        

Eagle Ford Shale

     5,744         3,802         51

Conventional

     663         678         -2
  

 

 

    

 

 

    

 

 

 

Total Oil Equivalent

     6,407         4,480         43
  

 

 

    

 

 

    

 

 

 

Our production increased 43% from an average of 4,480 Boe/d during the year ended December 31, 2014 to an average of 6,407 Boe/d during the year ended December 31, 2015. The increase in our average daily production is the result of an effective drilling program. For the year ended December 31, 2015, approximately 66% of our production was crude oil, 14% was NGLs and 20% was natural gas.

 

    Net production from our Eagle Ford Shale assets averaged approximately 5,744 Boe/d in the year ended December 31, 2015, a 51% increase over the approximate 3,802 Boe/d in the year ended December 31, 2014. Approximately 79% of our Eagle Ford production in the year ended December 31, 2015 was liquid hydrocarbons.

 

    Net production from our conventional properties decreased 2% from 678 Boe/d in the year ended December 31, 2014 to 663 Boe/d in the year ended December 31, 2015. Approximately 58% of our production from our Conventional properties during the year ended December 31, 2015 was liquid hydrocarbons.

 

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Average Sales Price

 

     For the Year Ended
December 31,
        
     2015      2014      % Change  

Crude Oil ($/Bbls):

        

Eagle Ford Shale

   $ 45.96       $ 87.34         -47

Conventional

     45.61         87.89         -48
  

 

 

    

 

 

    

 

 

 

Total Crude Oil

   $ 45.93       $ 87.41         -47
  

 

 

    

 

 

    

 

 

 

Natural Gas Liquids ($/Bbls):

        

Eagle Ford Shale

   $ 12.56       $ 29.08         -57

Conventional

     18.87         35.06         -46
  

 

 

    

 

 

    

 

 

 

Total NGLs

   $ 12.66       $ 29.26         -57
  

 

 

    

 

 

    

 

 

 

Natural Gas ($/Mcf):

        

Eagle Ford Shale

   $ 2.30       $ 4.04         -43

Conventional

     2.71         5.59         -52
  

 

 

    

 

 

    

 

 

 

Total Natural Gas

   $ 2.39       $ 4.50         -47
  

 

 

    

 

 

    

 

 

 

Oil Equivalent ($/Boe):

        

Eagle Ford Shale

   $ 35.13       $ 71.78         -51

Conventional

     32.82         68.37         -52
  

 

 

    

 

 

    

 

 

 

Total Oil Equivalent, excluding the effect from hedging

   $ 34.89       $ 71.27         -51
  

 

 

    

 

 

    

 

 

 

Total Oil Equivalent, including the effect from hedging

   $ 50.43       $ 72.01         -30
  

 

 

    

 

 

    

 

 

 

The average wellhead price for our production in the year ended December 31, 2015 was $34.89 per Boe, which was 51% lower than the average price in the comparable period in 2014. Reported wellhead realizations were driven lower by significant declines (30 - 50%) in both the crude oil and natural gas benchmarks between the periods. While benchmark prices fell sharply, our revenues were bolstered by crude oil hedge positions, which added $23.61 per bbl to crude oil price realization.

 

    The average wellhead price for our Eagle Ford Shale production in the year ended December 31, 2015 was $35.13 per Boe, which was 51% lower than the average price in the comparable period in 2014 due to the significant decline in the crude oil and natural gas benchmarks.

 

    The average wellhead price for our Conventional properties in the year ended December 31, 2015 was $32.82 per Boe, which was 52% lower than the average price in the comparable period in 2014 due to the significant decline in WTI pricing.

 

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Revenues

 

     For the Year Ended
December 31,
        

($ in thousands)

   2015      2014      % Change  

Oil Revenues:

        

Eagle Ford Shale

   $ 64,492       $ 90,296         -29

Conventional

     6,247         13,937         -55
  

 

 

    

 

 

    

 

 

 

Total Oil Revenues

   $ 70,739       $ 104,233         -32

NGLs Revenues:

        

Eagle Ford Shale

   $ 1,928       $ 3,732         -49

Conventional

     0         72        
  

 

 

    

 

 

    

 

 

 

Total NGLs Revenues

   $ 1,928       $ 3,804         -47

Natural Gas Revenues:

        

Eagle Ford Shale

   $ 5,185       $ 4,766         8

Conventional

     1,638         2,824         -43
  

 

 

    

 

 

    

 

 

 

Total Natural Gas Revenues

   $ 6,823         7,590         -11

Total Wellhead Revenues:

        

Eagle Ford Shale

   $ 71,605       $ 98,794         -28

Conventional

     7,885         16,833         -53
  

 

 

    

 

 

    

 

 

 

Total Wellhead Revenues

   $ 79,490       $ 115,627         -31
  

 

 

    

 

 

    

 

 

 

While wellhead revenue declined $36.1 million (31%) in the year ended December 31, 2015 compared to the comparable period in 2014 due to the significant decrease in benchmark prices, we realized a favorable crude oil hedge, which added $36.3 million in gains on commodity derivatives for the year ended December 31, 2015.

 

    Wellhead revenues for our Eagle Ford Shale assets decreased $27.2 million (28%) in the year ended December 31, 2015 from the comparable period in 2014 as a result of a 50% decrease in wellhead price realizations but partially offset by a 51% increase in production in the year ended December 31, 2015.

 

    Wellhead revenues for our Conventional properties decreased $8.9 million (53%) in the year ended December 31, 2015 from the comparable period in 2014 as a result of a 55% decrease in wellhead price realizations.

Operating Costs and Expenses

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

 

     For the Year
Ended December 31,
        
(In thousands, except expense per BOE)    2015      2014      % Change  

Operating Expenses:

        

Lease operating and gas gathering

   $ 17,190       $ 16,632         7

Production, ad valorem, and severance taxes

     4,982         7,123         -30

Depreciation, depletion and amortization

     58,828         40,522         45

General and administrative

     10,825         8,913         20

Rig standby expense

     663         —          

Operating Expenses per BOE:

        

Lease operating and gas gathering

   $ 7.35       $ 10.17         -25

Production, ad valorem, and severance taxes

     2.13         4.35         -51

General and administrative

     4.62         5.45         -15

 

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Lease Operating 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 increased slightly in the year ended December 31, 2015 from the comparable period in 2014 as we controlled costs. Costs were controlled by developing experienced field staff, by upgrading our preventative maintenance activities and by more effective use and centralized purchasing of chemicals, among other activities. On a units-of-production basis, our lease operating expenses declined 28% from $10.17 per Boe in the year ended December 31, 2014 to $7.35 per Boe in the year ended December 31, 2015. While lease operating expenses remained virtually unchanged in absolute dollar terms, given the increase in production, lease operating expenses on a units-of-production basis dropped significantly.

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 and ad valorem taxes declined $2.1 million (30%) in the year ended December 31, 2015 from the comparable period in 2014 principally due to the 30% decline in wellhead revenues.

Rig Standby Expense.

During the year ended December 31, 2015, we incurred rig standby expense of $0.7 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 units-of-production method aggregating properties on a field basis. For leasehold acquisition costs and the cost to acquire proved properties, the reserve base used to calculate depreciation and depletion is the sum of proved developed reserves and proved undeveloped reserves. For development costs, the reserve base used to calculate depletion and depreciation is proved developed reserves only. Other property and equipment are carried at cost, and depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years.

DD&A increased $18.3 million (45%) in the year ended December 31, 2015 from the comparable period in 2014 primarily due to the 43% increase in total oil equivalent produced in the year ended December 31, 2015.

 

     Twelve Months Ended
December 31,
 
     2015      2014  
     (In thousands)  

DD&A of proved oil and gas properties

   $ 58,348       $ 40,149   

Depreciation of other property and equipment

     480         372   

Accretion of asset retirement obligations

     214         201   
  

 

 

    

 

 

 

Depreciation, Depletion and Amortization

   $ 59,041       $ 40,723   
  

 

 

    

 

 

 

 

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General and Administrative (G&A) Expenses

G&A increased $1.9 million (21%) in the year ended December 31, 2015 from the comparable period in 2014 primarily due to the general and administrative expenses necessary to support higher production. Included in the 2015 G&A expense was approximately $1.0 million of legal and audit expenses associated with the company’s efforts to re-domicile to the United States, and list on NASDAQ. As we scale the business, we achieved a 15% decrease in G&A per Boe to $4.62 per Boe in the year ended December 31, 2015 from $5.45 per Boe in the year ended December 31, 2014.

Interest Expense

Our interest expense increased $4.6 million (23%) in the year ended December 31, 2015 from the comparable period in 2014 primarily due to (i) interest on the Notes, which were issued in April 2014, accruing the entire year for 2015 but only partially during the year ended December 31, 2014 and (ii) a non-cash write-off of approximately $0.7 million of deferred financing costs associated with the extinguishment of our previous credit facility that was replaced by a Citibank-led facility in July 2015.

Net borrowings under our credit facilities averaged $78.9 million in the year ended December 31, 2015 and the weighted average interest rate on outstanding borrowings was 2.6% during the year. Net borrowings under our credit facilities averaged $43 million in the year ended December 31, 2014 and the weighted average interest rate on outstanding borrowings was 2.95% during the year.

 

     Twelve Months Ended
December 31,
 
     2015      2014  
     (In thousands)  

Interest expense on Senior Notes

   $ 19,250       $ 14,277   

Interest expense on revolving credit facility

     2,470         2,162   

Amortization of debt issuance cost, premiums, and discounts

     2,824         3,481   

Other interest expense

     32         30   
  

 

 

    

 

 

 

Interest expense, net

   $ 24,576       $ 19,950   
  

 

 

    

 

 

 

Commodity Derivative Transactions

We apply mark-to-market accounting to our derivative contracts. In the year ended December 31, 2015, we recognized a non-cash $8.7 million loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $36.3 million realized gain on settlement of our commodity derivative contracts. Settlement of the crude oil hedge positions added $23.68 per bbl to crude oil price realization. The crude oil hedge positions settled covered 64% of total crude oil production for the year ended December 31, 2015, and provided a $37.01 positive delta to benchmark pricing based on our weighted average hedge contract price of $85.87.

In the year ended December 31, 2014, we recognized a non-cash $42.8 million gain on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $1.2 million realized gain on settlement of our commodity derivative contracts. The crude oil hedge positions settled covered 74% of total crude oil production for the year ended December 31, 2014, and provided a $1.44 positive delta to benchmark pricing based on our weighted average hedge contract price of $95.58.

Income Taxes

As a result of the net loss before income tax of $42.5 million in 2015 and net income before tax of $58.9 million in 2014, we recorded income tax benefit of $15.1 million in 2015 and an income tax expense of $22.4 million in 2014.

 

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Net Income (Loss) Before Taxes

As a result of the above factors, and particularly the $36.1 million (31%) decrease in revenue resulting from the decline in crude oil and natural gas benchmark prices, we recorded a net loss before income tax of $42.5 million in the year ended December 31, 2015 compared to net income of $58.9 million in the year ended December 31, 2014.

Liquidity and Capital Resources

We expect that our primary sources of liquidity and capital resources will be cash flows generated by operating activities and borrowings under our revolving credit facility. We have historically financed our acquisition and development activity through cash flows generated by operating activities, borrowings under our revolving credit facility, and the issuance of bonds.

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

Our Revolving Credit Facility

On July 28, 2015, we entered into a senior secured revolving credit agreement (as amended, supplemented, or otherwise modified prior to the date hereof) with Citibank, N.A., or Citibank, as administrative agent for the several lenders, with a maximum revolving credit facility of $500 million subject to a borrowing base based, in part, on our oil and natural gas reserves. The borrowing base is subject to scheduled semi-annual redeterminations on or about May 1 and November 1 of each year, and other elective collateral borrowing base redeterminations. Effective May 19, 2016, we received notification that the borrowing base for our revolving credit facility was reduced to $120 million. Our next scheduled borrowing base redetermination is scheduled for November 1, 2016. As of June 30, 2016, we had $99.5 million outstanding under our revolving credit facility. Our revolving credit facility matures on October 16, 2018. Capitalized terms used in this section but not defined in this section shall have the meaning given such terms in the Credit Agreement.

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

Borrowings under our revolving credit facility, at our election, bear interest at either: (i) an alternate base rate (“ABR”) equal to the higher of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5% per annum, and (c) the adjusted LIBO rate of a three-month interest period in effect 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 or six 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 1.50% to 2.50% for ABR loans and from 2.50% to 3.50% for adjusted LIBO rate loans.

In connection with the revolving credit facility, certain subsidiaries of the Company unconditionally guaranteed our indebtedness, obligations, and liabilities arising under or in connection with our revolving credit facility.

Subject to certain permitted liens, our obligations under the revolving credit facility have been secured by the grant of a first priority lien on no less than 90% of the value of our proved oil and gas properties. Our revolving credit facility requires we maintain certain financial ratios and contains restrictive covenants that may limit our ability to, among other things:

 

    incur additional indebtedness;

 

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    sell assets;

 

    make loans to others;

 

    make investments;

 

    enter into mergers;

 

    make or declare dividends;

 

    enter into transactions with affiliates;

 

    alter the business we conduct;

 

    hedge future production or interest rates;

 

    incur liens; and

 

    engage in certain other transactions without the prior consent of the lenders.

Effective as of July 27, 2016, our revolving credit agreement was further amended to, among other things, permit us to incur the second lien obligations contemplated by the Purchase Agreement and for the contemplated use of proceeds thereof.

The Notes

On April 4, 2014, the Company issued $220,000,000 aggregate principal amount of Notes. Interest is payable on the Notes semi-annually in arrears on April 15 and October 15 of each year until the maturity date. The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each subsidiary of LRAI. The issuance of these notes resulted in net proceeds, after discounts and offering expenses, of approximately $212 million which proceeds were used to repay a portion of our revolving credit facility, all outstanding borrowings, accrued interest and a prepayment penalty under our second lien term loan, and for general corporate purposes. The second lien term loan was terminated upon prepayment.

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

 

Year

   Percentage  

2016

     106.563

2017

     104.375

2018 and thereafter

     100.000

In addition, upon a change of control of the Company, holders of the Notes will have the right to require us to repurchase all or any part of their Notes for cash at a price equal to 101% of the aggregate principal amount of the Notes repurchased, plus any accrued and unpaid interest.

The indenture governing the Notes restricts our ability and the ability of certain of our subsidiaries to, among other things, limit the ability to: (i) incur indebtedness; (ii) pay dividends or make other distributions on stock; (iii) purchase or redeem stock or subordinated indebtedness; (iv) make investments; (v) create liens; (vi) enter into transactions with affiliates; (vii) sell assets; (viii) refinance certain indebtedness; and (ix) I’s assets.

Working Capital

Our working capital, which we define as current assets minus current liabilities, totaled $3.6 million and $14.5 million as of June 30, 2016 and December 31, 2015, respectively. Our collection of receivables has

 

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historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash balances totaled $5.1 million and $4.3 million as of June 30, 2016 and December 31, 2015, respectively. Due to the amounts that accrue related to our drilling program, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our credit agreement after application of the estimated net proceeds from this offering, as described under “Use of Proceeds,” will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

Cash Flows

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

 

     For the Six Months Ended
June 30,
    For the Twelve Months Ended
December 31,
 

($ in thousands)

         2016                 2015                   2015                     2014          

Statement of Cash Flows Data:

        

Net cash provided by (used in):

        

Operating activities

   $ 7,533      $ 25,628      $ 50,839      $ 82,227   

Investing activities

     (19,177   $ (58,190     (94,519     (233,045

Financing activities

     12,485        26,985        37,997        154,470   

Effect of exchange rate changes on cash and cash equivalents

     (16     1        12.3        (404.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

   $ 825      $ (5,576   $ (5,671   $ 3,248   
  

 

 

   

 

 

   

 

 

   

 

 

 

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

Net cash provided by operating activities decreased $31.3 million from $82.2 million in the year ended December 31, 2014 to $50.9 million in the year ended December 31, 2015. This decrease is primarily due to a $63.8 million decline in net income (resulting in a net loss of $27.3 million) and a $26.0 million decrease in net operating assets and liabilities, offset by an $18.3 million increase in DD&A. We also experienced a $16.4 million increase in gain on derivative financial instruments and an increase of $23.1 million in impairment of oil and gas properties.

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

Net cash used in investing activities decreased $138.5 million from $233.0 million in the year ended December 31, 2014 to $94.5 million in the year ended December 31, 2015. This decrease is primarily due to (i) a $62.3 million decrease in the acquisition of oil and gas properties and (ii) a $78.7 million decrease in the development of oil and gas properties, partially offset by a decrease of $3.2 million in proceeds from the sale of oil and gas properties.

Net Cash Provided By Financing Activities. Net cash provided by financing activities decreased $14.5 million from $27.0 million provided during the six months ended June 30, 2015 to $12.5 million provided in the

 

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six months ended June 30, 2016. The decrease was due to a decrease in borrowings of $8.5 million and a payment on bank borrowings exceeding proceeds from bank borrowings of $6.0 million in the six months ended June 30, 2016. During the six months ended June 30, 2015 the Company reported borrowings of $23.5 million.

Net cash provided by financing activities decreased $116.5 million from $154.5 million in the year ended December 31, 2014 to $38.0 million in the year ended December 31, 2015. The decrease was principally due to the receipt of $214.5 million from the sale of 8.750% Senior Notes due 2019 in 2014, partially offset by a net change in bank borrowings of $98.0 million.

Contractual Obligations

The following table summarizes our contractual obligations as of June 30, 2016.

 

     Payments due by period  

($ in thousands)

   Total      Less than
1 year
     1 - 2 years      3 - 5 years      More than
5 years
 

Revolving credit facility(1)

   $ 99,500       $ —         $ —         $ 99,500       $ —     

8.750% Senior Notes due 2019

     220,000         —           —           220,000         —     

Interest on 8.750% Senior Notes due 2019

     57,750         19,250         19,250         19,250         —     

Drilling rig commitment

     300         300         —           —           —     

Office Lease

     2,330         467         434         845         584   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 379,880       $ 20,017       $ 19,684       $ 339,595       $ 584   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) These amounts do not include any estimated interest on these borrowings, because our revolving borrowings have short-term interest periods, and we are unable to determine what our borrowing costs may be in future periods.

Capital Expenditures

Historical capital expenditures

The table below summarizes our capital expenditures incurred for the six months ended June 30, 2016 and years ended December 31, 2014 and 2015.

 

     Six Months Ended
June 30, 2016
(unaudited)
     Year ended December 31,  

($ in thousands)

            2015                  2014        

Acquisitions of oil and gas properties

     2,717         8,723         70,978   

Development of oil and gas properties

     19,003         85,458         164,181   

Purchase of other property and equipment

     177         337         1,086   
  

 

 

    

 

 

    

 

 

 

Total Capital Expenditures

   $ 21,897       $ 94,519       $ 236,245   
  

 

 

    

 

 

    

 

 

 

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to a variety of financial market risks including interest rate, commodity prices, foreign exchange and liquidity risk. Our risk management focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. We utilize derivative financial instruments to hedge certain risk exposures. Our financial instruments consist mainly of deposits with banks, short-term investments, accounts receivable, derivative financial instruments, finance facility and payables. The main purpose of non-derivative financial instruments is to raise finance for our operations.

Financial risk management is carried out by our management. Our board of directors sets financial risk management policies and procedures to which our management is required to adhere. Our management identifies

 

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and evaluates financial risks and enters into financial risk instruments to mitigate these risk exposures in accordance with the policies and procedures outlined by our board of directors.

Commodity Price Risk

As a result of our operations, we are exposed to commodity price risk arising from fluctuations in the prices of crude oil, NGLs and natural gas. The demand for, and prices of, crude oil, NGLs and natural gas, are dependent on a variety of factors, including supply and demand, weather conditions, the price and availability of alternative fuels, actions taken by governments and international cartels and global economic and political developments.

Our board of directors actively reviews oil and natural gas hedging on a monthly basis. Reports providing detailed analysis of our hedging activity are continually monitored. We sell our oil and natural gas on market using NYMEX market spot rates reduced for basis differentials in the basins from which we produce. We use forward contracts to manage our commodity price risk exposure.

Our primary commodity risk management objective is to reduce volatility in our cash flows. Management makes recommendations on hedging that are approved by the board of directors before implementation. We enter into hedges for oil using NYMEX futures or over-the-counter derivative financial instruments with only certain well-capitalized counterparties which have been approved by our board of directors. Historically we have not sought to hedge the price of our natural gas or NGL production.

Presently, all of our hedging arrangements are concentrated with three counterparties, each of which are lenders under our revolving credit facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.

The result of oil market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

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

 

Settlement Period

  

Derivative Instrument

  

Total Volume

   Fixed Price  

July – December 2016

  

Oil – WTI Fixed Price Swap

  

99,000 BBL

     $84.45   

July – December 2016

  

Oil – WTI Fixed Price Swap

  

144,600 BBL

     90.45   

July – December 2016

  

Oil – WTI Fixed Price Swap

  

59,800 BBL

     63.20   

July – December 2016

  

Oil – WTI Fixed Price Swap

  

78,300 BBL

     56.90   

July – December 2016

  

Oil – WTI Fixed Price Swap

  

113,550 BBL

     42.11   

January – December 2017

  

Oil – WTI Fixed Price Swap

  

109,500 BBL

     51.05   

January – December 2017

  

Oil – WTI Fixed Price Swap

  

73,000 BBL

     50.60   

 

Instrument

   Total Volume    Settlement Period    Puts      Calls  

Oil – 3 Way Collar

   365,100 BBL    January – December 2017    $ 40.00 / 60.00       $ 85.00   
  

 

  

 

  

 

 

    

 

 

 

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

 

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Counterparty and Customer Credit Risk

In connection with our hedging activity, we have exposure to financial institutions in the form of derivative transactions. The counterparties on our derivative instruments currently in place have investment-grade credit ratings. We expect that any future derivative transactions we enter into will be with these counterparties or our lenders under our credit facilities that will carry an investment-grade credit rating.

We are also subject to credit risk due to concentration of our oil and natural gas receivables with certain significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. We review the credit rating, payment history and financial resources of our customers, but we do not require our customers to post collateral.

Interest Rate Risk

As of June 30, 2016, we had $99.5 million outstanding under our revolving credit facility, which is subject to floating market rates of interest. Borrowings under our revolving credit facility bear interest at a fluctuating rate that is tied to an adjusted base rate or LIBOR, at our option. Any increase in this interest rate can have an adverse impact on our results of operations and cash flow. Based on borrowings outstanding at June 30, 2016, a 100 basis point change in interest rates would change our annualized interest expense by approximately $1.0 million.

Critical Accounting Policies and Estimates

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

Estimates of Reserve Quantities

Reserve estimates are inexact and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated. All reserve reports prepared by the independent third-party reserve engineers are reviewed by our senior management team, including the Chief Executive Officer and Senior Vice President-Operations. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can

 

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lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods. A 10% increase or decrease in our estimates of total proved reserves at December 31, 2015 would have decreased or increased our DD&A expense of proved oil and gas properties by approximately $5.2 million or 9% or $6.4 million or 11%, respectively, for the year ended December 31, 2015.

Oil and Natural Gas Properties

We use the successful efforts method of accounting to account for our oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Our policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive.

Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-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.

Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors.

It is common for operators of oil and natural gas properties to request that joint interest owners pay for large expenditures, typically for drilling new wells, in advance of the work commencing. This right to call for cash advances is typically found in the joint operating agreement that joint interest owners in a property adopt. As an operator, we record these advance payments in other current liabilities and relieve this account when the actual expenditure is billed by us in the monthly joint interest billing statement.

On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.

Impairment of Long-Lived Assets

The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment. ASC 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or changes in circumstances indicate that

 

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the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.

Under ASC 360, the Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows.

Derivative Financial Instruments

We use derivative financial instruments to hedge our exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity price swap, option and costless collar contracts. The use of these instruments is subject to policies and procedures as approved by our board directors. We do not trade in derivative financial instruments for speculative purposes. None of our derivative contracts have been designated as cash flow hedges for accounting purposes. Derivative financial instruments are initially recognized at cost, if any, which approximates fair value. Subsequent to initial recognition, derivative financial instruments are recognized at fair value. The derivatives are valued on a mark-to-market valuation, and the gain or loss on re-measurement to fair value is recognized through the statement of operations. The estimated fair value of our derivative instruments requires substantial judgment. These values are based upon, among other things, option pricing models, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

The counterparties to our derivative instruments are not known to be in default on their derivative positions. However, we are exposed to credit risk to the extent of nonperformance by the counterparty in the derivative contracts. We believe credit risk is minimal and do not anticipate such nonperformance by such counterparties.

Asset Retirement Obligations (ARO)

We account for asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statement of operations. The estimation of future costs associated with the dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirement, technological advances and other factors that are difficult to predict.

There are many variables in estimating AROs. We primarily use the remaining estimated useful life from the year-end independent third-party reserve reports in estimating when abandonment could be expected for each property based on field or industry practices. We expect to see our calculations impacted significantly if interest rates move from their current levels, as the credit-adjusted-risk-free-rate is one of the variables used on a quarterly basis. Our technical team has developed a standard cost estimate based on the historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging cost to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of an inflation factor and a discount factor, could differ from actual results.

 

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Income Taxes

We follow the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Changes in our expectations regarding our future taxable income (which is materially impacted by volatility in commodity prices), can result in our recording of a valuation allowance against our deferred tax assets. We would record this valuation allowance when our judgment is that our existing U.S. federal net operating loss carryforwards are not, on a more-likely-than-not basis, recoverable in future years. We will continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.

We evaluate uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements.

Recently Issued Accounting Pronouncements

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

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

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

In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing,

 

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and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted, but only for fiscal years beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method of adoption. Management is currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption.

In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for any entity in any interim or annual period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. Management is currently evaluating what the effects of adopting this updated guidance will be on its 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 was effective for the Company on January 1, 2016. The Company’s adoption of this guidance was applied retrospectively and did not have a material impact on the Company’s consolidated financial statements.

Internal Controls and Procedures

Section 404(a) of the Sarbanes-Oxley Act requires that, beginning with our annual report for the year ending December 31, 2017, our management assess and report annually on the effectiveness of our internal controls over financial reporting and identify any material weaknesses in our internal controls over financial reporting. Once we are no longer a smaller reporting company, Section 404(b) of the Sarbanes-Oxley Act will require our independent registered public accounting firm to issue an annual report that addresses the effectiveness of our internal controls over financial reporting. We expect, however, to rely on the exemptions provided in the JOBS Act, and consequently will not be required to comply with SEC rules that implement Section 404(b) of the Sarbanes-Oxley Act until such time as we are no longer an emerging growth company.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2015 or 2014. Although the impact of inflation has

 

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been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

 

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BUSINESS

The following discussion should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus.

Business Overview

We are an independent oil and natural gas company, focused on the acquisition, development and production of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas, where we have accumulated approximately 40,271 gross (35,230 net) acres in what we believe to be the formation’s crude oil and condensate windows as of June 30, 2016.

Our primary operational focus is on our Eagle Ford Shale position in seven Texas counties. Our properties in the Eagle Ford Shale are divided into three distinct regions: Western Eagle Ford (comprised of Dimmit, La Salle and Frio Counties), Central Eagle Ford (comprised of Gonzales and Wilson Counties) and Eastern Eagle Ford (comprised of Brazos and Robertson Counties). As of June 30, 2016, we operated 100% of our Eagle Ford position and approximately 60% of our acreage was held by production, or HBP. We have identified 159 gross (143 net) horizontal drilling locations on our Eagle Ford Shale acreages. We also own 44,084 gross (28,655 net) undeveloped acres in the Bakken Three Forks formation in Roosevelt County, Montana, though we do not plan to make capital expenditures to develop this acreage in 2016.

We plan to invest substantially all of our 2016 capital budget for the horizontal development of our Eagle Ford Shale properties and have allocated between $35 million and $45 million to operate drilling and completion activities to develop these assets there. Our preliminary 2017 budget calls for us to spend between $62 million and $72 million to develop our Eagle Ford Shale properties of which $10 million is allocated for leasehold acquisition expenditures. We have historically grown our Eagle Ford leasehold position through acquisitions, organic leasing activities, farm-ins and other structures. We believe our management team’s extensive experience in the basin provides us with relationships and contacts that will provide us opportunities to grow our acreage footprint.

We seek to deploy advanced drilling, completion and production techniques across our unconventional acreage with a goal of minimizing completed well costs and maximizing per well hydrocarbon recoveries. Increasingly, we utilize 3-D seismic imaging to plan our lateral programs while utilizing log-based petrophysical analysis to optimize our drilling targets within distinct horizons within the Eagle Ford Shale section. We are also frequently drilling laterals in excess of 7,000 feet in an effort to maximize per-well recoveries. Further, we are utilizing thru-bit logging in our laterals to design non-geometric completions which allow for the use of diverters while increasing proppant concentrations in an effort to make our fracture stimulations more effective. Additionally, we employ active choke management to optimize pressure drawdowns in an effort to maximize liquid hydrocarbon recoveries.

Business Strategies

Our primary business objective is to increase reserves, production and cash flows at attractive rates of return on invested capital. We are focused on exploiting long-lived, unconventional oil, NGLs and natural gas reserves from the crude oil window of the Eagle Ford Shale. Key elements of our business strategy include:

 

    Develop our Eagle Ford Shale leasehold positions. We intend to develop our acreage position to maximize the value of our resource potential and generate returns for our stockholders through continuing to utilize best in class drilling and completion techniques at the lowest possible costs. Through the conversion of our resource base to developed reserves, we will seek to increase our production and cash flow, thereby increasing the value of our reserves. As of June 30, 2016, we were producing from 68 gross (61 net) Eagle Ford wells and we intend to deploy the large majority of our capital budget for 2016 and 2017 on the development of our Eagle Ford acreage.

 

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    Pursue strategic acquisitions, organic leasing and other structures to continue to develop and grow our production and leasehold position. We believe that we will be able to continue to identify and acquire additional acreage and producing assets in the Eagle Ford Shale. By leveraging our longstanding relationships in this area, we intend to expand our Eagle Ford shale acreage. We have increased our Eagle Ford Shale net acres by over eight times from 3,710 net acres in 2011 to 35,230 net acres as of June 30, 2016. We also intend to continue to find creative ways to fund our continued development while maintaining financial discipline and seeking to maximize returns from our projects. We have successfully used farm-ins and drilling commitments as means of adding prospective Eagle Ford Shale acreage by committing to drilling activity as opposed to deploying capital with lease acquisition costs. We also have a track record of executing on this strategy through our Joint Development Agreement with IOG Capital L.P., or IOG. This agreement allows for working interest level participation with IOG participating on a promoted basis for funding farm-ins. It is a wellbore only agreement that allows Lonestar to develop acreage or hold expiring acreage while maintaining some upside through a specified return hurdle earn-in and all of the upside associated with future development of offsetting wells.

 

    Leverage our extensive operational expertise and concentration of our operating areas to reduce costs and enhance returns. We are focused on continuously improving our operating measures. We intend to leverage the magnitude and concentration of our acreage within the Eagle Ford Shale in our operating areas, as well as our experience within our areas of operation to capture economies of scale, including by employing multiple-well pad drilling, and utilizing centralized production and fluid handling facilities. Our management and operating team has significant industry and operating experience, and it regularly evaluates our operating measures against those of other operators in our area in order to improve our performance and identify additional opportunities to optimize our drilling and completion techniques and make informed decisions about our capital expenditure program and drilling activity.

 

    Maintain operational control over our drilling and completion operations. We operate 100% of the Eagle Ford Shale wells in which we have a working interest and intend to maintain a high degree of operational control over substantially all of our producing locations. Moreover, we hold an average working interest of 87% in our Eagle Ford Shale leasehold. We believe this strategy allows us to manage the timing and levels of our development spending, while controlling the techniques used to drill and complete wells, as well as overall well costs and operating costs. We expect to operate the drilling and completion phase on approximately 100% of our identified drilling locations. Approximately 80% of our existing Eagle Ford net acreage that contains our Proved Reserves is HBP, and 60% of our existing Eagle Ford net acreage is HBP, and we anticipate that our current planned development program in 2016 and 2017 will be sufficient to maintain the majority of our acreage currently not HBP. We believe that continuing to exercise a high degree of control over our acreage position will provide us with flexibility to manage our drilling program and optimize our returns and profitability.

 

   

Maintain and enhance financial liquidity and flexibility. We intend to use cash on hand and borrowings from our revolving credit facility, combined with our cash flow from operations, to continue executing a capital expenditure program that we believe will result in steady growth of production, cash flow and proved reserves. Upon completion of this offering and the use of proceeds therefrom we will have $         million in cash and $         million available under our $120 million revolving credit facility to execute on the remainder of our 2016 and our 2017 capital budgets. Furthermore, we intend to continue to employ a hedging strategy on our PDP production to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in oil, NGLs and natural gas prices. We regularly assess the futures markets for opportunities to enter into additional hedging contracts. Generally, we have entered into additional hedges when we believe that they are additive to our borrowing base and/or lock-in rates of return which exceed our hurdle rates. Based on our 2017 drilling plans, current NYMEX strip oil and gas prices and our current hedge positions, we expect cash

 

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flow from operations to cover 70% to 80% of our 2017 budget. Further, we have strived to enter into unique and strategically effective arrangements to reduce our outstanding indebtedness and improve our financial liquidity. See “Recent Developments.” We intend to continue to seek out such opportunity to improve our balance sheet and financial flexibility.

 

    Optimize our current position and maximize cost-saving opportunities in response to oil price declines. We have moderated our drilling activity plans for 2016 in response to oil price declines that began in late 2014, and our revised plan is to complete 9 gross (6.7 net) wells in 2016. We believe that we are in a good position to be flexible due to our financial position, a $100 million joint development agreement entered into with IOG in July 2015, the absence of material drilling obligations and strong operational capabilities. We estimate production will be between 6,000 to 6,300 Boe/d in 2016, including the impact from asset sales.

Our Competitive Strengths

We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategy:

 

    Geographic focus in one of North America’s leading unconventional oil plays. We have assembled a leasehold position of approximately 35,230 net acres in the Eagle Ford Shale as of June 30, 2016. We believe this unconventional oil and natural gas formation has one of the higher rates of return among such formations in North America. In addition to leveraging our technical expertise in our project areas, our geographically-concentrated acreage position allows us to establish economies of scale with respect to drilling, production, operating and administrative costs. Based on our drilling and production results and well-established offset operator activity in and around our project areas, we believe there are relatively low geologic risks and ample repeatable drilling opportunities across our core operating areas in the Eagle Ford Shale where we have devoted almost all of our 2016 drilling capital budget.

 

    Experienced management team. Our top eight executives each average 30 years of industry experience. We have assembled what we believe to be a strong technical staff of geoscientists, field operations managers and engineers with significant experience drilling horizontal wells and with fracture stimulation of unconventional formations, which has resulted in reserve and production growth. In addition, our management team has extensive expertise and operational experience in the oil and natural gas industry with a proven track record of successfully negotiating, executing and integrating acquisitions. Members of our management team have previously held positions with major and large independent oil and natural gas companies.

 

    Demonstrated ability to increase acreage position and drive growth of oil production and reserves. We have increased our Eagle Ford Shale net acres by over eight times from 3,710 net acres in 2011 to 35,230 net acres as of June 30, 2016. We placed 16 gross (13 net) and 5 gross (4 net) Eagle Ford Shale wells onstream during 2015 and through June 30, 2016, respectively. We had a total of 68 gross (61 net) producing wells in the Eagle Ford, as of June 30, 2016. The resulting production rates achieved by this program increased Eagle Ford sales volumes by approximately 43% over 2014. Our average total production for 2015 was 6,407 Boe/d, of which 90% was from the Eagle Ford Shale. Moreover, between December 31, 2014 and December 31, 2015, our total proved reserves increased by approximately 30% from 31.0 MMBoe to 40.2 MMBoe, and our proved developed reserves increased by approximately 8% from 12.3 MMBoe to 13.3 MMBoe. Our three-year average reserve replacement ratio is approximately 400%, which we believe demonstrates our ability to grow reserves year over year. We believe the location and concentration of our project areas within the Eagle Ford provide us an opportunity to continue to increase production, lower costs and further delineate our proved reserves.

 

   

Demonstrated ability to adapt and employ leading drilling and completion techniques. We are focused on enhancing our drilling, completion and production techniques to maximize recovery of

 

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hydrocarbons. Industry techniques with respect to drilling and completion have significantly evolved over the past several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the implementation of longer laterals and more tightly spaced fracture stimulation stages. We continuously evaluate industry results and methods and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques will continue to improve and evolve. We have demonstrated a track record of innovation and operational improvement through our partnership with Schlumberger, the Geo-Engineered Completion Alliance (“GECA”). This Alliance utilizes a variety of technologies intended to focus our wells in precise, optimal intervals of the Eagle Ford Shale and utilize analysis of advanced logs run through the laterals to assist in the design of non-geometric fracture stimulation stages, which in combination with diverters, are intended to stimulate a greater percentage of the lateral on a cost-effective basis.

 

    Multi-year drilling inventory in existing and emerging resource plays. We have identified 159 gross (143 net) horizontal drilling locations on our Eagle Ford Shale acreage. As of June 30, 2016, these identified drilling locations included 59 gross (54 net) locations to which we have assigned proved undeveloped reserves. We have identified 9 gross (6.7 net) locations in the Eagle Ford Shale that we expect to drill in 2016, the completion of which would represent approximately 6% of our gross identified drilling locations in the Eagle Ford Shale at June 30, 2016. We believe our acreage is prospective for additional locations and plan to continue evaluating this acreage and monitoring industry activity in order to maximize our efficiency in developing this acreage. Furthermore, we are evaluating our acreage to identify and develop additional locations across our portfolio as we evaluate down-spacing in the Eagle Ford Shale and accessing other stratigraphic horizons that lie above and below the Eagle Ford Shale, such as the Austin Chalk, Buda, Georgetown, Woodbine and Wilcox formations. We believe our multi-year drilling inventory and exploration portfolio will provide near-term growth in our production and reserves and highlight the long-term resource potential across our asset base

 

    Oil-weighted reserves and production. Our net proved reserves at December 31, 2015 were comprised of approximately 58.5% oil, and our net average daily production for the year ended December 31, 2015 and 2014 was comprised of 66% oil and 73% oil, respectively. Given the current commodity price environment and resulting disparity between oil and natural gas prices on a Boe basis, we believe our high percentage of oil reserves, compared to our overall reserve base, is a key strength.

 

    Low field operating expenses. Even in light of recent declines in oil prices, we expect to generate sufficient cash margins on the operation of our Eagle Ford Shale acreage due to our low cash operating costs. For the six months ended June 30, 2016, our total field operating expenses (including lease operating expenses and production taxes) totaled $9.12 per Boe around our project areas. We believe there are relatively low geologic risks and repeatable drilling opportunities across our core operating areas in the Eagle Ford Shale, where we have devoted almost all of our 2016 drilling capital budget.

 

    Hedging position. As of June 30, 2016, we had in place hedges covering approximately 2,692 bbls/d for calendar year 2016 at an average price of approximately $69.57 per bbl. We believe that these hedges help insulate us from oil price volatility on approximately 85% of our expected crude oil production in 2016. We also 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, but 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.

Our Properties

We are an independent oil and natural gas company, focused on the acquisition, development and production of unconventional oil, NGLs and natural gas properties in the Eagle Ford Shale in Texas. We also own undeveloped acreage in the Bakken Three Forks formation in Roosevelt County, Montana.

 

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Eagle Ford Shale Trend

Our primary operational focus is on our Eagle Ford Shale position, which as of June 30, 2016 is comprised of 40,271 gross (35,230 net) acres in seven Texas counties. The Eagle Ford Shale is an oil and natural gas producing stratigraphic horizon of sedimentary rock that extends across portions of south Texas from the Mexican border into east Texas forming a band roughly 50 to 100 miles wide and 400 miles long. The Eagle Ford Shale is organically rich and calcareous, in places transitioning to an organic, argillaceous lime-mudstone. The formation lies between the deeper Buda limestone and the shallower Austin Chalk formation. Its thickness generally ranges between 100 and 200 feet in the productive parts of the play, is found at depths ranging from as shallow as 4,000 feet to as deep as 13,000 feet, and in much of the deeper portions of the horizon is overpressured.

Along the entire length of the Eagle Ford Shale the structural dip of the formation is consistently down to the south with relatively few, modestly-sized structural perturbations. As a result, depth of the horizon increases consistently southwards along with the thermal maturity of the formation. Where the formation is shallow, it is less thermally mature and therefore more oil prone, and as it gets deeper and becomes more thermally mature, the Eagle Ford Shale is more natural gas. The transition between being more oil prone and more natural gas prone includes an interval that typically produces wet gas and NGLs.

The first horizontal wells drilled specifically for the Eagle Ford Shale were drilled in 2008, leading to a discovery in La Salle County. Since then, the play has expanded significantly across a large portion of south Texas and then into east Texas.

Our properties in the Eagle Ford Shale are divided into three distinct regions: Western Eagle Ford (comprised of Dimmit, La Salle and Frio Counties), Central Eagle Ford (comprised of Gonzales and Wilson Counties) and Eastern Eagle Ford (comprised of Brazos and Robertson Counties). As of June 30, 2016, 35,230 net acres were operated by us and 21,156 net acres were held by production, or HBP. Our Eagle Ford Shale net production for the six months ended June 30, 2016 was 5,974 Boe/d, comprised of 3,338 Bbls/d of oil, 1,211 Bbls/d of NGLs and 8,548 Mcf/d of natural gas, from 68 gross (61 net) producing wells.

As of December 31, 2015, according to our reserve report, our Eagle Ford Shale properties had proved reserves of 38.0 MMBoe, of which 76% is crude oil and NGLs and 29% is proved developed producing, or PDP. The PV-10 of our Eagle Ford proved reserves as of December 31, 2015 was $275.9 million using SEC pricing and $321.9 million using NYMEX strip pricing, and 50% of such PV-10 is PDP. See “Business—Oil and Natural Gas Data—PV-10.”

We had identified 159 gross (143 net) horizontal drilling locations on our Eagle Ford Shale acreages as of June 30, 2016 of which 61% are expected to be drilled using lateral lengths of or greater than 7,000’ and 99% are expected to drilled using lateral lengths of or greater than 5,000’. Approximately 100% of these locations are on leases operated by us, and 59 gross (54 net) locations are currently categorized as proved undeveloped, or PUD. As of June 30, 2016, we had 3,695 additional net acres in the Eagle Ford Shale trend with surrounding industry activity to which we have not assigned locations. In furtherance of our ongoing development activities, in July 2015 we entered into a Joint Development Agreement with IOG. Pursuant to the Joint Development Agreement, IOG will fund up to $100 million to be used in drilling incremental Eagle Ford Shale wells. IOG will fund up to 90% of the initial capital for the wells drilled in the program, and we will contribute the remainder of the incremental costs. IOG will have the right to participate in the drilled wells as a non-operated working interest owner. As of June 30, 2016 IOG has participated in the drilling and completion of four horizontal wells in La Salle and Gonzales Counties, Texas, which were spud in October 2015 and February 2016, respectively.

In addition, we have identified 9 gross (6.7 net) drilling locations in the Eagle Ford Shale that we expect to drill in 2016. Based on our total of 159 gross identified drilling locations as of June 30, 2016, this would provide for approximately 16 years of drilling inventory. We plan to continue evaluating this acreage and monitoring industry activity and believe the acreage may be prospective for additional locations.

 

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Western Eagle Ford. As of June 30, 2016, our Western Eagle Ford region was comprised of 15,208 gross (13,413 net) acres in Dimmit, La Salle and Frio Counties. Approximately 90% of this net acreage was HBP. Production in the six months ended June 30, 2016 was 4,924 Boe/d, which was comprised of 2,383 Bbls/d of oil, 1,161 Bbls/d of NGLs and 8,279 Mcf/d of gas from 41 gross (38 net) producing wells.

As of December 31, 2015, according to our reserve report, our Western region had proved reserves of 32.6 MMBoe, of which 73% is crude oil and NGLs and 27% is PDP. The PV-10 of our Western region proved reserves as of December 31, 2015 was $220.7 million and 46% of such PV-10 is PDP. See “Business—Oil and Natural Gas Data—PV-10.”

As of December 31, 2015, according to our reserve report, single well gross estimated ultimate recoveries , or EURs, on our undeveloped locations range from 381 MBoe to 1,284 MBoe across our Western region wells, projected well costs currently range from $3.5 million to $5.8 million for wells with lateral lengths of 3,600 feet to 8,000 feet. In certain cases, we have the ability to extend lateral lengths beyond the lengths assumed in our 2015 reserve report. The most recent wells drilled in our Western Eagle Ford area had an average well cost of $4.1 million and average lateral length of 6,100 feet.

As of June 30, 2016, our Western Eagle Ford acreage had a total of 41 gross (38 net) Eagle Ford producing wells with 51 gross (47 net) identified Eagle Ford drilling locations. 100% of these gross drilling locations are on leases that we operate. Of these locations, 47 gross (43 net) locations are categorized as PUD. Approximately 84% of our engineered locations are expected to be drilled with lateral lengths of 7,000’ or greater and 98% are expected to be drilled with lateral lengths of 5000’ or greater.

We plan on allocating approximately $17.8 million in the second half of 2016 and between $27.3 million to $42.3 million of our 2017 budget to our Western Eagle Ford acreage.

Central Eagle Ford. Our Central Eagle Ford region as of June 30, 2016 was comprised of 12,695 gross (12,211 net) acres in Wilson and Gonzales Counties. As of June 30, 2016, we operated 100% of this acreage. Approximately 44% of this net acreage was HBP. Production in the six months ended June 30, 2016 was 735 Boe/d, which was comprised of 678 Bbls/d of oil, 30 Bbls/d of NGLs and 163 Mcf/d of natural gas from 19 gross (15 net) producing wells.

As of December 31, 2015, according to our reserve report, acreage in the Central region had proved reserves of 1.9 MMBoe, of which 96% is crude oil and NGLs and 30% is PDP. The PV-10 of our Central region proved reserves as of December 31, 2015 was $126.0 million and 76% of such PV-10 is PDP. See “Business—Oil and Natural Gas Data—PV-10.”

As of December 31, 2016, according to our reserve report, single well gross EURs range from 309 MBoe to 475 MBoe across our Central region wells. Projected well costs range from $4.2 million to $5.1 million for wells with lateral lengths of 5,000 feet to 8,000 feet. The most recent wells drilled in our Central Eagle Ford area had an average well cost of $4.7 million and average lateral length of 6,700 feet. Based on our drilling experience and that of offset operators, we believe that success in the Central Eagle Ford area is related to a different set of factors than in other parts of the Eagle Ford Shale. The Eagle Ford Shale horizon in this area is thinner yet exhibits higher porosities, and is more prone to significant faulting than in our other leasehold positions. We employ 3-D seismic imaging to maximize the lateral’s interface with the Eagle Ford and avoid the Buda formation, which produces high rates of water locally. We also take care to design well paths so as to minimize intersecting large faults that may take the lateral well bore out of our target Eagle Ford zone.

Our Central Eagle Ford region had a total of 19 gross (15 net) Eagle Ford producing wells and had a total of 76 gross (66 net) identified Eagle Ford drilling locations as of June 30, 2016. All of these drilling locations are on leases that we operate. Of these locations, 2 gross (2 net) were categorized as PUD.

 

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We will not allocate any of our remaining 2016 capital budget to the development of our Central Eagle Ford acreage but we plan on allocating between $15.9 million to $30.9 million of our 2017 budget this area.

Eastern Eagle Ford. Our Eastern Eagle Ford region as of June 30, 2016, was comprised of 12,367 gross (9,606 net) acres in Brazos and Robertson Counties. Approximately 38% of this net acreage is HBP. Our Eastern region includes 5,380 gross (4,651) net acres, which are located within the productive limits of the Aguila Vado Eagle Ford Shale Field, and an additional 6,987 gross (4,956) net acres that are under appraisal. Production in the six months ended June 30, 2016 was 315 Boe/d, which was comprised of 277 Bbls/d of oil, 20 Bbls/d of NGLs and 106 Mcf/d of natural gas from 8 gross (7.6 net) producing wells.

As of December 31, 2015, according to our reserve report, our Eastern region had proved reserves of 3.5 MMBoe, of which 94% is crude oil and NGLs and 21% is PDP. The PV-10 of our Eastern region proved reserves as of December 31, 2015 was $25.5 million and 48% of such PV-10 is PDP. See “Business—Oil and Natural Gas Data—PV-10.”

As of December 31, 2015, according to our reserve report, single well gross EURs range from 356 MBoe to 783 MBoe across our Eastern Eagle Ford region wells, and projected well costs range between $4.7 million and $6.5 million for wells with lateral lengths ranging from 5,000 feet to 7,000 feet. We believe current well costs are in the $5.1 to $6.4 million range.

Our Eastern Eagle Ford region had a total of 8 gross (7.6 net) producing wells, and had a total of 32 gross (30 net) identified drilling locations as of June 30, 2016. All of these drilling locations are on leases that are operated by us. Of these locations, 10 gross (9.5 net) locations are currently categorized as PUD.

We plan on allocating approximately $3.2 million in the second half of 2016 and approximately $3.7 million of our 2017 budget to our Eastern Eagle Ford acreage.

Non-Core Properties

Conventional Texas Assets

In addition to our Eagle Ford Shale acreage, we have historically maintained conventional oil and natural gas properties located in 13 counties in Texas, including long-lived reserves in the Canyon, Delaware Sand, Hackberry, Caddo, Cockfield and Jackson formations. As of December 31, 2015, these properties contained approximately 2.2 MMBoe of estimated proved reserves, of which 79% is crude oil. For the six months ended June 30, 2016 production from our conventional assets was 590 Boe/d, which represented 9% of our total net production for the year. Consistent with our plan to divest non-core assets and reduce our outstanding indebtedness, on June 15, 2016, we sold a portion of these assets for $2.2 million. On September 26, 2016, we entered into an agreement to sell the remaining assets for $14.0 million, and this transaction is scheduled to close, subject to customary closing conditions, on October 31, 2016.

Bakken Three Forks Assets

We also have 44,084 gross (28,655 net) undeveloped acres in the Poplar West area of the Bakken Three Forks formation in Roosevelt County, Montana. We expect to pursue a number of farm-in or other structured transactions to bring in a potential exploration partner in this area.

We currently do not plan on spending any of our remaining 2016 or preliminary 2017 budgets outside of the Eagle Ford.

 

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Summary of Primary Project Areas

The following table presents summary data for each of our primary project areas as of June 30, 2016:

 

     Net Acreage      Average
Working
Interest
    Identified
Drilling
Locations(1)(2)(3)
 
            Gross          Net    

Western Eagle Ford

     13,413         88     51         47   

Central Eagle Ford

     12,211         96     76         66   

Eastern Eagle Ford

     9,606         78     32         30   
  

 

 

    

 

 

   

 

 

    

 

 

 

Total Eagle Ford

     35,230         87     159         143   

West Poplar

     28,655         65     —           —     
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

     63,885         75     159         143   
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) We identify these potential drilling locations based on our analysis of relevant geologic and engineering data. Our total identified drilling locations include 59 gross (54 net) locations that were associated with proved undeveloped reserves, or PUDs, as of June 30, 2016. The remaining drilling locations were not associated with proved reserves as of December 31, 2015, however, based on our analysis of our drilling results, the drilling results of offset operators and applicable geologic and engineering data, we believe locations are prospective for development.
(2) The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified locations may not be successful and may not result in our adding additional proved reserves to our existing reserves. See “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Our identified drilling locations are subject to many uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.”
(3) We have estimated our drilling locations based on well spacing assumptions that we view as reasonable for the areas in which we operate and other criteria. Our identified drilling location count implies well spacing of (a) 500 feet in the crude oil window of our Western Eagle Ford region and 750 feet in the condensate window, with approximately 84% of these locations expected to be drilled with greater than 7,000 foot lateral lengths and approximately 98% expected to be drilled with greater than 5,000 foot lateral lengths and (b) between 500-750 feet depending on specific location in our Central and Eastern Eagle Ford regions, with well spacing with approximately 50% of these locations expected to be drilled with greater than 7,000 foot lateral lengths and approximately 99% of these locations expected to be drilled with greater than 5,000 foot lateral lengths. The ultimate spacing between wells may be less than these amounts, which would result in a higher location count, or greater than these amounts, which would result in a lower location count.

We are continuously evaluating opportunities to grow both our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on both the opportunities and the financing alternatives available to us at the time we consider such opportunities.

 

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Oil and Natural Gas Data

Estimated Proved Reserves

The following table presents estimated net proved oil, NGLs and natural gas reserves attributable to our properties and the Standardized Measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2015, 2014 and 2013. We employ a technical staff of engineers and geoscientists that perform technical analysis of each producing well and undeveloped location. The staff uses industry accepted practices to estimate, with reasonable certainty, the economically producible oil and gas reserves. The practices for estimating hydrocarbons in place include, but are not limited to, mapping, seismic interpretation, core analysis, log analysis, mechanical properties of formations, thermal maturity, well testing and flowing bottom hole pressure analysis. We employ an independent petroleum engineer to estimate 100% of our proved reserves. The data below is based on our reserve report prepared by W.D. Von Gonten & Co. for our Eagle Ford Shale properties and on the reserve report prepared by LaRoche Petroleum Consultants, Ltd. for our conventional properties in the State of Texas. The Standardized Measure and PV-10 amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. We do not currently have proved reserves on our acreage in the West Poplar Area of the Bakken-Three Forks trend in Montana. Reserves reported below for our Eagle Ford shale assets are owned by our subsidiary Lonestar Resources, Inc., and reserves reported below for our conventional assets are owned by our subsidiary Amadeus Petroleum, Inc.

 

     NYMEX(1)      SEC(2)  
     As of December 31,  
     2015      2015      2014      2013  

Estimated Proved Reserves(2)

           

Eagle Ford Shale:

           

Oil (MBbls)

     22,980         21,789         20,861         10,490   

NGLs (MBbls)

     7,453         7,154         3,044         1,841   

Natural Gas (MMcf)

     56,613         54,395         21,528         12,651   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford Shale (MBoe)(3)

     39,869         38,009         27,493         14,440   
  

 

 

    

 

 

    

 

 

    

 

 

 

Conventional Assets:

           

Oil (MBbls)

     2,355         1,727         2,749         2,994   

NGLs (MBbls)

     40         35         —           —     

Natural Gas (MMcf)

     3,867         2,586         4,441         4,722   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Conventional Assets (MBoe)(3)

     3,039         2,193         3,490         3,781   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Estimated Proved Reserves (MBoe)(3)

     42,907         40,201         30,983         18,221   
  

 

 

    

 

 

    

 

 

    

 

 

 

Estimated Proved Developed Reserves

           

Eagle Ford Shale:

           

Oil (MBbls)

     7,231         6,596         7,044         3,801   

NGLs (MBbls)

     2,159         2,020         1,212         639   

Natural Gas (MMcf)

     15,944         14,948         8,360         4,355   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford Shale (MBoe)(3)

     12,047         11,107         9,649         5,166   
  

 

 

    

 

 

    

 

 

    

 

 

 

Conventional Assets:

           

Oil (MBbls)

     1,957         1,727         2,140         2,394   

NGLs (MBbls)

     40         35         —           —     

Natural Gas (MMcf)

     3,357         2,586         3,631         3,933   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Conventional Assets (MBoe)(3)

     2,557         2,193         2,745         3,049   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Estimated Proved Developed Reserves (MBoe)(3)

     14,604         13,300         12,395         8,215   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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     NYMEX(1)      SEC(2)  
     As of December 31,  
     2015      2015      2014      2013  

Estimated Proved Undeveloped Reserves

           

Eagle Ford Shale:

           

Oil (MBbls)

     15,749         15,193         13,817         6,688   

NGLs (MBbls)

     5,294         5,134         1,833         1,203   

Natural Gas (MMcf)

     40,669         39,447         13,167         8,296   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford Shale (MBoe)(3)

     27,822         26,902         17,844         9,274   
  

 

 

    

 

 

    

 

 

    

 

 

 

Conventional Assets:

           

Oil (MBbls)

     397         —           609         600   

NGLs (MBbls)

     —           —           —           —     

Natural Gas (MMcf)

     510         —           810         789   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Conventional Assets (MBoe)(3)

     482         —           744         731   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Estimated Proved Undeveloped Reserves (MBoe)(3)

     28,304         26,902         18,588         10,005   
  

 

 

    

 

 

    

 

 

    

 

 

 

PV-10 (millions)(4)

   $ 344.2       $ 294.3       $ 705.8       $ 418.7   

Standardized Measure (millions)(5)

     —         $ 268.4       $ 549.0       $ 302.8   

Oil and Gas Prices Used(2) :

           

Oil—NYMEX-WTI per Bbl

     N/A         50.28       $ 94.99       $ 96.94   

Natural Gas—NYMEX-Henry Hub per MMBtu

     N/A         2.59       $ 4.35       $ 3.67   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Our estimated net proved NYMEX reserves were prepared on the same basis as our SEC reserves, except for the use of pricing based on closing monthly futures prices as reported on the NYMEX for oil and natural gas on December 31, 2015 rather than using the average of the first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Prices were in each case adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

Our NYMEX reserves were determined using index prices for oil and natural gas, without giving effect to derivative transactions. The average future prices for benchmark commodities used in determining our NYMEX reserves were $ 40.45/Bbl for oil for 2016, $46.06 for 2017, $49.36 for 2018, $51.96 for 2019, $53.64 for 2020, $54.66 for 2021, $55.24 for 2022, $55.67 for 2023, and escalated 3% thereafter and $2.49/MMBtu for natural gas for 2016, $2.79 for 2017, $2.91 for 2018, $3.03 for 2019, $3.26 for 2020, $3.31 for 2021, $3.46 for 2022, $3.61 for 2023 and escalated 3% thereafter. NGLs pricing used in determining our NYMEX reserves were approximately 30% of future crude oil prices.

We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. NYMEX futures prices are not necessarily a projection of future oil and natural gas prices. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves.

 

(2) Our estimated net proved reserves and related Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The prices are based on the average prices during the 12-month period prior to the ending date of the period covered, determined as the unweighted arithmetic average of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, and are adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead.

 

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(3) One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an industry-standard approximate energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities.
(4) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 differs from the Standardized Measure because it does not include the effect of future income taxes.
(5) Standardized Measure is calculated in accordance with Statement of Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities, as codified in ASC Topic 932, Extractive Activities—Oil and Gas.

The data in the table above represent estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, NGLs and natural gas that are ultimately recovered.

Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure amounts shown above should not be construed as the current market value of our estimated oil, NGLs and natural gas reserves. The 10% discount factor used to calculate Standardized Measure, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

PV-10

Certain of our oil and natural gas reserve disclosures included in this registration statement are presented on a PV-10 basis. PV-10 is the estimated present value of the future cash flows less future development and production costs from our proved reserves before income taxes discounted using a 10% discount rate. PV-10 is considered a non-GAAP financial measure because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows (the “Standardized Measure”). We believe that the presentation of a pre-tax PV-10 value provides relevant and useful information because it is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. Because many factors that are unique to each individual company may impact the amount and timing of future income taxes, the use of a pre-tax PV-10 value provides greater comparability when evaluating oil and gas companies. The PV-10 value is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of proved oil and gas reserves. The definition of PV-10 value as defined in “Glossary of Oil and Natural Gas Terms” may differ significantly from the definitions used by other companies to compute similar measures. As a result, the PV-10 value as defined may not be comparable to similar measures provided by other companies.

 

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The following table provides a reconciliation of PV-10 to the Standardized Measure:

 

     As of December 31,  

($ in millions)

   2015      2014      2013  

PV-10:

        

Eagle Ford

   $ 275.9       $ 643.6       $ 344.5   

Conventional Assets

     18.4         62.2         74.2   
  

 

 

    

 

 

    

 

 

 

Total PV-10

     294.3         705.8         418.7   

Future Income Taxes:

        

Eagle Ford

     25.8         143.1         94.8   

Conventional Assets

     .1         13.7         21.1   
  

 

 

    

 

 

    

 

 

 

Total Future Income Taxes

     25.9         156.8         115.9   

Standardized Measure of Discounted Future Net Cash Flows:

        

Eagle Ford

     250.1         500.5         249.7   

Conventional Assets

     18.3         48.5         53.1   
  

 

 

    

 

 

    

 

 

 

Total Standardized Measure of Discounted Future Net Cash Flows

   $ 268.4       $ 549.0       $ 302.8   
  

 

 

    

 

 

    

 

 

 

Reconciliation of Proved Reserves

Our proved developed oil and natural gas reserves increased 7% from 12.4 million BOE at December 31, 2014 to 13.3 million BOE at December 31, 2015 due to drilling delineation and development wells on our existing properties, and augmented by drilling on new properties which were acquired via farm-ins during the year. During the year, we converted 3.4 million BOE of Proved Undeveloped reserves to the Proved Developed Producing category and added 2.4 million BOE through drilling on new properties, while producing 2.4 million BOE during the year ended December 31, 2015. Our proved developed oil and natural gas reserves experienced negative revisions of 2.6 million BOE, largely as a result of lower oil and gas prices.

 

     Proved Developed Reserves  
     Eagle Ford
MBOE
     Conventional
MBOE
     Total
BOE
 

As of Dec, 31 2014

     9,649         2,745         12,395   

Extensions and Discoveries

     2,401         0         2,401   

Purchases of minerals in place

     21         0         21   

Revisions of prior estimates

     (2,286      (315      (2,601

Production

     (2,112      (237      (2,350

Conversion of proved undeveloped to proved developed

     3,434         0         3,434   
  

 

 

    

 

 

    

 

 

 

As of Dec, 31 2015

     11,107         2,193         13,300   
  

 

 

    

 

 

    

 

 

 

Our proved undeveloped oil and natural gas reserves increased 45% from 18.6 million BOE at December 31, 2014 to 26.9 million BOE at December 31, 2015 due to drilling delineation and development wells on our existing properties, and augmented by drilling on new properties which were acquired via farm-ins during the year. In the Eagle Ford Shale, through farm-ins, lease acquisitions and reserve purchases, we added 36 gross PUD locations in 2015 with reserves totaling 16.4 million BOE. Our proved undeveloped oil and natural gas reserves experienced negative revisions of 4.6 million BOE as a result of lower oil and gas prices. Included in the negative price revisions were 3.9 million BOE in the Eagle Ford Shale, associated with a combination of price-related revisions to PUD’s which remained in our reserves at December 31, 2015 as well as certain PUD locations that were removed as a result of lower prices. Additionally, all of the Company’s 0.7 million BOE’s of PUD’s associated with its Conventional assets were removed as a result of lower prices.

 

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At December 31, 2015, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD drilling locations are scheduled to be converted within five years of their initial booking.

 

     Proved Undeveloped Reserves  
     Eagle Ford
MBOE
     Conventional
MBOE
     Total
BOE
 

As of Dec, 31 2014

     17,844         744         18,588   

Extensions and Discoveries

     14,149         0         14,149   

Purchases of minerals in place

     2,209         0         2,209   

Revisions of prior estimates

     (3,865      (744      (4,610

Conversion of proved undeveloped to proved developed

     (3,434      0         (3,434
  

 

 

    

 

 

    

 

 

 

As of Dec, 31 2015

     26,902         0         26,902   
  

 

 

    

 

 

    

 

 

 

Development of Proved Undeveloped Reserves

At December 31, 2015, our proved undeveloped reserves were approximately 26,902 MBoe, an increase of approximately 8,314 MBoe over our December 31, 2014 estimated proved undeveloped reserves of approximately 18,588 MBoe. In 2015, we added net proved undeveloped reserves of 14,149 MBoe as a result of drilling and completion activities and 2,209 MBoe as a result of the acquisition of proved undeveloped reserves. During 2015, approximately 3,434 MBoe of proved undeveloped reserves as of December 31, 2014 were converted to proved developed reserves as a result of drilling and completion activities during the year, and 4,610 MBoe of reserves were subtracted from our proved undeveloped reserves as a result of revisions in estimates from 2014. During the year ended December 31, 2015, we incurred capital expenditures of approximately $49.4 million to convert these proved undeveloped reserves as of December 31, 2014 to proved developed reserves.

At December 31, 2014, our proved undeveloped reserves were approximately 18,588 MBoe, an increase of approximately 8,583 MBoe over our December 31, 2013 estimated proved undeveloped reserves of approximately 10,005 MBoe. In 2014, we added net proved undeveloped reserves of 1,904 MBoe as a result of drilling and completion activities and 7,916 MBoe as a result of the acquisition of proved undeveloped reserves. During 2014, approximately 1,576 MBoe of proved undeveloped reserves as of December 31, 2013 were converted to proved developed reserves as a result of drilling and completion activities during the year, and 339 MBoe of reserves were added to proved undeveloped reserves as a result of revisions in estimates from 2013. During the year ended December 31, 2014, we incurred capital expenditures of approximately $34.2 million to convert these proved undeveloped reserves as of December 31, 2013 to proved developed reserves.

Qualifications of Responsible Technical Persons

Internal Company Person. Thomas H. Olle, our Senior Vice President- Operations, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. Olle is also responsible for our interactions with and oversight of our independent third-party reserve engineers. Mr. Olle has more than 35 years of industry experience, with expertise in reservoir management and project development across a broad range of reservoir types. Mr. Olle previously held senior positions at Encore Acquisition Corp. and Burlington Resources. He holds a Bachelor of Science degree in Mechanical Engineering with Highest Honors from the University of Texas at Austin and is a member of the Society of Petroleum Engineers.

Independent Reserve Engineers. W.D. Von Gonten & Co. is an independent petroleum engineering and geological services firm. No director, officer or key employee of W.D. Von Gonten & Co. has any financial ownership in Lonestar. W.D. Von Gonten & Co.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and W.D. Von Gonten & Co. has not

 

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performed other work for us or our affiliates that would affect its objectivity. The engineering information presented in W.D. Von Gonten & Co.’s reports was overseen by William D. Von Gonten, Jr., P.E. Mr. Von Gonten is an experienced reservoir engineer having been a practicing petroleum engineer since 1990. He has a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and is a licensed Professional Engineer in the State of Texas.

LaRoche Petroleum Consultants, Ltd. is an independent petroleum engineering and consulting firm. No director, officer or key employee of LaRoche Petroleum Consultants, Ltd. has any financial ownership in Lonestar. LaRoche Petroleum Consultants, Ltd.’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and LaRoche Petroleum Consultants, Ltd. has not performed other work for us or our affiliates that would affect its objectivity. The engineering information presented in LaRoche Petroleum Consultants, Ltd.’s report was overseen by William M. Kazmann. Mr. Kazmann is an experienced reservoir engineer having been a practicing petroleum engineer since 1974. He has been with LaRoche Petroleum Consultants, Ltd. for more than 17 years, where he is President and Senior Partner. He has a Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas at Austin and is a licensed Professional Engineer in the State of Texas.

Technology Used To Establish Proved Reserves

Our independent reserve engineers follow SEC rules and definitions in preparing their reserve estimates. Under SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geological, geochemical and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well-test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Internal Controls Over Reserves Estimation Process

Our estimated reserves at December 31, 2015, 2014 and 2013 for the Eagle Ford Shale properties were prepared by W.D. Von Gonten & Co., independent reserve engineers. Our estimated reserves at December 31, 2015, 2014 and 2013 for our conventional long-lived, crude oil-weighted onshore assets were prepared by LaRoche Petroleum Consultants, Ltd., independent reserve engineers. We expect to continue to have our reserve estimates prepared annually by our independent reserve engineers. Our internal professional staff works closely with W.D. Von Gonten & Co. and with LaRoche Petroleum Consultants, Ltd. to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation processes. All of the production, expense and well-ownership information, maintained in our secure reserve engineering database, is provided to our independent engineers. In addition, we provide such engineers other pertinent data, such as seismic

 

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information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures, pricing differentials and relevant economic criteria, including lease operating statements. We make all requested information, as well as our pertinent personnel, available to our independent engineers in connection with their evaluation of our reserves. Year-end reserve estimates are reviewed by our Senior Vice President-Operations, our Chief Executive Officer and other senior management, and revisions are communicated to our board of directors.

Oil and Natural Gas Production Prices and Costs

Production, Revenues and Price History

The following table sets forth information regarding gross wells brought online during the period, combined net production of oil, NGLs and natural gas and certain price and cost information attributable to our properties, for the six months ended June 30, 2016 and years ended December 31, 2015, 2014 and 2013.

 

     Six Months Ended
June 30,
     Year Ended December 31,  
     2016      2015      2014      2013  

Gross Wells Drilled by Area:(1)

           

Western Eagle Ford

     3         13         8         10   

Central Eagle Ford

     2         3         9         2   

Eastern Eagle Ford

     —           —           5         —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford

     5         16         22         12   

Conventional

     —           —           —           —     

Production

           

Oil (Bbls/day):

           

Western Eagle Ford

     2,383         2,384         1,817         1,477   

Central Eagle Ford

     678         943         623         —     

Eastern Eagle Ford

     277         516         393         —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford

     3,338         3,843         2,833         1,477   

Conventional Assets

     358         373         434         547   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Oil

     3,696         4,216         3,267         2,024   

Natural gas liquids (Bbls/day):

           

Western Eagle Ford

     1,161         795         399         265   

Central Eagle Ford

     30         35         —           —     

Eastern Eagle Ford

     20         33         24         —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford

     1,211         864         423         265   

Conventional Assets

     11         13         13         3   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total NGLs

     1,222         877         436         268   

Natural Gas (Mcf/day):

           

Western Eagle Ford

     8,279         5,873         3,149         1,897   

Central Eagle Ford

     163         175         2         —     

Eastern Eagle Ford

     106         176         126         —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford

     8,548         6,224         3,277         1,897   

Conventional Assets

     1,326         1,663         1,387         1,248   

Barnett Shale

     —           —           —           1,224   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Natural Gas

     9,874         7,887         4,664         4,369   
  

 

 

    

 

 

    

 

 

    

 

 

 

Average Daily Production (Boe/d)

     6,564         6,407         4,480         3,020   

Average Daily Sales Price:

           

Oil ($/Bbl)

   $ 35.85       $ 45.93       $ 87.41       $ 96.95   

NGLs ($/Bbl)

     7.30         12.66         29.26         29.78   

Natural Gas ($/Mcf)

     1.81         2.39         4.50         4.15   

Average Unit Cost ($/Boe):

           

Lease operating expenses(2)

   $ 7.33       $ 7.35       $ 10.17       $ 12.54   

Production taxes

     1.79         2.13         4.36         4.65   

Depreciation, depletion and amortization

     23.22         25.16         24.91         25.66   

 

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(1) Includes wells placed online during the period shown.
(2) Includes $0.6 million in 2013 associated with P&A expense related to actions mandated by regulatory agencies.

Productive Wells

As of June 30, 2016, we owned an approximate 87% average working interest in 68 gross (61 net) productive wells. Our wells are oil wells that produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.

Developed and Undeveloped Acreage

The following table sets forth information relating to our leasehold acreage in the Eagle Ford and the Bakken-Three Forks Trend (West Poplar). As of June 30, 2016, approximately 60% of our net Eagle Ford acreage was held by production.

 

     As of June 30, 2016  
     Developed Acreage      Undeveloped
Acreage
     Total Acreage  
       Gross          Net        Gross      Net      Gross      Net  

Western Eagle Ford

     4,544         4,255         10,665         9,158         15,209         13,413   

Central Eagle Ford

     3,073         2,589         9,622         9,622         12,695         12,211   

Eastern Eagle Ford

     1,065         1,029         11,302         8,577         12,367         9,606   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford

     8,682         7,872         31,589         27,357         40,271         35,230   

West Poplar

     —           —           44,084         28,655         44,084         28,655   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     8,682         7,872         75,673         56,012         84,355         63,885   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

As of June 2016, we had leases across the Eagle Ford Shale representing 2,331 net acres expiring in 2016, 4,519 net acres expiring in 2017 and 2,249 net acres expiring in 2018 and beyond. We anticipate that our current and future drilling plans together with selected lease extensions will address a significant portion of our leases expiring in the Eagle Ford Shale in 2016. Our 28,655 net acres in the West Poplar project are subject to leases expiring in 2016, and we have an option to renew those leases for another three to five years at prices ranging from $125 to $300 per acre. With respect to West Poplar, we received approval of the Stone Turtle Indian Exploratory unit by the Bureau of Land Management and Bureau of Indian Affairs that establishes a 5-year primary term on all leasehold in the unit, in exchange for drilling activity. This approval opens the door for development of the block either by Lonestar or a farm-in partner. To date, we have only drilled one vertical exploratory well in our West Poplar leasehold.

 

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Drilling Activities

The following table sets forth information with respect to wells drilled and completed during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.

 

     Six Months ended June 30,      Year ended December 31,  
     2016      2015      2014      2013  
     Gross      Net      Gross      Net      Gross      Net      Gross      Net  

Development Wells:

                       

Productive

     5         4         16         13         21         19         12         10   

Dry

     —           —           —           —           —           —           —           —     

Exploratory Wells:

                       

Productive

     —           —           —           —           —           —           —           —     

Dry

     —           —           —           —           —           —           —           —     

Total Wells:

                       

Productive

     5         4         16         13         21         19         12         10   

Dry

                 —           —           —           —     

The following table sets forth information relating to the productive wells in which we owned a working interest as of June 30, 2016. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

     Productive
Wells (Oil)
     Productive
Wells (Gas)
     Total
Wells
 
     Gross      Net      Gross      Net      Gross      Net  

Eagle Ford:

                 

Operated by us

     64.0         58.2         4.0         2.3         68.0         60.5   

Non-operated

     —           —           —           —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Eagle Ford

     64.0         58.3         4.0         2.3         68.0         60.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Conventional:

                 

Operated by us

     241.0         187.0         23.0         19.8         264.0         206.8   

Non-operated

     15.0         3.8         —           —           15.0         3.8   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Conventional

     256.0         190.8         23         19.8         279.0         210.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Operations

General

We operate 100% of the Eagle Ford Shale wells in which we have a working interest and intend to maintain a high degree of operational control over substantially all of our producing locations. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

For the six months ended June 30, 2016, purchases by our largest four customers accounted for 38%, 20%, 18%, and 11% respectively, of our total sales revenues.

 

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Since the oil and natural gas that we sell are commodities for which there are a large number of potential buyers and because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time.

Transportation

During the initial development of our fields, we consider all gathering and delivery infrastructure options in the area of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm or by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system

Competition

We operate in a highly competitive environment for leasing and acquiring properties and in securing trained personnel. Our competitors include major and independent oil and natural gas companies that operate in our project areas. These competitors include, but are not limited to, Anadarko Petroleum Corporation, Chesapeake Energy Corporation, EP Energy Corporation, Carrizo Oil & Gas, Inc., Halcón Resources Corporation, Hunt Oil Company, Marathon Oil Corporation, Newfield Exploration Company and Stonegate Production Company. Many of our competitors have substantially greater financial, technical and personnel resources than we do, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive crude oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry.

We are also affected by the competition for and the availability of equipment, including drilling rigs and completion equipment. We are unable to predict when, or if, shortages of such equipment may occur or how they would affect our development and exploitation programs.

Seasonality of Business

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation.

Title to Properties

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain an additional title opinion or conduct a review to ensure all title is current relative to previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

We typically conduct title review of all acquired properties, regardless of whether they have proved reserves. Prior to the commencement of drilling operations on any property, we update our title examination and perform curative work with respect to significant defects or customary assignments, if any. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

 

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We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties range from 19.0% to 25.0% resulting in a net revenue interest to us ranging from 75.0% to 81.0%.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, crude oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the rateability or fair apportionment of production from fields and individual wells.

The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the crude oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We believe that we are in substantial compliance with all applicable laws and regulations and that our continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. Nor are we currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.

Regulation of Production of Oil and Natural Gas

Our operations are substantially affected by federal, state and local laws and regulations. In particular, crude oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for crude oil and natural gas production have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of

 

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properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in an area, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the rateability or fair apportionment of production from fields and individual wells.

The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the crude oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We believe that we are in substantial compliance with all applicable laws and regulations and that our continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. Nor are we currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.

Regulation of Sales and Transportation of Oil

Our sales of oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act of 1887 (“ICA”), the Energy Policy Act of 1992 (“EPAct”), and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport oil and refined products (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. EPAct deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA, which are commonly referred to as “grandfathered rates.” Pursuant to EPAct, FERC also adopted a generally applicable rate-making methodology, which, as currently in effect, allows petroleum pipelines to change their rates provided they do not exceed prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods (“PPI”), plus 1.3%. For the five-year period beginning July 1, 2011, the index will be PPI plus 2.65%.

FERC has also established cost-of-service rate-making, market- based rates and settlement rates as alternatives to the indexing approach. A pipeline may file rates based on its cost of service if there is a substantial divergence between its actual costs of providing service and the rate resulting from application of the index. A pipeline may charge market-based rates if it establishes that it lacks significant market power in the affected markets. Further, a pipeline may establish rates through settlement with all current non-affiliated shippers.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates vary from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors that are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

 

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Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and regulations issued under those statutes. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could re-enact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in the adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas, transportation rates and terms and conditions of service, which affect the marketing of natural gas that we produce as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others that buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case-by-case basis. To the extent that FERC issues an order that reclassifies transmission facilities as gathering facilities and, depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, non-discriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services vary from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

 

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Regulation of Environmental and Occupational Safety and Health Matters

Our exploration, development, production and processing operations are subject to various federal, state and local laws and regulations relating to health and safety, the discharge of materials and environmental protection. These laws and regulations may, among other things: require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas, such as wetlands, wilderness areas, or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of crude oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the crude oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. In addition, Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly emissions control, waste handling, disposal, clean-up and remediation requirements for the crude oil and gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position in the future. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that this will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future may have a material adverse effect on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. CERCLA exempts “petroleum, including oil or any fraction thereof” from the definition of “hazardous substance” unless specifically listed or designated under CERCLA. While the EPA interprets CERCLA to exclude oil and fractions of oil, hazardous substances that are added to petroleum or that increase in concentration as a result of contamination of the petroleum during use are not considered part of the petroleum and are regulated under CERCLA as a hazardous substance.

Responsible persons under CERCLA include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural

 

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resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. The RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes. The RCRA regulations specifically exclude from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. No such effort has been successful to date. Further, nonprofit environmental groups have recently filed petitions and a notice of intent to sue EPA regarding the RCRA E&P waste exemption.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce crude oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators) and to perform remedial operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, as amended, or the Clean Water Act (“CWA”), and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the United States. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permits issued by the EPA or analogous state agencies. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. Currently, storm water discharges from crude oil and natural gas exploration, production, processing or treatment operations, or transmission facilities are exempt from regulation under the CWA. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Air Emissions

The Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations, and impose various monitoring and

 

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reporting requirements. These laws and regulations may require us to obtain preapproval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, the EPA also issued CAA regulations relevant to hydraulic fracturing in 2012, including a new source performance standard for volatile organic chemicals (“VOCs”) and sulfur dioxide (“SO2”) emissions with expanded applicability to natural gas operations, as well as a new air toxics standard. These rules create significant new technology requirements for controlling wellhead emissions from our operations. The EPA has made several changes to these rules in response to industry and environmental group legal challenges and administrative petitions, including, most recently, a decision to include a specific performance standard for methane in the rules (discussed further below). In general, there is increasing interest in and focus on regulation of methane emissions from oil and natural gas operations, and hydraulic fracturing operations in particular, under the CAA. We cannot predict future regulatory requirements in this area or the cost to comply with such requirements. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce. We further note that states are authorized to regulate methane emissions within their boundaries provided their requirements are not weaker than federal rules.

Regulation of GHG Emissions

Climate and related energy policy, laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential developments that could impact the sources and uses of energy. In December 2015, the United States and 194 other countries, adopted the Paris Agreement, committing to work towards limiting global warming and agreeing to a monitoring and review process of GHG emissions. This will heighten political pressure on the United States to ensure continued compliance with enforcement measures resulting from the Clean Air Act and to bring forward further actions to reduce GHGs in the period post 2030. On October 4, 2016, the E.U. ratified the Paris Agreement, thus meeting the threshold for the agreement to come into force.

In the absence of comprehensive climate change legislation, significant regulatory action to regulate GHGs under the federal Clean Air Act has occurred over the past several years. In particular, the Clean Power Plan regulation under the Clean Air Act, which regulates carbon pollution from existing fossil fuel-fired power plants represents a significant portion of the United States’ reductions proposed under the Paris agreement. EPA also issued a final rule in May 2016 controlling methane air emissions from crude oil and natural gas sources. The EPA has also announced that it intends to propose similar standards for existing sources. The EPA also finalized rules in 2016 that clarify when crude oil and natural gas sites should be aggregated for purposes of air permitting, which could increase our compliance and permitting costs. Any future federal laws, agreements or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

The EPA requires the reporting of GHGs from specified large GHG emission sources, including GHGs from petroleum and natural gas systems that emit more than 25,000 tons of GHGs per year. Reporting is required from onshore and offshore petroleum and natural gas production, natural gas processing, transmission and distribution, underground natural gas storage and liquefied natural gas import, export and storage. While new legislation requiring GHG controls is not expected at the national level in the near term, almost one-half of the states have taken actions to monitor and/or reduce emissions of GHGs, including obligations on utilities to purchase renewable energy and GHG cap and trade programs. Although most of the state level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future.

 

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Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, such as coal, our products would become more desirable in the market with more stringent limitations on GHG emissions. To the extent that our products are competing with lower GHG emitting energy sources, such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Finally, increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas we produce or otherwise cause us to incur significant costs in preparing for or responding to those effects.

Hydraulic Fracturing Activities

The federal Safe Drinking Water Act (“SDWA”) and comparable state statutes may restrict the disposal, treatment or release of water produced or used during crude oil and natural gas development. Subsurface emplacement of fluids (including disposal wells) is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory authority or the state’s environmental authority. We utilize hydraulic fracturing in our operations as a means of maximizing the productivity of our wells and operate saltwater disposal wells to dispose of produced water. The federal Energy Policy Act of 2005 amended the Underground Injection Control (“UIC”) provisions of the SDWA to expressly exclude hydraulic fracturing without diesel additives from the definition of “underground injection.” However, the U.S. Senate and House of Representatives have considered several bills in recent years to end this exemption, as well as other exemptions for crude oil and gas activities under U.S. environmental laws.

Federal agencies have also begun to directly regulate hydraulic fracturing. The EPA has recently asserted federal regulatory authority over, and issued permitting guidance for, hydraulic fracturing involving diesel additives under the SDWA’s UIC Program. As a result, service providers or companies that use diesel products in the hydraulic fracturing process are expected to be subject to additional permitting requirements or enforcement actions under the SDWA. The EPA has also issued new CAA regulations relevant to hydraulic fracturing in 2012, including the NSPS for VOC and SO2 emissions with expanded applicability to natural gas operations and new national emission standards for hazardous air pollutants standards for air toxics. Also, in June 2016, the EPA finalized rules to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plans. These regulatory developments are indicative of increasing federal regulatory activity related to hydraulic fracturing, which has the potential to create additional permitting, technology, recordkeeping and site study requirements, among others, for our business. The EPA is also collecting information as part of a multi-year study into the effects of hydraulic fracturing on drinking water. The results of this study could result in additional regulations, which could lead to operational burdens similar to those described above. The U.S. Department of the Interior has likewise developed comprehensive regulations for hydraulic fracturing on federal land, which were successfully challenged by industry groups and are now under appellate review.

State governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. A majority of states around the country, including Texas, have also adopted some form of fracturing fluid disclosure law to compel disclosure of fracturing fluid ingredients and additives that are not subject to trade secret protection. Other states, such as Ohio and Texas, have begun to study

 

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potential seismic risks related to underground injection of fracturing fluids. For example, on October 28, 2014, the Texas Railroad Commission, or TRC, published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.

At this time, it is not possible to estimate the potential impact on our business of these state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing.

ESA and Migratory Birds

The federal Endangered Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. While some of our facilities may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA and the Migratory Bird Treaty Act. However, the designation of previously unidentified endangered or threatened species or habitats in areas where our operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could have a material adverse impact on the value of our leases.

National Environmental Policy Act

Our operations on federal lands are subject to the National Environmental Policy Act, or NEPA. Under NEPA, federal agencies, including the Department of Interior must evaluate major agency actions having the potential to significantly impact the environment. This review can entail a detailed evaluation including an Environmental Impact Statement. This process can result in significant delays and may result in additional limitations and costs associated with projects on federal lands.

OSHA

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (the “OSH Act”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSH Act’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used, produced or released in our operations and that this information be provided to employees, state and local government authorities and citizens. In 2012, the Occupational Safety and Health Administration (“OSHA”) issued a hazard alert related to worker exposure to respirable dust from silica sand, a common additive to hydraulic fracturing fluids. The alert stated that workers at drill sites can be exposed to excessive levels of respirable silica sand, which can cause lung disease and cancer. Increasing concerns about worker safety at drill sites may lead to increased regulation and enforcement or related tort claims by our employees. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

 

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Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state, federal and/or Tribal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for on-going operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2015, nor do we anticipate that such expenditures will be material in 2016.

Related Insurance

We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations. Further, we have no coverage for gradual, long-term pollution events.

Employees

As of June 30, 2016, we had 55 employees, including seven engineers and geoscientists, five land professionals and eighteen field operating personnel. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed.

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 Lonestar.

 

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MANAGEMENT

The following table sets forth the name, position and age of each of our directors and executive officers.

 

Name

  

Position

   Age
Frank D. Bracken, III    Chief Executive Officer and Director    52
Barry D. Schneider    Chief Operating Officer    54
Douglas W. Banister    Chief Financial Officer    54
Bryan M. Moody    Chief Commercial Officer    46
Thomas H. Olle    Senior Vice President—Operations    62
Jana Payne    Vice President—Geosciences    54
John Pinkerton    Chairman    62
Bernard Lambilliotte    Director    58
Daniel R. Lockwood    Director    59
Dr. Christopher Rowland    Director    61
Robert Scott    Director    69
Henry B. Ellis    Director    66
Mitchell Wells    Director    41

Frank D. Bracken, III is our Chief Executive Officer. Mr. Bracken has served in this position since January 2012 and has served as a director and Chief Executive Officer of Lonestar Resources, Inc., our wholly-owned subsidiary, since January 2012. Mr. Bracken previously served as Senior Managing Director of Sunrise Securities from September 2008 to December 2011 and as Managing Director of Jefferies LLC from November 1999 to August 2008. During that time, Mr. Bracken led oil and natural gas transactions, spanning from public and private equity and debt offerings to joint ventures in the Haynesville Shale to one of the first purchases of a publicly-traded oil & gas company by a private equity firm. As Chief Financial Officer and a member of the board of directors at Gerrity Oil & Gas Corp, an NYSE-listed exploration and production company, Mr. Bracken was responsible for corporate budgeting and development, acquisitions, equity and debt financing in public and private offerings, and acquisitions and divestitures. Mr. Bracken holds a Bachelors of Arts degree from Yale University.

Barry D. Schneider is our Chief Operating Officer. Mr. Schneider has served in this position since May 2014. Prior to joining us, Mr. Schneider held the position of Vice President—Northern Region for Denbury Resources, Inc. from January 2012 to May 2014. Mr. Schneider was at Denbury for 15 years and held positions of increasing responsibility. After holding the positions of Vice President, Production & Operations, Mr. Schneider was promoted to Vice President-East Region in October 2009 and held that position until January 2012 when he became responsible for Denbury’s Northern Region business unit. Prior to Denbury, Mr. Schneider was employed by Wiser Oil and Conoco-Philips. Mr. Schneider received his B.S. in Natural Gas Engineering from Texas A&M—Kingsville in 1985.

Douglas W. Banister is our Chief Financial Officer. Mr. Banister has served in this position since January 2014 and previously served as Chief Accounting Officer of Lonestar Resources, Inc., our wholly-owned subsidiary since August 2010. Mr. Banister is a Certified Public Accountant with 30 years of experience in finance, planning, negotiating and business development. Mr. Banister began his career in public accounting with Ernst & Young, where he served in various accountant roles between June 1984 and December 1987. Between December 1987 and April 1990, Mr. Banister served as Corporate Controller for D.R. Horton, Inc. and, between October 2004 and October 2005, served as VP of finance for Richmond American Homes. Mr. Banister holds a B.B.A. from Texas Wesleyan University with an emphasis in accounting.

Bryan M. Moody is our Chief Commercial Officer. He became Chief Commercial Officer of Lonestar Resources, Inc., our wholly-owned subsidiary in July 2016. Prior to joining us, Mr. Moody held the position of VP of Finance, Business Development and Reservoir Engineering at Eclipse Resources, Corp. from May 2012 to

 

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September 2015. Mr. Moody spent two years at EXCO Resources Inc. from June 2010 to May 2012 as Director of Development Planning. Mr. Moody also spent three years at Sandridge Energy Inc. from May 2007 to July 2010 as Director of Reservoir Reporting. Mr. Moody holds an MSc in Nuclear Engineering from Thomas Edison State College and an M.B.A. from the University of Rochester.

Thomas H. Olle is our Senior Vice President-Operations. Mr. Olle has served in this position since August 2010. Mr. Olle has over 35 years of oil and gas industry experience in multiple facets of the business, such as reservoir management and management of unconventional resource development projects including horizontal well field development and tertiary recovery projects. Mr. Olle also has significant experience with reserve evaluation and reporting, production engineering and operations, and business development functions including acquisitions, divestitures and new ventures. During his tenure at Encore Acquisition Company, Mr. Olle served as Vice President-Strategic Solutions and also held executive positions responsible for asset management and engineering. He also served as Senior Engineering Advisor for Burlington Resources from December 1985 to March 2002 and District Reservoir Engineer for Southland Royalty Company from May 1982 to December 1985. Mr. Olle holds a Bachelor’s of Science in Mechanical Engineering with Highest Honors from the University of Texas in Austin.

Jana Payne was appointed our Vice-President of Geosciences in November 2015, bringing over 25 years of experience in the oil and gas industry. Prior to joining us, Ms. Payne held the position of Senior Exploitation Manager and Geologist at Halcon Resources, Inc. from November 2012 to May 2015. Ms. Payne spent eight years at Petrohawk Energy Inc. from June 2004 to October 2012 (and subsequently BHP Billiton following its acquisition of Petrohawk) as Geologic Manager and Senior Geologist, where her initial mapping of the Eagle Ford shale led to the discovery of the first commercial Eagle Ford Shale well and acquisition of over 300,000 acres by the Company. Ms. Payne’s early career was as a geologist at Marathon Oil Co. and Petroleum Geo-Services, Inc. Ms. Payne has published works in learned journals and holds an MSc and BSc in geology from the University of Texas at Arlington.

John Pinkerton has served as a Director since August 2014 and became Chairman of the Board in August 2016. He has been a director of Range Resources Corporation (NYSE: RRC) since 1988 and was Chairman of its Board of Directors from 2008 until January 2015. He joined Range as President in 1990 and served as Chief Executive Officer from 1992 until 2012. Prior to joining Range, Mr. Pinkerton served in various capacities at Snyder Oil Corporation for twelve years, including the position of Senior Vice President. Mr. Pinkerton received his Bachelor of Arts degree in Business Administration from Texas Christian University, where he now serves on the board of trustees, and a Master’s degree from the University of Texas at Arlington. During his 27-year tenure Range Resources grew from its small cap origins to be a $13 billion dollar enterprise with a pre-eminent position in the Marcellus Shale. As CEO of Range Resources, Mr. Pinkerton established the technical expertise to enable a drilling-led strategy complemented by bolt-on acquisitions where synergies would enhance growth. This resulted in a rapid and impressive increase in the scale of the business, and seven consecutive years of double-digit growth in both production and reserves (adjusted for debt). Mr. Pinkerton has widespread skill in the management, acquisition and divestiture of oil and gas properties—including related corporate financing activities—hedging, risk analysis and the evaluation of drilling programs. He has represented the industry in policy matters, serving on the executive committee of America’s Natural Gas Alliance. We believe that Mr. Pinkerton’s experience at oil and natural gas exploration companies qualify him for service on our board of directors.

Bernard Lambilliotte has served as a Director since January 2013 . Mr. Lambilliotte has served as Chief Investment Officer of EF Realisation, a specialist fund manager in equity, utilities and infrastructure, since 1992. Mr. Lambilliotte served as an investment manager with Pictet & Cie., private bankers, in Geneva and London, where he was responsible for the development of sector funds, having previously been an investment banker with Swiss Bank Corporation in London and Paris, and with Drexel Burnham Lambert in London. He sits on the board of directors of each of Hamon er Cie S.A., an international power engineering group based in Belgium, and Oro Negro, an oil services company based in Mexico. He graduated from the Université Libre de Bruxelles with a

 

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degree in engineering, and from INSEAD, Fontainebleau, France where he received an M.B.A. degree. Mr. Lambilliotte is also a trustee of the Ecofin Research Foundation, a UK-based registered charity, which aims to promote the development of sustainable, low carbon solutions. We believe that Mr. Lambilliotte’s background in investment banking and energy investing qualify him to serve on our board of directors.

Daniel R. Lockwood has served as a Director since May 2014. He also serves as Vice-President of New Tech Global and is responsible for overseeing and managing NTG engineering and project management services. Mr. Lockwood is a graduate of the Colorado School of Mines with a degree in Petroleum Engineering. Dan joined New Tech Engineering in 2000, and brings with him more than 35 years of engineering and management experience and is considered one of the industry’s leading experts in Shale Operations. We believe that Mr. Lockwood’s engineering and management experience in the oil and gas industry qualifies him for service on our board of directors.

Dr. Christopher Rowland has been a Director of Lonestar since January 2013. He is also Director of Special Situations for EF Realisation where he is responsible for initiating and monitoring unlisted investments. Prior to joining EF Realisation in 2006, Dr. Rowland formed and led equity research teams over a 20-year period at several investment banks, including Merrill Lynch and Dresdner Klienwort Benson. Apart from his career as a research analyst, Dr. Rowland spent time setting up an alternative generator to buy coal-fired power stations in 1993. He has a Ph.D. for his research into the economics of UK oil taxation and holds a MSc (Econ) from the University of London and a BSc in Economics from the University of Bath. We believe that Mr. Rowland’s academic background in economics and his professional experience in finance and energy investment qualify him to serve on our board of directors.

Robert Scott has served as a Director since 1996. He has over 35 years’ experience as an advisor on corporate services and taxation, specializing in the mining and resources sector. Mr. Scott holds a Fellowship of the Australian Institute of Chartered Accountants and the Taxation Institute of Australia. Mr. Scott is currently Non-Executive Director of Homeloans Limited, Sandfire Resources Limited and RTG Mining Inc., and Non-Executive Chairman of Manas Resources Limited. Mr. Scott was formerly Chairman of bioMD Limited and Australian Renewable Fuels Limited and a Non-executive Director of New Guinea Energy Limited, Neptune Marine Services Limited and CGA Mining Limited. We believe Mr. Scott’s extensive professional experience advising on corporate services and taxation as well as his broad knowledge of the industry qualify him to serve on our board of directors.

Mitchell Wells has served as a director since December 2014. Mr. Wells is an Australian qualified lawyer with legal experience in Australia, the United States and the United Kingdom. He has worked in the oil and gas sector for the past 8 years both as a Chief Operating Officer and as a Company Secretary. Mr. Wells also previously served as Lonestar Resources Limited’s Company Secretary. We believe that Mr. Wells’ academic background and professional experience in the oil and gas sector qualify him for service on our board of directors.

Henry B. Ellis was appointed as a director in October 2016. Mr. Ellis presently serves as managing director and Chief Executive Officer of Bassett California Co. & The Bassett Company and previously served as a director of several other boards including Bluebonnet Savings Bank and State National Bank and held management positions at companies including State National Bank and Grayson County State Bank. Mr. Ellis received his Bachelor of Arts degree in Business Administration from Texas Christian University. We believe that Mr. Ellis’ financial experience in the banking industry qualifies him for service on our board of directors.

There are no family relationships among any of our directors or executive officers.

 

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Board Composition

Our board of directors consists of eight members: Frank D. Bracken, III, John Pinkerton, Bernard Lambilliotte, Daniel R. Lockwood, Dr. Christopher Rowland, Mitchell Wells, Henry B. Ellis and Robert Scott. On October 26, 2016, we entered into a Board Representation Agreement with EF Realisation. Under the Board Representation Agreement, EF Realisation will have the right to designate two nominees to our board of directors subject to the maintenance of certain ownership thresholds in our Class A common stock. Each director is to hold office until his or her successor is duly elected and qualified or until his or her earlier death, resignation or removal. Vacancies and newly created directorships on the board of directors may be filled at any time by the remaining directors, subject to the Board Representation Agreement.

Our board of directors has determined that each of Robert Scott and Henry B. Ellis is an “independent director” as such term is defined by the applicable NASDAQ rules. In accordance with the rules of NASDAQ, the Company will appoint one additional independent member within one year of the effective date of our Form 10 filing.

Status as a Controlled Company

EF Realisation, through subsidiaries and/or affiliates, control a majority of the voting power of our outstanding Class A common stock. As a result, we are a “controlled company” under NASDAQ corporate governance standards. As a controlled company, exemptions under NASDAQ standards will exempt us from certain NASDAQ corporate governance requirements, including the requirements:

 

    that a majority of our board of directors consists of “independent directors,” as defined under NASDAQ rules;

 

    that the compensation of our executive officers be determined, or recommended to the board of directors for determination, by majority vote of the independent directors or by a compensation committee comprised solely of independent directors; and

 

    that director nominees be selected, or recommended to the board of directors for selection, by majority vote of the independent directors or by a nomination committee comprised solely of independent directors.

Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of NASDAQ’s corporate governance requirements. In the event that we cease to be a controlled company, we will be required to comply with these provisions within the transition periods specified in NASDAQ rules.

These exemptions do not modify the independence requirements for our audit committee, and we expect to satisfy the member independence requirement for the audit committee prior to the end of the transition period provided under NASDAQ rules and SEC rules.

Committees of the Board of Directors

Our board of directors has an Audit and Risk Committee, a Compensation Committee and a Nominating and Corporate Governance Committee. Under the rules of NASDAQ, the membership of the Audit and Risk Committee is required to consist entirely of independent directors, subject to applicable phase-in periods applicable to new public companies. As a controlled company, we are not required to have fully independent Compensation and Nominating and Corporate Governance Committees. The following is a brief description of our committees.

Audit and Risk Committee. Our Audit and Risk Committee assists the board in monitoring the audit of our financial statements, our independent auditors’ qualifications and independence, the performance of our audit function and independent auditors and our compliance with legal and regulatory requirements. The Audit and Risk Committee has direct responsibility for the appointment, compensation, retention (including termination) and oversight of our independent auditors, and our independent auditors report directly to the Audit and Risk Committee. The Audit and Risk Committee will also review and approve related party transactions as required by the rules of NASDAQ.

 

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Our Audit and Risk Committee is comprised of Henry B. Ellis, Robert Scott and Dr. Christopher Rowland. The board of directors has determined that each of Mr. Ellis and Mr. Scott qualifies as an “audit committee financial expert.” The board has also determined that each of Mr. Ellis and Mr. Scott is “independent” for purposes of Rule 10A-3 of the Exchange Act and NASDAQ rules.

The board of directors has determined that Dr. Rowland is not independent under Rule 10A-3 or NASDAQ listing rules. Accordingly, we are relying on the phase-in provisions of NASDAQ listing rules applicable to new public companies, and we plan to have an Audit and Risk Committee comprised solely of independent directors that are independent for purposes of serving on an Audit and Risk Committee within one year of our listing. Until such time as we have independent directors available to serve on the Audit and Risk Committee, we may also rely on additional exemptions provided under NASDAQ listing rules, including the exemption afforded by Rule 5605(c)(2)(B) to the extent the board determines that reliance on such exemption would be in the best interests of the Company and our stockholders.

Compensation Committee. Our Compensation Committee reviews and recommends policies relating to compensation and benefits of our directors and employees and is responsible for approving the compensation of our Chief Executive Officer and other executive officers.

Our Compensation Committee is comprised of Daniel R. Lockwood, John Pinkerton, and Dr. Christopher Rowland. Our board has determined that Messrs. Lockwood, Pinkerton and Rowland are not independent under NASDAQ rules. Because we are a “controlled company” under the rules of NASDAQ, our Compensation Committee is not required to be fully independent, although if such rules change in the future or we no longer meet the definition of a controlled company under the current rules, we will adjust the composition of the Compensation Committee accordingly in order to comply with such rules.

Nominating and Corporate Governance. Our Nominating and Corporate Governance Committee selects or recommends that the board of directors select candidates for election to our board of directors, develops and recommends to the board of directors corporate governance guidelines that are applicable to us and oversees board of director and management evaluations.

Our Nominating and Corporate Governance Committee is comprised of Robert Scott, John Pinkerton, and Dr. Christopher Rowland. Our board has determined that Messrs. Pinkerton and Rowland are not independent under NASDAQ rules. Because we are a “controlled company” under the rules of NASDAQ, our Nominating and Corporate Governance Committee is not required to be fully independent, although if such rules change in the future or we no longer meet the definition of a controlled company under the current rules, we will adjust the composition of the Nominating and Corporate Governance Committee accordingly in order to comply with such rules.

Compensation Committee Interlocks and Insider Participation

None of our executive officers currently serve, or in the past year has served, as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving on our board of directors or compensation committee.

Code of Ethics and Business Conduct

Our board of directors has adopted a code of ethics and business conduct that applies to all of our employees, officers and directors, including our Chief Executive Officer, Chief Financial Officer and other executive officers.

Corporate Governance Guidelines

Our board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of NASDAQ.

 

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EXECUTIVE COMPENSATION

Named Executive Officers

We are currently considered a “smaller reporting company” for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are providing a Summary Compensation Table and an Outstanding Equity Awards at Fiscal Year-End Table as well as narrative disclosures regarding our executive compensation program. The individuals covered by this executive compensation disclosure are our chief executive officer and our two other most highly compensated executive officers. For 2015, our named executive officers were:

 

Name

  

Principal Position

Frank D. Bracken, III

   Chief Executive Officer

Barry D. Schneider

   Chief Operating Officer

Thomas H. Olle

   Senior Vice President—Operations

Our board strives to align Lonestar’s compensation strategy with company performance and stockholder interests, and ensure that it is equitable for participants. To assist with this, prior to the Reorganization the board had in place a Remuneration & Nomination Committee, which consisted of non-employee Directors only. Lonestar’s Chief Executive Officer has historically attended meetings of the Remuneration & Nomination Committee but did not attend discussions regarding his compensation.

The Remuneration & Nomination Committee’s objective was to support and advise the board in fulfilling its oversight responsibility by focusing on Lonestar’s approach to executive compensation as well as the use of equity across the company.

In connection with our listing on NASDAQ, we formed a Compensation Committee and adopted a charter for it in compliance with NASDAQ listing rules applicable to controlled companies. (See “Management—Committees of the Board of Directors—Compensation Committee”)

Summary of principles and the components of compensation. The structure of our executive compensation and the non-employee director compensation programs are separate and distinct. The following table is an overview of the compensation framework elements as we intend to apply to our named executive officers and our non-employee directors:

 

    

Element

   Executives    Non-Employee
Directors

Fixed compensation

   Base salary    Ö    ×
   Fees / Consultancy    ×    Ö
   401(k)/Australian superannuation    Ö    ×
   Other benefits    Ö    ×

Variable compensation

   Short term incentive    Ö    ×
   Long term incentives    Ö    ×

 

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Executive compensation policy

The objective of the executive compensation framework is to competitively and appropriately reward performance and results delivered. To this end, our compensation policy is intended to embody the following principles in its compensation framework:

 

  compensation should facilitate the delivery of long term results for the business and its stockholders;

 

  compensation should support the attraction, retention, motivation and alignment of the talent needed to achieve the organization’s goals;

 

  compensation should reinforce leadership, accountability, teamwork and innovation; and

 

  compensation should be aligned to the contribution and performance of the business, teams and individuals.

Approach to executive compensation

Prior to the Reorganization, our Remuneration & Nomination Committee considered the appropriate level of compensation, as well as the mix and structure of fixed and variable compensation, for our executive officers. This determination has been made by our Compensation Committee following the Reorganization.

We will broadly seek to position fixed compensation in line with similar oil and gas companies, although no specified peer group has yet been identified. Individual positioning of compensation depends on this positioning aspiration plus consideration of experience, individual performance and Lonestar’s circumstances. When setting compensation, we seek to establish an appropriate mix between fixed and variable compensation. For fiscal 2015, most of the executives had a target package split with approximately 67% based on fixed compensation and 33% based on variable compensation.

Fixed compensation: Base salary is designed to compensate for the value the individual provides to Lonestar, including the following:

 

  skills and competencies needed to generate results;

 

  sustained contribution to the team and Lonestar; and

 

  the value of the role and contribution of the individual in the context of the external market.

In addition, U.S.-based executives receive health and welfare plan benefits, which are the same as those made available to all full-time salaried employees. The Company provides a 401(k) plan to all eligible full-time employees which allows for pre-tax employee contributions up to the maximum allowed by the Internal Revenue Code of 1986, as amended (the “Code”). The Company supplements the employee’s contribution by providing a matching contribution of 100% of up to the first 4% contributed by each employee. This matching contribution is deposited on each semi-monthly payroll and is 100% vested to the employee’s account.

Short-term incentives: Our executives were eligible to receive an annual cash bonus in 2015 based on Lonestar’s performance and the executive’s individual performance, as determined by the board. In determining 2015 annual bonuses for our named executive officers, the board considered the following company performance criteria: production and reserves growth, EBITDAX growth and achievement of EBITDAX guidance (normalized). The achievement of Lonestar’s performance criteria was weighted approximately 75% and the executive’s individual performance was weighted approximately 25%. The actual bonus amounts that the board elected to pay our named executive officers are set forth in the “Bonus” column of the 2015 Summary Compensation Table below.

Long-term incentives: We had two long-term incentive plans in place during 2015, however, no options or other equity-based awards were granted to our named executive officers in 2015. Following the Reorganization, these plans were replaced by our Lonestar Resources US Inc. 2016 Incentive Plan (the “2016 Plan”), as described in more detail below in the section titled “—2016 Incentive Plan,” and the options issued under the prior long-term incentive plans were cancelled and replaced with awards issued pursuant to the 2016 Plan.

 

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The options issued under the 2016 Plan are options to purchase shares of the Company’s Class A common stock and are designated as either “Class A options” or “Class B options” based on their vesting schedule. Class A options vest in substantially equal installments over a three-year period, unless there is a change in control (as defined in the 2016 Plan) or cessation of employment by redundancy or termination. In the event of such a change in control, redundancy or termination event, all Class A options that have not vested will vest on the date of that change in control, redundancy or termination event. Class B options will only vest in the event of a change in control or cessation of employment by redundancy or termination.

Employment Agreements: Each of the employment agreements to which our executives were a party expired as of December 31, 2015. Currently none of our executive officers are parties to any employment agreement or compensatory arrangement, other than customary indemnification agreements.

2015 Summary Compensation Table

The following table sets forth the compensation of our principal executive officer and the two most highly compensated executive officers other than our principal executive officer for 2015 and 2014.

 

Name and Principal Position

  Year     Salary ($)     Bonus ($)     Option
Awards ($)(1)
    All Other
Compensation($)
    Total ($)  

Frank D. Bracken, III

    2015        600,000        400,000        —          23,890 (2)      1,023,890   

Chief Executive Officer

    2014        575,000        300,000        —          18,290 (2)      893,290   

Thomas H. Olle

    2015        350,000        233,333        —          20,200 (3)      603,533   

Senior Vice President—Operations

    2014        337,500        175,000        —          20,000 (3)      532,500   

Barry D. Schneider(4)

    2015        420,000        204,467        —          31,353 (5)      655,820   

Chief Operating Officer

    2014        68,937        134,468        665,064        8,669 (5)      877,138   

 

(1) Represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718.
(2) For 2015, includes $9,890 for executive medical coverage and $14,000 representing Mr. Bracken’s auto allowance. For 2014, includes $4,290 for executive medical coverage and $14,000 representing Mr. Bracken’s auto allowance.
(3) For 2015, includes $9,600 representing Mr. Olle’s auto allowance and $10,600 representing company matched 401(k) contributions. For 2014, includes $9,600 representing Mr. Olle’s auto allowance and $10,400 representing company matched 401(k) contributions.
(4) Mr. Schneider’s employment with Lonestar commenced in May 2014.
(5) For 2015, includes $8,753 for executive medical coverage, $12,000 representing Mr. Schneider’s auto allowance and $10,600 representing company matched 401(k) contributions. For 2014, includes $1,019 for executive medical coverage and $7,650 representing Mr. Schneider’s auto allowance

 

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Outstanding Equity Awards at Fiscal Year-End

The following table sets forth all outstanding equity awards held by each of our named executive officers at December 31, 2015 without giving effect to the Reorganization. As described above, in connection with the Reorganization, the options issued under the 2012 Plan were cancelled and reissued pursuant to our 2016 Plan on a one for two basis. These reissued options have the same exercise price and expiration date as prior to the Reorganization, except the exercise price is denominated in U.S. dollars instead of Australian Dollars.

 

Name

  Number of
Securities Underlying
Unexercised Options
(#) Exercisable(1)
    Number of Securities
Underlying
Unexercised Options
(#) Unexercisable(2)
    Option Exercise
Price
(A$)
    Option Expiry Date  

Frank D. Bracken, III

    412,058        103,014        15.00        Dec. 31, 2016   

Chief Executive Officer

    —          100,000        20.00        Dec. 31, 2016   

Thomas H. Olle

    236,240        59,060        15.00        Dec. 31, 2016   

Senior Vice President—Operations

       

Barry D. Schneider

    150,000        —          20.00        Dec. 31, 2017   

Chief Operating Officer

    —          50,000        20.00        Dec. 31, 2016   

 

(1) The option awards in this column represent Class A options granted to each of our named executive officers, all of which were fully vested as of December 31, 2015. For a description of the Class A options, please see the section above titled “—Approach to executive compensation—Long-term incentives.”
(2) The option awards in this column represent Class B options granted to each of our named executive officers, all of which remain unvested. For a description of the Class B options, please see the section above titled “—Approach to executive compensation—Long-term incentives.”

Compensation of Directors

For 2015, the compensation received by non-employee Directors consisted of a fixed fee, plus an additional fee for service as the Chairman of the Board.

The following table sets forth the compensation received by each non-employee Directors during our fiscal year ended December 31, 2015.

 

Name    Fees Earned or
Paid in Cash
($)(1)
     Option
Awards

($)(2)
     All Other
Compensation
($)(3)
     Total
($)
 

Bernard Lambilliotte

     100,000         —           —           100,000   

Daniel R. Lockwood

     50,000         —           —           50,000   

Dr. Christopher Rowland

     50,000         —           100,000         150,000   

Robert Scott

     48,714         —           —           48,714   

John Pinkerton

     —           377,277         —           377,277   

Mitchell Wells

     —           —           142,500         142,500   

 

(1) Represents the cash portion of the annual board fees and chair fees.
(2) Represents the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. As of December 31, 2015, Mr. Pinkerton held outstanding options to purchase 180,000 shares of the Company’s Class A common stock (without giving effect to the Reorganization), excluding options that expired unexercised on December 31, 2015
(3) Other compensation for Dr. Rowland and Mr. Wells consisted of consulting fees, as described in more detail above in the section titled “Certain Relationships and Related Party Transactions—Related Transactions.”

 

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2016 Incentive Plan

In connection with the Reorganization, we adopted and our stockholders approved the 2016 Incentive Plan, or the 2016 Plan, under which we may grant awards of options to purchase shares of Class A common stock (“Options”) to eligible service providers in order to attract employees and directors of experience and ability, foster and promote loyalty between us and our employees and directors, recognize the ongoing ability of our employees and their expected efforts and contribution in the long term to our performance and success and provide an incentive to our employees and directors by giving them an opportunity to acquire Options, and ultimately, shares of Class A common stock in accordance with the terms of the 2016 Plan. The material terms of the 2016 Plan are summarized below.

Eligibility and Administration

Our employees and directors, and employees of certain of our affiliates, are eligible to receive awards under the 2016 Plan. The 2016 Plan is administered by our board of directors, which may delegate administration of the 2016 Plan to one or more committees of our directors and/or officers (referred to collectively as the plan administrator below), subject to the limitations imposed under the 2016 Plan, Section 16 of the Exchange Act, stock exchange rules and other applicable laws. The plan administrator has the authority to make all decisions and determinations under the 2016 Plan, to interpret the 2016 Plan and award agreements and to establish, adopt or revise rules for the administration of the 2016 Plan as it deems advisable. The plan administrator also has the authority to determine which eligible service providers receive awards, grant awards and set the terms and conditions of all awards under the 2016 Plan, including any vesting and vesting acceleration provisions, subject to the conditions and limitations in the 2016 Plan.

Shares Available for Awards

An aggregate of 2,500,000 shares of Class A common stock were initially reserved for issuance under the 2016 Plan. All such shares of Class A common stock reserved for issuance may be issued under the 2016 Plan upon the exercise of incentive stock options. Shares issued under the 2016 Plan may be authorized but unissued shares, shares purchased on the open market or treasury shares.

If an award under the 2016 Plan expires, lapses or is terminated, any unused shares subject to the award will again be available for new grants under the 2016 Plan. Shares issued pursuant to awards under the 2016 Plan in assumption of, or substitution for, any outstanding awards of an entity acquired in any form of combination by us or our affiliate will not reduce the shares available for grant under the 2016 Plan. In addition, in the event the company acquired by (or combined with) us or our affiliate has shares available under a preexisting plan approved by its stockholders and not adopted in contemplation of such acquisition or combination, the shares available for grant pursuant to such pre-existing plan may, in the plan administrator’s discretion, be used for awards under the 2016 Plan in lieu of awards under the applicable preexisting plan of the other company and will not reduce the shares available for grant under the 2016 Plan, subject to certain limitations set forth in the 2016 Plan. However, the 2016 Plan does not allow the share pool available for awards to be recharged or replenished with shares covered by an Option that are surrendered to satisfy the exercise price of an Option or tax withholding obligations, with shares that are not issued or delivered as a result of the net-settlement of an outstanding Option or with shares we repurchase on the open market with the proceeds from the exercise of Options.

In addition, the maximum aggregate grant date fair value (as determined in accordance with GAAP) of Options granted to any non-employee Director for services as a non-employee Director in any calendar year may not exceed $300,000 (or, in the calendar year of any director’s initial service, $1,000,000).

Awards

The 2016 Plan provides for the grant of Options, including incentive stock options, or ISOs, and nonqualified stock options, or NSOs. Certain awards under the 2016 Plan may constitute or provide for payment

 

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of “nonqualified deferred compensation” under Section 409A of the Code. All awards under the 2016 Plan must be set forth in award agreements, which detail the terms, conditions and limitations of awards, including any applicable vesting and payment terms and post-termination exercise limitations. Unless otherwise provided by the plan administrator, if a participant ceases to provide services to us or any of our affiliates due to retirement, disability, redundancy or death, any unvested portion of such participant’s Option will vest in full.

Options provide for the purchase of shares of Class A common stock in the future at an exercise price set on the grant date. ISOs, by contrast to NSOs, may provide tax deferral beyond exercise and favorable capital gains tax treatment to their holders if certain holding period and other requirements of the Code are satisfied. The plan administrator determines the number of shares covered by each Option, the exercise price of each Option and the conditions and limitations applicable to the exercise of each Option. The exercise price of an Option may not be less than 100% of the fair market value of the underlying share on the grant date (or 110% in the case of ISOs granted to certain significant stockholders). The term of an Option may not be longer than seven years (or five years in the case of ISOs granted to certain significant stockholders).

Certain Transactions; Change in Control

In connection with certain corporate transactions and events affecting our Class A common stock or any unusual or nonrecurring transactions or events affecting us, any of our affiliates, or our or any of our affiliates’ financial statements, or any change in any applicable laws or accounting principles, the plan administrator has broad discretion to take action under the 2016 Plan to prevent the dilution or enlargement of intended benefits, facilitate the transaction or event or give effect to the change in applicable laws or accounting principles. This includes canceling awards for cash or property, accelerating the vesting of awards, providing that the award cannot vest or be exercised, providing for the assumption or substitution of awards by a successor entity, and adjusting the number and type of shares subject to outstanding awards and/or with respect to which awards may be granted under the 2016 Plan, or the exercise price of outstanding Options. In addition, in the event of certain non-reciprocal transactions with our stockholders, the number and type of securities, and exercise price of, outstanding awards will be equitable adjusted, and the plan administrator will make equitable adjustments to the number and kind of shares that may be issued under 2016 Plan as it deems appropriate to reflect the transaction.

However, notwithstanding the preceding paragraph, if an award is not converted, assumed, substituted or replaced by a successor entity in connection with a change in control, then such award will become fully vested and exercisable immediately prior to the change in control, except as provided otherwise in an award agreement. The plan administrator may provide that an award will automatically accelerate in connection with a change in control or, if assumed after a change in control, that an award will automatically accelerate upon an involuntary termination of the participant’s employment or service within a certain period following such change in control.

Minimum Vesting

Awards granted under the 2016 Plan may not vest earlier than the first anniversary of the grant date, subject to earlier vesting in connection with a change in control or the participant’s termination of service due to retirement, disability, redundancy or death (in each case, as described above); provided that awards resulting in the issuance of an aggregate of up to 5% of the shares of Class A common stock available under the 2016 Plan may be granted to any one or more participants without respect to such minimum vesting provisions.

Plan Amendment, Modification and Termination

With the approval of our board of directors, the plan administrator may amend, modify or terminate the 2016 Plan at any time; however, stockholder approval will be obtained to the extent necessary to comply with applicable laws and for any amendment that increases the number of shares available under the 2016 Plan (except in connection with certain transactions as described above) or permits the plan administrator to extend the exercise period for an Option beyond seven years from the grant date. Further, the plan administrator cannot,

 

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without the approval of our stockholders, amend any outstanding Option to reduce its price per share and, except in connection with certain transactions as described above, (a) no Option may be granted in exchange for the cancellation, surrender or substitution of an Option having a higher price per share and (b) no Option may be cancelled in exchange for the payment of a cash amount at a time when the Option has a price per share that is higher than the fair market value of a share. As determined in the plan administrator’s discretion, no termination, amendment or modification of the 2016 Plan may adversely affect, in any material way, any outstanding award under the 2016 Plan without the written consent of the affected participant. The 2016 Plan will remain in effect until it is terminated by the board of directors, except that no ISO may be granted after the tenth anniversary of the date it was adopted by the board. Any awards that are outstanding on the date the 2016 Plan terminates will remain in force according to the terms of the 2016 Plan and the applicable award agreement.

Foreign Participants, Claw-Back Provisions, Transferability and Participant Payments

The plan administrator may establish, adopt or revise any rules and regulations, including adopting sub-plans or addenda to the 2016 Plan, for purposes of complying with foreign laws and/or taking advantage of tax-favorable treatment for awards granted to participants outside the United States. All awards are subject to any company claw-back policy as set forth in such claw-back policy or the applicable award agreement. Except as the plan administrator may determine, awards under the 2016 Plan are generally non-transferrable other than by will or the laws of descent and distribution. The plan administrator may determine the methods by which the exercise price of an Option may be paid, including cash or check, surrender of shares that meet specified conditions, a promissory note, a “market sell order,” other property acceptable to the plan administrator or any combination of the foregoing. To satisfy any tax withholding obligations arising in connection with awards under the 2016 Plan, we (or any of our Affiliates) may withhold from the participant’s wages or other cash compensation, withhold from the proceeds of a sale of shares underlying an award or, in the plan administrator’s discretion, withhold shares otherwise issuable pursuant to an award.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The table below sets forth certain information regarding the beneficial ownership of our Class A common stock as of September 30, 2016 by (i) each of our named executive officers and directors; (ii) each person who, to our knowledge, beneficially owns more than 5% of our outstanding Class A common stock; and (iii) all of our directors and executive officers as a group.

Beneficial ownership is determined according to the rules of the SEC and generally includes any shares over which a person exercises sole or shared voting or investment power. All shares of Class A common stock owned by such person, including shares of Class A common stock underlying stock options that are currently exercisable or exercisable within 60 days after September 30, 2016 are deemed to be outstanding and beneficially owned by that person for the purpose of computing the ownership percentage of that person, but are not considered outstanding for the purpose of computing the percentage ownership of any other person. Except as otherwise indicated, to our knowledge, each person listed in the table below has sole voting and investment power with respect to the shares shown to be beneficially owned by such person, except to the extent that applicable law gives spouses shared authority. The address of each of our executive officers and directors listed below is c/o Lonestar Resources US Inc., 600 Bailey Avenue, Suite 200, Ft. Worth, Texas 76107.

 

     Before this Offering     After this Offering  

Name

   Number of
Shares

Beneficially
Owned
     Percentage
of
Outstanding
Shares(1)
    Number of
Shares

Beneficially
Owned
     Percentage
of
Outstanding
Shares(1)
 

EF Realisation Company Limited (2)

     4,174,259         52.0     

BNP Paribas House, St. Julian’s Avenue, St Peter Port, Guernsey, Channel Islands, GY1 1WA, U.K.

          

Leucadia National Corporation (3)

     1,000,227         11.7     

520 Madison Ave., New York, New York 10022

          

Named Executive Officers

          

Frank D. Bracken, III (4)

     280,400         3.4     

Barry Schneider (5)

     96,500         1.2     

Thomas H. Olle (6)

     150,996         1.9     

Directors (other than Mr. Bracken)

          

Bernard Lambilliotte (7)

     196,128         2.4     

Christopher Rowland, Ph.D. (8)

     62,438         *        

Daniel Lockwood

     8,982         *        

Mitchell Wells

     2,200         *        

John Pinkerton (9)

     90,000         1.1     

Robert Scott (10)

     35,600         *        

Henry B. Ellis

     0         *        

Executive Officers and Directors as a group (13 persons) (11)

     989,633         11.6     

 

* Represents beneficial ownership of less than 1% of the outstanding shares of Class A common stock.

 

(1) Based on 8,022,015 shares of Class A common stock issued and outstanding as of September 30, 2016.

 

(2) Consists of 4,174,259 shares directly held by EFR Guernsey Holding Limited (“EFR Guernsey”). EFR Guernsey is a wholly-owned subsidiary of EF Realisation Company Limited (“EFR”). A majority of the board of directors of EFR, comprised of Martin Negre, Robert Sinclair and Nicholas Tostevin, has sole voting and investment power over the shares directly held by EFR Guernsey. Each director of EFR disclaims beneficial ownership of such shares.

 

(3) Consists of 500,227 shares and 500,000 shares that may be acquired upon the exercise of stock options that have vested or will vest within 60 days after September 30, 2016.

 

 

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(4) Consists of 74,371 shares and 206,029 shares that may be acquired upon the exercise of stock options that have vested or will vest within 60 days after September 30, 2016.

 

(5) Consists of 46,500 shares and 50,000 shares that may be acquired upon the exercise of stock options that have vested or will vest within 60 days after September 30, 2016.

 

(6) Consists of 32,876 shares and 118,120 shares that may be acquired upon the exercise of stock options that have vested or will vest within 60 days after September 30, 2016.

 

(7) Consists of 47,170 shares directly held by an international pension plan and 148,958 shares directly held by Ecofin Holdings Limited (“EHL”). Mr. Lambilliotte exercises control over the international pension plan and therefore may be deemed to have beneficial ownership with respect to such shares. Mr. Lambilliotte holds a majority of the shares of EHL directly as an individual and indirectly through a family-owned company and a family trust, which he controls as the settlor and a discretionary beneficiary. As a result of his direct and indirect holdings of a majority of EHL’s shares, Mr. Lambilliotte may be deemed to have shared voting and investment power over the shares directly held by EHL, and therefore may be deemed to share beneficial ownership with respect to such shares.

 

(8) Consists of 62,438 shares that Dr. Rowland directly holds. Dr. Rowland also holds 2,500 shares of the Company’s non-voting Class B common stock, which is not reflected in the table above.

 

(9) Consists of 90,000 shares that may be acquired upon the exercise of stock options that have vested or will vest within 60 days of the filing after September 30, 2016.

 

(10) Consists of 35,300 shares directly held by Ferber Holdings Pty Ltd and 300 shares directly held by Carpenter Nominees Pty Ltd. As the only shareholders and directors of each of the foregoing entities, Mr. Scott and his spouse Susanne Scott may be deemed to have shared voting and investment power over the shares directly held by such entities.

 

(11) Includes an aggregate of 522,102 shares that may be acquired upon the exercise of stock options that have vested or will vest within 60 days after September 30, 2016.

 

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RECENT AND FORMATION TRANSACTIONS

We were incorporated in Delaware in December 2015 for purposes of effecting our Reorganization, which was completed on July 5, 2016, pursuant to the Scheme, dated December 28, 2015, between us and our Predecessor and former parent 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, we acquired all of the issued and outstanding ordinary shares of our Predecessor, and each of our Predecessor’s stockholders received one share of our Class A common stock for every two ordinary shares of our Predecessor such stockholder held.

In connection with the Reorganization, the Company filed a registration statement on Form 10 (the “registration statement”) to register our Class A common stock pursuant to Section 12(b) of the Exchange Act. Following the effectiveness of the registration statement and in connection with the completion of the Reorganization, the ordinary shares of our Predecessor were delisted from the ASX, and our Class A common stock was listed on NASDAQ.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Other than as disclosed below, since January 1, 2013 we have not entered into any transactions or loans with any: (i) enterprises that directly or indirectly, through one or more intermediaries, control, are controlled by or are under common control with us; (ii) associates; (iii) individuals owning, directly or indirectly, an interest in our voting power that gives them significant influence over us, and close members of any such individual’s family; (iv) key management personnel and close members of such individuals’ families; or (v) enterprises in which a substantial interest in our voting power is owned, directly or indirectly, by any person described in (iii) or (iv) or over which such person is able to exercise significant influence.

Related Transactions

Leucadia

On August 2, 2016, LRAI and the Company entered into the Purchase Agreement with Juneau, 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 Second Lien Notes and (ii) Warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock. Pursuant to the Purchase Agreement Juneau purchased $13,000,000 aggregate principal amount of Second Lien Notes and Warrants to purchase 500,000 shares of Class A common stock. On August 2, 2016, the Company also issued 500,227 shares of Class A common stock to Juneau pursuant in exchange for interests in certain oil and gas assets pursuant to a purchase and sale agreement (the “Purchase and Sale Agreement”).

Due to Leucadia’s ownership interests in Juneau, Leucadia is considered to be the beneficial owner of shares Juneau owns. As a result of the Warrants and Class A common stock issuances to Juneau in connection with the Purchase Agreement and the Purchase and Sale Agreement, respectively, Leucadia is the beneficial owner of more than 10% of the Company’s Class A common stock.

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 common stock issued or issuable to Juneau and Leucadia, including those issuable upon exercise of the Warrants. Leucadia has agreed, pursuant to the equity commitment agreement, to purchase a certain number of Class A common stock in case the Company elects to pursue an equity offering prior to December 31, 2016.

EF Realisation

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

On October 26, 2016, we entered into a Registration Rights Agreement with EF Realisation, pursuant to which we agreed to register for resale Class A common stock held by EF Realisation. We have agreed to file a registration statement providing for the resale of Class A common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date we first become eligible to file a registration statement on Form S-3. We have also granted EF Realisation certain piggyback and demand registration rights.

 

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Frank D. Bracken III and Thomas H. Olle

In April 2014, we 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.

Dr. Christopher Rowland

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

Daniel R. Lockwood

New Tech Global Ventures, LLC, a company in which Daniel R. Lockwood, a current director, 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 $938,000 and $2,300,000 in 2015 and 2014, respectively.

Mitchell Wells

Mitchell Wells, who has been a director of our predecessor 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 $142,500 in 2015 and $181,458 in 2014. He has not received any additional compensation for his service as a Director.

Our Policies Regarding Review, Approval or Ratification of Related-Party Transactions

We review all relationships and transactions in which we, our directors and executive officers or their immediate family members are participants to determine whether such persons have a direct or indirect material interest. Our Chief Executive Officer and Chief Financial Officer are primarily responsible for the development and implementation of processes and controls to obtain information from the directors and executive officers with respect to related party transactions. Our Audit and Risk Committee reviews and approves or ratifies any related party transaction pursuant to the authority given under the charter of the Audit and Risk Committee.

 

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DESCRIPTION OF CAPITAL STOCK

The following description of our capital stock is a summary only and is qualified in its entirety by reference to our Certificate of Incorporation and Bylaws, which are included as Exhibits 3.1 and 3.2 of this registration statement, the provisions of applicable law, the Board Representation Agreement and the registration rights agreements, which are filed as exhibits to this registration statement.

We are authorized to issue up to 15,000,000 shares of Class A common stock, $0.001 par value per share, and 5,000 shares of Class B common stock, $0.001 par value per share.

Holders of our Class A common stock are entitled to one vote for each share on all matters voted on by stockholders, including the election of directors. Except as required by law, the holders of our Class B common stock will not be entitled to vote on matters voted on by stockholders.

Holders of our Class A and Class B common stock are entitled to receive dividends when and as declared by our board of directors out of funds legally available for dividends; provided, however, that any dividend upon the common stock that is payable in common stock shall be paid only in Class A common stock to the holders of Class A common stock and only in Class B common stock to the holders of Class B common stock.

Holders of our common stock do not have any conversion, redemption or pre-emptive rights. In the event of any voluntary or involuntary liquidation, dissolution or winding up of the company, the holders of shares of our common stock will be entitled to receive all of the remaining assets of the company available for distribution to its stockholders, ratably in proportion to the number of shares of common stock held by them, regardless of whether such shares are Class A common stock or Class B common stock.

Any outstanding shares of our common stock are fully paid and non-assessable.

Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law

Certain provisions of our Certificate of Incorporation and Bylaws may be considered as having an anti-takeover effect, such as the following provisions:

 

    requiring advance notice of stockholder intention to put forth director nominees or bring up other business at a stockholders’ meeting (subject to the Board Representation Agreement);

 

    requiring the affirmative vote of 66 2/3% of the voting power of all then outstanding shares entitled to vote in order for stockholders to adopt, amend or repeal any provision of our Bylaws or Certificate of Incorporation; and

 

    providing that the number of directors shall be fixed from time to time by our board of directors pursuant to a resolution adopted by a majority of the total number of authorized directors (whether or not there exist any vacancies in previously authorized directorships) or by the stockholders (subject to the Board Representation Agreement). Newly created directorships resulting from any increase in our authorized number of directors will be filled only by a majority vote of our board of directors then in office, whether or not such directors number less than a quorum, and directors so chosen will serve for a term expiring at the annual meeting of stockholders at which the term of office to which they have been elected expires or until such director’s successor shall have been duly elected and qualified.

We are also subject to Section 203 of the Delaware General Corporation Law (the “DGCL”), which in general prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

 

    prior to that date, our board of directors approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

 

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    upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares outstanding (but not the outstanding voting stock owned by the interested stockholder) those shares owned by (i) persons who are directors and also officers and (ii) employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or

 

    on or subsequent to that date, the business combination is approved by our board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.

In general, Section 203 defines an interested stockholder as an entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by any of these entities or persons.

The above-summarized provisions of the DGCL and our Certificate of Incorporation and Bylaws could make it more difficult to acquire us by means of a tender offer, a proxy contest or otherwise, or to remove incumbent officers and directors. These provisions are expected to discourage certain types of coercive takeover practices and takeover bids that our board of directors may consider inadequate and to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging takeover or acquisition proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

Limitation of Liability and Indemnification Matters

Our Certificate of Incorporation provides that, our directors shall not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except to the extent such exemption from liability or limitation is not permitted under the DGCL. Our Bylaws provide that, to the fullest extent permitted by Delaware law, we will indemnify and advance expenses (including attorneys’ fees, judgments, fines or penalties and amounts paid in settlement) to a director or officer in an action brought by reason of the fact that the director or officer is or was our director or officer, or is or was serving at our request as a director or officer of any other entity, against all expenses, liability and loss incurred or suffered by such person in connection therewith. We may also, to the extent authorized by the board of directors, grant rights to indemnification and to the advancement of expenses to any employee or agent of Lonestar to the fullest extent permitted by the DGCL. We may maintain insurance to protect a director, officer, employee or agent against any expense, liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under Delaware law.

The limitation of liability and indemnification provisions in our Certificate of Incorporation and Bylaws may discourage stockholders from bringing a lawsuit against directors for breach of their fiduciary duty. These provisions may also have the effect of reducing the likelihood of derivative litigation against our directors and officers, even though such an action, if successful, might otherwise benefit us and our stockholders. However, these provisions do not limit or eliminate our rights, or those of any stockholder, to seek non-monetary relief such as injunction or rescission in the event of a breach of a director’s duty of care. The provisions will not alter the liability of directors under the federal securities laws. In addition, your investment may be adversely affected to the extent that, in a class action or direct suit, we pay the costs of settlement and damage awards against directors and officers pursuant to these indemnification provisions. There is currently no pending litigation or proceeding against any of our directors, officers or employees for which indemnification is sought.

 

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Transfer Agent and Registrar

The transfer agent and registrar for our Class A common stock is Computershare.

Listing

Shares of our Class A common stock trade on NASDAQ under the symbol “LONE.”

 

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SHARES ELIGIBLE FOR FUTURE SALE

Our Class A common stock currently trades on NASDAQ. Future sales of our Class A common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect the market price of our Class A common stock prevailing from time to time. As described below, some shares will not be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our Class A common stock in the public market after such restrictions lapse, or the perception that those sales may occur, together with our Class A common stock issued prior to this offering, could adversely affect the prevailing market price of our Class A common stock at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Upon the closing of this offering, we will have outstanding an aggregate of              shares of Class A common stock. Of these shares, all of the              shares of Class A common stock (or              shares of Class A common stock if the underwriters’ option to purchase additional shares is exercised) to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act.

Rule 144

In general, under Rule 144 under the Securities Act as currently in effect, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for at least sixth months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person (who has been unaffiliated for at least the past three months) who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

A person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our Class A common stock or the average weekly trading volume of our Class A common stock reported through NASDAQ during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Lock-up Agreements

We, all of our directors and officers and certain of our principal stockholders have agreed not to sell any Class A common stock for a period of 90 days from the date of this prospectus, subject to certain exceptions and extensions. See “Underwriting” for a description of these lock-up provisions.

Registration Rights Agreements

We have entered into a Registration Rights Agreement, dated as of August 2, 2016, with Leucadia and Juneau. Pursuant to the Registration Rights Agreement, we have agreed to register for resale certain restricted shares of Class A common stock issued or issuable to, including those issuable upon exercise of our Warrants. We have agreed to file a registration statement providing for resale of such shares no later than the earlier of (i) the one year anniversary of the consummation of a registered public offering and (ii) 30 days after the date we first become eligible to file a registration statement on Form S-3. We have also granted Leucadia and Juneau certain piggyback and demand registration rights.

On October 26, 2016, we entered into a Registration Rights Agreement with EF Realisation, pursuant to which we agreed to register for resale Class A common stock held by EF Realisation. We have agreed to file a registration statement providing for the resale of Class A common stock held by EF Realisation no later than the earlier of (i) October 26, 2017, and (ii) 30 days after the date we first become eligible to file a registration statement on Form S-3. We have also granted EF Realisation certain piggyback and demand registration rights.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following discussion is a summary of the material U.S. federal income tax consequences to Non-U.S. Holders (as defined below) of the purchase, ownership and disposition of our Class A common stock issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects relating thereto. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local or non-U.S. tax laws are not discussed. This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), Treasury regulations promulgated thereunder (“Treasury Regulations”), judicial decisions, and published rulings and administrative pronouncements of the U.S. Internal Revenue Service (the “IRS”), in each case as in effect as of the date hereof. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could adversely affect a Non-U.S. Holder of our Class A common stock. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership and disposition of our Class A common stock.

This discussion is limited to Non-U.S. Holders that hold our Class A common stock as a “capital asset” within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all U.S. federal income tax consequences relevant to a Non-U.S. Holder’s particular circumstances, including the impact of the Medicare contribution tax on net investment income. In addition, it does not address consequences relevant to Non-U.S. Holders subject to special rules, including, without limitation:

 

    U.S. expatriates and former citizens or long-term residents of the United States;

 

    persons subject to the alternative minimum tax;

 

    persons holding our Class A common stock as part of a hedge, straddle or other risk reduction strategy or as part of a conversion transaction or other integrated investment;

 

    banks, insurance companies, and other financial institutions;

 

    brokers, dealers or traders in securities;

 

    “controlled foreign corporations,” “passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax;

 

    partnerships, or other entities or arrangements treated as partnerships for U.S. federal income tax purposes (and investors therein);

 

    tax-exempt organizations or governmental organizations;

 

    persons deemed to sell our Class A common stock under the constructive sale provisions of the Code;

 

    persons who hold or receive our Class A common stock pursuant to the exercise of any employee stock option or otherwise as compensation;

 

    “qualified foreign pension funds” as defined in Section 897(l)(2) of the Code and entities all of the interests of which are held by qualified foreign pension funds; and

 

    tax-qualified retirement plans.

If an entity or arrangement treated as a partnership for U.S. federal income tax purposes holds our Class A common stock, the tax treatment of a partner in such partnership will depend on the status of the partner, the activities of such partnership and certain determinations made at the partner level. Accordingly, partnerships holding our Class A common stock and partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.

 

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THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF OUR CLASS A COMMON STOCK ARISING UNDER THE U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR UNDER THE LAWS OF ANY STATE, LOCAL OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE INCOME TAX TREATY.

Definition of a Non-U.S. Holder

For purposes of this discussion, a “Non-U.S. Holder” is any beneficial owner of our Class A common stock that is neither a “U.S. person” nor an entity treated as a partnership for U.S. federal income tax purposes. A U.S. person is any person that, for U.S. federal income tax purposes, is or is treated as any of the following:

 

    an individual who is a citizen or resident of the United States;

 

    a corporation (or an entity treated as such for U.S. federal income tax purposes) created or organized under the laws of the United States, any state thereof, or the District of Columbia;

 

    an estate, the income of which is subject to U.S. federal income tax regardless of its source; or

 

    a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more “United States persons” (within the meaning of Section 7701(a)(30) of the Code), or (2) has a valid election in effect to be treated as a United States person for U.S. federal income tax purposes.

Distributions

As described above in the section entitled “Dividend Policy” we do not anticipate declaring or paying dividends to holders of our Class A common stock in the foreseeable future. However, if we do make distributions of cash or property on our Class A common stock, such distributions will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Amounts not treated as dividends for U.S. federal income tax purposes will constitute a return of capital and first be applied against and reduce a Non-U.S. Holder’s adjusted tax basis in its Class A common stock, but not below zero. Any excess will be treated as capital gain and will be treated as described below under “Sale or Other Taxable Disposition.”

Subject to the discussion below on effectively connected income, dividends paid to a Non-U.S. Holder of our Class A common stock will be subject to U.S. federal withholding tax at a rate of 30% of the gross amount of the dividends (or such lower rate specified by an applicable income tax treaty, provided the Non-U.S. Holder furnishes a valid IRS Form W-8BEN or W-8BEN-E (or other applicable documentation) certifying qualification for the lower treaty rate). A Non-U.S. Holder that does not timely furnish the required documentation, but that qualifies for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. Holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.

If dividends paid to a Non-U.S. Holder are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such dividends are attributable), the Non-U.S. Holder will be exempt from the U.S. federal withholding tax described above. To claim the exemption, the Non-U.S. Holder must furnish to the applicable withholding agent a valid IRS Form W-8ECI, certifying that the dividends are effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States.

Any such effectively connected dividends will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected

 

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earnings and profits (as adjusted for certain items), which will include such effectively connected dividends. Non-U.S. Holders should consult their tax advisors regarding any applicable tax treaties that may provide for different rules.

For additional withholding rules that may apply to dividends, see the discussions below under the headings “Information Reporting and Backup Withholding” and “Additional Withholding Tax on Payments Made to Foreign Accounts.”

Sale or Other Taxable Disposition

Subject to the discussions below in “Information Withholding and Backup Reporting” and “Additional Withholding Tax on Payments Made to Foreign Accounts,” a Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of our Class A common stock unless:

 

    the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such gain is attributable);

 

    the Non-U.S. Holder is a nonresident alien individual present in the United States for 183 days or more during the taxable year of the disposition and certain other requirements are met; or

 

    our Class A common stock constitutes a United States real property interest (“USRPI”) by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes. Generally, a domestic corporation is a USRPHC if the fair market value of its USRPIs equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests plus its other assets used or held for use in its trade or business.

Gain described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on its effectively connected earnings and profits (adjusted for certain items), which will include such effectively connected gain.

A Non-U.S. Holder described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on any gain derived from the disposition, which may be offset by U.S. source capital losses of the Non-U.S. Holder (even though the individual is not considered a resident of the United States), provided the Non-U.S. Holder has timely filed U.S. federal income tax returns with respect to such losses.

With respect to the third bullet point above, we believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, a Non-U.S. Holder of our Class A common stock will not be subject to U.S. net federal income tax as a result of our being a USRPHC if our Class A common stock is “regularly traded,” as defined by applicable Treasury Regulations, on an established securities market, and such Non-U.S. Holder did not own, actually or constructively, greater than 5% of our Class A common stock throughout the shorter of the five-year period ending on the date of the sale or other taxable disposition or the Non-U.S. Holder’s holding period. If our Class A common stock is not considered to be so traded, a Non-U.S. Holder generally would be subject to net U.S. federal income tax on the gain realized on a disposition of our Class A common stock as a result of our being a USRPHC and generally would be required to file a U.S. federal income tax return. Additionally, a 15% withholding tax would apply to the gross proceeds from such disposition.

Non-U.S. Holders should also consult their tax advisors regarding potentially applicable income tax treaties that may provide for different rules.

 

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Information Reporting and Backup Withholding

Payments of dividends on our Class A common stock will not be subject to backup withholding, provided the applicable withholding agent does not have actual knowledge or reason to know the Non-U.S. Holder is a United States person and the Non-U.S. Holder either certifies its non-U.S. status, such as by furnishing a valid IRS Form W-8BEN, W-8BEN-E or W-8ECI, or otherwise establishes a valid exemption. However, information returns are required to be filed with the IRS in connection with any dividends on our Class A common stock paid to the Non-U.S. Holder, regardless of whether any tax was actually withheld. In addition, proceeds of the sale or other taxable disposition of our Class A common stock within the United States or conducted through certain U.S.-related brokers generally will not be subject to backup withholding or information reporting if the applicable withholding agent receives the certification described above and does not have actual knowledge or reason to know that such Non-U.S. Holder is a United States person, or the Non-U.S. Holder otherwise establishes a valid exemption. Proceeds of a disposition of our Class A common stock conducted through a non-U.S. office of a non-U.S. broker generally will not be subject to backup withholding or information reporting.

Copies of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the country in which the Non-U.S. Holder resides or is established.

Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. Holder’s U.S. federal income tax liability, provided the required information is timely furnished to the IRS.

Additional Withholding Tax on Payments Made to Foreign Accounts

Withholding taxes may be imposed under Sections 1471 to 1474 of the Code (such Sections commonly referred to as the Foreign Account Tax Compliance Act, or “FATCA”) on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or gross proceeds from the sale or other disposition of, our Class A common stock paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each direct and indirect substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as IRS Form W-8BEN-E). If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain “specified United States persons” or “United States-owned foreign entities” (each as defined in the Code), annually report certain information about such accounts, and withhold 30% on certain payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.

Under the applicable Treasury Regulations and administrative guidance, withholding under FATCA generally applies to payments of dividends on our Class A common stock, and will apply to payments of gross proceeds from the sale or other disposition of such stock on or after January 1, 2019.

Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our Class A common stock.

 

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UNDERWRITING

Overview

We have entered into an underwriting agreement with the underwriters named below. Seaport Global Securities LLC is acting as the representative of the underwriters.

The underwriting agreement provides for the purchase of a specific number of shares of Class A common stock by each of the underwriters. The underwriters’ obligations are several, which means that each underwriter is required to purchase a specified number of shares, but is not responsible for the commitment of any other underwriter to purchase shares. Subject to the terms and conditions of the underwriting agreement, each underwriter has severally agreed to purchase the number of shares of Class A common stock set forth opposite its name below:

 

Underwriters    Number of Shares  

Seaport Global Securities LLC

  

Johnson Rice & Company L.L.C.

  
  
  
  

Total

  
  

 

 

 

The underwriters have agreed to purchase all of the shares offered by this prospectus (other than those covered by the over-allotment option described below) if any are purchased. Under the underwriting agreement, if an underwriter defaults in its commitment to purchase shares, the commitments of non-defaulting underwriters may be increased or the underwriting agreement may be terminated, depending on the circumstances. We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act.

The underwriters have advised us that they currently intend to make a market in the Class A common stock. However, the underwriters are not obligated to do so and may discontinue any market-making activities at any time without notice. No assurance can be given as to the liquidity of the trading market for our Class A common stock. The underwriters are offering shares of Class A common stock subject to their acceptance of the shares from us and subject to prior sale. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part. In addition, the underwriters have advised us that they do not intend to confirm sales to any account over which they exercise discretionary authority.

The shares should be ready for delivery on or about                     , 2016, against payment in immediately available funds. The underwriters are offering the shares subject to various conditions and may reject all or part of any order. The representative has advised us that the underwriters propose to offer the shares directly to the public at the public offering price that appears on the cover page of this prospectus. In addition, the representative may offer some of the shares to other securities dealers at such price less a concession of $        per share. The underwriters may also allow, and such dealers may reallow, a concession not in excess of $        per share to other dealers. After the shares are released for sale to the public, the representative may change the offering price and other selling terms at various times.

 

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Commission and Expenses

The following table provides information regarding the amount of the discount to be paid to the underwriters by us:

 

     Per Share      Total  
     Without
Option to
Purchase
Additional
Shares
     With Option
to
Purchase
Additional
Shares
     Without
Option
to Purchase
Additional
Shares
     With
Option to
Purchase
Additional
Shares
 

Public offering price

           

Underwriting discounts and commissions paid by us

           

Proceeds to us, before expenses

           

In this offering, Leucadia National Corporation has agreed to purchase from the Underwriters              shares of Class A common stock at $        per share, which is the price per share paid by the public.

We estimate that our total expenses of the offering, excluding the underwriting discount, will be $        .

Option to Purchase Additional Shares

We have granted the underwriters an over-allotment option. This option, which is exercisable for up to 30 days after the date of this prospectus, permits the underwriters to purchase a maximum of              additional shares from us to cover overallotments. If the underwriters exercise all or part of this option, they will purchase shares covered by the option at the public offering price that appears on the cover page of this prospectus, less the underwriting discount. If this option is exercised in full, the total price to public will be approximately $        million and the total proceeds to us will be approximately $        million. The underwriters have severally agreed that, to the extent the over-allotment option is exercised, they will each purchase a number of additional shares proportionate to the underwriter’s initial amount reflected in the foregoing table.

Listing

Our Class A common stock is quoted on NASDAQ under the trading symbol “LONE”.

No Sales of Similar Securities

We, along with our executive officers, directors and EF Realisation, have agreed with the underwriters that, subject to certain exceptions, for a period of 90 days following the date of the underwriting agreement, we or they will not offer, pledge, announce the intention to sell, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, make any short sale or otherwise transfer or dispose of, directly or indirectly, any shares of our Class A common stock or any securities convertible into, exercisable or exchangeable for or that represent the right to receive our Class A common stock (including without limitation, Class A common stock which may be deemed to be beneficially owned by such director, executive officer or security holder in accordance with rules and regulations of the SEC and securities that may be issued upon exercise of a stock option or warrant) whether owned or later acquired, or enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of our Class A common stock or such other securities, or make any demand for, or exercise any right with respect to, the registration of any shares of our Class A common stock or any security convertible into or exercisable or exchangeable for our Class A common stock.

The 90-day lock-up period described in the preceding paragraph will be extended if (i) during the last 17 days of the 90-day lock-up period we issue an earnings release or material news or a material event relating to us occurs, or (ii) prior to the expiration of the 90-day lock-up period, we announce that we will release earnings

 

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results during the 16-day period beginning on the last day of the 90-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the release or the occurrence of the material news or material event, unless such extension is waived, in writing, by on behalf of the underwriters.

Among other exceptions and subject to certain conditions, the foregoing restrictions will not apply to (i) the sale of the shares of Class A common stock to the underwriters as contemplated by the underwriting agreement, (ii) our ability to issue up to 5% of our outstanding Class A common stock to one or more counterparties in connection with certain strategic transactions, including partnering or collaboration arrangements, that we may enter into in the future, (iii) certain transfers by gift, or by will or intestate succession, (iv) distributions by the locked up party to its partners, members or stockholders, (v) the exercise or settlement of any equity awards pursuant to our equity incentive plans or the exercise of warrants issued by us, provided that the underlying securities shall continue to be subject to the restrictions set forth in the lock-up agreement, (vi) the establishment of a trading plan pursuant to Rule 10b5-1 under the Exchange Act for the sale of our securities, provided that such plan does not provide for any sales during the lock- up period, and (vii) transfers of our Class A common stock, or any securities convertible into, exercisable or exchangeable for our Class A common stock, pursuant to a sale or an offer to purchase 100% of our outstanding Class A common stock, whether pursuant to a merger, tender offer or otherwise, to a third party or group of third parties. may, in their sole discretion and at any time or from time to time before the termination of the 90-day period, without public notice, release all or any portion of the securities subject to lock-up agreements. There are no existing agreements between the underwriters and any of our stockholders who will execute a lock-up agreement, providing consent to the sale of shares prior to the expiration of the lock-up period.

Compliance with State Securities Laws

In order to comply with the securities laws of certain states, the securities will be offered or sold in those states only if they have been registered or qualified for sale or an exemption from such registration is available and with which the Company has complied. In addition, and without limiting the foregoing, the Company will be subject to applicable provisions, rules and regulations under the Exchange Act with regard to securities transactions during the period of time when this Registration Statement is effective.

Stabilization

Rules of the Securities and Exchange Commission may limit the ability of the underwriters to bid for or purchase shares before the distribution of the shares is completed. However, the underwriters may engage in the following activities in accordance with the rules:

 

    Stabilizing transactions—The representative may make bids or purchases for the purpose of pegging, fixing or maintaining the price of the shares, so long as stabilizing bids do not exceed a specified maximum.

 

   

Over-allotments and syndicate covering transactions—The underwriters may sell more shares of our Class A common stock in connection with this offering than the number of shares than they have committed to purchase. This overallotment creates a short position for the underwriters. This short sales position may involve either “covered” short sales or “naked” short sales. Covered short sales are short sales made in an amount not greater than the underwriters’ over-allotment option to purchase additional shares in this offering described above. The underwriters may close out any covered short position either by exercising their over-allotment option or by purchasing shares in the open market. To determine how they will close the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market, as compared to the price at which they may purchase shares through the over-allotment option. Naked short sales are short sales in excess of the over-allotment option. The underwriters must close out any naked short position by purchasing

 

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shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that, in the open market after pricing, there may be downward pressure on the price of the shares that could adversely affect investors who purchase shares in this offering.

 

    Penalty bids—If the representative purchases shares in the open market in a stabilizing transaction or syndicate covering transaction, it may reclaim a selling concession from the underwriters and selling group members who sold those shares as part of this offering.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales or to stabilize the market price of our Class A common stock may have the effect of raising or maintaining the market price of our Class A common stock or preventing or mitigating a decline in the market price of our Class A common stock. As a result, the price of the shares of our Class A common stock may be higher than the price that might otherwise exist in the open market. The imposition of a penalty bid might also have an effect on the price of the shares if it discourages resales of the shares.

Neither we nor the underwriters make any representation or prediction as to the effect that the transactions described above may have on the price of the shares. If such transactions are commenced, they may be discontinued without notice at any time.

Electronic Delivery of Prospectus:

A prospectus in electronic format may be delivered to potential investors by one or more of the underwriters participating in this offering. The prospectus in electronic format will be identical to the paper version of such prospectus. Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of this prospectus or the registration statement of which this prospectus forms a part.

Other Relationships

Effective September 29, 2016, we entered into a Facilitation Agreement with Seaport Global, pursuant to which Seaport Global has agreed to provide us with financing from time to time in connection with the repurchase of Notes. We anticipate that Seaport Global will receive a cash payment of $2,166,486 at the time of the closing of this offering as a repayment for principal and interest in connection with the repurchase of Notes under the Facilitation Agreement. To the extent we are unable to complete this offering, we anticipate issuing to Seaport Global shares of our Class A common stock in lieu of such cash payment.

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for the issuer, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the issuer. The underwriters and certain of their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

 

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LEGAL MATTERS

The validity of our Class A common stock offered by this prospectus will be passed upon for us by Latham & Watkins LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Baker & Hostetler LLP, Houston, Texas.

EXPERTS

The financial statements as of December 31, 2015 and 2014 and for each of the two years in the period ended December 31, 2015 included in this Prospectus and in the Registration Statement have been so included in reliance on the report of BDO USA, LLP, an independent registered public accounting firm, appearing elsewhere herein and in the Registration Statement, given on the authority of said firm as experts in auditing and accounting.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a Registration Statement on Form 10 (the “Form 10”) under the Securities Act, with respect to shares of our Class A common stock. Pursuant to Section 12(d) of the Exchange Act, the Form 10 went effective on July 5, 2016, and as of that date we are subject to the reporting requirements of the Exchange Act and the rules and regulations thereunder. As such, we will file periodic reports, proxy statements and information statements with the SEC. These periodic reports and other information are available for inspection and copying at the public reference room and website of the SEC referred to below. We maintain a website at www.lonestarresources.com. You may access our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as they become filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act with the SEC free of charge at our website as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. The information contained in, or that can be accessed through, our website is not part of this prospectus. We intend to furnish our stockholders with annual reports containing financial statements certified by an independent public accounting firm.

We have filed with the SEC a registration statement on Form S-1 under the Securities Act, with respect to shares of our Class A common stock. This prospectus, which is part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Room of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the Public Reference Room. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

 

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INDEX TO FINANCIAL STATEMENTS

 

     Page  

Consolidated Balance Sheets as of June 30, 2016 (unaudited) and December 31, 2015

     F-2   

Unaudited Consolidated Statements of Operations and Other Comprehensive Income (Loss) for three and six months ended June 30, 2016 and 2015

     F-4   

Unaudited Consolidated Statement of Changes in Stockholders’ Equity for the six months ended June 30, 2016

     F-5   

Unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2016 and 2015

     F-6   

Notes to Unaudited Consolidated Financial Statements

     F-7   

Report of Independent Registered Public Accounting Firm

     F-19   

Consolidated Balance Sheets as of December 31, 2015 and December  31, 2014

     F-20   

Consolidated Statements of Operations and Other Comprehensive Income (Loss) for the years ended December 31, 2015 and 2014

     F-22   

Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2015 and 2014

     F-23   

Consolidated Statements of Cash Flows for the years ended December 31, 2015 and 2014

     F-24   

Notes to Consolidated Financial Statements

     F-25   

 

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Lonestar Resources Limited

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

Lonestar Resources Limited

Consolidated Balance Sheets

(In thousands, except share and per share data)

 

     June 30,
2016
(unaudited)
     December 31,
2015
 

Assets

     

Current assets

     

Cash and cash equivalents

   $ 5,147       $ 4,322   

Accounts receivable:

     

Oil, natural gas liquid and natural gas sales

     6,402         5,043   

Joint interest owners and other

     1,044         1,305   

Related parties

     —           279   

Derivative financial instruments

     13,182         33,219   

Prepaid expenses and other

     703         724   
  

 

 

    

 

 

 

Total current assets

     26,478         44,892   

Oil and gas properties, net, using the successful efforts method of accounting

     478,363         488,100   

Other property and equipment, net

     2,106         2,223   

Derivative financial instruments

     681         2,864   

Other noncurrent assets

     1,609         1,580   

Restricted certificates of deposit

     77         77   
  

 

 

    

 

 

 

Total assets

   $ 509,314       $ 539,736   
  

 

 

    

 

 

 

See accompanying notes to unaudited consolidated financial statements.

 

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Lonestar Resources Limited

Consolidated Balance Sheets (continued)

(In thousands, except share and per share data)

 

     June 30,
2016
(unaudited)
    December 31,
2015
 

Liabilities and Stockholders’ Equity

    

Current liabilities

    

Accounts payable

   $ 9,156      $ 18,027   

Accounts payable—related parties

     160        45   

Oil, natural gas liquid and natural gas sales payable

     3,995        3,870   

Accrued liabilities

     8,311        8,276   

Accrued liabilities—related parties

     243        125   

Derivative financial instruments

     968        —     
  

 

 

   

 

 

 

Total current liabilities

     22,833        30,343   

Long-term debt

     315,197        301,926   

Deferred tax liability

     3,885        16,013   

Other non-current liabilities

     1,000        1,000   

Asset retirement obligations

     7,218        7,488   

Derivative financial instruments

     182        —     
  

 

 

   

 

 

 

Total liabilities

     350,315        356,770   
  

 

 

   

 

 

 

Commitments and contingencies

    

Stockholders’ equity

    

Common stock, $0.20 par value, 500,000,000 shares authorized, 15,044,051 shares issued and outstanding at June 30, 2016 and December 31, 2015

     142,638        142,638   

Additional paid-in capital

     10,461        10,270   

Accumulated other comprehensive loss

     (776     (760

Retained earnings

     6,676        30,818   
  

 

 

   

 

 

 

Total stockholders’ equity

     158,999        182,966   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 509,314      $ 539,736   
  

 

 

   

 

 

 

See accompanying notes to unaudited consolidated financial statements.

 

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Lonestar Resources Limited

Consolidated Statements of Operations & Comprehensive Loss

(In thousands, except share and per share data)

(Unaudited)

 

     Three months ended
June 30,
    Six months ended
June 30,
 
     2016     2015     2016     2015  

Revenues

        

Oil sales

   $ 15,168      $ 21,338      $ 24,119      $ 37,559   

Natural gas sales

     1,636        1,151        3,257        2,479   

Natural gas liquid sales

     999        609        1,623        1,122   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     17,803        23,098        28,999        41,160   
  

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses

        

Lease operating and gas gathering

     4,398        4,589        8,758        8,050   

Production, ad valorem, and severance taxes

     1,223        1,476        2,139        2,827   

Rig standby expense

     1,584        —          1,897        —     

Depletion, depreciation, and amortization

     12,498        13,253        27,636        26,039   

Accretion of asset retirement obligations

     51        54        107        106   

(Gain) loss on sale of oil and gas properties

     (1,531     —          (1,531     625   

Impairment of oil and gas properties

     1,938        —          1,938        —     

Stock-based compensation

     95        433        191        866   

General and administrative

     2,858        2,408        5,631        4,696   

Other (income) expense

     819        (4     1,047        35   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     23,933        22,209        47,813        43,244   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

     (6,130     889        (18,814     (2,084
  

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense)

        

Interest expense

     (6,174     (5,972     (12,299     (11,819

Losses on derivative financial instruments

     (6,785     (7,500     (5,069     (525
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense, net

     (12,959     (13,472     (17,368     (12,344
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss before income taxes

     (19,089     (12,583     (36,182     (14,428

Income tax benefit

     6,245        4,230        12,040        5,350   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

   $ (12,844   $ (8,353   $ (24,142   $ (9,078
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss per common share-basic and diluted

   $ (0.85   $ (0.56   $ (1.60   $ (0.60

Weighted average common shares outstanding–basic and diluted

     15,044,051        15,044,051        15,044,051        15,044,051   
  

 

 

   

 

 

   

 

 

   

 

 

 

Other comprehensive loss:

        

Net loss

   $ (12,844   $ (8,353   $ (24,142   $ (9,078

Foreign currency translation adjustments

     (17     (13     (16     1   
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive loss

   $ (12,861   $ (8,366   $ (24,158   $ (9,077
  

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to unaudited consolidated financial statements.

 

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Lonestar Resources Limited

Consolidated Statements of Changes in Stockholders’ Equity

 

    

 

Common Stock

     Additional
Paid-in
Capital
     Retained
Earnings
    Accumulated
other
comprehensive

loss
    Total Stockholder’s
Equity
 
     Shares      Amount            

Balance at December 31, 2015

     15,044,051       $ 142,638       $ 10,270       $ 30,818      $ (760     182,966   

Stock-based compensation

     —           —           191         —          —          191   

Foreign currency translation

     —           —           —           —          (16     (16

Net loss

     —           —           —           (24,142     —          (24,142
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Balance at June 30, 2016

     15,044,051       $ 142,638       $ 10,461       $ 6,676      $ (776   $ 158,999   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

 

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Lonestar Resources Limited

Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

 

Six months ended June 30,

   2016     2015  

Operating activities

    

Net loss

   $ (24,142   $ (9,078

Adjustments to reconcile net loss to net cash provided by operating activities:

    

(Gain) loss on disposal of oil and gas properties

     (919     625   

Accretion of asset retirement obligations

     107        106   

Depreciation, depletion, and amortization

     27,636        26,039   

Stock-based compensation

     191        866   

Deferred taxes

     (12,129     (5,357

Loss on derivative financial instruments

     5,069        525   

Settlements of derivative financial instruments

     18,300        18,376   

Impairment of oil and gas properties

     1,938        —     

Non-cash interest expense

     550        550   

Changes in operating assets and liabilities:

    

Accounts receivable

     (818     1,415   

Prepaid expenses and other assets

     229        (213

Accounts payable and accrued expenses

     (8,479     (8,226
  

 

 

   

 

 

 

Net cash provided by operating activities

     7,533        25,628   
  

 

 

   

 

 

 

Investing activities

    

Acquisition of oil and gas properties

     (2,717     (3,470

Development of oil and gas properties

     (19,003     (54,585

Proceeds from sales of oil and gas properties

     2,720        —     

Purchases of other property and equipment

     (177     (135
  

 

 

   

 

 

 

Net cash used in investing activities

     (19,177     (58,190
  

 

 

   

 

 

 

Financing activities

    

Proceeds from bank borrowings

     23,500        32,000   

Payments on bank borrowings

     (11,000     (5,000

Payments on other note payable

     (15     (15
  

 

 

   

 

 

 

Net cash provided by financing activities

     12,485        26,985   
  

 

 

   

 

 

 

Effect of exchange rate changes on cash and cash equivalents

     (16     1   
  

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     825        (5,576

Cash and cash equivalents, beginning of the period

     4,322        9,992   
  

 

 

   

 

 

 

Cash and cash equivalents, end of the period

   $ 5,147      $ 4,416   
  

 

 

   

 

 

 

Supplemental information

    

Cash paid for interest expense

   $ 11,082      $ 10,672   
  

 

 

   

 

 

 

See accompanying notes to unaudited consolidated financial statements.

 

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

(Unaudited)

1. Nature of Business and Presentation

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

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

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

Unless the context otherwise requires, references to “Lonestar,” “we,” “us,” “our,” and “the Company” refer to (i) Lonestar Resources Limited and its subsidiaries prior to the Reorganization and (ii) Lonestar Resources US Inc. and its subsidiaries upon completion of the Reorganization, as applicable.

Basis of Presentation

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

Principles of Consolidation

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

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

Lonestar Resources, Inc. (“LRI”),

Barnett Gas, LLC (“Barnett Gas”),

Eagleford Gas, LLC (“Eagleford Gas”),

 

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Poplar Energy, LLC (“Poplar”),

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

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

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

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

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

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

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

Lonestar Operating, LLC (“LNO”),

Amadeus Petroleum, Inc. (“API”),

T-N-T Engineering, Inc. (“TNT”) and

Albany Services, LLC (“Albany”).

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

2. Recently Issued Accounting Pronouncements

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

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

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

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

 

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

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

3. Acquisitions and Divestitures

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

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

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

4. Restricted Certificates of Deposit

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

5. Commodity Price Risk Activities

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

Inherent in the Company’s fixed price contracts, are certain business risks, including market risk and credit risk. Market risk is the risk that the price of oil and natural gas will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the Company’s

 

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counterparty to a contract. The Company does not currently require collateral from any of its counterparties nor does its counterparties require collateral from the Company. At June 30, 2016, the Company had no open physical delivery obligations.

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

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

 

Instrument

   Total Volume    Settlement Period    Fixed
Price
 

Oil – WTI Fixed Price Swap

   99,000 BBL    July – December 2016    $ 84.45   

Oil – WTI Fixed Price Swap

   144,600 BBL    July – December 2016      90.45   

Oil – WTI Fixed Price Swap

   59,800 BBL    July – December 2016      63.20   

Oil – WTI Fixed Price Swap

   78,300 BBL    July – December 2016      56.90   

Oil – WTI Fixed Price Swap

   113,550 BBL    July – December 2016      42.11   

Oil – WTI Fixed Price Swap

   109,500 BBL    January – December 2017      51.05   

Oil – WTI Fixed Price Swap

   73,000 BBL    January – December 2017      50.60   

 

Instrument

   Total Volume   

Settlement Period

  

Puts

   Calls  

Oil – 3 Way Collar

   365,100 BBL    January – December 2017    $40.00 / 60.00    $ 85.00   
  

 

  

 

  

 

  

 

 

 

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

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

6. Fair Value Measurements

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

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

 

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

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

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

 

     Fair Value Measurements Using  
     Quoted
Prices in Active
Markets for
Identical
Assets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
     Total  
June 30, 2016 (unaudited)    (In thousands)  

Assets:

           

Commodity derivatives

   $ —         $ 13,863       $ —         $ 13,863   

Liabilities:

           

Commodity derivatives

     —           (1,150      —         $ (1,150
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —         $ 12,713       $ —         $ 12,713   
  

 

 

    

 

 

    

 

 

    

 

 

 
December 31, 2015    (In thousands)  

Assets:

           

Commodity derivatives

   $ —         $ 36,083       $ —         $ 36,083   

Liabilities:

           

Commodity derivatives

     —           —           —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —         $ 36,083       $ —         $ 36,083   
  

 

 

    

 

 

    

 

 

    

 

 

 

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

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

7. Oil and Gas Properties

A summary of oil and gas properties follows:

 

     June 30,
2016

(unaudited)
     December 31,
2015
 
     (In thousands)  

Proved properties and equipment

   $ 592,259       $ 584,692   

Unproved properties

     73,176         70,298   

Less accumulated depreciation, depletion, and amortization

     (187,072      (166,890
  

 

 

    

 

 

 
   $ 478,363       $ 488,100   
  

 

 

    

 

 

 

 

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

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

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

8. Accrued Liabilities

The accrued liabilities consist of the following:

 

     June 30,
2016

(unaudited)
     December 31,
2015
 
     (In thousands)  

Bonus payable

   $ 1,023       $ 1,433   

Payroll payable

     29         28   

Accrued interest

     4,536         4,420   

Accrued rent

     356         410   

Accrued expenses

     2,044         1,401   

Other

     323         584   
  

 

 

    

 

 

 
   $ 8,311       $ 8,276   
  

 

 

    

 

 

 

9. Long-Term Debt

The Company’s debt consists of the following:

 

     June 30,
2016

(unaudited)
     December 31,
2015
 
     (In thousands)  

Revolving credit facility

   $ 99,500       $ 87,000   

8.750% senior notes

     220,000         220,000   

Less unamortized discount on 8.750% senior notes

     (3,025      (3,575

Less deferred financing costs on 8.750% senior notes

     (1,548      (1,785

Other

     270         286   
  

 

 

    

 

 

 
   $ 315,197       $ 301,926   
  

 

 

    

 

 

 

Senior Revolving Credit Facility

On July 28, 2015, LRAI closed a new $500,000,000 Senior Secured Credit Facility which replaced a $400,000,000 Wells Fargo-led syndicated facility. The new facility was arranged by Citibank, N.A. and features an expanded borrowing base of $180,000,000 as of December 31, 2015. The new facility provides additional liquidity for the Company and a lower interest rate. The new rate is a 25 basis point improvement over the LIBOR interest rate spread. The new facility provides for an extension in the maturity date to October 16, 2018, which represents a seven month extension over the Wells Fargo-led facility. The financial covenants contained in this new facility are substantially the same as the previous facility. As of June 30, 2016 (giving effect to the

 

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amended covenant ratio discussed below) and December 31, 2015, LRAI was in compliance with all covenants including all financial ratios under the Citibank-led facility. As of June 30, 2016 and December 31, 2015, $99,500,000 and $87,000,000 was borrowed, respectively, under the Citibank-led revolving credit facility.

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

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

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

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

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

8.750% Senior Notes

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

 

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

 

Year

   Percentage  

2016

     106.563

2017

     104.375

2018 and thereafter

     100.000

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

Debt Issuance Costs

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

10. Stock Options

Determining Fair Value of Stock Options

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

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

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

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

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

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

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

 

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Stock Option Activity

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

 

     Shares      Weighted
Average
Exercise Price
Per Share
     Weighted
Average

Remaining
Contractual
Term

(in years)
 

Outstanding at December 31, 2015

     1,699,872         15.50         1.0   

Options vested and exercisable at December 31, 2015

     1,615,372       $ 15.50         1.0   

Granted

     —           —           —     

Exercised

     —           —           —     

Canceled/Expired

     —           —           —     

Forfeited

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Outstanding at June 30, 2016

     1,699,872         15.50         1.0   

Options vested and exercisable at June 30, 2016

     1,615,372       $ 15.50         1.0   

 

     Shares      Weighted
Average
Fair
Value per
Share
     Weighted
Average
Exercise
Price per
share
     Weighted
Average
Remaining
Contractual
Term
(in years)
 

Outstanding non-vested options at December 31, 2015

     84,500       $ 4.50       $ 15.50         1.0   

Granted

     —           —           —           —     

Vested

     —           —           —           —     

Forfeited

     —           —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Outstanding non-vested options at June 30, 2016

     84,500       $ 4.50       $ 15.50         1.0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Stock-Based Compensation Expense

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

11. Earnings Per Share

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

In connection with the Reorganization, discussed in Note 1, Lonestar Resources US Inc., immediately prior to the Reorganization, will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting

 

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policies have been adopted in these financial statements as if the Company were a public company. The following table presents unaudited pro forma earnings per share of Lonestar Resources US Inc., assuming that the 1 for 2 reverse stock split upon Reorganization had occurred at the beginning of the three and six month periods ended June 30, 2016 and 2015:

Unaudited Pro Forma Earnings Per Share (After Reorganization)

 

     Three months ended
June 30,
    Six months ended
June 30,
 
     2016     2015     2016     2015  

Net income (loss) per common share:

        

Basic

   $ (1.71   $ (1.11   $ (3.21   $ (1.21

Diluted

     (1.71     (1.11     (3.21     (1.21

Weighted average common shares outstanding:

        

Basic

     7,522,025        7,522,025        7,522,025        7,522,025   

Diluted

     7,522,025        7,522,025        7,522,025        7,522,025   

12. Related Party Activities

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

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

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

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

13. Subsequent Events

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

Securities Purchase Agreement

On August 2, 2016, LRAI and Successor entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Juneau Energy, LLC, as initial purchaser (the “Initial Purchaser”), Leucadia National Corporation (“Leucadia”), as guarantor of the Initial Purchaser’s obligations, the other purchasers party thereto (collectively, along with the Initial Purchaser, the “Purchasers”) and Jefferies, LLC, in its capacity as the

 

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collateral agent for the Purchasers, relating to the issuance and sale of (i) up to $49,900,000 aggregate principal amount of LRAI’s 12% senior secured second lien notes due 2021 (the “Second Lien Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Successor’s common stock at a price equal to $5.00 per share (the “Warrants” and, together with the Notes, the “Securities”). The initial sale of $10,000,000 aggregate principal amount of Securities closed on August 4, 2016 (the “Closing Date”).

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

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

Registration Rights Agreement

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

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

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

In the event Leucadia purchases not less than the Commitment Amount in an Offering, the Successor has agreed to use commercially reasonable efforts to enter into arrangements that provide Leucadia will have the right to

 

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appoint one director to the board of directors of the Successor, provided that such right will terminate at such time as Leucadia and its affiliates own a number of shares of Common Stock equal to less than 50% of the shares purchased by Leucadia and its affiliates in the Offering.

Purchase and Sale Agreement

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

 

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Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Lonestar Resources Limited

Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Lonestar Resources Limited and Subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations and other comprehensive income (loss), changes in stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Lonestar Resources Limited and Subsidiaries at December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Dallas, Texas

April 21, 2016

 

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Lonestar Resources Limited

Consolidated Balance Sheets

 

December 31,

   2015      2014  

Assets

     

Current assets

     

Cash and cash equivalents

   $ 4,321,456       $ 9,992,477   

Accounts receivable:

     

Oil, natural gas liquid and natural gas sales

     5,043,398         8,987,525   

Joint interest owners and other

     1,305,146         7,933,752   

Related parties

     279,043         562,634   

Derivative financial instruments

     33,218,474         31,045,260   

Prepaid expenses and other

     723,988         654,880   
  

 

 

    

 

 

 

Total current assets

     44,891,505         59,176,528   

Oil and gas properties, net, using the successful efforts method of accounting

     488,099,597         481,079,275   

Other property and equipment (net of accumulated depreciation of $1,067,956 and $680,002, respectively)

     2,223,399         2,366,013   

Derivative financial instruments

     2,864,372         12,713,295   

Other noncurrent assets

     3,364,621         3,608,331   

Restricted certificates of deposit

     77,397         125,980   
  

 

 

    

 

 

 

Total assets

   $ 541,520,891       $ 559,069,422   
  

 

 

    

 

 

 

 

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Lonestar Resources Limited

Consolidated Balance Sheets (continued)

 

December 31,

   2015     2014  

Liabilities and Stockholders’ Equity

    

Current liabilities

    

Accounts payable

   $ 18,027,156      $ 30,650,081   

Accounts payable—related parties

     44,848        192,187   

Oil, natural gas liquid and natural gas sales payable

     3,870,464        4,961,510   

Accrued liabilities

     8,276,085        11,605,120   

Accrued liabilities—related parties

     125,000        —     
  

 

 

   

 

 

 

Total current liabilities

     30,343,553        47,408,898   

Long-term debt

     303,710,512        264,613,529   

Deferred tax liability

     16,013,276        31,510,744   

Other non-current liabilities

     1,000,000        1,000,000   

Asset retirement obligations

     7,487,501        6,834,615   
  

 

 

   

 

 

 

Total liabilities

     358,554,842        351,367,786   
  

 

 

   

 

 

 

Commitments and contingencies (Note 13)

    

Stockholders’ equity

    

Common stock, $.20 par value, 500,000,000 shares authorized, 15,044,051 and 14,661,004 shares issued and outstanding at December 31, 2015 and 2014, respectively

     142,637,636        142,637,636   

Additional paid-in capital

     10,270,288        7,685,177   

Accumulated other comprehensive loss

     (760,366     (772,633

Retained earnings

     30,818,491        58,151,456   
  

 

 

   

 

 

 

Total stockholders’ equity

     182,966,049        207,701,636   
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 541,520,891      $ 559,069,422   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Lonestar Resources Limited

Consolidated Statements of Operations and Other Comprehensive Income (Loss)

 

Years ended December 31,

   2015     2014  

Revenues

    

Oil sales

   $ 70,739,269      $ 104,233,379   

Natural gas sales

     6,823,019        7,589,599   

Natural gas liquid sales

     1,928,068        3,803,582   
  

 

 

   

 

 

 

Total revenues

     79,490,356        115,626,560   
  

 

 

   

 

 

 

Operating expenses

    

Lease operating and gas gathering

     17,853,428        16,631,611   

Production, ad valorem, and severance taxes

     4,981,826        7,123,332   

Depletion, depreciation, and amortization

     58,827,705        40,521,546   

Accretion of asset retirement obligations

     214,335        201,076   

Impairment of oil and gas properties

     28,622,961        5,478,264   

Stock-based compensation

     2,585,111        1,938,400   

General and administrative

     10,824,845        8,913,052   
  

 

 

   

 

 

 

Total operating expenses

     123,910,211        80,807,281   
  

 

 

   

 

 

 

Income (loss) from operations

     (44,419,855     34,819,279   
  

 

 

   

 

 

 

Other income (expense)

    

Interest expense

     (24,576,993     (19,949,359

Gains on derivative financial instruments

     27,608,534        43,972,245   

Other income (expense)

     (1,065,539     55,187   
  

 

 

   

 

 

 

Total other income, net

     1,966,002        24,078,073   
  

 

 

   

 

 

 

Income (loss) before taxes

     (42,453,853     58,897,352   

Income tax (expense) benefit

     15,120,888        (22,431,722
  

 

 

   

 

 

 

Net income (loss)

   $ (27,332,965   $ 36,465,630   
  

 

 

   

 

 

 

Net income (loss) per common share-basic

   $ (1.82   $ 2.49   

Net income (loss) per common share-diluted

   $ (1.82   $ 2.42   

Weighted average common shares outstanding–basic

     15,044,051        14,661,004   

Weighted average common shares outstanding–diluted

     15,044,051        15,069,610   
  

 

 

   

 

 

 

Other comprehensive income (loss):

    

Net income (loss)

   $ (27,332,965   $ 36,465,630   

Foreign currency translation adjustments

     12,267        (404,038
  

 

 

   

 

 

 

Comprehensive income (loss)

   $ (27,320,698   $ 36,061,592   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Lonestar Resources Limited

Consolidated Statements of Changes in Stockholders’ Equity

 

   

 

Common Stock

    Additional
Paid-
in Capital
    Accumulated
Other
Comprehensive

Income (Loss)
    Retained
Earnings
    Total
Stockholders,

Equity
 
    Shares     Amount          

Balance at December 31, 2013

    13,943,744      $ 142,637,636      $ 5,746,777        (368,595   $ 21,685,826        169,701,644   

Share issuance

    1,100,000        —          —          —          —          —     

Stock-based compensation

    —          —          1,938,400        —          —          1,938,400   

Foreign currency translation

    —          —            (404,038     —          (404,038

Net income

    —          —          —          —          36,465,630        36,465,630   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2014

    15,043,744      $ 142,637,636      $ 7,685,177        (772,633   $ 58,151,456      $ 207,701,636   

Share issuance

    307        —          —          —          —          —     

Stock-based compensation

    —          —          2,585,111        —          —          2,585,111   

Foreign currency translation

    —          —            12,267        —          12,267   

Net loss

    —          —          —          —          (27,332,965     (27,332,965
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2015

    15,044,051      $ 142,637,636      $ 10,270,288        (760,366   $ 30,818,491      $ 182,966,049   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Lonestar Resources Limited

Consolidated Statements of Cash Flows

 

Years ended December 31,

   2015     2014  

Operating activities

    

Net income (loss)

   $ (27,332,965   $ 36,465,630   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

(Gain) loss on sale of oil and gas properties

     629,253        (466,490

Accretion of asset retirement obligations

     214,335        201,076   

Depreciation, depletion, and amortization

     58,827,705        40,521,546   

Stock-based compensation

     2,585,111        1,938,400   

Deferred taxes

     (15,497,468     22,662,988   

Gain on derivative financial instruments

     (27,608,534     (43,972,245

Settlements of derivative financial instruments

     35,284,243        (1,503,609

Impairment of oil and gas properties

     28,622,961        5,478,264   

Non-cash interest expense

     1,100,000        825,000   

Changes in operating assets and liabilities:

    

Accounts receivable

     10,856,325        (9,408,033

Prepaid expenses and other assets

     223,186        (1,856,749

Accounts payable and accrued expenses

     (17,065,347     31,341,672   
  

 

 

   

 

 

 

Net cash provided by operating activities

     50,838,805        82,227,450   
  

 

 

   

 

 

 

Investing activities

    

Acquisition of oil and gas properties

     (8,723,497     (70,978,282

Development of oil and gas properties

     (85,458,433     (164,180,576

Purchases of other property and equipment

     (337,147     (1,086,073

Proceeds from sales of oil and gas properties

     —          3,200,000   
  

 

 

   

 

 

 

Net cash used in investing activities

     (94,519,077     (233,044,931
  

 

 

   

 

 

 

Financing activities

    

Proceeds from bank borrowings

     140,513,602        135,000,000   

Payments on bank borrowings

     (102,513,602     (195,000,000

Proceeds from bond offering

     —          214,500,000   

Payment on other note payable

     (3,016     (30,000
  

 

 

   

 

 

 

Net cash provided by financing activities

     37,996,984        154,470,000   
  

 

 

   

 

 

 

Effect of exchange rate changes on cash and cash equivalents

     12,267        (404,038

Increase (decrease) in cash and cash equivalents

     (5,671,021     3,248,481   

Cash and cash equivalents, beginning of the year

     9,992,477        6,743,996   
  

 

 

   

 

 

 

Cash and cash equivalents, end of the year

   $ 4,321,456      $ 9,992,477   
  

 

 

   

 

 

 

Supplemental information

    

Cash paid for federal income taxes

   $ 257,000      $ 90,000   

Cash paid for interest expense

   $ 21,492,189      $ 13,400,795   
  

 

 

   

 

 

 

See accompanying notes to consolidated financial statements.

 

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Lonestar Resources Limited

Notes to Consolidated Financial Statements

1. Nature of Business and Presentation

Lonestar Resources Limited (the “Parent”) is a company limited by shares incorporated in Australia, whose shares are publicly traded on the Australian Stock Exchange and the OTCQX. The financial report consists of the consolidated financial statements of Lonestar Resources Limited and its subsidiaries.

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

Lonestar Resources America, Inc. was formed as a U.S. holding company for Lonestar Resources, Inc. and Amadeus Petroleum, Inc., which are subsidiaries previously wholly-owned by the Parent. This formation was effected through an exchange of shares of the Company for those issued by the merged subsidiaries and has been treated as a reorganization of entities under common control.

2. Summary of Significant Accounting Policies

A summary of the Company’s significant accounting policies, consistently applied in the preparation of the accompanying consolidated financial statements, follows.

Basis of Accounting

The accounts are maintained and the consolidated financial statements have been prepared using the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect certain reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from these estimates and assumptions.

Reserve estimates are inexact and may change as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production and timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Accordingly, there can be no assurance that ultimately, the reserves will be produced, nor can there be assurance that the proved undeveloped reserves will be developed within the period anticipated.

Principles of Consolidation

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

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

 

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Lonestar Resources, Inc. (“LRI”),

Barnett Gas, LLC (“Barnett Gas”),

Eagleford Gas, LLC (“Eagleford Gas”),

Poplar Energy, LLC (“Poplar”),

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

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

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

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

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

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

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

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.

Reclassifications

Certain prior year amounts which were determined to be immaterial have been reclassified to conform to current year presentation, with no effect on the previously reported results of operations.

Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less when purchased to be cash equivalents.

Currency Translation

The consolidated financial statements are presented in U.S. dollars. The functional currency of Parent is the Australian Dollar. At the end of each reporting period, the assets and liabilities of Parent are translated from its functional currency to U.S. dollars using the exchange rate at the end of the month. The monthly results of operations of Parent are generally translated from its functional currency to U.S. dollars using the average exchange rate during the month. Changes in exchange rates result in currency translation gains and losses, which are recorded within other comprehensive income (loss).

Parent may also enter into transactions in currencies other than their functional currency. At the end of each reporting period, Parent re-measures the related receivables, payables, and cash to its functional currency using the exchange rate at the end of the period. Changes in exchange rates between the time the transactions were entered into and the end of the reporting period result in currency transaction gains or losses, which are recorded in the consolidated statements of operations.

Concentrations and Credit Risk

The Company’s financial instruments exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. The Company places its cash and cash equivalents with reputable financial institutions. At times, the balances deposited may exceed amounts covered by insurance provided by the U.S. Federal Deposit Insurance Corporation (“FDIC”). The Company has not incurred any losses related to amounts in excess of FDIC limits.

Substantially all of the Company’s accounts receivable are due from either purchasers of oil, NGL and natural gas or working interest partners in oil and natural gas wells for which a subsidiary of the Company serves as the

 

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operator. Generally, operators of oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells. The Company’s receivables are generally unsecured. The Company has experienced no credit losses since its inception and does not carry an allowance for uncollectible amounts at December 31, 2015.

Oil, NGL and natural gas revenues from Trafigura AG, BP Products North America LLC, Shell Trading (US) Company and Texla Energy Management, Inc. for the year ended December 31, 2015, represented 38%, 20%, 16% and 11%, respectively, of total revenues. Oil, NGL and natural gas revenues from Shell Trading (US) Company, Trafigura AG and BP Products North America LLC for the year ended December 31, 2014, represented 36%, 23% and 16%, respectively, of total revenues. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and Texla Energy Management, Inc. represented 26%, 25% and 23%, respectively, of total receivables at December 31, 2015. Accounts receivable relating to oil, NGL and natural gas sales from Shell Trading, Trafigura AG and BP Products North America LLC represented 19%, 27% and 32%, respectively, of total receivables at December 31, 2014.

Prepaid Expenses

Prepaid expenses generally relate to prepaid drilling and completion costs that will be capitalized into oil and gas properties.

Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting to account for its oil and gas properties. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The Company’s policy is to expense the costs of such exploratory wells if a determination of proved reserves has not been made within a 12-month period after drilling is complete. All costs related to development wells, including related production equipment and lease acquisition costs, are capitalized when incurred, whether productive or nonproductive.

Capitalized costs attributed to the proved properties are subject to depreciation and depletion. Depreciation and depletion of the cost of oil and gas properties is calculated using the units-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.

Unproved properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as an impairment of oil and gas properties in the consolidated statement of operations, as applicable. Unproved oil and gas property costs are transferred to proven oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, future plans to develop acreage, and other relevant factors.

On the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and any gain or loss is recognized.

 

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Other Property and Equipment

Other property and equipment, consisting primarily of office, transportation and computer equipment, is carried at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, ranging from 3 to 5 years. Major renewals and improvements are capitalized, while expenditures for maintenance and repairs are expensed as incurred. Upon sale or abandonment, the cost of the equipment and related accumulated depreciation are removed from the accounts, and any gain or loss is recognized.

Impairment of Long-Lived Assets

The carrying value of the oil and gas properties and other related property and equipment is periodically evaluated under the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 360, Property, Plant, and Equipment. ASC 360 requires long-lived assets and certain identifiable intangibles to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows and an asset’s fair value. These judgments and assumptions include such matters as the estimation of oil and gas reserve quantities, risks associated with the different categories of oil and gas reserves, the timing of development and production, expected future commodity prices, capital expenditures, production costs, and appropriate discount rates.

Under ASC 360, the Company evaluates impairment of proved and unproved oil and gas properties on an area basis. On this basis, certain fields may be impaired because they are not expected to recover their entire carrying value from future net cash flows. As a result of this evaluation, the Company recorded impairment of unproved oil and gas properties of $8,927,000 as of December 31, 2015 and impairment of proven oil and gas properties of $19,696,000 and $5,478,000 for the years ended December 31, 2015 and 2014, respectively.

Asset Retirement Obligations

The Company accounts for asset retirement obligations under ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Oil and gas producing companies incur such a liability upon acquiring or drilling a well. Under ASC 410, an asset retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties in the accompanying consolidated balance sheet, which is allocated to expense over the useful life of the asset. Periodic accretion of the discount on asset retirement obligations is recorded as an expense in the accompanying consolidated statement of operations. See Note 9.

Revenue Recognition

Oil, NGL and natural gas revenues are recognized when title to the product transfers to the purchaser. The Company follows the sales method of accounting for its crude oil, NGL and natural gas revenue, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. There were no imbalances at December 31, 2015 or 2014.

Fair Value of Financial Instruments

In accordance with the reporting requirements of ASC 825, Financial Instruments, the Company calculates the fair value of its assets and liabilities that qualify as financial instruments under this guidance and includes this additional information in the notes to consolidated financial statements when the fair value is different from the carrying value of those financial instruments. See Note 6.

 

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Income Taxes

The Company follows the asset and liability method in accounting for income taxes in accordance with ASC 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and tax credit carryforwards.

Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which these temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

The Company periodically evaluates deferred tax assets and recognizes a valuation allowance based on the estimate of the amount of such deferred tax assets which the Company believes does not meet the more-likely-than-not recognition criteria. At December 31, 2015 and 2014, it has been concluded that no deferred tax asset valuation allowance is necessary.

The Company evaluates uncertain tax positions, which requires significant judgments and estimates regarding the recoverability of deferred tax assets, the likelihood of the outcome of examinations of tax positions that may or may not be currently under review, and potential scenarios involving settlements of such matters. Changes in these estimates could materially impact the consolidated financial statements. No liability for material uncertain tax positions existed as of December 31, 2015 or 2014.

Share-Based Payments

The Company accounts for equity-based awards in accordance with ASC 718, Compensation-Stock Compensation, which requires companies to recognize in the statement of operations all share-based payments granted to employees based on their fair value. Share-based compensation is recognized by the Company on a straight-line basis over the requisite service period, which approximates the option vesting period of three years.

3. Acquisitions and Divestitures

In March 2014 the Company acquired additional working interests in four wells and approximately 1,240 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle County. The Company paid approximately $2,385,000 to acquire the acreage. $750,000 was allocated to proved properties, while $1,635,000 was allocated to unproved properties.

In March 2014 the Company acquired an additional 15,232 gross / 13,156 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle, Frio, Wilson, Brazos and Robertson counties. The Company paid approximately $70,737,000 to acquire the acreage. $58,490,000 of the purchase price was allocated to proved properties, while $12,247,000 was allocated to unproved properties. Virtually all of the properties will be operated by Lonestar.

In June 2014, the Company sold its working interest in its non-operated Raccoon Bend property for approximately $3,200,000. The effective date of the sale was June 1, 2014. The gain on the sale approximated $461,000.

In September 2014 the Company acquired an additional 720 net acres in the Eagle Ford Shale trend. The acquired assets are located in La Salle County. The Company paid approximately $2,500,000 to acquire the acreage. All of the purchase price was allocated to unproved properties.

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 for $500,000 as a further component of the exchange.

 

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4. Restricted Certificates of Deposit

The Company is required to maintain certain certificates of deposit (“CDs”) by a municipality in which drilling operations are located. This CD is pledged as collateral for a letter of credit issued by the Company’s bank to the municipality. The CD has a maturity date of March 8, 2016, 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 December 31, 2015, 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 derivative (realized and unrealized) are included in the consolidated statement of operations.

As of December 31, 2015, the following derivative transactions were outstanding:

 

Instrument

       Total Volume       

Settlement Period

   Fixed
    Price    
 

Oil – WTI Fixed Price Swap

   205,000 BBL   

January –December 2016

   $ 84.45   

Oil – WTI Fixed Price Swap

   309,000 BBL   

January – December 2016

     90.45   

Oil – WTI Fixed Price Swap

   135,600 BBL   

January – December 2016

     63.20   

Oil – WTI Fixed Price Swap

   183,400 BBL   

January – December 2016

     56.90   

 

Instrument

   Total Volume   

Settlement Period

  

Puts

   Calls  

Oil – 3 Way Collar

   365,100 BBL    January – December 2017    $40.00 / 60.00    $ 85.00   
  

 

  

 

  

 

  

 

 

 

The above derivative contracts aggregate to 833,000 barrels or 2,276 barrels of oil per day for 2016 and 365,100 barrels or 1,000 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 December 31, 2015 and 2014, all of the Company’s economic derivative hedge positions were with large financial institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features.

6. Fair Value Measurements

In accordance with ASC 820, Fair Value Measurements and Disclosures, fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories:

 

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observable inputs and unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. ASC 820 prioritizes the inputs used in measuring fair value into the following fair value hierarchy:

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

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

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

The following tables present the Company’s assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014, for each fair value hierarchy level:

 

     Fair Value Measurements Using  
     Quoted
Prices in
Active
Markets for
Identical
Assets
(Level 1)
     Significant
Other
Observable
Inputs
(Level 2)
     Significant
Unobservable
Inputs
(Level 3)
     Total  
December 31, 2015    (In thousands)  

Assets:

           

Commodity derivatives

   $ —         $ 36,083       $ —         $ 36,083   

Liabilities:

           

Commodity derivatives

     —           —           —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —         $ 36,083       $ —         $ 36,083   
  

 

 

    

 

 

    

 

 

    

 

 

 
December 31, 2014    (In thousands)  

Assets:

           

Commodity derivatives

   $ —         $ 43,759       $ —         $ 43,759   

Liabilities:

           

Commodity derivatives

     —           —           —         $ —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ —         $ 43,759       $ —         $ 43,759   
  

 

 

    

 

 

    

 

 

    

 

 

 

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.

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2015 and 2014 periods.

7. Oil and Gas Properties

A summary of oil and gas properties as of December 31, follows:

 

     2015      2014  

Proved properties and equipment

   $ 584,691,945       $ 495,954,566   

Unproved properties

     70,298,349         65,725,668   

Less accumulated depreciation, depletion, and amortization

     (166,890,697      (80,600,959
  

 

 

    

 

 

 
   $ 488,099,597       $ 481,079,275   
  

 

 

    

 

 

 

 

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The Company recorded impairment of oil and gas properties of $28,623,000 and $5,478,000 for the years ended December 31, 2015 and 2014, respectively, which is included in accumulated depreciation, depletion, and amortization.

During 2015, the sustained deterioration in the long-term outlook for commodity prices was a triggering event that requiring us to perform impairment testing of our assets that are sensitive to commodity prices. The impairment testing of our long-lived assets was based upon a two-step process as prescribed in the accounting standards.

Step one was performed on each of our oil and gas producing regions and involved a determination as to whether the property’s net book value is expected to be recovered from the estimated undiscounted future cash flows for each respective region. To compute estimated future cash flows, we used our independent reserve engineers’ estimates of proved and probable reserves.

For those regions that failed the impairment test’s first step, we then made a fair market value assessment using discounted cash flow analysis. Based on these results, we recognized $19,696,000 of impairment on those regions where the carrying value exceeded its estimated fair market value.

In addition, during 2015, we recorded a $8,927,000 impairment of undeveloped, unproven properties in Gonzales County. Our independent reserve engineers’ estimates for this region did not include any probable or possible reserves, therefore, it was necessary to impair the remaining net book value of undeveloped, unproven properties for this region.

8. Recently Issued Accounting Pronouncements

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

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

In May 2014, the FASB issued ASU No. 2014-09 that introduces a new five-step revenue recognition model in which an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU also requires disclosures sufficient to enable users to understand the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, including qualitative and quantitative disclosures about contracts with customers, significant judgments and changes in judgments, and assets recognized from the costs to obtain or fulfill a contract. This standard is effective for fiscal years beginning

 

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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. We are currently evaluating the new guidance to determine the impact it will have on our consolidated financial statements and the method of adoption.

9. Asset Retirement Obligations

Pursuant to ASC 410, Asset Retirement Obligations, the Company recognizes the fair value of its asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets, which approximated $6,927,000 as of December 31, 2015.

The liability has been accreted to its present value as of December 31, 2015. The Company evaluated its wells and has determined a range of abandonment dates through December 2069.

The following represents a reconciliation of the asset retirement obligations:

 

     Amount  

Asset retirement obligations at December 31, 2013

   $ 5,937,118   

Wells drilled during the year

     543,555   

Wells acquired during the year

     965,917   

Wells sold during the year

     (482,081

Accretion of discount

     201,076   

Wells plugged and abandoned during the year

     (330,970
  

 

 

 

Asset retirement obligations at December 31, 2014

     6,834,615   

Wells drilled during the year

     330,969   

Wells acquired during the year

     176,156   

Wells sold during the year

     (5,421

Accretion of discount

     214,335   

Wells plugged and abandoned during the year

     (63,153
  

 

 

 

Asset retirement obligations at December 31, 2015

   $ 7,487,501   
  

 

 

 

10. Accrued Liabilities

The accrued liabilities consist of the following at December 31:

 

     2015      2014  

Bonus payable

   $ 1,432,768       $ 1,848,612   

Severance and vacation payable

     28,388         283,540   

Accrued interest

     4,420,317         4,149,105   

Accrued rent

     409,643         489,191   

Accrued expenses

     1,401,080         4,592,152   

Other

     583,890         242,520   
  

 

 

    

 

 

 
   $ 8,276,086       $ 11,605,120   
  

 

 

    

 

 

 

 

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11. Income Taxes

The current and deferred components of income tax expense (benefit) are as follows:

 

Years Ended December 31,

   2015      2014  

Current tax expense (benefit)

     

Federal

   $ 287,855       $ 112,621   

State

     74,324         81,936   
  

 

 

    

 

 

 

Deferred tax expense (benefit)

     

Federal

     (15,130,060      21,592,426   

State

     (353,007      644,739   
  

 

 

    

 

 

 

Income tax expense (benefit)

   $ (15,120,888    $ 22,431,722   
  

 

 

    

 

 

 

Total income tax (benefit)/expense differs from the amounts computed by applying the U.S. statutory federal income tax rate to income (loss) before income taxes as a result of state income taxes, certain permanent differences and valuation allowances.

The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for the periods indicated:

 

Years Ended December 31,

   2015      2014  

Expected income tax provision (benefit) at statutory rate

   $ (14,858,849    $ 20,614,073   

State tax, tax effected

     10,536         675,733   

Other

     (39,646      833,016   

Rate difference

     (232,929      308,900   
  

 

 

    

 

 

 

Actual income tax provision

   $ (15,120,888    $ 22,431,722   
  

 

 

    

 

 

 

The tax effects of the Company’s temporary differences that give rise to significant portions of the deferred tax assets and liabilities are presented below:

 

December 31,

   2015     2014  

Deferred tax assets:

    

Net operating loss carryforward

   $ 77,507,544      $ 64,772,240   

Severance costs

     —          96,679   

Organizational expenses

     57,439        58,187   

Stock based compensation

     2,431,147        1,522,325   

Intangibles

     775,719        869,594   

Other

     1,418,801        24,207   
  

 

 

   

 

 

 
     82,190,650        67,343,232   

Deferred tax liabilities:

    

Oil and gas properties and other property and equipment, principally due to intangible drilling costs

     (86,789,694     (84,371,190

Unrealized hedging gain

     (11,414,232     (14,482,786
  

 

 

   

 

 

 

Net deferred tax liabilities

   $ (16,013,276   $ (31,510,744
  

 

 

   

 

 

 

The net operating loss carryforward as of December 31, 2015, approximates $222,656,000 and begins to expire in 2030. The deferred tax asset recorded for the net operating losses does not include $2,200,000 of deductions for excess stock-based compensation. In January 2013, the Company experienced an ownership change as defined in Section 382 of the Internal Revenue Code of 1986, as amended. The provisions of Section 382 apply

 

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an annual limit to the amount of the net operating loss carryforward that was incurred prior to the ownership change that can be used to offset future taxable income beginning with the 2013 taxable year. Management believes that the Company’s net operating losses will be fully utilized during the loss carryforward period. The Company has approximately $10,810,000 of percentage depletion carryover which has no expiration.

The Company files income tax returns in the United States federal jurisdiction and in various state jurisdictions. At December 31, 2015, there are no current examinations of federal or state jurisdictions in progress. The Company’s income tax returns related to fiscal years ended December 31, 2010 through 2015 remain open to possible examination by the tax authorities. The Company has not recorded any interest or penalties associated with uncertain tax positions.

The Parent files income tax returns in Australia. Management is not aware of a corporate tax implication as a result of the redomiciliation of the Parent to the United States via an Australian Scheme of Arrangement.

12. Long-Term Debt

The Company’s debt consists of the following:

 

December 31,

   2015      2014  

Revolving credit facility

   $ 87,000,000       $ 49,000,000   

8.75% senior notes

     220,000,000         220,000,000   

Less discount on 8.75% senior notes

     (3,575,000      (4,675,000

Other

     285,512         288,529   
  

 

 

    

 

 

 
   $ 303,710,512       $ 264,613,529   
  

 

 

    

 

 

 

Senior Revolving Credit Facility

In March 2013, the Company entered into a $400,000,000 syndicated credit facility agreement (“revolving credit facility”) with Wells Fargo Bank (as Administrative Agent). The initial borrowing base was set at $105,000,000. The borrowing base shall be re-determined semi-annually based on the credit agreement, and such re-determined borrowing base shall become effective and applicable on April 1 and October 1 of each year commencing October 1, 2013. The revolving credit facility matures on March 14, 2018. As of December 31, 2014, $49,000,000 was borrowed under the revolving credit facility. The borrowing base as of December 31, 2014 was $150,000,000.

The revolving credit facility may be used for loans and, subject to a $2,500,000 sub-limit, letters of credit. The Company has not drawn any advances on the letter of credit as of December 31, 2014. The revolving credit facility provides for a commitment fee of 0.5% based on the unused portion of the borrowing base under the revolving credit facility.

Borrowings under the revolving credit facility, at the Company’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 1.0% to 2.0% for ABR loans and from 2.0 to 3.0% for adjusted LIBO rate loans.

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

 

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In connection with the revolving credit facility, the Company and certain of its subsidiaries also entered into certain customary ancillary agreements and arrangement, which, among other things, provide that the indebtedness, obligations, and liabilities of the Company arising under or in connection with the revolving credit facility are unconditionally guaranteed by such subsidiaries. As of December 31, 2014, the Company was in compliance with all covenants including all financial ratios under the Wells Fargo led facility.

In June 2013, the Company entered into a $35,000,000 second lien term loan agreement (“2nd lien facility”) with Wells Fargo Energy Capital, Inc. (as Administrative Agent). The 2nd lien facility provides for a commitment fee of 0.75% based on the unused portion of the commitment amount under the 2nd lien facility. The 2nd lien facility matures on September 14, 2018. In February 2014, the 2nd lien facility was amended increasing the commitment amount to $55,000,000. In April 2014, the 2nd lien facility was fully paid and subsequently terminated.

On July 28, 2015, the Company closed a new $500,000,000 Senior Secured Credit Facility which replaced the $400,000,000 Wells Fargo led syndicated facility outlined above. The new facility was arranged by Citibank, N.A. and features an expanded borrowing base of $180,000,000 as of December 31, 2015, which is an increase over the $150,000,000 borrowing base available under the Wells Fargo led facility at December 31, 2014. 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. As of December 31, 2015, the Company was in compliance with all covenants including all financial ratios under the Citibank led facility. As of December 31, 2015, $87,000,000 was borrowed under the Citibank led revolving credit facility.

8.75% Senior Notes

On April 4, 2014, the Company issued at par $220,000,000 of 8.75% Senior Unsecured Notes due April 15, 2019 (“Notes”) to U.S. based institutional investors. The net proceeds from the offering of approximately $212,000,000 (after deducting purchasers’ discounts and offering expenses) were used to repay the Company’s revolving credit facility and 2nd lien facility, and for general corporate purposes. Under the 2nd lien term loan agreement, the Company 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, the Company may redeem the Notes in whole or in part at the redemption prices (expressed as percentages of the principal amount) set forth in the following table plus accrued and unpaid interest, if any, on the Notes redeemed, to the applicable date of redemption, if redeemed during the twelve-month period beginning on April 15 of the years indicated below:

 

Year

   Percentage  

2016

     106.563

2017

     104.375

2018 and thereafter

     100.000

In addition, upon a change of control of the Company, holders of the Notes will have the right to require the Company to repurchase all or any part of their Notes for cash at a price equal to 101% of the aggregate principal amount of the Notes repurchased, plus any accrued and unpaid interest. The Notes were issued under and governed by an Indenture dated April 4, 2014, between the Company, Wells Fargo Bank, National Association, as trustee and the Company’s subsidiaries named therein as guarantors (the “Indenture”). The Indenture contains covenants that, among other things, limit the ability of the Company 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 the Company’s assets.

 

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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. During 2014, the Company capitalized approximately $3.5 million in costs associated with the issuance of the Notes and costs incurred for amendments to the Company’s Senior Revolving Credit Facility. With the payoff and termination of the 2nd lien facility, the Company expensed approximately $700,000 of debt issuance costs. At December 31, 2015 and 2014, the Company had approximately $2,900,000 and $3,300,000, respectively, of debt issuance costs remaining that are being amortized over the lives of the respective debt.

13. Commitments and Contingencies

Employment Agreements

Each of the employment agreements to which our executives were a party expired as of December 31, 2015. Currently none of our executive officers are party to any employment agreement or compensatory arrangement, other than customary indemnification agreements.

Litigation

The Company is subject to certain claims and litigation arising in the normal course of business. In the opinion of management, the outcome of such matters will not have a materially adverse effect on the consolidated results of operations or financial position of the Company.

Environmental Remediation

Various federal, state, and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company’s operations and the costs of its oil and gas exploration, development, and production operations. The Company does not anticipate that it will be required in the near future to expend significant amounts in relation to the consolidated financial statements taken as a whole by reason of environmental laws and regulations, and appropriately no reserves have been recorded.

Lease Agreement

The Company entered into an operating lease agreement for its primary facility in October 2014. The lease will expire in October 2021. Future minimum annual lease payments are as follows:

 

     Amount  

2016

   $ 478,040   

2017

     455,600   

2018

     411,768   

2019

     422,301   

2020

     432,835   

Thereafter

     368,011   
  

 

 

 

Total

   $ 2,568,555   
  

 

 

 

Rent expense was $404,000 and $337,000 for the years ended December 31, 2015 and 2014, respectively. Included in rent expense for 2014 was $88,000 representing the acceleration of the office rent for our previous Fort Worth corporate office that was subleased in December 2014.

Rig Contract

As of December 31, 2015, the Company had one drilling rig under contract. The contract provides for a drilling rate that is indexed on a monthly basis to the West Texas Intermediate (Cushing) average price for that particular

 

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month. The current daily drilling rate is $19,000. The rig contract terminates on July 20, 2016. The early termination fee is equal to 75% of the highest month operating rate earned during the 2016 contract period times the number of days remaining on the contract term. Using the $19,000 daily rate, as of December 31, 2015 the minimum remaining commitment per the terms of the agreement is approximately $3.8 million.

14. Stockholders’ Equity

In January 2013, Amadeus Energy Limited acquired Ecofin Energy Resources Plc (the previous holding company for Lonestar Resources, Inc.) from its controlling shareholder, Ecofin Water & Power Opportunities PLC, and minority shareholders in a reverse merger effected by way of an Australian Scheme of Arrangement.

On a pre-reverse merger basis, there were 236,187,211 shares of Amadeus Petroleum, Inc. (“Amadeus”) issued and outstanding. At the time of the reverse merger, 460,000,000 shares of Amadeus were issued.

At the annual meeting of stockholders held December 17, 2012, Parent’s stockholders approved the merger and associated stock options to be issued under the 2012 Employee Share Option scheme. All outstanding shares from the previous plan, issued in May 2012, fully vested upon completion of the merger.

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 Parent’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 Parent’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. Parent has not paid any cash dividends on its common shares and 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.

 

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Stock Option Activity

For the year ended December 31, 2015, no stock options were exercised. The following tables summarize certain information related to outstanding stock options under the 2012 Plan as of and for the years ended December 31, 2015 and 2014:

 

     Shares     Weighted
Average
Exercise Price
Per Share
     Weighted Average
Remaining
Contractual Term
(in years)
 

Options outstanding at December 31,2013

     1,477,685      $ 16.00         3.0   

Granted

     410,822        18.00         3.0   

Exercised

     —          —           —     

Canceled/Expired

     (24,667     18.00         1.5   

Forfeited

     (249,570     15.00         2.0   
  

 

 

   

 

 

    

 

 

 

Outstanding at December 31, 2014

     1,614,270        16.00         2.0   

Options vested and exercisable at December 31, 2014

     970,155      $ 16.00         2.0   

Granted

     160,000        10.00         1.0   

Exercised

     —          —           —     

Canceled/Expired

     (50,000     12.00         —     

Forfeited

     (24,398     12.00         —     
  

 

 

   

 

 

    

 

 

 

Outstanding at December 31, 2015

     1,699,872        15.50         1.0   

Options vested and exercisable at December 31, 2015

     1,615,372      $ 15.50         1.0   

 

     Shares     Weighted
Average Fair
Value
per Share
     Weighted
Average
Exercise Price

per share
     Weighted Average
Remaining
Contractual Term

(in years)
 

Outstanding non-vested options at December 31, 2013

     882,456      $ 11.50       $ 15.00         3.0   

Granted

     410,822        4.50         18.00         3.0   

Vested

     (399,593     4.50         16.00         3.0   

Forfeited

     (249,570     4.50         15.00         3.0   
  

 

 

   

 

 

    

 

 

    

 

 

 

Outstanding non-vested options at December 31, 2014

     644,115      $ 4.50       $ 16.00         2.0   

Granted

     160,000        2.40         10.00         1.0   

Vested

     (695,217     4.00         15.50         1.0   

Forfeited

     (24,398     4.50         15.50         —     
  

 

 

   

 

 

    

 

 

    

 

 

 

Outstanding non-vested options at December 31, 2015

     84,500      $ 4.50       $ 15.50         1.0   
  

 

 

   

 

 

    

 

 

    

 

 

 

Stock-Based Compensation Expense

For the years ended December 31, 2014 and 2013, the Company recorded stock-based compensation expense of $2,585,000 and $1,938,000, respectively.

As of December 31, 2015, the Company had approximately $380,000 of unrecognized compensation cost related to unvested stock options, which is expected to be amortized over 2016.

15. 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.

 

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Lonestar Resources Limited had outstanding ordinary common shares (prior to the reorganization) of 15,044,051 at December 31, 2015 and 14,661,004 at December 31, 2014. Each share entitles the holder to participate in dividends and the proceeds of winding up of the Company in proportion to the number of, and amounts paid on, the shares held. Each share is also entitled to one vote at a stockholder meeting either in person or by proxy.

In connection with a planned reorganization, a new corporate entity was formed, Lonestar Resources US Inc., which immediately prior to the reorganization will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting policies have been adopted in these financial statements as if the Company were a public company. The following table presents unaudited pro forma earnings per share of Lonestar Resources US Inc., assuming that the 1 for 2 reverse stock split upon reorganization had occurred at the beginning of years ended December 31, 2015 and 2014:

UNAUDITED PRO FORMA EARNINGS PER SHARE (AFTER REORGANIZATION)

 

     2015      2014  

Net income (loss) per common share:

     

Basic

   $ (3.63    $ 4.97   

Diluted

     (3.63      4.84   

Weighted average common shares outstanding:

     

Basic

     7,522,025         7,330,602   

Diluted

     7,522,025         7,534,805   

16. Related Party Activities

During the years ended December 31, 2015 and 2014 the Company paid dividends to its Parent of approximately $308,000 and $637,000, respectively.

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

Butterfly Flaps, Ltd, a company in which Dr. Christopher Rowland (a director of Lonestar) owns an interest, has performed consultancy work for Lonestar 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 Lonestar) owns a limited partnership interest, has provided field engineering staff and consultancy services for Lonestar since 2013. The total cost for such services was approximately $938,000 and $2,300,000 in 2015 and 2014, respectively.

Mitchell Wells, who has been a Director of Lonestar Resources Limited 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 $143,000 for 2015 and $182,000 for 2014. He has not received any additional compensation for his service as a Director.

 

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17. Supplemental Information on Oil and Natural Gas Exploration and Production Activities (unaudited)

Capitalized Costs

The following table presents the Company’s aggregate capitalized costs relating to oil and gas activities at the end of the periods indicated:

 

December 31,

   2015      2014  

Oil and natural gas properties:

     

Proved properties and equipment

   $ 577,764,738       $ 489,472,814   

Unproved properties

     70,298,349         65,725,668   

Capitalized asset retirement cost

     6,927,207         6,481,752   

Less:

     

Accumulated depletion and amortization

     (133,080,366      (75,122,695

Property impairment

     (33,810,331      (5,478,264
  

 

 

    

 

 

 

Total

   $ 488,099,597       $ 481,079,275   
  

 

 

    

 

 

 

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

 

Years ended December 31,

   2015      2014  

Property acquisition costs:

     

Unproved properties

   $ 7,327,635       $ 12,247,000   

Proved properties

     1,395,862         58,731,282   

Exploration costs

     —           —     

Development costs

     85,458,433         164,180,576   
  

 

 

    

 

 

 

Total costs incurred

   $ 94,181,930         235,158,858   
  

 

 

    

 

 

 

Results of Operations

The following table sets for the results of operations from oil and gas producing activities for the years ended December 31, 2015 and 2014.

 

Years ended December 31,

   2015      2014  

Oil and gas producing activities:

     

Oil sales

   $ 70,739,269       $ 104,233,379   

Natural gas sales

     6,823,019         7,589,599   

Natural gas liquids sales

     1,928,068         3,803,582   

Lease operating and gas gathering

     (17,860,216      (16,631,611

Production, ad valorem and severance taxes

     (4,981,826      (7,123,332

Accretion of asset retirement obligations

     (214,335      (201,076

Depreciation, depletion and amortization

     (58,827,705      (40,521,546

Property impairment

     (28,622,961      (5,478,264
  

 

 

    

 

 

 

Results of operations from oil and gas producing activities

   $ (31,016,687    $ 45,670,731   
  

 

 

    

 

 

 

Depletion rate per BOE

   $ 25.16       $ 24.78   

Crude Oil and Natural Gas Reserves

Net Proved Reserve Summary

The reserve information presented below is based upon estimates of net proved oil and gas reserves that were prepared by the independent petroleum engineering firms of W.D. Von Gonten & Co. for the evaluation of the

 

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Company’s Eagle Ford Shale properties and LaRoche Petroleum Consultants, Ltd. for the evaluation of the Company’s conventional assets. All of the Company’s reserves are located in the United States.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs of the date the estimate is made). The project to extract the hydrocarbons must have commenced or the interest owner must be reasonably certain that it will commence within a reasonable period of time.

Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimate are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.

The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2015 and 2014.

 

     Oil
(BBL)
     NGLs
(BBL)
     Gas
(MCF)
     BOE(1)  

Net proved reserves

           

Reserves at December 31, 2013

     13,483,483         1,841,457         17,373,143         18,220,463   

New discoveries and extensions

     2,462,295         321,301         2,528,029         3,204,934   

Purchase of reserves in place

     9,648,101         484,493         3,655,020         10,741,764   

Reserves sold

     (252,200      —           (5,632      (253,139

Revisions of prior year estimates

     (532,522      551,078         4,106,883         703,038   

Production

     (1,198,279      (154,215      (1,689,029      (1,633,999
  

 

 

    

 

 

    

 

 

    

 

 

 

Reserves at December 31, 2014

     23,610,878         3,044,114         25,968,414         30,983,061   
  

 

 

    

 

 

    

 

 

    

 

 

 

New discoveries & extensions

     6,575,775         4,281,649         34,155,539         16,550,014   

Purchase of reserves in place

     1,541,828         297,634         2,344,083         2,230,142   

Reserves sold

     —           —           —           —     

Revisions of prior year estimates

     (6,637,821      (146,113      (2,562,392      (7,210,998

Production

     (1,539,505      (322,808      (2,923,787      (2,349,611
  

 

 

    

 

 

    

 

 

    

 

 

 

Reserves at December 31, 2015

     23,551,155         7,154,476         56,981,857         40,202,608   
  

 

 

    

 

 

    

 

 

    

 

 

 

Proved Developed Reserves:

           

December 31, 2013

     6,195,280         638,632         8,287,574         8,215,173   

December 31, 2014

     9,184,925         1,211,551         11,990,723         12,394,930   

December 31, 2015

     8,357,772         2,020,216         17,534,695         13,300,438   

Proved Undeveloped Reserves:

           

December 31, 2013

     7,288,203         1,202,825         9,085,569         10,005,290   

December 31, 2014

     14,425,953         1,832,563         13,977,691         18,588,131   

December 31, 2015

     15,193,383         5,134,260         39,447,162         26,902,170   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) BOE (barrels of oil equivalent) is calculated by converting 6 MCF of natural gas to 1 BBL of oil. A BBL (barrel) of oil is one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

 

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Standardized Measure of Discounted Future Net Cash Flows

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented.

For the years ended December 31, 2015 and 2014, calculations were made using average prices of $50.28 and $94.99 per barrel of crude oil, respectively, and $2.59 and $4.35 per MCF of natural gas, respectively. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials.

These assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and do not necessarily reflect the Company’s expectations of the actual net cash flow to be derived from those reserves, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves.

The standardized measure of discounted future net cash flows as of December 31, 2015 and 2014 were as follows:

 

December 31,

   2015      2014  

Future cash flows

   $ 1,363,349,591       $ 2,389,844,493   

Future costs

     

Production

     (456,088,889      (649,398,768

Development

     (289,026,333      (320,222,400

Future inflows before income tax

     618,234,369         1,420,223,325   

Future income taxes

     (66,565,870      (353,602,580

Future net cash flows

     551,668,499         1,066,620,745   

10% annual discount for estimated timing of cash flows

     (283,242,412      (517,581,023
  

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 268,426,087       $ 549,039,722   
  

 

 

    

 

 

 

 

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Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Nature Gas Reserves were as follows for the years indicated:

 

December 31,

   2015     2014  

Standardized measure at beginning of year

   $ 549,039,722      $ 302,771,526   

Extensions and discoveries and improved recovery net of future production and development costs

     74,142,661        88,919,601   

Purchase of minerals in place

     11,519,608        270,331,369   

Accretion of discount

     70,582,116        41,871,778   

Net change in sales price, net of production costs

     (501,189,743     (38,540,796

Changes in estimated future development costs

     56,188,859        (9,274,717

Changes of production rates (timing) and other

     125,681,828        12,731,855   

Revisions of quantity estimates

     (191,356,505     18,066,206   

Net change in income taxes

     130,906,060        (40,835,170

Sales net of production costs

     (57,088,519     (91,571,228

Sales of minerals in place

     —          (5,430,702
  

 

 

   

 

 

 

Net increase (decrease)

     (280,613,635     246,268,196   
  

 

 

   

 

 

 

Standardized measure at end of year

   $ 268,426,087      $ 549,039,722   
  

 

 

   

 

 

 

18. 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.

19. Reorganization

In connection with the planned reorganization, a new corporate entity was formed, Lonestar Resources U.S. Inc., which immediately prior to the reorganization will acquire the Parent via an Australian Scheme of Arrangement. As a result, certain accounting policies have been adopted in these financial statements as if the Company were a public company. These include earnings per share, segment reporting and supplemental oil and gas disclosures.

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The terms defined in this section are used throughout this prospectus:

3-D seismic.” Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl.” One stock tank barrel, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.

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

Boe/d.” One barrel of oil equivalent per day.

British thermal unit” or “Btu.” The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting of abandonment to the appropriate agency.

condensate.” A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

development capital.” Expenditures to obtain access to proved reserves and to construct facilities for producing, treating and storing hydrocarbons.

development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

downspacing.” Additional wells drilled between known producing wells to better exploit the reservoir.

dry well” or “dry.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

economically producible.” A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For a complete definition of economically producible, refer to the SEC’s Regulation S-X, Rule 4-10(a)(10).

exploitation.” A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

exploratory well.” A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

 

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field.” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. For a complete definition of field, refer to the SEC’s Regulation S-X, Rule 4-10(a)(15).

formation.” A layer of rock which has distinct characteristics that differ from nearby rock.

GAAP.” Accounting principles generally accepted in the United States.

gross acres” or “gross wells.” The total acres or wells, as the case may be, in which an entity owns a working interest.

held by production.” Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

IRS.” Internal Revenue Service.

lease operating expense.” All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.

LIBOR.” London Interbank Offered Rate.

MBbl.” One thousand barrels of crude oil, condensate or NGLs.

MBoe.” One thousand barrels of oil equivalent.

Mcf.” One thousand cubic feet of natural gas.

MMBbls.” One million stock tank barrels, of 42 U.S. gallons liquid volume, used in reference to crude oil, condensate or natural gas liquids.

MMBoe.” One million barrels of oil equivalent.

MMBtu.” One million British thermal units.

MMcf.” One million cubic feet of natural gas.

natural gas liquids” or “ NGLs.” The combination of ethane, propane, butane, isobutane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

net acres” or “net wells.” The percentage of total acres or wells, as the case may be, an owner has out of a particular number of gross acres or wells. For example, an owner who has 50% interest in 100 gross acres owns 50 net acres.

net revenue interest.” An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

 

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NYMEX.” The New York Mercantile Exchange.

operator.” The entity responsible for the exploration, development and production of a well or lease.

present value of future net revenues” or “PV-10.” The estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

proved developed reserves.” Proved reserves that can be expected to be recovered:

i. Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well; or

ii. Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

proved reserves.” Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations —prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence, the project within a reasonable time. For a complete definition of proved oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

proved undeveloped reserves” or “PUDs.” Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

reasonable certainty.” A high degree of confidence. For a complete definition of reasonable certainty, refer to the SEC’s Regulation S-X, Rule 4-10(a)(24).

recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

 

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reliable technology.” A grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

reserves.” Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development prospects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.

reservoir.” A porous and permeable underground formation containing a natural accumulation of producible hydrocarbons that is confined by impermeable rock or water barriers and is separate from other reservoirs.

royalty.” An interest in an oil and natural gas lease that gives the owner the right to receive a portion of the production from the leased acreage (or of the proceeds from the sale thereof), but does not require the owner to pay any portion of the production or development costs on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

SEC.” The United States Securities and Exchange Commission.

spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

spud.” Commenced drilling operations on an identified location.

undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

wellbore.” The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

working interest.” The right granted to the lessee of a property to explore for and to produce and own oil, natural gas or other minerals. The working interest owners bear the exploration, development and operating costs on either a cash, penalty or carried basis.

workover.” Operations on a producing well to restore or increase production.

WTI.” West Texas Intermediate crude oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API 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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LOGO

 

Lonestar Resources US Inc.

             Shares of Class A Common Stock

 

 

 

Prospectus

                    , 2016

 

 

 

 

Seaport Global Securities    Johnson Rice & Company L.L.C.

 

 

Dealer Prospectus Delivery Obligation

Until              (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

 

 

 


Table of Contents

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, and the FINRA filing fee, the amounts set forth below are estimates.

 

SEC registration fee

   $ 5,795   

Financial Industry Regulatory Authority filing fee

     8,000   

Legal fees and expenses

                 *   

Accounting fees and expenses

                 *   

Miscellaneous

                 *   
  

 

 

 

Total

   $             *   
  

 

 

 

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS

Section 145 of the General Corporation Law of the State of Delaware (the “DGCL”) permits a Delaware corporation to indemnify its officers, directors and other corporate agents to the extent and under the circumstances set forth therein. Our Certificate of Incorporation (the “certificate of incorporation”) and Bylaws (the “bylaws”) provide that we will indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was our director or officer or board observer, or is or was serving at our request as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, in accordance with provisions corresponding to Section 145 of the DGCL. These indemnification provisions may be sufficiently broad to permit indemnification of our executive officers and directors for liabilities, including reimbursement of expenses incurred, arising under the Securities Act.

Pursuant to Section 102(b)(7) of the DGCL, our certificate of incorporation will eliminate the personal liability of a director to us or our stockholders for monetary damages for a breach of fiduciary duty as a director, except for liability:

 

    for any breach of the director’s duty of loyalty to us or our stockholders;

 

    for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law;

 

    under Section 174 of the DGCL (or any successor provision thereto); and

 

    for any transaction from which the director derived any improper personal benefit.

The above discussion of Section 145 of the DGCL and of our certificate of incorporation and bylaws is not intended to be exhaustive and is respectively qualified in its entirety by Section 145 of the DGCL, our certificate of incorporation and bylaws.

As permitted by Section 145 of the DGCL, we carry primary and excess insurance policies insuring our directors and officers against certain liabilities they may incur in their capacity as directors and officers. Under the policies, the insurer, on our behalf, may also pay amounts for which we granted indemnification to our directors and officers.

In addition, the underwriting agreement to be filed as Exhibit 1.1 to this Registration Statement provides that the underwriters will indemnify us and our executive officers and directors for certain liabilities related to this offering, including liabilities arising under the Securities Act.

 

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ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES

During the past three years, we have issued unregistered securities to a limited number of persons as described below. We believe that each of these transactions was exempt from the registration requirement pursuant to Section (4)(a)(2) available under the Securities Act.

On July 5, 2016, the Company acquired all of the issued and outstanding ordinary shares of Lonestar Resources Limited (the “Predecessor”) as part of a reorganization (“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 common stock for every two ordinary shares of the Predecessor that were issued and outstanding.

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 common stock.

On August 2, 2016, LRAI and the Company entered into a Securities Purchase Agreement (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 LRAI’s 12% senior secured second lien notes due 2021 (the “Notes”) and (ii) five-year warrants to purchase up to an aggregate 998,000 shares of the Company’s Class A common stock at a price equal to $5.00 per share (the “Warrants”). Pursuant to the Purchase Agreement, LRAI has issued $38 million aggregate principal worth of Notes at par and the Company has issued Warrants for the purchase of 760,000 shares of Class A common stock. The date and amount of each issuance is detailed below:

 

Date

   Aggregate Principal Amount
of Notes
     # of Class A common stock
underlying Warrants
 

August 3, 2016

   $ 10,000,000         200,000   

August 10, 2016

   $ 2,000,000         40,000   

August 15, 2016

   $ 13,000,000         260,000   

August 19, 2016

   $ 5,000,000         100,000   

September 30, 2016

   $ 4,000,000         80,000   

September 30, 2016

   $ 4,000,000         80,000   

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 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.

ITEM 16. EXHIBITS

See the Exhibit Index on the page immediately preceding the exhibits for a list of exhibits filed as part of this registration statement on Form S-1, which Exhibit Index is incorporated herein by reference.

ITEM 17. UNDERTAKINGS

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of

 

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expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Fort Worth, State of Texas, on the 26th day of October, 2016.

 

Lonestar Resources US Inc.

/s/ Frank D. Bracken, III

Name: Frank D. Bracken, III

Title: Chief Executive Officer

Each person whose signature appears below appoints Frank D. Bracken, III as his true and lawful attorney-in-fact and agent, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any registration statement (including any amendments thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended and to file the same with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorney-in-fact and agent or his or her substitute, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities and the dates indicated.

 

Signature

  

Title

 

Date

/s/ Frank D. Bracken, III

Frank D. Bracken, III

   Chief Executive Officer and Director   October 26, 2016

/s/ Douglas W. Banister

Douglas W. Banister

   Chief Financial Officer   October 26, 2016

/s/ John Pinkerton

John Pinkerton

   Chairman   October 26, 2016

/s/ Daniel R. Lockwood

Daniel R. Lockwood

   Director   October 26, 2016

/s/ Dr. Christopher Rowland

Dr. Christopher Rowland

   Director   October 26, 2016

/s/ Robert Scott

Robert Scott

   Director   October 26, 2016

/s/ Bernard Lambilliotte

Bernard Lambilliotte

   Director   October 26, 2016

/s/ Henry B. Ellis

Henry B. Ellis

   Directors   October 26, 2016

/s/ Mitchell Wells

Mitchell Wells

   Director   October 26, 2016

 

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EXHIBIT INDEX

Set forth below is a list of exhibits that are being or will be filed with this Registration Statement on Form S-1.

 

Exhibit

Number

  

Description

  1.1*    Form of Underwriting Agreement
  3.1    Certificate of Incorporation of Lonestar Resources US Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form 10-12B (File No. 001-37670) filed on December 31, 2015)
  3.2    Bylaws of Lonestar Resources US Inc. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form 10-12B (File No. 001-37670) filed on December 31, 2015)
  4.1    Registration Rights Agreement, dated August 2, 2016, by and among Lonestar Resources US Inc., Leucadia National Corporation and Juneau Energy, LLC (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-37670) filed on August 3, 2016)
  4.2*    Registration Rights Agreement, dated October 26, 2016, between Lonestar Resources US Inc. and EF Realisation Company Limited
  5.1*    Opinion of Latham & Watkins LLP, with respect to the legality of the securities being registered
10.1†    Lonestar Resources US Inc. 2016 Incentive Plan (Incorporated by reference to Exhibit 10.4 of the Company’s Registration Statement on Form 10-12B/A (File No. 001-37670) filed on March 24, 2016
10.2    Credit Agreement, dated July 28, 2015, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto (Incorporated by reference to Exhibit 10.3 of the Company’s Registration Statement on Form 10-12B (File No. 001-37670) filed on December 31, 2015)
10.3    First Amendment to Credit Agreement, dated effective April 29, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto (Incorporated by reference to Exhibit 10.5 of the Company’s Registration Statement on Form 10-12B/A (File No. 001-37670) filed on June 9, 2016)
10.4    Second Amendment to Credit Agreement, dated effective May 19, 2016, among Lonestar Resources America Inc., Citibank, N.A., as Administrative Agent, and the guarantors and lenders party thereto (Incorporated by reference to Exhibit 10.6 of the Company’s Registration Statement on Form 10-12B/A (File No. 001-37670) filed on June 9, 2016)
10.5    Third Amendment to Credit Agreement and Limited Waiver, dated effective July 27, 2016, among Lonestar Resources America Inc., Citibank, N.A., in its capacity as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-37670) filed on August 2, 2016)
10.6    Securities Purchase Agreement, dated August 2, 2016, among Lonestar Resources America Inc., Lonestar Resources US Inc., Jefferies, LLC, in its capacity as the collateral agent for the purchasers, Juneau Energy, LLC, as initial purchaser, Leucadia National Corporation, as guarantor of Juneau Energy, LLC, and the other purchasers party thereto (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-37670) filed on August 3, 2016)
10.7    Joint Development Agreement, dated July 27, 2015, between Lonestar Resources America Inc. and IOG South Texas I, LLC (Incorporated by reference to Exhibit 10.3 of the Company’s Registration Statement on Form 10-12B/A (File No. 001-37670) filed on April 21, 2016)
10.8    Repurchase Facilitation Agreement, dated September 29, 2016, between Lonestar Resources US Inc. and Seaport Global Securities LLC (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-37670) filed on October 5, 2016)


Table of Contents

Exhibit

Number

  

Description

10.9*    Board Representation Agreement, dated October 26, 2016, between Lonestar Resources US Inc. and EF Realisation Company Limited
10.10*    Amended and Restated Repurchase Facilitation Agreement, effective September 29, 2016, between Lonestar Resources US Inc. and Seaport Global Securities LLC
21.1    List of significant subsidiaries of Lonestar Resources US Inc.
23.1    Consent of BDO USA, LLP
23.2    Consent of W.D. Von Gonten & Co.
23.3    Consent of LaRoche Petroleum Consultants, Ltd.
23.4*    Consent of Latham & Watkins LLP (included in Exhibit 5.1)
24.1    Power of Attorney (Included on page 11-4)
99.1    Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2013, dated March 22, 2014 (Incorporated by reference to Exhibit 99.1 of the Company’s Registration Statement on Form 10-12B (File No. 001-37670) filed on December 31, 2015)
99.2    Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2014, dated January 29, 2015 (Incorporated by reference to Exhibit 99.2 of the Company’s Registration Statement on Form 10-12B (File No. 001-37670) filed on December 31, 2015)
99.3    Report of W.D. Von Gonten & Co. regarding the Company’s estimated proved reserves as of December 31, 2015, dated February 22, 2016 (Incorporated by reference to Exhibit 99.3 of the Company’s Registration Statement on Form 10-12B/A (File No. 001-37670) filed on March 24, 2016)
99.4    Report of LaRoche Petroleum Consultants, Ltd. regarding the Company’s estimated proved reserves as of December 31, 2013, dated January 28, 2014 (Incorporated by reference to Exhibit 99.3 of the Company’s Registration Statement on Form 10-12B (File No. 001-37670) filed on December 31, 2015)
99.5    Report of LaRoche Petroleum Consultants, Ltd. regarding the Company’s estimated proved reserves as of December 31, 2014, dated January 30, 2015 (Incorporated by reference to Exhibit 99.4 of the Company’s Registration Statement on Form 10-12B (File No. 001-37670) filed on December 31, 2015)
99.6    Report of LaRoche Petroleum Consultants, Ltd. regarding the Company’s estimated proved reserves as of December 31, 2015, dated January 15, 2016 (Incorporated by reference to Exhibit 99.6 of the Company’s Registration Statement on Form 10-12B/A (File No. 001-37670) filed on March 24, 2016)

 

* To be provided by amendment.
Compensatory plan or arrangement.