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TABLE OF CONTENTS
CUBIC ENERGY, INC. INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on December 2, 2014

Registration No. 333-193298


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form S-1
Post-effective Amendment No. 1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

CUBIC ENERGY, INC.
(Exact name of registrant as specified in its charter)

Texas
(State or other jurisdiction of
incorporation or organization)
  1311
(Primary Standard Industrial
Classification Code Number)
  87-0352095
(I.R.S. Employer
Identification No.)

9870 PLANO ROAD
DALLAS, TEXAS 75238
(972) 686-0369
(Address, including zip code, and telephone number, including
area code, of registrant's principal executive offices)

Calvin A. Wallen, III
President and Chief Executive Officer
Cubic Energy, Inc.
9870 Plano Road
Dallas, Texas 75238
(972) 686-0369
(Name, address, including zip code, and telephone number,
including area code, of agent for service)

Copy to:
David R. Earhart
Gray Reed & McGraw PC
1601 Elm Street
Suite 4600
Dallas, Texas 75201
(214) 954-4135

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

           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:    ý

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

           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.    o

           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.    o

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

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

CALCULATION OF REGISTRATION FEE

               
 
Title of Each Class of Securities
to be Registered

  Amount to be
Registered(1)

  Proposed Maximum
Offering Price Per
Share

  Proposed Maximum
Aggregate Offering
Price

  Amount of
Registration Fee

 

Common Stock, $0.05 par value, issuable upon exercise of Class A Warrants

  65,834,549   $0.2600(2)   $17,116,982.74   $2,204.67
 

Common Stock, $0.05 par value, issuable upon exercise of Class B Warrants

  32,917,274   $0.50(3)   $16,458,637.00   $2,119.87
 

Total

  98,751,823       $33,575,619.74   $4,324.54(4)

 

(1)
All of the shares registered pursuant to this registration statement are to be offered by selling shareholders. Pursuant to Rule 416 under the Securities Act, this registration statement also covers such number of additional shares of common stock to prevent dilution resulting from stock splits, stock dividends and similar transactions, including pursuant to the terms of the warrants pursuant to which such shares may be issued.

(2)
Estimated solely for the purpose of calculating the registration fee, which has been computed in accordance with Rule 457(c) and Rule 457(g) under the Securities Act, based on the average of the high and low prices for the Common Stock on January 8, 2014, as reported on the OTCQB Tier of the U.S. OTC Market.

(3)
Reflects the exercise price of the Class B Warrants.

(4)
Previously paid.

           The Registrant hereby amends this Registration Statement on such date or date 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, as amended, or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

   


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The information in this prospectus is not complete and may be changed. The selling shareholders may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

(Subject to completion, dated December 2, 2014)

Prospectus

Cubic Energy, Inc.

98,751,823 Shares

Common Stock

        This prospectus relates to the resale by the holders of 98,751,823 shares of our common stock issuable upon the exercise of warrants to purchase shares of our common stock. We will not receive any of the proceeds from the resale of shares offered by the selling shareholders under this prospectus.

        Our common stock is traded on the OTCQB Tier of the U.S. OTC Markets under the symbol "CBNR." On November 28, 2014 the last reported sale price of our common stock was $0.11 per share.

        This investment involves risks. See "Risk Factors" beginning on page 6.

        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.

   

The date of this prospectus is                        , 2014.


Table of Contents


TABLE OF CONTENTS

 
  Page No.  

SUMMARY

    1  

RISK FACTORS

    6  

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

    20  

BUSINESS

    21  

MARKET PRICE OF AND DIVIDENDS ON COMMON EQUITY AND RELATED SHAREHOLDER MATTERS

    47  

USE OF PROCEEDS

    49  

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

    50  

DIRECTORS AND EXECUTIVE OFFICERS

    64  

EXECUTIVE COMPENSATION

    67  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    76  

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

    77  

DESCRIPTION OF SECURITIES

    79  

CONTROLS AND PROCEDURES

    80  

SELLING SHAREHOLDERS

    82  

PLAN OF DISTRIBUTION

    83  

LEGAL MATTERS

    84  

WHERE YOU CAN FIND MORE INFORMATION

    84  

INDEX TO FINANCIAL STATEMENTS

    F-1  

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        Unless otherwise indicated in this Registration Statement on Form S-1 (this "Registration Statement"), references to "we," "our," "us," "Cubic," the "Company" or the "Registrant" refer to Cubic Energy, Inc., a Texas corporation and its direct and indirect subsidiaries. References to "our common stock," "our shares of common stock," "our shares of preferred stock" or "our capital stock" or similar terms shall refer to the common stock and preferred stock of the Company.


SUMMARY

The Company

        We are an independent energy company engaged in the development and production of, and exploration for, crude oil, natural gas and natural gas liquids. Our oil and gas assets are concentrated in Texas and Louisiana. At June 30, 2014, our total proved reserves were 135,071,173 Mcfe. Our principal executive offices are located at 9870 Plano Road, Dallas, Texas 75238, and our telephone number is (972) 686-0369.

Financing and Acquisition Transactions

        On October 2, 2013, we consummated all of the following transactions. This date will be considered as the effective date for purposes of recording the acquisitions and new operations on our books and records.

Formation of New Subsidiaries

        We approved the formation and capitalization of two new, wholly owned direct subsidiaries (Cubic Asset Holding, LLC, a Delaware limited liability company ("Cubic Asset Holding"), and Cubic Louisiana Holding, LLC, a Delaware limited liability company ("Cubic Louisiana Holding")) and two new, wholly owned indirect subsidiaries (Cubic Asset LLC, a Delaware limited liability company and a direct subsidiary of Cubic Asset Holding ("Cubic Asset"), and Cubic Louisiana, LLC, a Delaware limited liability company and a direct subsidiary of Cubic Louisiana Holding ("Cubic Louisiana")).

Senior Secured Notes Financing

        We entered into a Note Purchase Agreement dated October 2, 2013 (the "Note Purchase Agreement"), pursuant to which we issued an aggregate of $66.0 million of senior secured notes due October 2, 2016 (the "Notes") to certain purchasers. Prior to giving effect to the Amendment (as defined below), the Notes bore interest at the rate of 15.5% per annum, in cash, payable quarterly; provided, however, that interest for the first six months following the closing was payable 7.0% per annum in cash and 8.5% per annum in additional Notes. The indebtedness under the Note Purchase Agreement is secured by substantially all of our assets, including a first priority lien over all of the assets of the Company, Cubic Asset and Cubic Asset Holding and a second priority lien over all of the assets of Cubic Louisiana and Cubic Louisiana Holding.

Issuance of Warrants and Series C Redeemable Voting Preferred Stock

        Pursuant to the terms of a Warrant and Preferred Stock Agreement, dated as of October 2, 2013 (the "Warrant and Preferred Stock Agreement"), and in connection with the issuance and sale of the Notes under the Note Purchase Agreement, the Company issued certain warrants and shares of Series C Redeemable Voting Preferred Stock, par value $0.01 per share (the "Series C Redeemable Voting Preferred Stock"), to certain purchasers of the Notes and their affiliates (the "Investors"). The Company issued warrants exercisable for (a) an aggregate of 65,834,549 shares of the Company's common stock, par value $0.05 per share (the "Common Stock"), at an exercise price of $0.01 per share (the "Class A Warrants"), and (b) an aggregate of 32,917,274 shares of Common Stock, at an

 

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exercise price of $0.50 per share (the "Class B Warrants" and together with the Class A Warrants, the "Warrants").

        The Company also issued an aggregate of 98,751.823 shares of Series C Redeemable Voting Preferred Stock to the Investors. The holders of the Series C Redeemable Voting Preferred Stock are entitled to vote, together with holders of Common Stock, as a single class with respect to all matters presented to holders of Common Stock of the Company. The holders of Series C Redeemable Voting Preferred Stock are entitled, in the aggregate, to a number of votes equal to the number of shares of Common Stock that would be issuable upon the exercise of all outstanding Warrants on a Full Physical Settlement basis (as defined in the Warrant and Preferred Stock Agreement). The holders of Series C Redeemable Voting Preferred Stock are not entitled to receive any dividends from the Company. Shares of the Series C Redeemable Voting Preferred Stock have a stated value of $0.01 per share and may be redeemed at the option of the holders thereof at any time.

Investment Agreement and Voting Agreement

        In connection with entering into the Note Purchase Agreement and the Warrant and Preferred Stock Agreement, we entered into an Investment Agreement, dated as of October 2, 2013, with the Investors, pursuant to which the Investors have the right to designate three members (subject to adjustment for changes in board size) for election or appointment to our board of directors and certain information rights, veto rights, pre-emptive rights and sale rights, among others.

        The Investors and Calvin A. Wallen, III, our Chairman, President and Chief Executive Officer, also entered into a Voting Agreement, dated as of October 2, 2013 (the "Voting Agreement"), pursuant to which Mr. Wallen has agreed to vote shares of our voting securities beneficially owned by him in favor of the Investors' designees to our board of directors and with the Investors in connection with certain other matters. Mr. Wallen has also agreed not to transfer shares of our voting securities beneficially owned by him unless certain conditions specified in the Voting Agreement are satisfied.

Registration Rights Agreement

        In connection with entering into the Note Purchase Agreement and the Warrant and Preferred Stock Agreement, we entered into a Registration Rights Agreement, dated as of October 2, 2013, with the Investors, providing for, among other things, the registration of shares of our common stock issuable upon exercise of the Warrants with the Securities and Exchange Commission.

Hedging Transaction

        On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Call Option Structured Derivative arrangement with a third party that resulted in the receipt of an upfront payment at closing of approximately $35,000,000, through the sale of calls, which upfront payment approximated fair value of the calls sold at inception. As a result, the Call Option Structured Derivative arrangement was initially recognized and measured at the amount of its upfront payment. Under the terms of the Call Option Structured Derivative arrangement, Cubic Asset sold calls to the third party covering (i) approximately 556,000 barrels of oil at a strike price set between $80 per barrel and $90 per barrel, and (ii) approximately 51.3 million MMBtu's of gas at a strike price set between $3.45 per MMBtu and $3.90 per MMBtu. The scheduled volumes subject to the calls sold relate to production months from November 2013 through December 2018. The Company is subject to the price risks associated with product price changes that differ from the specified call prices. If the market price during the applicable production month is above the applicable strike price, Cubic Asset would be required to pay the third party the difference between the market price and strike price for the amount of production subject to the call. This arrangement does not hedge the Company's risk associated with product price decreases.

 

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        On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Fixed Price Swap arrangement. Under the terms of the Fixed Price Swap arrangement, Cubic Asset sold calls to a third party covering approximately 18,000 barrels of oil at a price of $92 per barrel. The scheduled volumes subject to the calls sold relate to production months from November 2013 through October 2016. Cubic Asset is subject to the price risks associated with product price increases above the specified fixed prices. Cubic Asset is using swaps to hedge some of its natural gas production. Cubic Asset receives the fixed price and pays the third party the floating market price during the applicable production month for the amount of production subject to the call.

Wells Fargo Debt Restructuring

        Cubic Louisiana and Wells Fargo Energy Capital, Inc. ("WFEC") entered into an Amended and Restated Credit Agreement dated October 2, 2013 (the "Credit Agreement"). In conjunction with entering into the Credit Agreement, we assigned all of our previously held oil and gas interests in Northwest Louisiana to Cubic Louisiana (the "Legacy Louisiana Assets"). Pursuant to the terms of the Credit Agreement, we repaid the $5 million term loan payable to WFEC, and Cubic Louisiana assumed the remaining unpaid debt to WFEC, which amount was $20,865,110 as of that date. That debt is reflected in a term loan bearing interest at Wells Fargo Bank prime rate, plus 2%, per annum. In the event that Cubic Louisiana does not have available cash to pay interest on the Credit Facility, accrued and unpaid interest will be paid in kind via an additional promissory note. As part of the Credit Agreement, WFEC is providing a revolving credit facility in the amount of up to $10,000,000, bearing interest at the same rate, with all advances under that revolving credit facility to be made in the sole discretion of WFEC. The indebtedness to WFEC pursuant to the Credit Agreement is secured by a first priority lien over all of the assets of Cubic Louisiana and Cubic Louisiana Holdings. Our other oil and gas properties, including the assets acquired from Gastar, Navasota and Tauren, as described below, do not secure the indebtedness under the Credit Agreement.

Conversion of Wallen Note and Series A Convertible Preferred Stock into Series B Convertible Preferred Stock

        We entered into and consummated the transactions contemplated by a Conversion and Preferred Stock Purchase Agreement dated as of October 2, 2013 (the "Conversion Agreement") with Mr. Wallen and Langtry Mineral & Development, LLC, an entity controlled by Mr. Wallen ("Langtry"). Pursuant to the terms of the Conversion Agreement, (a) Langtry was issued 12,047 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $12,047,000, in exchange for the cancellation of all of the issued and outstanding shares of Series A Convertible Preferred Stock held by Langtry and (b) Mr. Wallen was issued 2,115 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $2,115,000, in exchange for the cancellation of a promissory note payable to Mr. Wallen in the principal amount of $2,000,000, plus $114,986 of accrued and unpaid interest.

        The Series B Convertible Preferred Stock is entitled to dividends at a rate of 9.5% per annum and, subject to certain limitations, is convertible into our common stock at an initial conversion price of $0.50 per share of common stock. The holders of the Series B Convertible Preferred Stock are entitled to vote (on an as-converted basis), together with holders of our common stock, as a single class with respect to all matters presented to holders of our common stock.

Acquisition of Properties from Gastar

        We consummated the transactions contemplated by the Purchase and Sale Agreement dated as of April 19, 2013 (the "Gastar Agreement") with Gastar Exploration Texas, LP ("Gastar") and Gastar Exploration USA, Inc. Pursuant to the Gastar Agreement, we acquired proved reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The acquired properties include approximately 17,400 net acres of leasehold interests. The acquisition price paid at closing was $39,188,300, following various adjustments set forth in the Gastar Agreement, and

 

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net of the various deposits paid prior to the closing date. For purposes of allocating revenues and expenses and capital costs between Gastar and us, such amounts were netted effective January 1, 2013 and have been recorded as an adjustment to the purchase price.

Acquisition of Properties from Navasota

        On September 27, 2013, we entered into a Purchase and Sale Agreement (the "Navasota Agreement") with Navasota Resources Ltd., LLP ("Navasota"). On October 2, 2013, pursuant to the Navasota Agreement, we acquired proved reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The leasehold interests acquired from Navasota generally consist of additional fractional interests in the properties acquired pursuant to the Gastar Agreement, comprising approximately 6,400 net acres. The acquisition price paid was $19,400,000, prior to certain post-closing adjustments.

Acquisition of Properties from Tauren

        We entered into and consummated the transactions contemplated by a Purchase and Sale Agreement dated as of October 2, 2013 (the "Tauren Agreement") with Tauren Exploration, Inc., an entity controlled by Mr. Wallen. Pursuant to the Tauren Agreement, we acquired well bores, proved reserves, oil & natural gas production and undeveloped leasehold interests in the Cotton Valley formation in DeSoto and Caddo Parishes, Louisiana. The acquired properties include approximately 5,600 net acres of leasehold interests. The acquisition price paid was $4,000,000 in cash and 2,000 shares of the Company's Series B Convertible Preferred Stock with an aggregate stated value of $2,000,000 and a fair value of $368,000. The Tauren Agreement was unanimously approved by our board of directors, excluding Mr. Wallen.

Amendment to Note Purchase Agreement

        On July 14, 2014, we entered into an Amendment, Forbearance and Waiver Agreement (the "Amendment") with the holders of the Notes, and certain other parties thereto. Pursuant to the Amendment, the holders of the Notes waived various defaults specified in the Amendment, and the parties agreed to modify certain covenants in the Note Purchase Agreement. The holders of the Notes also waived their right to receive Default Interest and Registration Default Interest (as such terms are defined in the Note Purchase Agreement). In addition, the Amendment provides that after March 31, 2014, the interest rate applicable to the Notes is increased from 15.5% per annum to 20.5% per annum; provided that after such date interest shall not be payable in cash but shall accrue and compound on a quarterly basis.

        The Amendment includes an additional covenant requiring the Company, among other things, by no later than October 17, 2014, to enter into a definitive agreement with respect to a Strategic Transaction (as defined below) that is reasonably expected to be consummated no later than December 31, 2014. A Strategic Transaction includes a transaction resulting in the complete repayment of the Notes, or another transaction acceptable to the holders of the Notes. We continue to explore alternatives with respect to a Strategic Transaction, although we did not enter into a definitive agreement by October 17, 2014. We are in discussions with the holders of the Notes with respect to available alternatives. Unless the requirement regarding a Strategic Transaction is waived, or we obtain an extension of time, the holders of the Notes could declare a default under the Note Purchase Agreement, accelerate the indebtedness represented by the Notes and exercise all other remedies available to them, including foreclosing on our assets.

 

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The Offering

        Pursuant to the terms of the Warrant and Preferred Stock Agreement, we issued warrants exercisable for (a) an aggregate of 65,834,549 shares of our common stock at an exercise price of $0.01 per share and (b) an aggregate of 32,917,274 shares of our common stock at an exercise price of $0.50 per share. Prior to entering into these transactions, there were no relationships between the selling shareholders and us, or our directors, officers or other affiliates.

        The selling shareholders will determine when and how they will sell our common stock offered by this prospectus. See "Plan of Distribution." We will not receive any of the proceeds from the sale of our common stock offered by this prospectus.

        On October 1, 2013, the closing sale price of our common stock on the OTCQB was $0.38 per share. As a result of the $0.37 discount between the closing sale price on the day immediately prior to their issuance and the exercise price of the Class A Warrants of $0.01, the maximum profit that could be realized by the selling shareholders as a result of such discount is $24,358,783.13.

 

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RISK FACTORS

        You should carefully consider the following risk factors, in addition to the other information set forth in this Prospectus, in connection with any investment decision regarding shares of our Common Stock. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our Common Stock. Some information in this Prospectus may contain "forward-looking" statements that discuss future expectations of our financial condition and results of operation. The risk factors noted in this section and other factors could cause our actual results to differ materially from those contained in any forward-looking statements.

Our ability to continue operations is dependent on our ability to work with our lenders and identify an acceptable Strategic Transaction.

        As of September 30, 2014, we had cash in the amount of $5,858,973 and total liabilities in the amount of $123,650,382. We also had a working capital deficit of $78,403,281 and an accumulated deficit of $79,042,487. Additionally, we are currently subject to a forbearance agreement in relation to the Note Purchase Agreement which requires us to, among others, enter into a definitive agreement with respect to a Strategic Transaction by October 17, 2014. The holders of the Notes have the ability to require the terms of the Strategic Transaction to permit us to repay all amounts owing to the holders of the Notes. We continue to explore alternatives with respect to a Strategic Transaction, although we did not enter into a definitive agreement by October 17, 2014. We are in discussions with the holders of the Notes with respect to available alternatives. Unless the requirement regarding a Strategic Transaction is waived, or we obtain an extension of time, the holders of the Notes could declare a default under the Note Purchase Agreement, accelerate the indebtedness represented by the Notes and exercise all other remedies available to them, including foreclosing on our assets.

        We believe we have complied with the other terms of the forbearance agreement; however, there can be no assurance that we will be successful in consummating a Strategic Transaction within the mandated time period.

Servicing our debt requires a significant amount of cash.

        On October 2, 2013, we entered into the Note Purchase Agreement, pursuant to which we initially issued an aggregate of $66,000,000 of Notes. In addition, our prior debt of approximately $21,000,000 to WFEC was renegotiated and assumed by one of our subsidiaries. As of September 30, 2014, after giving effect to the issuance of additional debt to pay interest thereon, there is an aggregate principal amount of approximately $68,834,798 of Notes, and the aggregate indebtedness to WFEC is approximately $24,880,936. As a result of the Amendment to the Note Purchase Agreement, we are required to enter into a definitive agreement with respect to a Strategic Transaction by October 17, 2014, which we have not done. In addition, the Amendment provides that the interest rate applicable to the Notes is increased to 20.5%.

        Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our ability to develop our Leon and Robertson Counties, Texas assets and our Louisiana assets, generate cash flows from those assets and collect amounts owed to us by our third-party operators. We continue to explore alternatives with respect to a Strategic Transaction, although we did not enter into a definitive agreement by October 17, 2014. No assurances can be given that we will be able to complete a Strategic Transaction.

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Our acquisition of assets from Gastar, Navasota and Tauren presents certain risks to our business and operations.

        In October 2013, we consummated the acquisition of certain assets from Gastar, Navasota and Tauren. The acquisitions present numerous risks, including the following:

    The possibility that the expected benefits of such transaction may not materialize in the timeframe expected, or at all, or may be more costly to achieve than anticipated;

    The increase in our indebtedness that has resulted from entering into financing for the acquisitions;

    That the acquired assets may not produce as expected;

    That we are unable to successfully develop the assets;

    Risks associated with the ownership and operation of the acquired assets, which differ from those that we previously held, in that the acquired assets in East Texas are primarily oil producing, while our legacy assets are primarily gas producing;

    The integration of these transactions may require diversion of the attention of our management and other key employees from ongoing business activities, including the pursuit of other opportunities that could be beneficial to us; and

    That we have incurred substantial costs in connection with these transactions.

        One or more of these factors could negatively affect our business, financial condition or results of operations.

Our common stockholders may experience dilution due to the exercise of warrants to purchase Common Stock.

        As part of the transactions consummated in October 2013, we issued warrants exercisable into an aggregate of 65,834,549 shares of Common Stock at an exercise price of $0.01 per share, and warrants exercisable into an aggregate of 32,917,274 shares of Common Stock at an exercise price of $0.50 per share. As a result of the issuance of these warrants, the exercise price of warrants held by WFEC, which are exercisable into an aggregate of 8,500,000 shares of Common Stock, was adjusted to $0.1753 per share. The issuance of additional shares of Common Stock upon exercise of any of these warrants would result in dilution to existing holders of Common Stock. In addition, the issuance of additional warrants or other securities convertible into Common Stock could result in the dilution of existing stockholder's equity interests. The issuance of additional shares of Common Stock or warrants or other securities convertible into Common Stock could also trigger additional anti-dilution adjustments in the exercise price of outstanding warrants and other securities convertible into Common Stock.

Fluctuations in oil and natural gas prices, which have been volatile at times, may adversely affect our revenues as well as our ability to maintain or increase our borrowing capacity, repay current or future indebtedness and obtain additional capital.

        Our future financial condition, access to capital, cash flows and results of operations depend upon the prices we receive for our oil and natural gas. Historically, we have been particularly dependent on prices for natural gas, but as a result of the acquisition of our properties in Leon and Robertson Counties, Texas, we have become increasingly dependent on prices for oil. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Factors that affect the prices we receive for our oil and natural gas include:

    The level of domestic production;

    The availability of imported oil and natural gas;

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    Political and economic conditions and events in foreign oil and natural gas producing nations, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;

    The ability of members of OPEC to agree to and maintain oil price and production controls;

    The cost and availability of transportation and pipeline systems with adequate capacity;

    The cost and availability of other competitive fuels;

    Fluctuating and seasonal demand for oil, natural gas and refined products;

    Concerns about global warming or other conservation initiatives and the extent of governmental price controls and regulation of production;

    Weather;

    Foreign and domestic government relations; and

    Overall economic conditions, particularly the recent worldwide economic slowdown which has put downward pressure on oil and natural gas prices and demand.

        In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. During fiscal 2014, the Henry Hub spot price for natural gas fluctuated from a high of $7.90 per Mcf to a low of $3.27 per Mcf, while the NYMEX West Texas Intermediate crude oil price ranged from a high of $110.62 per Bbl to a low of $91.36 per Bbl.

        Our revenues, cash flow and profitability and our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital depend substantially upon oil and natural gas prices.

We face significant competition, and many of our competitors have resources in excess of our available resources.

        The oil and gas industry is highly competitive. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and exploratory prospects and sale of crude oil, natural gas and NGL. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies with substantially larger operating staffs and greater capital resources than us. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.

        Drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by us or in which we have an interest will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems,

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pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays sometimes involve drilling rigs where inclement weather prohibits the movement of land rigs causing a high demand for rigs by a large number of companies during a relatively short period of time. Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.

        Our operations are also subject to all of the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We participate in insurance coverage maintained by the operators of our wells, although there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

        Where appropriate, we may evaluate and pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:

    Recoverable reserves;

    Exploration potential;

    Future natural gas and oil prices;

    Operating costs;

    Potential environmental and other liabilities; and

    Permitting and other environmental authorizations required for our operations.

        In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are inexact and their accuracy inherently uncertain and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every facility or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:

    Problems integrating the purchased operations, personnel or technologies;

    Unanticipated costs;

    Diversion of resources and management attention from our exploration business;

    Entry into regions or markets in which we have limited or no prior experience; and

    Potential loss of key employees, particularly those of the acquired organization.

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We have a history of losses from operations and may not achieve profitable operations. If we are not able to achieve and maintain profitable operations in the future, we might not be able to access funds through debt or equity financings.

        We had losses from operations of $7,527,465 for the year ended June 30, 2014 and $3,609,972 for the year ended 2013, $2,117,242 for the three months ended September 30, 2014 and $1,348,606 for the same period of 2013. Our accumulated deficit as of September 30, 2014 was $79,042,487. Historically, we have funded our operating losses, acquisitions and drilling costs primarily through a combination of private offerings of convertible debt, senior secured debt, and equity securities. We must repay or refinance all amounts payable under the Note Purchase Agreement and to WFEC. Our success in obtaining the necessary capital resources to fund the repayment under the Note Purchase Agreement, the Credit Agreement with WFEC as well as future costs associated with our operations and drilling plans is dependent upon our ability to: (i) increase revenues through acquisitions and recovery of our proved producing and proved developed non-producing oil and gas reserves; (ii) maintain effective cost controls at the corporate administrative office and in field operations; and (iii) obtain additional financing. However, even if we achieve some success with our plans, there can be no assurance that we will be able to generate sufficient revenues to achieve significant profitable operations or to fund our drilling plans.

We have substantial capital requirements necessary for undeveloped properties for which we may not be able to obtain adequate financing.

        At June 30, 2014, a significant portion of our proved oil and gas reserves were undeveloped. At June 30, 2014, we had total proved undeveloped reserves of 44,346 MMcfe, which represented approximately 34% of our total proved reserves of 135,071 MMcfe. Recovery of our future undeveloped reserves will require significant capital expenditures to further develop these reserves for the foreseeable future. In addition to our results of operations, our derivative sales contracts can potentially affect cash flow negatively, if prices for natural gas or oil exceed their respective strike prices. Pursuant to the derivative sales contracts, we are required to pay to the counterparty the difference between the strike price and actual sales price for volumes subject to the respective contract, to the extent the actual sales price exceeds the strike price. If our capital resources are utilized for that purpose, we would have fewer capital resources available for development of our undeveloped properties.

        No assurance can be given that our financing sources will be sufficient to fund our costs for third-party operators' development activities or that development activities will be either successful or in accordance with our schedule. Additionally, if natural gas prices do not increase or if our costs of development significantly increase, we could experience a significant reduction in the number of gas wells drilled and/or reworked. No assurance can be given that any wells will produce oil or gas in commercially profitable quantities. Development of our properties could require capital resources in addition to amounts available to us. There can be no assurance that sufficient cash on hand or additional financing (on either favorable or unfavorable terms) will be available, when required, to fund the development. In the event of product price increases resulting in payments by us under the derivative sales contracts, no assurances can be given that we will have increases in oil and/or gas production in excess of the notional amounts of oil and/or gas specified in our derivative sales contracts. Any inability to obtain additional financing could have a material adverse effect on us, including requiring us to cease our oil and gas development plans or not being able to maintain our working interest due to failure to pay our share of expenses. Any additional financing may involve substantial dilution to the interests of our stockholders at that time.

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Our natural gas and oil sales and our related hedging activities expose us to potential regulatory risks.

        The Federal Trade Commission, the Federal Energy Regulatory Commission ("FERC"), and the U.S. Commodity Futures Trading Commission ("CFTC") hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of natural gas and oil and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations and financial condition.

        To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use of such capacity. Any failure on our part to comply with the FERC's regulations and policies, or with an interstate pipeline's tariff, could result in the imposition of civil and criminal penalties.

We could incur significant costs and liabilities in responding to contamination that occurs as a result of our operations.

        There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations or in operations in which we own a working interest as a result of the handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to operations, and due to historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination. Private parties, including the owners of properties upon which our wells or the wells in which we own a working interest are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition.

Technological changes could affect our operations.

        The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement such new technologies at substantial costs. In addition, many other natural gas and oil companies have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may be unable to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If one or more of the technologies that we currently use or may implement in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, it could have a material adverse effect on our financial condition, future cash flows and the results of operations.

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We are subject to uncertainties in reserve estimates and future net cash flows.

        This Prospectus contains estimates of our oil and gas reserves as of June 30, 2014 and the expected future net cash flows from those reserves, most of which have been prepared by an independent petroleum consultant. There are numerous uncertainties inherent in estimating quantities of reserves of oil and gas and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve estimates in this Prospectus are based on various assumptions, including, for example, constant oil and gas prices, operating expenses, capital expenditures and the availability of funds, and, therefore, are inherently imprecise indications of future net cash flows. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this Prospectus. Additionally, our reserves may be subject to downward or upward revision based upon actual production performance, results of future development and exploration, prevailing oil and gas prices and other factors, many of which are beyond our control.

        The present value of future net reserves discounted at 10% (the "PV-10") of proved reserves referred to in this Prospectus should not be construed as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with applicable requirements of the SEC, the estimated discounted future net cash flows from proved reserves are based on an average price as of the first day of each month during the applicable 12 months. For oil volumes, the average West Texas Intermediate posted price of $96.75 per barrel is adjusted by field for quality, transportation fees, and a regional price differential. For gas volumes, the average Henry Hub spot price of $4.10 per MMBTU is adjusted by field for energy content, transportation fees, and a regional price differential. All prices are held constant throughout the lives of the properties. For the proved reserves, the average adjusted product prices weighted by production over the remaining lives of the properties are $97.51 per barrel of oil, $47.66 per barrel of NGL, and $4.01 per Mcf of gas. Actual future net cash flows also will be affected by: (i) the timing of both production and related expenses; (ii) changes in consumption levels; and (iii) governmental regulations or taxation. In addition, the calculation of the present value of the future net cash flows using a 10% discount as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general.

Derivatives contracts on our production may result in losses or prevent us from benefiting to the fullest extent possible from increases in prices for natural gas and oil.

        In October 2013, we entered into New York Mercantile Exchange ("NYMEX") futures contracts as derivatives on natural gas production and crude oil production, in the form of a Call Option Structured Derivative with a third party. This derivative limits our ability to benefit from increases in the prices of natural gas and oil.

If the counterparties to the derivative instruments we use to mitigate our business risks default or fail to perform, we may be exposed to risks we had sought to mitigate, which could materially adversely affect our financial condition and results of operations.

        In October 2013, we began to use derivatives to mitigate our natural gas and oil price risk with counterparties. This is a more pronounced risk to us in view of the recent stresses suffered by financial institutions. We cannot provide assurance that our counterparties will honor their obligations now or in the future.

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The enactment of the Dodd-Frank Act could have an adverse impact on our ability to hedge risks associated with our business.

        Comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, that participate in that market. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act the CFTC has issued final regulations to set 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 would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Colombia in September 2012. In response, the CFTC adopted rules and dismissed its appeal of the District Court's decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of "swap", "security-based swap", "swap dealer" and "major swap participant". The Dodd-Frank Act and CFTC rules also may 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. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

        The Dodd-Frank Act and any new regulations could significantly increase the cost of derivatives contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act 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. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.

We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.

        Our oil and gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels that we believe are reasonable, we are not fully insured against all risks. We do not carry business interruption insurance. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.

        From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which we own an interest have been subject to production curtailments. The

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curtailments range from production being partially restricted to wells being completely shut-in. The duration of curtailments varies from a few days to several months. In most cases, we are provided only limited notice as to when production will be curtailed and the duration of such curtailments.

We cannot control the development of the properties we own but do not operate, which may adversely affect our production, revenues and results of operations.

        As of June 30, 2014, non-affiliated third parties operated wells that represented approximately 34% of our total proved reserves as of that date. As a result, the success and timing of our drilling and development activities on those properties depend upon a number of factors outside of our control, including:

    the timing and amount of capital expenditures;

    the operators' expertise and financial resources;

    the approval of other participants in drilling wells; and

    the selection of suitable technology.

        If drilling and development activities are not conducted on our properties or are not conducted on a timely basis, we may be unable to increase our production or offset normal production declines, which may adversely affect our production, revenues and results of operations.

Our business may suffer if we lose key personnel.

        We depend to a large extent on the services of Calvin A. Wallen, III, our President, Chairman of the Board, and Chief Executive Officer. The loss of the services of Mr. Wallen would have a material adverse effect on our operations.

Certain of our affiliates control a majority of the voting power of our securities, which may affect other stockholders' ability to influence matters submitted to a vote of stockholders.

        As of November 28, 2014, Mr. Wallen and the Investors, collectively, control over 70% of the voting power with respect to matters submitted to the holders of the Common Stock. As a result, they have the ability to control much of our business affairs, including the ability to control the election of directors and results of voting on all matters requiring stockholder approval. The Investors and Mr. Wallen can effectively prevent a change of control of the Company and determine the outcome of all matters submitted to the Company's shareholders.

Certain of our affiliates have engaged in business transactions with us, which may result in conflicts of interest.

        Certain officers, directors and related parties, including entities controlled by Mr. Wallen, have engaged in business transactions with us which were not the result of arm's length negotiations between independent parties. Our management believes that the terms of these transactions were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the independent members of our Board of Directors.

The liquidity, market price and volume of our stock are volatile.

        The trading price of our Common Stock could be subject to wide fluctuations in response to quarter-to-quarter variations in our operating results, announcements of our drilling results and other events or factors. In addition, the U.S. stock markets have from time to time experienced extreme price

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and volume fluctuations that have affected the market price for many companies and which often have been unrelated to the operating performance of these companies. These broad market fluctuations may adversely affect the market price of our securities. Currently, our Common Stock is traded on the OTCQB, the mid-tier on the OTC Markets, which is not a nationally recognized exchange.

We may experience adverse consequences because of required indemnification of officers and directors.

        Provisions of our Certificate of Formation and Bylaws provide that we will indemnify any director and officer as to liabilities incurred in their capacity as a director or officer and on those terms and conditions set forth therein to the fullest extent of Texas law. Further, we may purchase and maintain insurance on behalf of any such persons whether or not we would have the power to indemnify such person against the liability insured against. The foregoing could result in substantial expenditures by us and prevent any recovery from our officers, directors, agents and employees for losses incurred by us as a result of their actions.

Certain anti-takeover provisions may discourage a change in control.

        Provisions of Texas law and our Certificate of Formation and Bylaws may have the effect of delaying or preventing a change in control or acquisition of the Company. Our Certificate of Formation and Bylaws include "blank check" preferred stock (the terms of which may be fixed by our Board of Directors without stockholder approval), and certain procedural requirements governing stockholder meetings. These provisions could have the effect of delaying or preventing a change in control of the Company. As a result of the Voting Agreement, the Investors and Mr. Wallen control all votes of shareholders, and can effectively prevent a change of control.

We do not intend to declare cash dividends on our Common Stock in the foreseeable future.

        Our Board of Directors presently intends to retain all of our earnings, if any, for the repayment of debt, the payment of dividends on our preferred stock and the expansion of our business. We therefore do not anticipate the distribution of cash dividends on our Common Stock in the foreseeable future. Any future decision of our Board of Directors to pay cash dividends on our Common Stock will depend, among other factors, upon our earnings, financial position and cash requirements.

Our internal controls over financial reporting were deemed not effective, which could have a significant and adverse effect on our business.

        Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC, which we collectively refer to as "Section 404," require us to evaluate our internal controls over financial reporting to allow management to report on those internal controls as of the end of each year. Effective internal controls are necessary for us to produce reliable financial reports and are important in our effort to prevent financial fraud. In the course of our Section 404 evaluations, we may identify conditions that may result in significant deficiencies or material weaknesses and we may conclude that enhancements, modifications or changes to our internal controls are necessary or desirable. Implementing any such matters would divert the attention of our management, could involve significant costs, and may negatively impact our results of operations.

        In September and October 2014, we identified material weaknesses in our internal controls over financial reporting in connection with our (i) financial reporting and disclosure process (ii) accounting for asset retirement obligations and (iii) accounting for certain complex accounting transactions. The first material weakness, our financial reporting and disclosure process, resulted in additional disclosures and amendments to our quarterly reports for the quarterly periods ended September 30, 2013, December 31, 2013 and March 31, 2014 necessary to present the financial statements in accordance with accounting principles generally accepted in the United States. The second material weakness,

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accounting for asset retirement obligations (ARO), resulted in our inappropriate estimation of the ARO related to the properties acquired in our acquisitions in fiscal 2014. Our third material weakness, our accounting for certain complex accounting transactions, resulted in an incorrect accounting treatment related to the warrants that were issued together with the Notes. The warrants contained 'full-ratchet' anti-dilution adjustment provisions that were not properly accounted for. Additionally, certain warrants that were re-priced in 2013 and 2014 also contained certain anti-dilution provisions that were not accounted for correctly since their issuance date. Finally, we did not apply the proper accounting for the exchanges of certain related party debt and equity instruments in transactions that were deemed equity contributions.

        We note that there are inherent limitations on the effectiveness of internal controls, as they cannot prevent collusion, management override or failure of human judgment. If we fail to remediate the foregoing material weaknesses or otherwise fail to maintain an effective system of internal controls or if management or our independent registered public accounting firm were to discover additional material weaknesses in our internal controls, we may be unable to produce reliable financial reports or prevent fraud, and it could harm our financial condition and results of operations, result in a loss of investor confidence and negatively impact our share price.

We may not have satisfactory title or rights to all of our current or future properties.

        Prior to acquiring undeveloped properties, our contract land professionals review title records or other title review materials relating to substantially all of such properties. The title investigation performed by us prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. Prior to drilling, we obtain a title opinion on the drill site. However, a title opinion does not necessarily ensure satisfactory title. We believe we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. In the normal course of our business, title defects and lease issues of varying degrees arise, and, if practicable, reasonable efforts are made to cure such defects and issues.

        At June 30, 2014, we believe that our leaseholds for all of our net acreage in Louisiana were being kept in force by virtue of production in paying quantities, and 40% of our leaseholds in Leon and Robertson Counties, Texas are in force by virtue of production in paying quantities. The legal climate in Northwest Louisiana and Texas has become increasingly hostile and litigious towards oil and gas companies. Many mineral owners are seeking opportunities to make additional money from their minerals rights, including pursuit of claims of lease expiration by asserting that production does not exist in paying quantities. We are a defendant in a lawsuit brought by a mineral owner in Northwest Louisiana alleging, among other things, that all or part of our mineral lease lapsed. If the outcome of this lawsuit were to be determined entirely in favor of the mineral owner, our total acreage position, as of June 30, 2014, could decrease by a maximum of 4%. We are vigorously defending our position in this lawsuit.

Governmental regulations could adversely affect our business.

        Our business is subject to certain federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and natural gas, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste and other matters. These laws and regulations have increased the costs of our operations. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues. Laws and regulations

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relating to our business frequently change, and future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.

        In particular and without limiting the foregoing, various tax proposals currently under consideration could result in an increase and acceleration of the payment of federal income taxes assessed against independent oil and natural gas producers, for example by eliminating the ability to expense intangible drilling costs, removing the percentage depletion allowance and increasing the amortization period for geological and geophysical expenses. Any of these changes would increase our tax burden.

        The States of Texas and Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of these states limit the rate at which oil and gas can be produced from our properties. However, we do not believe we will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company.

Environmental liabilities could adversely affect our business.

        In the event of a release of oil, natural gas or other pollutants from our operations into the environment, we could incur liability for any and all consequences of such release, including personal injuries, property damage, cleanup costs and governmental fines. We could potentially discharge these materials into the environment in several ways, including:

    from a well or drilling equipment at a drill site;

    leakage from gathering systems, pipelines, transportation facilities and storage tanks;

    damage to oil and natural gas wells resulting from accidents during normal operations; and

    blowouts, cratering and explosions.

        In addition, because we may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination that we have not yet discovered relating to the acquired properties or any of our other properties.

        To the extent we incur any environmental liabilities, it could adversely affect our results of operations or financial condition.

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

        Our oil and natural gas exploration and production operations are subject to stringent and complex federal, regional, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of permits, including drilling permits, before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including

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administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations.

        There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations as a result of our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liabilities for the removal or remediation of previously released materials or property contamination. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. Changes in environmental laws and regulations occur frequently; for example, a number of state and regional legal initiatives have emerged in recent years that seek to reduce GHG emissions and the EPA, based on its findings that emissions of GHGs present a danger to public health and the environment, has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, restrict emissions of GHGs and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources in the United States on an annual basis, which includes certain of our operations. Any changes in legal requirements that restrict emissions or releases of GHGs or other pollutants or result in more stringent or costly well drilling, construction, completion or water management activities, or waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance, may reduce demand for the oil and gas we produce and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

Horizontal drilling activities could be subject to increased regulation and could expose us to environmental risks that could adversely affect us.

        Legislation relating to horizontal drilling activities that could impose new permitting disclosure or other environmental restrictions or obligations on our operations is currently being considered at the federal level, and may in the future be considered at the state or local level. In particular, the U.S. Congress recently signaled a renewed interest in certain downhole injection activities, some of which we utilize in our operations. The focus may lead to new legislation or regulations that could affect our operations. Any additional requirements or restrictions on our operations could result in delays, increased operating costs or a requirement to change or eliminate certain drilling and injection activities in a manner that may materially adversely affect us. In addition, because horizontal drilling involves fracture stimulation through the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production, it is also possible that our drilling and the fracturing process could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities.

We may be responsible for additional costs in connection with abandonment of properties.

        We are responsible for payment of plugging and abandonment costs on our oil and gas properties pro rata to our working interest. Based on our experience, we anticipate that the ultimate aggregate salvage value of lease and well equipment located on our properties will exceed the costs of abandoning such properties. There can be no assurance, however, that we will be successful in avoiding additional expenses in connection with the abandonment of any of our properties. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations.

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Our stock is categorized as a penny stock. Trading of our stock may be restricted by the SEC's penny stock regulations which may limit a stockholder's ability to buy and sell our stock.

        Our stock is categorized as a "penny stock". The SEC has adopted Rule 15g-9 which generally defines "penny stock" to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and accredited investors. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of our Common Stock.

FINRA sales practice requirements may also limit a stockholder's ability to buy and sell our stock.

        In addition to the "penny stock" rules described above, the Financial Industry Regulatory Authority ("FINRA") has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer's financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements make it more difficult for brokerdealers to recommend that their customers buy our Common Stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

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Cautionary Notice Regarding Forward-Looking Statements

        This Prospectus contains forward-looking statements. All statements, other than statements of historical facts, are forward-looking statements. These forward-looking statements relate to, among other things, the following: our future financial and operating performance and results; our business strategy; market prices; and our plans and forecasts.

        Forward-looking statements are identified by use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could" and similar words and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements. You should consider carefully the statements in the "Risk Factors" section and other sections of this Prospectus, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, including, but not limited to, the following factors:

    our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to service our debt and fully develop our undeveloped acreage positions;

    our ability to integrate our recently consummated acquisitions;

    the volatility in commodity prices for oil and natural gas;

    the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes);

    the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

    the ability to replace oil and natural gas reserves;

    lease or title issues or defects to our oil and gas properties;

    environmental risks;

    drilling and operating risks;

    exploration and development risks;

    competition, including competition for acreage in oil and natural gas producing areas;

    management's ability to execute our plans to meet our goals;

    our ability to retain key members of senior management;

    our ability to obtain goods and services, such as drilling rigs and other oilfield equipment, and access to adequate gathering systems and pipeline take-away capacity, to execute our drilling program;

    general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including that the United States economic slow-down might continue to negatively affect the demand for natural gas, oil and natural gas liquids;

    continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

    other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

        All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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BUSINESS

GENERAL

        Cubic Energy, Inc. is an independent energy company engaged in the development and production of, and exploration for, crude oil, natural gas and natural gas liquids. Our oil and gas assets are concentrated in Texas and Louisiana. At June 30, 2014, our total proved reserves were 135,071,173 Mcfe.

RECENT DEVELOPMENTS

        On July 14, 2014, we entered into an Amendment, Forbearance and Waiver Agreement (the "Amendment") with the holders of the Notes due October 2016 (the "Notes"), which were issued pursuant to a Note Purchase Agreement dated October 2, 2013, (the "Note Purchase Agreement"), and certain other parties thereto. The Company initially issued as aggregate of $66,000,000 of the Notes. The Notes originally bore interest at the rate of 15.5% per annum, in cash, payable quarterly; provided, however, that interest for the first six months following the closing was paid 7.0% per annum in cash and 8.5% per annum in additional Notes.

        Pursuant to the Amendment, the holders of the Notes waived various defaults specified in the Amendment, and the parties agreed to modify certain covenants in the Note Purchase Agreement. The holders of the Notes also waived their right to receive Default Interest and Registration Default Interest (as such terms are defined in the Note Purchase Agreement). In addition, the Amendment provides that after March 31, 2014, the interest rate applicable to the Notes is increased from 15.5% per annum to 20.5% per annum; provided that after such date interest shall not be payable in cash but shall accrue and compound on a quarterly basis.

        The Amendment includes an additional covenant requiring the Company, among other things, by no later than October 17, 2014, to enter into a definitive agreement with respect to a Strategic Transaction (as defined below) that is reasonably expected to be consummated no later than December 31, 2014. A Strategic Transaction includes a transaction resulting in the complete repayment of the Notes, or another transaction acceptable to the holders of the Notes. We continue to explore alternatives with respect to a Strategic Transaction, although we did not enter into a definitive agreement by October 17, 2014. We are in discussions with the holders of the Notes with respect to available alternatives. Unless the requirement regarding a Strategic Transaction is waived, or we obtain an extension of time, the holders of the Notes could declare a default under the Note Purchase Agreement, accelerate the indebtedness represented by the Notes and exercise all other remedies available to them, including foreclosing on our assets.

        The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note A to the financial statements, the Company has suffered recurring losses from operations and has a net working capital deficiency that raise substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

ASSETS

Legacy Louisiana Acreage

        Our corporate strategy with respect to our asset acquisition and development efforts was to position the Company in low risk opportunities while building mainstream high yield reserves. The acquisition of our acreage in DeSoto and Caddo Parishes, Louisiana, puts us in reservoir rich environments in the Hosston, Cotton Valley and Bossier/Haynesville Shale formations, with additional shallow formations to exploit as well. We have had success on our acreage with wells completed in the Hosston, Cotton Valley and Bossier/Haynesville Shale formations. We also own interests in the rights-of-way, infrastructure and pipelines for our Caddo and DeSoto Parish, Louisiana acreage.

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        We share our Cotton Valley and Bossier/Haynesville formation acreage with Goodrich Petroleum Corporation ("Goodrich"), Chesapeake Energy Corporation ("Chesapeake"), BHP Billiton Limited ("BHP Billiton"), EP Energy E&P Company, L.L.P. ("EP Energy"), BG US Production Company, LLC ("BG"), EXCO Operating Company, LP ("EXCO") and Indigo Minerals, LLC ("Indigo Minerals"), and all of these companies are third-party operators actively working on some of our shared acreage. Two new wells that came on line in the second half of fiscal 2014 helped boost production from our legacy Louisiana properties.

Legacy Texas Acreage

        Prior to our acquisition of properties in Leon and Robertson Counties, Texas described below, our Texas properties were situated in Eastland and Callahan Counties. These Texas properties consist primarily of wells acquired in several transactions between 1991 and 2002 and through overriding royalty interests reserved in farm-out agreements in 1998 and 1999. These wells produce limited amounts of natural gas and oil condensate.

Other Texas Acreage and Louisiana Working Interests

        In October 2013, we acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas, that puts us in the additional reservoir rich environments in the Eagle Ford, Woodbine, Austin Chalk, Buda, Glen Rose and Georgetown formations, with additional shallow formations to exploit as well. We also acquired additional rights in our leasehold interests in DeSoto and Caddo Parishes, Louisiana. The acquisitions summarized as follows:

    The Company consummated the transactions contemplated by the Purchase and Sale Agreement dated as of April 19, 2013 (the "Gastar Agreement") with Gastar Exploration Texas, LP ("Gastar") and Gastar Exploration USA, Inc. Pursuant to the Gastar Agreement, the Company acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The acquired properties include approximately 17,400 net acres of leasehold interests. The acquisition price paid by the Company at closing was $39,188,300, following various adjustments set forth in the Gastar Agreement, and net of the various deposits paid prior to the closing date. For purposes of allocating revenues and expenses and capital costs between Gastar and us, such amounts were netted effective January 1, 2013 and have been recorded as an adjustment to the purchase price.

    The Company also consummated the transactions contemplated by the Purchase and Sale Agreement dated as of September 27, 2013 (the "Navasota Agreement") with Navasota Resources Ltd., LLP ("Navasota"). Pursuant to the Navasota Agreement, the Company acquired proven reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The leasehold interests acquired consists of additional fractional interests in the properties acquired pursuant to the Gastar Agreement, comprising approximately 6,400 net acres. The acquisition price paid by the Company was $19,400,000, prior to certain post-closing adjustments.

    In addition, the Company entered into and consummated the transactions contemplated by a Purchase and Sale Agreement dated as of October 2, 2013 (the "Tauren Agreement") with Tauren Exploration, Inc. ("Tauren"), an entity controlled by Calvin A. Wallen, III, our Chairman of the Board, President and Chief Executive Officer ("Mr. Wallen"). Pursuant to the Tauren Agreement, the Company acquired well bores, proven reserves, oil & natural gas production and undeveloped leasehold interests in the Cotton Valley formation in DeSoto and Caddo Parishes, Louisiana. The acquired leasehold interests in the same leaseholds as our legacy Louisiana properties. The acquisition price paid by the Company was $4,000,000 in cash and 2,000 shares

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      of the Company's Series B Convertible Preferred Stock with an aggregate stated value of $2,000,000 and a fair value of $368,000. The Tauren Agreement was unanimously approved by the Company's board of directors, excluding Mr. Wallen.

        We have seen success on our acquired Texas acreage and Louisiana acreage with two wells drilled by EXCO achieving production from the Haynesville shale formation in Louisiana during fiscal 2014.

        The Texas legacy acreage, some of the Cotton Valley and Hosston formations in our legacy Louisiana acreage, and the Leon and Robertson Counties, Texas, acreage are operated by Fossil Operating, Inc. ("Fossil"), an entity controlled by Mr. Wallen.

HISTORY

        Our predecessor was incorporated in October 1978. Cubic was incorporated in 1999 in the State of Texas. Our principal executive office is located at 9870 Plano Road, Dallas, Texas 75238, and our telephone number is (972) 686-0369.

        On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital, Inc. ("WFEC") providing for a revolving credit facility of $20,000,000 and a convertible term loan of $5,000,000 (the "Credit Facility"). In connection with entering into the Credit Facility, the Company issued to WFEC warrants, with five-year expirations, for the purchase of up to 2,500,000 shares of Company Common Stock at an original exercise price of $1.00 per share. On December 18, 2009, the Company entered into a Second Amendment to Credit Agreement with WFEC, providing for a revolving credit facility of up to $40,000,000 subject to borrowing base limits and a convertible term loan of $5,000,000 (the "Amended Credit Agreement"). In connection with entering into the Amended Credit Agreement, the Company issued to WFEC additional warrants, expiring on December 1, 2014, for the purchase of up to 5,000,000 shares of Company Common Stock at an exercise price of $1.00 per share, and extended the expiration date of the warrants to purchase 2,500,000 shares of Company Common Stock that were previously issued to WFEC to December 1, 2017. In connection with the amendment, warrants held by WFEC, which are convertible into 8.5 million shares of the Company's Common Stock, were modified to provide for an exercise price of $0.20 per share and a termination date of December 1, 2017.

        On November 24, 2009, the Company entered into transactions with Tauren and Langtry Mineral & Development, LLC ("Langtry"), both of which are entities controlled by Mr. Wallen, under which the Company acquired $30,952,810 in pre-paid drilling credits (the "Drilling Credits") applicable towards the development of its Haynesville Shale rights in Northwest Louisiana. As consideration for the Drilling Credits, the Company (a) conveyed to Tauren a net overriding royalty interest of approximately 2% in its leasehold rights below the Taylor Sand formation of the Cotton Valley and (b) issued to Langtry 10,350,000 Company common shares and Series A Convertible Preferred Stock in the amount of $10,350,000, which was convertible at any time prior to the fifth anniversary of issuance into Company common shares at $1.20 per common share. The preferred stock was entitled to cumulative dividends equal to 8% per annum, payable quarterly.

        On December 18, 2009, the Company issued a subordinated promissory note payable to Mr. Wallen, in the principal amount of $2,000,000 (the "Wallen Note"). This note provided for interest at the prime rate plus one percent (1%). The proceeds of the Wallen Note were used to repay a previously outstanding promissory note.

        As of June 30, 2012, the Company used the Drilling Credits to fund $21,435,551 of its share of the drilling and completion costs for those horizontal Haynesville Shale wells drilled in sections previously operated by Fossil which are now operated by third parties. As of June 30, 2012 a total of $9,517,258 of the Drilling Credits remained. The counterparties (EXCO and BG) on the Drilling Credits asserted certain offsets against their obligations under the Drilling Credits. On September 12, 2012, we received

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a final judgment with respect to an arbitration award of approximately $12,800,000 from EXCO and BG.

        On October 2, 2012, the Company entered into a Settlement Agreement and Mutual Release with Tauren, EXCO and BG. This agreement provides that EXCO and BG shall (a) apply the Drilling Credits as provided in the agreement and place the Company in consent status in, which the Company gets paid for production on specified wells and (b) pay to the Company $12,179,853 in cash. The agreement also provides for mutual releases among the parties. Pursuant to the Fourth Amendment to Credit Agreement between the Company and WFEC, $9,134,890 of such amount was paid to WFEC when received from EXCO and BG in order to reduce the borrowings under the Company's revolving credit facility with the balance of the cash received by the Company.

        On October 2, 2013, the Company entered into the Note Purchase Agreement, pursuant to which the Company issued an aggregate of $66,000,000 of Notes to certain purchasers. The Notes originally bore interest at the rate of 15.5% per annum, in cash, payable quarterly; provided, however, that interest for the first six months following the closing was paid 7.0% per annum in cash and 8.5% per annum in additional Notes. As described under "Recent Developments", certain terms of the Note Purchase Agreement, including the interest rate, were modified as of March 31, 2014. The indebtedness under the Note Purchase Agreement is secured by substantially all of the assets of the Company, including a first priority lien over all of the assets of the Company, Cubic Asset and Cubic Asset Holding and a second priority lien over all of the assets of Cubic Louisiana and Cubic Louisiana Holding.

        On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Call Option Structured Derivative arrangement with a third party that resulted in the receipt of an upfront payment at closing of approximately $35,000,000, through the sale of calls, which upfront payment approximated fair value of the calls sold at inception. As a result, the Call Option Structured Derivative arrangement was initially recognized and measured at the amount of its upfront payment. Under the terms of the Call Option Structured Derivative arrangement, Cubic Asset sold calls to the third party covering (i) approximately 556,000 barrels of oil at a strike price set between $80 per barrel and $90 per barrel, and (ii) approximately 51.3 million MMBtu's of gas at a strike price set between $3.45 per MMBtu and $3.90 per MMBtu. The scheduled volumes subject to the calls sold relate to production months from November 2013 through December 2018. The Company is subject to the price risks associated with product price changes that are in excess of the specified call prices.

        On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Fixed Price Swap arrangement. Under the terms of the Fixed Price Swap arrangement, Cubic Asset will receive a fixed amount on approximately 18,000 barrels of oil at a price of $92 per barrel. The scheduled volumes subject to the swaps relate to production months from November 2013 through October 2016. Cubic Asset is subject to the price risks associated with product price increases above the specified fixed prices. The counterparties to this arrangement have a junior lien position on both of the assets of Cubic Asset and Cubic Louisiana.

        In connection with the issuance and sale of the Notes under the Note Purchase Agreement, the Company issued certain warrants and shares of Series C Redeemable Voting Preferred Stock, par value $0.01 per share (the "Series C Redeemable Voting Preferred Stock"), to certain purchasers of the Notes and their affiliates (the "Investors"). The Company issued warrants exercisable for (a) an aggregate of 65,834,549 shares of Common Stock, at an exercise price of $0.01 per share (the "Class A Warrants"), and (b) an aggregate of 32,917,274 shares of Common Stock, at an exercise price of $0.50 per share (the "Class B Warrants" and together with the Class A Warrants, the "Warrants").

        The Company also issued an aggregate of 98,751.823 shares of Series C Redeemable Voting Preferred Stock to the Investors. The holders of the Series C Redeemable Voting Preferred Stock are entitled to vote, together with holders of Common Stock, as a single class with respect to all matters

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presented to holders of Common Stock of the Company. The holders of Series C Redeemable Voting Preferred Stock are entitled, in the aggregate, to a number of votes equal to the number of shares of Common Stock that would be issuable upon the exercise of all outstanding Warrants on a Full Physical Settlement basis (as defined in the Warrant and Preferred Stock Agreement). The holders of Series C Redeemable Voting Preferred Stock are not entitled to receive any dividends from the Company. Shares of the Series C Redeemable Voting Preferred Stock have a stated value of $0.01 per share and may be redeemed at the option of the holders thereof at any time.

        In connection with entering into the Note Purchase Agreement and the Warrant and Preferred Stock Agreement, the Company entered into an Investment Agreement, dated as of October 2, 2013, with the Investors, pursuant to which the Investors have the right to designate three members (subject to adjustment for changes in board size) for election or appointment to the Company's board of directors and certain information rights, veto rights, pre-emptive rights and sale rights, among others.

        The Investors and Mr. Wallen also entered into a Voting Agreement, dated as of October 2, 2013 (the "Voting Agreement"), pursuant to which Mr. Wallen has agreed to vote shares of voting securities of the Company beneficially owned by him in favor of the Investors' designees to the board of directors of the Company and with the Investors in connection with certain other matters. Mr. Wallen has also agreed not to transfer shares of voting securities of the Company beneficially owned by him unless certain conditions specified in the Voting Agreement are satisfied.

        In connection with entering into the Note Purchase Agreement and the Warrant and Preferred Stock Agreement, the Company entered into a Registration Rights Agreement, dated as of October 2, 2013, with the Investors, providing for, among other things, the registration of shares of Common Stock issuable upon exercise of the Warrants with the Securities and Exchange Commission.

        The Company entered into and consummated the transactions contemplated by a Conversion and Preferred Stock Purchase Agreement dated October 2, 2013 (the "Conversion Agreement") with Mr. Wallen and Langtry. Pursuant to the terms of the Conversion Agreement, (a) Langtry was issued 12,047 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $12,047,000, in exchange for the cancellation of all of the issued and outstanding shares of Series A Convertible Preferred Stock held by Langtry and (b) Mr. Wallen was issued 2,115 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $2,115,000, in exchange for the cancellation of a promissory note payable to Mr. Wallen in the principal amount of $2,000,000, plus $114,986 of accrued and unpaid interest.

        The Series B Convertible Preferred Stock is entitled to dividends at a rate of 9.5% per annum and, subject to certain limitations, is convertible into Common Stock at an initial conversion price of $0.50 per share of Common Stock. The holders of the Series B Convertible Preferred Stock are entitled to vote (on an as-converted basis), together with holders of Common Stock, as a single class with respect to all matters presented to holders of Common Stock.

        Cubic Louisiana and WFEC entered into an Amended and Restated Credit Agreement dated October 2, 2013 (the "Credit Agreement"). In conjunction with entering into the Credit Agreement, the Company assigned all of its previously held oil and gas interests that it held in Northwest Louisiana to Cubic Louisiana. Pursuant to the terms of the Credit Agreement, the Company repaid the $5 million term loan payable to WFEC, and Cubic Louisiana assumed the remaining unpaid debt to WFEC, which amount was $20,865,110 as of that date. That debt is reflected in a term loan bearing interest at the Wells Fargo Bank prime rate, plus 2%, per annum. In the event that Cubic Louisiana does not have available cash to pay interest on the Credit Facility, accrued and unpaid interest may be paid in kind via additional promissory notes. Accrued and unpaid interest as of June 30, 2014 was paid in kind. As part of the Credit Agreement, WFEC is providing a revolving credit facility in the amount of up to $10,000,000, bearing interest at the same rate, with all advances under that revolving credit facility to be made in the sole discretion of WFEC. The indebtedness to WFEC pursuant to the Credit

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Agreement is secured by a first priority lien over all of the assets of Cubic Louisiana and Cubic Louisiana Holdings. The other oil and gas properties of Cubic and its other subsidiaries, including the assets acquired from Gastar, Navasota and Tauren, as described above, do not secure the indebtedness under the Credit Agreement. During fiscal 2014, Cubic Louisiana borrowed $4,015,826 against the WFEC revolving credit facility to finance participation in two new horizontal Haynesville wells drilled and completed by EXCO in our legacy Louisiana acreage. Leaving a balance of $5,894,174 available to the Company under its revolving credit facility, subject to the approval of WFEC, and a total debt outstanding of $24,880,936 with WFEC.

STRATEGY

        As of June 30, 2014, our strategy with respect to our domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk, field extension wells to the smaller scale pursuit of Company appropriate higher risk, high reserve potential prospects.

        Our acquisition of East Texas assets is at the core of our current strategy, which we believe provides lower risk development opportunities and high yield opportunities. The Company is exploring acquiring additional properties with this same development profile.

        Additionally, our focus is on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. We develop prospects in-house with an affiliate and through strategic alliances with exploration companies that have expertise in specific target areas. In addition, we evaluate externally generated prospects and look to participate in certain of these opportunities to enhance our portfolio.

        We are currently focusing our domestic exploration activities to develop and re-enter existing well bores, and re-complete existing well bores with respect to our recently acquired East Texas Basin assets; as well as developing our recently augmented leasehold interests in Louisiana. East Texas Basin prospects have been developed from the top of the Cretaceous formation all the way to the bottom of the Deep Bossier Shale. The various Cretaceous zones all have strong oil and liquids component that we believe will help the Company achieve its transition away from dry natural gas. The high production of dry natural gas from the various Bossier sands have the opportunity to provide the Company an increase in short term cash flow, with reasonable out-of-pocket expenditures, even at current commodity prices, through the re-recompletion and work over of existing wells. Prospects in our Louisiana leaseholds are focused on the Cotton Valley and the Haynesville Shale, but also include the Hosston; Gloyd; Pettet; Glen Rose and Paluxy.

        The Company's future results of operations and growth are substantially dependent upon (i) its ability to acquire or find new oil and gas properties, or successfully develop existing oil and gas properties, (ii) the prevailing prices for oil and gas. Numerous locations have been identified by third-party operators for additional drilling, and (iii) our ability to refinance the Notes and remain a going concern. If we are unable to economically complete additional producing wells, the Company's oil and gas production, and its revenues, would likely decline rapidly as its reserves are depleted. In addition, oil and gas prices are dependent upon numerous factors beyond the Company's control, such as economic, political, governmental, environmental and regulatory developments, as well as competition from other sources of energy. The oil and gas markets have historically been very volatile, and any further significant or extended decline in the price of gas would have a material adverse effect on the Company's financial condition and results of operations, and could result in a further reduction in the carrying value of the Company's proved reserves and adversely affect its access to capital.

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PRINCIPAL OIL AND GAS PROPERTIES

        The following table summarizes certain information with respect to our principal areas of operation at June 30, 2014:

Category
  Oil
(Bbls)
  Natural Gas
Liquids
(Bbls)
  Natural Gas
(Mcf)
  Total Gas
Equivalent
(Mcfe)(a)
  Estimated
Future Net
Cash Flows
  After
10% Discount
 

Proved Producing

                                     

Louisiana

    1,592     9,117     5,484,637     5,548,891   $ 13,929,700   $ 9,889,700  

Texas

    51,491     0     33,307,899     33,616,845     90,894,378     54,202,350  
                           

Total Proved Producing

    53,083     9,117     38,792,536     39,165,736     104,824,078     64,092,050  

Proved Non-Producing

                                     

Louisiana

                         

Texas

    1,678         51,549,622     51,559,690     147,595,900     71,891,200  
                           

Total Proved Non-Producing

    1,678         51,549,622     51,559,690     147,595,900     71,891,200  

Total Proved Developed Reserves

   
 
   
 
   
 
   
 
   
 
   
 
 

Louisiana

    1,592     9,117     5,484,637     5,548,891     13,929,700     9,889,700  

Texas

    53,169         84,857,521     85,176,535     238,490,278     126,093,550  
                           

Total Proved Developed

    54,761     9,117     90,342,158     90,725,426   $ 252,419,978   $ 135,983,250  
                           
                           

Proved Undeveloped

                                     

Louisiana

    466,926     893,884     32,535,438     40,700,298     30,925,300     318,300  

Texas

            3,645,449     3,645,449     2,390,600     291,300  
                           

Total Proved Undeveloped

    466,926     893,884     36,180,887     44,345,747   $ 33,315,900   $ 609,600  
                           
                           

Total Proved Reserves

                                     

Louisiana

    468,518     903,001     38,020,075     46,249,189   $ 44,855,000   $ 10,208,000  

Texas

    53,169         88,502,970     88,821,984     240,880,878     126,384,850  
                           

Total Proved Reserves

    521,687     903,001     126,523,045     135,071,173   $ 285,735,878   $ 136,592,850  
                           
                           

(a)
Mcfe is defined as 1 Bbl of oil to 6 Mcf of natural gas.

        As of June 30, 2014, our West Texas properties are situated in Eastland and Callahan Counties and represented an immaterial amount of reserves and are excluded from our SEC reserve report. Our East Texas properties are situated in Leon and Robertson Counties and contained approximately 66% of our total proved reserves, while our Louisiana properties that are situated in Caddo Parish and in DeSoto Parish contained approximately 34% of our total proved reserves. The West Texas properties owned as of June 30, 2014, consisted primarily of wells acquired by the Company in several transactions between 1991 and 2002 and through overriding royalty interests reserved in farm-out agreements in 1998 and 1999. The East Texas properties were acquired in October 2013. The vast majority of the legacy Louisiana acreage were acquired on or about October 1, 2004, January 11, 2005 and February 6, 2006.

        Our net production for the fiscal year ended June 30, 2014 for all of the Company's wells averaged approximately 11,080 Mcf of natural gas per day, 28 barrels of oil per day and 7 barrels of natural gas liquids per day as compared to approximately 3,127 Mcf of natural gas per day, 2 barrels of oil per day and 7 barrels of natural gas liquids per day in the fiscal year ended June 30, 2013.

GAS GATHERING

        Cubic has developed its infrastructure in Johnson Branch with approximately 16 miles of gathering lines and pipeline constructed for its currently producing wells and any further completions. In

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addition, a Johnson Branch tap, common point and compression facility were completed in November 2007 and are currently operational. The Company has also developed its infrastructure with approximately 7.8 miles of gathering lines and owns three taps in its Bethany Longstreet acreage.

        In addition, for our East Texas properties, we have a midstream contract with Hilltop Resort GS, LLC that runs through October 31, 2024. This contract with Hilltop Resort GS, LLC has a penalty provision expiring on October 31, 2014, if, for the previous quarter, an average of 50,000 Mcf/day is not sent through the pipelines. Since the acquisitions on October 2, 2013, the Company has had to pay a quarterly penalty due to insufficient production. As of June 30, 2014, the Company accrued an obligation of $976,494 related to this contract.

MARKETING OF PRODUCTION

Crude Oil and Natural Gas

        During fiscal 2014, our production consisted mainly of natural gas. During fiscal 2014, we marketed our production of natural gas that was produced from wells operated by our affiliate, Fossil Operating ("Fossil"), an entity controlled by Mr. Wallen, to four purchasers: (i) in Texas, BP Energy Company ("BP Energy"), Peninsula Pipelines ("Peninsula") and Regency Energy Partners ("Regency"), and (ii) in Louisiana, Atmos Energy Marketing, LLC ("Atmos Energy"). We sell our affiliate-operated crude oil and natural gas liquids ("NGL") production at or near the well-site; although in some cases it is gathered by us or others and delivered to a central point of sale. Our crude oil and condensate production is transported by truck or by pipeline and is marketed by BP Products North America ("BP Products"), Transoil Marketing, Inc. ("Transoil"), Eastex Crude Company ("Eastex"), and Martin Gas Sales ("Martin"). During fiscal 2014, all of our production was operated by Fossil and six third-party operators: BG, Chesapeake, EXCO, EP Energy, Goodrich and Indigo Minerals. Pursuant to the terms of our operating agreements, these third-party operators have the right to market our production from wells operated by them. Purchases by BP Energy through Fossil totaled 81% of our total revenues for fiscal 2014. A significant portion of our production and our revenue is now generated by wells drilled and operated by non-affiliated third-party operators.

        With respect to our production from Louisiana, we did not have any gas marketing agreements, commitments or contracts; we sell our crude oil, NGL and natural gas at the prevailing market prices.

        As for our East Texas production, our hedging agreements with BP dictate that BP purchases all of our oil and natural gas through the calendar year 2016 for oil and through the calendar year 2018 for natural gas. We receive from BP a fixed price for the respective commodity up to certain volumes pursuant to the derivative contracts. We then receive a floating market price for volumes in excess of such amounts bound by the derivative contracts.

        We believe we would be able to locate alternate purchasers in the event of the loss of any of these purchasers, and that any such loss would not have a material adverse effect on our financial condition or results of operations. Revenue totaled $15,849,482 for fiscal 2014 primarily from the sale of natural gas. Natural gas totaled $14,750,152 and represented 93%, oil totaled $977,880 and represented 6% and NGLs totaled $121,450 and represented 1% of our total oil and gas revenues, respectively for fiscal 2014.

Price Considerations

        Natural gas and NGL prices in the geographical areas in which we operate are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMbtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX ("NYMEX-Henry Hub"). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price our natural gas. Average natural gas prices received by us in each of our

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operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us in fiscal 2014 was $3.65 as compared to $3.21 in fiscal 2013. The average NGL price per barrel received by us in fiscal 2014 was $45.78 compared to $41.16 in fiscal 2013. Crude oil prices are established in a highly liquid, international market, with average crude oil prices that we receive generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil ("NYMEX-WTI"). The average crude oil price per barrel received by us in fiscal 2014 was $95.58 as compared to $90.00 in fiscal 2013.

OIL AND GAS RESERVES

        The following tables set forth our proved developed and proved undeveloped reserves at June 30, 2014, the estimated future net cash flows from such proved reserves and the Standardized Measure of Discounted Future Net Cash Flows attributable to our proved reserves at June 30, 2014, 2013 and 2012:

 
  At June 30,  
 
  2014   2013   2012  

Proved Developed Reserves:

                   

Oil (Bbls)

    54,761     1,835     443  

Natural Gas Liquids (Bbls)

    9,117     11,205     35  

Gas (Mcf)

    90,342,158     4,899,388     3,982,265  
               

Mcfe

    90,725,426     4,977,628     3,985,203  

Estimated future net cash flows (before income tax)

 
$

252,419,978
 
$

8,852,800
 
$

6,827,246
 

Standardized Measure

  $ 135,983,250   $ 6,075,300   $ 5,504,209  

Proved Undeveloped Reserves:

   
 
   
 
   
 
 

Oil (Bbls)

    466,926     393,673     427,190  

Natural Gas Liquids (Bbls)

    893,884     1,624,269     1,313,531  

Gas (Mcf)

    36,180,887     28,092,172     19,357,720  
               

Mcfe

    44,345,747     40,199,824     29,802,000  

Estimated future net cash flows (before income tax)

 
$

33,315,900
 
$

79,982,200
 
$

62,895,890
 

Standardized Measure

  $ 609,600   $ 32,972,500   $ 24,472,000  

Total Proved Reserves:

   
 
   
 
   
 
 

Oil (Bbls)

    521,687     395,508     427,633  

Natural Gas Liquids (Bbls)

    903,001     1,635,474     1,313,566  

Gas (Mcf)

    126,523,045     32,991,560     23,339,985  
               

Mcfe

    135,071,173     45,177,452     33,787,203  

Estimated future net cash flows (before income tax)

 
$

285,735,878
 
$

88,835,000
 
$

69,723,136
 

Standardized Measure of Discounted Future Net Cash Flows(1)

  $ 136,592,850   $ 39,047,800   $ 29,976,209  

Average price used to calculate reserves:

   
 
   
 
   
 
 

Oil (Bbl)

  $ 97.51   $ 85.13   $ 96.59  

Natural Gas Liquids (Bbls)

  $ 47.66   $ 54.99   $ 47.46  

Gas (Mcf)

  $ 4.01   $ 3.62   $ 3.25  

(1)
The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net cash flows from the production of proved reserves, without giving effect to the future income tax expense. In accordance with guidelines of the SEC, prices used in this Prospectus are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the fiscal year. See "Note M—Oil and gas reserves information (unaudited)" in the Notes to the Consolidated Financial Statements of the Company for the years ended June 30, 2014 and 2013 included elsewhere in this Prospectus for additional information regarding the disclosure of the Standardized Measure information in accordance with the provisions of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 932, Extractive Activities—Oil and Gas.

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        As of June 30, 2014, we had a net increase in proved undeveloped reserves of 4,145,923 Mcfe. This net increase includes (i) an increase of 4,706,416 Mcfe due to an "Extensions & Discoveries" gained through overall field development and activity and longer range Company planning, plus (ii) an increase of 24,280,352 Mcfe gained through the acquisition of the Tauren Louisiana Cotton Valley acreage and the existing East Texas proved undeveloped location acquired from Gastar partially offset by (iii) a downward "Revision of Previous Estimates" of 21,911,480 Mcfe due to wells not being drilled and dropping off of our drilling schedule and (iv) a downward revision of 2,929,365 Mcfe in estimated production from continuing Proved Undeveloped locations.

        None of our reserves were converted from proved undeveloped reserves to proved developed reserves during the fiscal year ended June 30, 2014. EXCO drilled and completed two new Haynesville Shale wells in fiscal 2014; however, neither of these drilling locations were proved undeveloped locations at June 30, 2013. The Company did not have any Haynesville Shale proved undeveloped locations at June 30, 2013. These two EXCO wells are now proved producing reserves.

        In compliance with Rule 4-10(a)(31)(ii) of Regulation S-X, the Company's development plan for all reserves listed as proved undeveloped reserves includes only planned development and drilling within sixty months of initial disclosure of such reserves. All of these wells are expected to be operated by an affiliate of the Company.

        The information set forth in this Prospectus relating to our proved reserves, estimated future net cash flows and present values is taken from reports prepared by Netherland, Sewell & Associates, Inc. ("NSAI") for the fiscal years 2014 and 2013. The report for fiscal 2012 was prepared by NPC Engineering Group, Inc. ("NPC-ENG"), an independent petroleum engineering firm. The reservoir engineers at NSAI and NPC-ENG who oversaw the preparation of the reserve estimates for NSAI and NPC-ENG had Master's of Science Degrees and are licensed as Professional Engineers in the State of Texas. The estimates of the independent petroleum engineering firms were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company. Information with respect to our reserves in legacy Texas properties as of June 30, 2014, 2013 and 2012 was prepared in-house, was not reviewed by an independent engineering firm, and due to the immaterial size was not reported in our reserve report for the periods ended June 30, 2014, 2013 and 2012. Our internal geologist has a Master's of Science Degree in Geology, is an American Association of Petroleum Geologists' Certified Petroleum Geologist and has twenty-nine years of experience in the upstream oil and gas industry. In accordance with guidelines of the SEC, prices used in this Prospectus are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the fiscal year. For oil volumes, the average West Texas Intermediate posted price of $96.75 per barrel is adjusted by field for quality, transportation fees, and a regional price differential. For gas volumes, the average Henry Hub spot price of $4.10 per MMbtu is adjusted by field for energy content, transportation fees, and a regional price differential. All prices are held constant throughout the lives of the properties. For the proved reserves, the average adjusted product prices for fiscal 2014 weighted by production over the remaining lives of the properties are $97.51 per barrel of oil, $47.66 per barrel of NGL, and $4.01 per Mcf of gas, but such costs do not include debt service or general and administrative expenses.

        There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. The reserve data set forth in this prospectus represents estimates only. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development, exploitation and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from

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the quantities of oil and gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. There can be no assurance that these estimates are accurate predictions of our oil and gas reserves or their values. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves.

        All reports were in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

        Our policies and practices regarding internal control over the estimating of reserves are structured to objectively and accurately estimate our oil and natural gas reserves quantities and present values in compliance with the SEC's regulations and U.S. Generally Accepted Accounting Principles. We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent petroleum consultant to ensure the integrity, accuracy and timeliness of data furnished to our independent petroleum consultant in its reserves estimation process. Inputs to our reserves estimation process are based on historical results for production history, oil and natural gas prices, lease operating expenses, development costs, ownership interest and other required data. Our technical team meets regularly with representatives of our independent petroleum consultants to review properties and discuss methods and assumptions used in our independent petroleum consultant's preparation of the year-end reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves our independent petroleum engineer's reserve report and any internally estimated significant changes to our proved reserves on a timely basis.

Costs Incurred

        The following table shows certain information regarding the costs incurred by us in our property acquisition, development and exploratory activities during the periods indicated.

 
  Year Ended June 30,  
 
  2014   2013   2012  

Property acquisition costs

                   

Louisiana

  $ 26,946,000   $ 178,685   $ 109,076  

Texas

    62,578,148          

Exploratory costs

                   

Louisiana

             

Texas

             

Development costs

                   

Louisiana

    6,537,062     (290,569 )   8,224,013  

Texas

    2,860,692          

Total by State

                   

Louisiana

    33,483,062     (111,884 )   8,333,089  

Texas

    65,438,840          
               

Total

  $ 98,921,902   $ (111,884 ) $ 8,333,089  
               
               

        The Company received several credits from EXCO during fiscal 2013 thus creating negative total costs incurred for the year ended June 30, 2013.

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FISCAL 2014 DRILLING

        During fiscal 2014, EXCO drilled and completed two wells, both of which are in the Haynesville Shale formation in which the Company has interests.

        We drilled or participated in the drilling of wells as set out in the table below for the periods indicated. The table was completed based upon the date drilling was completed. Other than the East Texas properties in Leon and Robertson Counties (the "Hilltop"), we did not acquire any wells during these periods. You should not consider the results of prior drilling activities as necessarily indicative of future performance, nor should you assume that there is necessarily any correlation between the number of productive wells drilled and the oil and natural gas reserves generated by those wells.

 
  Year Ended June 30,  
 
  2014   2013   2012  
 
  Gross   Net   Gross   Net   Gross   Net  

Development wells:

                                     

Louisiana

    2     0.25     3     0.04     1      

Texas

                             
                           

Productive

    2     0.25     3     0.04     1      
                           

Louisiana

                         

Texas

                         
                           

Dry

                         
                           

Total development

    2     0.25     3     0.04     1      
                           
                           

Exploratory wells:

                                     

Louisiana

                         

Texas

                             
                           

Productive

                         
                           

Louisiana

                         

Texas

                         
                           

Dry

                         
                           

Total exploratory

                         
                           
                           

Total wells:

                                     

Louisiana

    2     0.25     3     0.04     1      

Texas

                             
                           

Productive

    2     0.25     3     0.04     1      
                           

Louisiana

                         

Texas

                         
                           

Dry

                         
                           

Total wells

    2     0.25     3     0.04     1      
                           
                           

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NET PRODUCTION, SALES PRICES AND COSTS

        The following table presents certain information with respect to production, prices and costs attributable to all oil and gas property interests owned by us for the fiscal years ended June 30, 2014, 2013 and 2012:

 
  Year ended June 30,  
 
  2014   2013   2012  

Operating Data:

                   

Proved Reserves (Bcfe)

    135.1     45.2     33.8  

Production (Mcfe)

    4,121,418     1,161,802     2,258,577  

Producing wells at end of period, gross

    97     64     60  

Producing wells at end of period, net

    53.25     31.41     13.52  

Acreage, gross

    53,225     13,123     13,123  

Acreage, net

    31,692     5,100     5,100  

Production:

   
 
   
 
   
 
 

Oil (Bbl)

    10,231     863     1,100  

Natural gas (Mcf)

    4,044,085     1,141,474     2,244,315  

Natural gas liquids (Bbl)

    2,658     2,525     1,277  

Total oil, gas and liquids (Mcfe)

    4,121,418     1,161,802     2,258,577  

Average daily (Mcfe)

    11,292     3,183     6,188  

Weighted Average Sales Prices:

   
 
   
 
   
 
 

Oil (per Bbl)

  $ 95.58   $ 90.00   $ 93.25  

Natural gas (per Mcf)

  $ 3.65   $ 3.21   $ 3.01  

Natural gas liquids (per Bbl)

  $ 45.78   $ 41.16   $ 66.78  

Natural gas equivalent (per Mcfe)

  $ 3.85   $ 3.31   $ 3.07  

Selected Expenses per Mcfe:

   
 
   
 
   
 
 

Production costs

  $ 0.71   $ 0.65   $ 0.43  

Workover expenses (non-recurring)

  $ 0.18   $ 0.04   $ 0.07  

Severance taxes

  $   $ 0.16   $ (0.06 )

Other revenue deductions

  $ 1.30   $ 0.76   $ 0.43  
               

Total lease operating expenses

  $ 2.19   $ 1.61   $ 0.87  

General and administrative expenses:

   
 
   
 
   
 
 

Non-cash stock-based compensation

  $ 0.01   $ 0.05   $ 0.10  

Other general and administrative

  $ 1.51   $ 1.96   $ 1.48  
               

Total general and administrative

  $ 1.52   $ 2.01   $ 1.58  

Depreciation, depletion and amortization

 
$

1.89
 
$

2.80
 
$

2.70
 

        We had two fields that exceeded 15% of our total Proved Reserves as of June 30, 2014 and one field that exceeded 15% as of June 30, 2013. Our Johnson Branch field represented approximately 31%, 57% and 95% of our total Proved Reserves as of June 30, 2014, 2013 and 2012, respectively. Our Hilltop field represented 66% of our total Proved Reserves as of June 30, 2014.

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        The following table provides additional information related to production from those fields:

 
  Year Ended June 30,  
 
  2014   2013   2012  

Johnson Branch field—Louisiana

                   

Oil (Bbl)

    374     223     629  

Average price (per Bbl)

  $ 100.27   $ 88.47   $ 96.64  

Natural gas production sold (Mcf)

   
410,562
   
649,132
   
1,271,948
 

Average price (per Mcf)

  $ 4.16   $ 3.20   $ 2.91  

NGL's per (Bbl)

   
1,373
   
1,048
   
1,277
 

Average price (per Bbl)

  $ 33.65   $ 55.77   $ 66.78  

Average production cost (per Mcfe) (excluding severance and ad valorem taxes)

  $ 1.55   $ 1.58   $ 0.69  

 

 
  Year Ended June 30,  
 
  2014   2013   2012  

Caspiana field—Louisiana

                   

Oil (Bbl)

             

Average price (per Bbl)

  $   $   $  

Natural gas production sold (Mcf)

   
   
   
 

Average price (per Mcf)

  $   $   $  

NGL's per (Bbl)

   
1,285
   
   
 

Average price (per Bbl)

  $ 45.31   $   $  

Average production cost (per Mcfe) (excluding severance and ad valorem taxes)

  $ 2.24   $   $  

 

 
  Year Ended June 30,  
 
  2014   2013   2012  

Bethany Longstreet field—Louisiana

                   

Oil (Bbl)

             

Average price (per Bbl)

  $   $   $  

Natural gas production sold (Mcf)

   
742,494
   
   
 

Average price (per Mcf)

  $ 4.27   $   $  

NGL's per (Bbl)

   
   
   
 

Average price (per Bbl)

  $   $   $  

Average production cost (per Mcfe) (excluding severance and ad valorem taxes)

  $ 1.14   $   $  

 

 
  Year Ended June 30,  
 
  2014   2013   2012  

Hilltop—Texas

                   

Oil (Bbl)

    9,347          

Average price (per Bbl)

  $ 95.47   $   $  

Natural gas production sold (Mcf)

   
2,824,826
   
   
 

Average price (per Mcf)

  $ 3.42   $   $  

NGL's per (Bbl)

               
 

Average price (per Bbl)

  $   $   $  

Average production cost (per Mcfe) (excluding severance and ad valorem taxes)

  $ 2.53   $   $  

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PRODUCTIVE WELLS AND ACREAGE

Productive Wells

        The following table sets forth our productive wells at June 30, 2014:

 
  Oil   Gas   Total  
State
  Gross   Net   Gross   Net   Gross   Net  

Louisiana

            52.00     19.78     52.00     19.78  

Texas

    10.00     9.75     35.00     23.72     45.00     33.47  
                           

Total Wells

    10.00     9.75     87.00     43.50     97.00     53.25  
                           
                           

        The East Texas properties had 18 wells producing oil during fiscal 2014, eight of those wells were determined to be non-economical and probably will be scheduled for shut-in, leaving the Company 10 wells producing oil in economic quantities, at June 30, 2014. The Company had two new natural gas wells drilled and completed on our Louisiana acreage during fiscal 2014. The Company had four new natural gas wells approved to drill and complete on our Louisiana acreage during fiscal 2015. One is being drilled but not yet completed the other three are schedule to be drill during the second quarter of fiscal 2015 and completed in the early part of the third quarter of fiscal 2015.

Acreage

        The following table sets forth our undeveloped and developed gross and net leasehold acreage at November 21, 2014. The Louisiana undeveloped leasehold acreage is made up of alternate unit well sites that are part of our future drilling plan and currently have at least one well drilled and completed, so all of our acreage is held-by-production. Our East Texas acreage is approximately 40% held-by-production. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

 
  Undeveloped   Developed   Total  
State
  Gross   Net   Gross   Net   Gross   Net  

Louisiana

    17,846     7,284     6,296     2,570     24,142     9,854  

East Texas

    26,979     11,658     10,951     10,384     37,930     22,042  
                           

Total Acres

    44,825     18,942     17,247     12,954     62,072     31,896  
                           
                           

        As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights.

        The Company engaged in the Cotton Valley vertical drilling program on its Northwest Louisiana acreage during 2005 through 2009. In the last 24 months, it has been shown that a more economical way to exploit the Cotton Valley in and around our Northwest Louisiana acreage is to drill and complete well bores directed horizontally. Generally, each square mile unit, or section, is economically capable of eight horizontally developed Cotton Valley well bores. Based on current development in and around our acreage, we take a more conservative approach and project four horizontally developed Cotton Valley wells in each section. Horizontal development of the Cotton Valley has achieved significantly higher ultimate recoveries of dry gas plus a good recovery of oil, while vertical development provides only a modest recovery of dry gas. Therefore, our strategy with respect to development of our acreage in the Cotton Valley is through horizontal exploitation.

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        Substantially all of the Company's acreage is prospective for horizontal Haynesville Shale development. Generally, each section is economically capable of eight horizontally developed Haynesville Shale wells. Unlike the Cotton Valley formation, which provides a good recovery of oil when exploited horizontally, the Hayesville Shale in our area produces dry gas. If natural gas prices increase, we expect horizontal Haynesville Shale development to increase.

        There is one vertical Cotton Valley or Haynesville Shale well bore in each section. Therefore, each section in which we hold an interest contains acreage that we expect to further develop. Ultimately, the Company expects that there will be several Cotton Valley well bores drilled and completed horizontally in each of these sections. However, the development of different formations in each of these sections, drilling multiple wells in certain formations in each section and employing horizontal completion techniques will allow for much greater future production from each of these sections than has been seen to-date.

        On October 2, 2013, the Company purchased East Texas assets, well bores and infrastructure from Gastar and Navasota. The East Texas assets provide drilling opportunities in the Cretaceous oily zones, the Cotton Valley Knowles, the middle Bossier and the Deep Bossier Reagan sands. As of June 30, 2014, the Company only lightly engaged in re-completion activity in the middle Bossier zones in existing well bores. Recent activity and recently completed 3-D seismic analysis has afforded the Company greater clarity as to the most advantageous opportunities to exploit the East Texas properties. It is anticipated that in the upcoming fiscal year, the Company will exploit the oily Cretaceous zones, both through existing well bores and through new drilling, and exploit the deep Bossier formation and/or the Cotton Valley Knowles through new drilling. This new drilling is expected to convert undeveloped acreage into developed acreage.

Lease Expirations

        Our Louisiana acreage is all held-by-production. While our East Texas undeveloped lease acreage, excluding optioned acreage, will expire during the next four years, unless the leases are converted into producing units or extended prior to lease expiration. The following table sets forth the lease expirations as of November 21, 2014.

Fiscal Year
  Net Acres  

2015

    6,665  

2016

    1,306  

2017

    1,934  

2018

    2,404  

OPERATIONS

        Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator's direct expenses and monthly per well supervision fees. Per well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas and other factors. As of June 30, 2014 approximately 18% of our properties, none of which totals 10% individually, were operated by third-party operators and the balance of our production was operated by Fossil, an entity wholly owned by Mr. Wallen.

        We have contract relationships with petroleum engineers, geologists and other operations and production specialists who believe the production rates and reserves will increase, which would lower the cost per Mcfe of operating our affiliated and non-affiliated third-party oil and gas properties.

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EMPLOYEES

        At November 28, 2014, the Company had thirteen (13) full-time employees. We regularly use independent consultants and contractors to perform various professional services, including well-site supervision, design, construction, permitting and environmental assessment. We use independent contractors to perform field and on-site production operation services.

FACILITIES

        The Company's principal executive and administrative offices are located at 9870 Plano Road, Dallas, Texas, and are owned by an affiliate controlled by Mr. Wallen. Effective January 1, 2011, the Company signed a 2-year lease that charges the Company a monthly fee of $8,000 per month, which lease was then on a month-to-month basis, until September 1, 2014. The Company has signed an 8 month lease that charges the Company a monthly fee of $10,000 per month, effective September 1, 2014 through April 30, 2015. The Company believes that there is other appropriate space available in the event the Company should terminate its current leasing arrangement, though the Company believes the monthly rental fee would likely exceed $10,000 per month.

COMPETITION

        The oil and gas business is a highly competitive industry. Being a smaller player in our core positions, we are always susceptible to the influence of the larger companies operating in our primary areas of operations. As of June 30, 2014, our acreage was being operated by affiliated and non-affiliated third-party operators. Approximately 40% of our acreage in Leon and Robertson Counties, Texas is held by production, with the balance of this acreage expected to be renewed or drilled to hold. Additionally, there is open acreage in and around our Leon and Robertson County acreage position. We are experiencing some competition in Leon and Robertson Counties with both renewing our current acreage position not held by production as well as entering into new leases; however, this has not had a material impact in our operations or our plans for development.

        We have approximately 10,000 Cotton Valley acres and 4,000 Haynesville acres in Caddo and DeSoto Parishes in Northwest Louisiana. Through an affiliate, we control operations on the vast majority of our Cotton Valley acreage in Northwest Louisiana. In DeSoto and Caddo Parishes, Louisiana, our Bossier/Haynesville acreage is operated by EXCO, BG, Goodrich, Chesapeake, BHP Billiton, Indigo Minerals, and EP Energy. This acreage is held by production, and we are not looking to expand our position in Northwest Louisiana.

        In Eastland and Callahan Counties, Texas, we both operate through an affiliate and have farmout arrangements on properties that produce limited amounts of natural gas and oil condensate. This is not a material asset for the Company.

REGULATION

        Exploration and Production.    The exploration, production and sale of oil and natural gas are subject to various types of local, state and federal laws and regulations. These laws and regulations govern a wide range of matters, including the drilling and spacing of wells, allowable rates of production, restoration of surface areas, plugging and abandonment of wells and requirements for the operation of wells. Our operations are also subject to various conservation requirements. These include the regulation of the size and shape of drilling and spacing units or proration units, the density of wells that may be drilled and the unitization or pooling of oil and natural gas properties. In this regard, Louisiana and Texas allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. All of these

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regulations may adversely affect the rate at which wells produce oil and natural gas and the number of wells we may drill. All statements in this Prospectus about the number of locations or wells reflect current laws and regulations.

        Laws and regulations relating to our business frequently change, and future laws and regulations, including changes to existing laws and regulations, could adversely affect our business.

        Environmental Matters.    The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy or control such discharges. Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities or oil and natural gas wells. Discharged hydrocarbons may migrate through soil to water supplies or adjoining property, giving rise to additional liabilities.

        A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing and may, in addition to other laws, impose liability in the event of discharges, whether or not accidental, failure to notify the proper authorities of a discharge, and other noncompliance with those laws. Compliance with such laws and regulations may increase the cost of oil and natural gas exploration, development and production; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings. Failure to comply with the requirements of the applicable laws and regulations, by us or our third-party operators could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

        The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "superfund law," imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that dispose or arrange for disposal of the hazardous substances found at the time. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We could be subject to liability under CERCLA because our drilling and production activities generate relatively small amounts of liquid and solid waste, which could be subject to classification as hazardous substances under CERCLA.

        The Resource Conservation and Recovery Act of 1976, as amended ("RCRA"), is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a "generator" or "transporter" of hazardous waste or an "owner" or "operator" of a hazardous waste treatment, storage or disposal facility. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses.

        The federal Water Pollution Control Act of 1972, as amended ("Clean Water Act"), and analogous state laws, impose restrictions and strict controls regarding the discharge of pollutants into certain water bodies. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to

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discharge pollutants into waters of the United States or, under state law, state surface or subsurface waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate operating protocols including containment berms and similar structures to help prevent the contamination of regulated waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities or during construction activities.

        Our third-party operators employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. The federal Energy Policy Act of 2005 amended the Underground Injection Control ("UIC") provisions of the federal Safe Drinking Water Act ("SDWA") to exclude hydraulic fracturing from the definition of "underground injection" under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. Similar legislation could be introduced in the current session of Congress. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a study of the potential environmental impacts of hydraulic fracturing. In December 2012, the EPA issued a progress report on its hydraulic fracturing study with final results now expected in 2016, after a two-year delay was announced by the EPA in June 2013. The agency also announced that one of its enforcement initiatives for 2014 to 2016 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny or further legislative or regulatory action regarding hydraulic fracturing or similar production operations that could make it difficult to perform hydraulic fracturing and increase our costs of compliance or significantly impact our business, results of operations, cash flows, financial position and future growth.

        In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. Our operations are concentrated in Louisiana and Texas. We now have significant operations in Texas as well. We do not currently have operations on federal lands or in the states where the most stringent proposals have been advanced. However, if new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, or if we acquire oil and gas properties in areas subject to those regulations, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities.

        The Oil Pollution Act of 1990, as amended ("OPA"), which amends the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A "responsible party" under the OPA includes owners and operators of certain onshore facilities from which a release may affect regulated waters.

        The federal Clean Air Act, as amended ("Clean Air Act"), and state air pollution permitting laws, restrict the emission of air pollutants from many sources, including processing plants and compressor stations and potentially from our drilling and production operations, and as a result affects oil and

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natural gas operations. We may be required to incur compliance costs or capital expenditures for existing or new facilities to remain in compliance. In addition, more stringent regulations governing emissions of air pollutants, including greenhouse gases such as methane (a component of natural gas) and carbon dioxide are being developed by the federal government, and may increase the costs of compliance for some facilities or the cost of transportation or processing of produced oil and gas which may affect our operating costs. Obtaining permits has the potential to delay the development of oil and natural gas projects. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe, based on current law, that such requirements will have a material adverse effect on our operations.

        In response to findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHG"), from industrial and energy sources contribute to increases of carbon dioxide levels in the earth's atmosphere and oceans, effects on climate, and other environmental effects and therefore present an endangerment to public health and the environment, the EPA has adopted various regulations under the Clean Air Act, addressing emissions of greenhouse gases that may affect the oil and gas industry. On November 8, 2010, the EPA finalized rules expanding its Mandatory Greenhouse Gas Reporting Rule, originally promulgated in October 2009, to be applicable to the oil and natural gas industry, including certain onshore oil and natural gas production activities, which may affect certain of our existing or future operations and require the inventory and reporting of emissions. In addition, the EPA has taken the position that existing Clean Air Act provisions require an assessment of greenhouse gas emissions within the permitting process for certain large new or modified stationary sources under the EPA's Prevention of Significant Deterioration and Title V permit programs, effective as of 2011. On April 17, 2012, the EPA issued final rules to subject oil and natural gas operations to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAPS") programs under the Clean Air Act, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce volatile organic compound ("VOC") emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, which became effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We are currently evaluating the effect these rules will have on our business.

        We are unable to assure that more stringent laws and regulations protecting the environment will not be adopted and that we will not incur material expenses in complying with them in the future. For example, although federal legislation regarding the control of emissions of GHG for the present, appears unlikely, the EPA has been implementing regulatory measures under existing Clean Air Act authority and some of those regulations may affect our operations. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce.

        Although this rule does not limit the amount of GHGs that can be emitted, it requires the operator of the wells to incur costs to monitor, record keep and report GHG emissions associated with our operations. In addition, some states have considered, and notably California has adopted, a state specific GHG regulatory program that may limit GHG emissions or may require costs in association with the control of GHG emissions.

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        The federal Endangered Species Act, as amended ("ESA"), and comparable state laws, may restrict activities that affect endangered and threatened species or their habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

        We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended ("OSHA"), and comparable state laws, whose purpose is to protect the health and safety of workers. In addition, the OSHA 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 or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. These laws and provisions of CERCLA require reporting of spills and releases of hazardous chemicals in certain situations.

        We do not believe that our environmental, health and safety risks will be materially different from those of comparable U.S. companies in the oil and natural gas industry. Nevertheless, there can be no assurance that such environmental, health and safety laws and regulations will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our capital expenditures, financial condition and results of operations.

        In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

        Natural Gas Marketing and Transportation.    Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission ("FERC"). The FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. Beginning in 1992, the 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 who buy and sell natural gas. Although the 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 addition, the FERC is continually proposing and implementing new rules affecting segments of the natural gas industry, most notably interstate natural gas transmission companies that remain subject to FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

        The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach established by the FERC under Order No. 637 will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

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        The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC, the Commodity Futures Trading Commission ("CFTC") and/or the Federal Trade Commission. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

        Crude Oil Marketing and Transportation.    Our sales of crude oil and condensate are currently not regulated and are made at market prices. Nevertheless, Congress could reenact price controls in the future.

        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, varies 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 materially different from those of our competitors who are similarly situated.

        Further, 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. 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.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

        The following are abbreviations and definitions of terms commonly used in the oil and gas industry, many of which are used in this Prospectus.

        "Bbl" means a barrel of 42 U.S. gallons, used herein in reference to oil or other liquid hydrocarbons.

        "Bcf" means one billion cubic feet.

        "Bcfe" means Bcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

        "Btu" means British thermal unit, which means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

        "Casing" means a type of pipe that is used for encasing a smaller diameter carrier pipe for installation in a well. Casing is used to send off fluids from the hole or keep a hole from caving in.

        "Completion" means the installation of permanent equipment for the production of oil or gas.

        "Compressor Station" means a facility in which the pressure of natural gas is raised to facilitate its transmission through pipelines.

        "Condensate" means hydrocarbons naturally occurring in the gaseous phase in a reservoir that condense to become a liquid at the surface due to the change in pressure and temperature.

        "Cubic Foot" means the volume of gas that fills one cubic foot of space under standard temperature and pressure conditions. Standard pressure is 14.73 psi and standard temperature is 60 degrees Fahrenheit.

        "Developed Acreage" means the number of acres that are allocated or assignable to producing wells or wells capable of production.

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        "Development Drilling" or "Development Well" means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

        "Dry Hole" or "Dry Well" means a well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil and gas well.

        "Estimated Future Net Cash Flows" means estimated future gross cash flows to be generated from the production of proved reserves, net of estimated production, future development costs, and future abandonment costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization.

        "Exploration" is the act of searching for potential sub-surface reservoirs of gas or oil. Methods include the use of magnetometers, gravity meters, seismic exploration, surface mapping, and the drilling of exploratory test wells (known as "wildcats").

        "Exploratory Drilling" or "Exploratory Well" means a well drilled to find and produce oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

        "Fracture Stimulation" means a stimulation treatment routinely performed involving the injection of water, sand and chemicals under pressure to stimulate hydrocarbon production in low-permeability reservoirs.

        "Farm-In" or "Farm-Out" means an agreement pursuant to which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" and the assignor issues a "farm-out."

        "Finding and Development Costs" means the total costs incurred for exploration and development activities (excluding exploratory drilling in progress and drilling inventories), divided by total proved reserve additions. To the extent any portion of the proved reserve additions consist of proved undeveloped reserves; additional costs would have to be incurred in order for such proved undeveloped reserves to be produced. This measure may differ from the measure used by other oil and natural gas companies.

        "Gas" means natural gas.

        "Full Cost Pool" The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.

        "Gathering System" means a system of pipelines, compressor stations and any other related facilities that gathers natural gas from a supply region and transports it to the major transmission systems.

        "Gross" when used with respect to acres or wells, means the total acres or wells in which we have a working interest.

        "Held-by-production" A provision in an oil, gas and mineral lease that perpetuates a company's right to operate a property or concession as long as the property or concession produces a minimum paying quantity of oil or gas.

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        "Horizontal Drilling" means drilling a well that deviates from the vertical and travels horizontally through a prospective reservoir.

        "Horizontal Wells" Wells which are drilled at angles greater than 70 degrees from vertical.

        "Hydrocarbons" means an organic chemical compound of hydrogen and carbon. Hydrocarbons are a large class of liquid, solid or gaseous organic compounds, which are the basis of almost all petroleum products.

        "Infill drilling" means drilling of a well between known producing wells to better exploit the reservoir.

        "Initial production rate" means generally, the maximum 24 hour production volume from a well.

        "Lease" means a formal agreement between two or more parties where the owner of the land grants another party the right to drill and produce hydrocarbons in exchange for payment.

        "Mcf" means one thousand cubic feet.

        "Mmcf/d" means one million cubic feet of natural gas per day.

        "Mcfe" means Mcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

        "MMbtu" means one million Btus.

        "MMcf" means one million cubic feet.

        "MMcfe" means MMcf of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

        "Natural Gas Liquids" or "NGLs" means liquid hydrocarbons which have been extracted from natural gas (e.g., ethane, propane, butane and natural gasoline).

        "Net" when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.

        "Net Production" means production that is owned by the Company less royalties and production due others.

        "NYMEX" means the New York Mercantile Exchange.

        "Overriding royalty interest" means an interest in an oil and/or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

        "Operator" means the individual or company responsible for the exploration, development and production of an oil or gas well or lease.

        "Play" means a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and gas reserves.

        "Pipeline" means all parts of a physical facility through which gas is transported, including pipe, valves and other appendages attached to the pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.

        "Present Value", "PV-10" or "Standardized Measure" when used with respect to oil and gas reserves, is the pre-tax present value, discounted at an annual rate of 10%, of the estimated future gross revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation (except to the extent a contract specifically provides otherwise), without giving effect to non-property related expenses such as general and

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administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization.

        "Productive Wells" or "Producing Wells" consist of producing wells and wells capable of production, including natural gas wells waiting on pipeline connections.

        "Proved Reserves" means those quantities of oil and 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.

        "Recompletion" means an operation within an existing well bore to make the well produce oil and/or gas from a different, separately producible zone other than the zone from which the well had been producing.

        "Reserves" means proved reserves.

        "Reservoir" means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

        "Royalty" means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells 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.

        "Sandstone" means rock composed mainly of sand-sized particles or fragments of the mineral quartz, which, because these grains are rigid, will withstand tremendous pressures without being compacted.

        "Shale" means a type of rock composed of common clay or mud. When clay is compacted under great pressure and temperature deep in the earth, water contained in the clay is expelled, and clay turns into shale.

        "2-D Seismic" means an advanced technology method by which a cross-section of the earth's subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.

        "3-D Seismic" means an advanced technology method by which a three dimensional image of the earth's subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.

        "Undeveloped Acreage" means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

        "Undeveloped Reserves" means reserves of any category 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.

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        "Working Interest" means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.

        "Workovers" means operations on a producing well to restore or increase production.

LEGAL PROCEEDINGS

        We are party to lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our financial position or results of operations. The legal climate in Northwest Louisiana is hostile and litigious towards oil and gas companies; and the legal environment in East Texas is becoming increasingly competitive and hostile. Mineral owners are seeking opportunities to make additional money from their mineral rights, including pursuit of claims of lease expiration by asserting that production does not exist in paying quantities. In the normal course of our business, title defects and lease issues of varying degrees will arise, and, if practicable, reasonable efforts will be made to cure any such defects and issues.

        A lawsuit was filed on or about June 15, 2010, styled, "Gloria's Ranch, LLC v. Tauren Exploration, Inc., Cubic Energy, Inc., Wells Fargo Energy Capital, Inc. ("WFEC") & EXCO USA Asset, LLC", filed in the 1st Judicial District Court, Caddo Parish, Louisiana, Cause No. 541-768, A. This lawsuit alleges that all or part of the Gloria's Ranch mineral lease has lapsed, and seeks a finding that the mineral lease has lapsed, damages, attorney fees, and other equitable relief. This lawsuit would have a material effect, with the lost acreage component having an estimated value of up to $9,100,000, if ultimately adjudicated entirely in favor of the mineral owner. The Company intends to vigorously defend its position and believes it will prevail regarding some, if not all, of the acreage at issue in this lawsuit.

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MARKET PRICE OF AND DIVIDENDS ON COMMON EQUITY
AND RELATED SHAREHOLDER MATTERS

        During fiscal 2013, the Common Stock of the Company traded on the NYSE-MKT under the trading symbol "QBC". On July 17, 2013, after the beginning of fiscal 2014, the Company's Common Stock began being quoted on the OTCQB under the symbol "CBNR". At November 28, 2014, there were 77,505,908 shares of Common Stock outstanding held by approximately 770 stockholders of record.

        Under its Amended and Restated Certificate of Formation, the Company is authorized to issue one class of up to 400,000,000 common shares, par value $0.05 per share, and one class of up to 10,000,000 preferred shares, par value $0.01 per share. As of November 28, 2014 there were 17,743.933 shares of Series B Convertible Preferred Stock issued and outstanding and 98,751.823 shares of Series C Redeemable Voting Preferred Stock issued and outstanding. No shares of the Company's Series A Preferred Stock remained outstanding, and such series was cancelled in February 2014.

Common Stock Price Range

        The following table shows, for the periods indicated, the range of high and low sales price information for our Common Stock on the NYSE-MKT during fiscal 2013 and quoted on the OTCQB beginning in July 2014. Any market for our Common Stock should be considered sporadic, illiquid and highly volatile. Our Common Stock's trading range during the periods indicated was as follows:

Fiscal Year 2013
  High   Low  

1st Quarter

  $ 0.40   $ 0.19  

2nd Quarter

  $ 0.39   $ 0.14  

3rd Quarter

  $ 0.33   $ 0.16  

4th Quarter

  $ 0.34   $ 0.22  

 

Fiscal Year 2014
  High   Low  

1st Quarter

  $ 0.34   $ 0.20  

2nd Quarter

  $ 0.44   $ 0.27  

3rd Quarter

  $ 0.28   $ 0.19  

4th Quarter

  $ 0.25   $ 0.17  

 

Fiscal Year 2015
  High   Low  

1st Quarter

  $ 0.20   $ 0.11  

2nd Quarter (through November 28, 2014)

  $ 0.17   $ 0.10  

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

        During fiscal 2014 and thus far in fiscal 2015, the Company did not sell any of its equity securities that were not registered under the Securities Act of 1933, other than the Notes, the Class A Warrants, the Class B Warrants, the Series B Convertible Preferred Stock and the Series C Convertible Preferred Stock.

        We did not purchase any of our equity securities during the fourth quarter of fiscal 2014 or the first quarter of fiscal 2015.

Dividend Policy

        We have neither declared nor paid any dividends on our Common Stock since our inception. Presently, we intend to retain our earnings, if any, to provide funds for expansion of our business.

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Therefore, we do not anticipate declaring or paying cash dividends on our Common Stock in the foreseeable future. Any future dividends on our Common Stock will be subject to the discretion of our Board of Directors and will depend upon, among other things, future earnings, our operating and financial condition, our capital requirements, debt obligation agreements, general business conditions and other pertinent factors. Moreover, the terms of the Note Purchase Agreement prohibit the payment of dividends on our Common Stock.

Securities Authorized for Issuance under Equity Compensation Plans

        The following table provides information as of June 30, 2014 with respect to compensation plans (including individual compensation arrangements) under which equity securities of the registrant are authorized for issuance:

 
  Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
  Weighted
average
exercise price
of outstanding
options, warrants
and rights
  Number of shares
of common stock
remaining available
for future issuance
under equity
compensation plans
 

2005 Stock Option Plan approved by shareholders

    288,667   $ 1.20     1,290,805  
                 

Total

    288,667           1,290,805  
                 
                 

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USE OF PROCEEDS

        This prospectus relates to shares of our common stock that may be offered and sold from time to time by certain selling shareholders. We will not receive any of the proceeds of the sale of the common stock offered by this prospectus. However, we may receive proceeds from the exercise of warrants.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.

        The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere herein. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under "risk factors" and elsewhere herein.

Overview and Going Concern

        Cubic Energy, Inc. is an independent upstream energy company engaged in the development and production of, and exploration for, crude oil and natural gas. Our oil and gas assets and activities are concentrated exclusively in Louisiana and Texas.

        Our corporate strategy with respect to our asset acquisition and development efforts was to position the Company in a low risk opportunity while building main stream high yield reserves. The acquisition of our Cotton Valley acreage in DeSoto and Caddo Parishes, Louisiana, put us in a reservoir rich environment both in the Cotton Valley and Bossier/Haynesville Shale formations, and gives us the potential to discover additional commercial horizons that can add value to the bottom line. We have had success on our acreage with wells drilled by achieving production from not only the Cotton Valley and Bossier/Haynesville Shale formations, but also the Hosston formation.

        We believe that our East Texas Basin assets along with our Louisiana assets provide lower risk development and high yield opportunities.

        As of September 30, 2014, we had cash in the amount of $5,858,973 and total liabilities in the amount of $123,650,382. We also had a working capital deficit of $78,403,281 and an accumulated deficit of $79,042,487. Additionally, we are currently subject to a forbearance agreement in relation to the Note Purchase Agreement which requires us to, among others, enter into a definitive agreement with respect to a Strategic Transaction by October 17, 2014. The holders of the Notes have the ability to require the terms of the Strategic Transaction to permit us to repay all amounts owing to the holders of the Notes. Unless the requirement regarding a Strategic Transaction is waived, or we obtain an extension of time, the holders of the Notes could utilize all remedies available to them under the Note Purchase Agreement, including accelerating the indebtedness represented by the Notes and foreclosing on the assets securing the indebtedness.

        We are actively exploring various potential Strategic Transactions and believe we have complied with the other terms of the forbearance agreement; however, there can be no assurance that we will be successful in consummating a Strategic Transaction.

STRATEGY

        As of September 30, 2014, our strategy with respect to our domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk, field extension wells to the smaller scale pursuit of Company appropriate higher risk, high reserve potential prospects.

        Our acquisition of East Texas Basin assets is at the core of our current strategy, which we believe provides lower risk development opportunities and high yield opportunities. The Company is exploring acquiring additional properties with this same development profile.

        Additionally, our focus is on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. We develop prospects in-house with an affiliate and through strategic alliances with exploration companies that have

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expertise in specific target areas. In addition, we evaluate externally generated prospects and look to participate in certain of these opportunities to enhance our portfolio.

        We are currently focusing our domestic exploration activities to develop and re-enter existing well bores, and re-complete existing well bores with respect to our recently acquired East Texas Basin assets; as well as developing our recently augmented leasehold interests in Louisiana. East Texas Basin prospects have been developed from the top of the Cretaceous formation all the way to the bottom of the Deep Bossier Shale. The various Cretaceous zones all have strong oil and liquids component that we believe will help the Company achieve its transition away from dry natural gas. The high production of dry natural gas from the various Bossier sands have the opportunity to provide the Company an increase in short term cash flow, with reasonable out-of-pocket expenditures, even at current commodity prices, through the re-recompletion and work over of existing wells. Prospects in our Louisiana leaseholds are focused on the Cotton Valley and the Haynesville Shale, but also include the Hosston; Gloyd; Pettet; Glen Rose and Paluxy.

        The Company's future results of operations and growth are substantially dependent upon (i) its ability to work with the holders of the Notes in order to obtain additional time within which to consummate a Strategic Transaction (ii) its ability to acquire or find new oil and gas properties, or successfully develop existing oil and gas properties, and (iii) the prevailing prices for oil and gas. Numerous locations have been identified by third-party operators for additional drilling. If we are unable to economically complete additional producing wells, the Company's oil and gas production, and its revenues, would likely decline rapidly as its reserves are depleted. In addition, oil and gas prices are dependent upon numerous factors beyond the Company's control, such as economic, political, governmental, environmental and regulatory developments, as well as competition from other sources of energy. The oil and gas markets have historically been very volatile, and any further significant or extended decline in the price of gas would have a material adverse effect on the Company's financial condition and results of operations, and could result in a further reduction in the carrying value of the Company's proved reserves and adversely affect its access to capital.

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RESULTS OF OPERATIONS

Summary Operating, Reserve and Other Data

        The following table presents an unaudited summary of certain operating and oil and natural gas reserve data, and non-GAAP financial data for the periods indicated:

 
  Year ended June 30,  
 
  2014   2013   2012  

Operating Data:

                   

Proved Reserves (Bcfe)

    135.1     45.2     33.8  

Production (Mcfe)

    4,121,418     1,161,802     2,258,577  

Producing wells at end of period, gross

    97     64     60  

Producing wells at end of period, net

    53.25     31.41     13.52  

Acreage, gross

    53,225     13,123     13,123  

Acreage, net

    31,692     5,100     5,100  

Production:

   
 
   
 
   
 
 

Oil (Bbl)

    10,231     863     1,100  

Natural gas (Mcf)

    4,044,085     1,141,474     2,244,315  

Natural gas liquids (Bbl)

    2,658     2,525     1,277  

Total oil, gas and liquids (Mcfe)

    4,121,418     1,161,802     2,258,577  

Average daily (Mcfe)

    11,292     3,183     6,188  

Weighted Average Sales Prices:

   
 
   
 
   
 
 

Oil (per Bbl)

  $ 95.58   $ 90.00   $ 93.25  

Natural gas (per Mcf)

  $ 3.65   $ 3.21   $ 3.01  

Natural gas liquids (per Bbl)

  $ 45.78   $ 41.16   $ 66.78  

Natural gas equivalent (per Mcfe)

  $ 3.85   $ 3.31   $ 3.07  

Selected Expenses per Mcfe:

   
 
   
 
   
 
 

Production costs

  $ 0.71   $ 0.65   $ 0.43  

Workover expenses (non-recurring)

  $ 0.18   $ 0.04   $ 0.07  

Severance taxes

  $   $ 0.16   $ (0.06 )

Other revenue deductions

  $ 1.30   $ 0.76   $ 0.43  
               

Total lease operating expenses

  $ 2.19   $ 1.61   $ 0.87  

General and administrative expenses:

   
 
   
 
   
 
 

Non-cash stock-based compensation

  $ 0.01   $ 0.05   $ 0.10  

Other general and administrative

  $ 1.51   $ 1.96   $ 1.48  
               

Total general and administrative

  $ 1.52   $ 2.01   $ 1.58  

Depreciation, depletion and amortization

 
$

1.89
 
$

2.80
 
$

2.70
 

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  Three months ended
September 30,
 
 
  2014   2013  

Production Volumes:

             

Oil (Bbl)

    4,305     141  

Natural gas liquids (Bbl)

    729     492  

Natural gas (Mcf)

    1,089,142     243,844  

Total (Mcfe)

    1,119,346     247,638  

Weighted Average Sales Prices:

   
 
   
 
 

Oil (per Bbl)

  $ 93.43   $ 103.22  

Natural gas liquids (per Bbl)

  $ 47.95   $ 43.88  

Natural gas (per Mcf)

  $ 3.37   $ 3.41  

Selected Expenses per Mcfe:

   
 
   
 
 

Production costs

  $ 0.67   $ 0.60  

Severance taxes

  $ 0.04   $ 0.08  

Other revenue deductions

  $ 1.62   $ 0.60  
           

Total lease operating expenses

  $ 2.33   $ 1.27  

General and administrative expenses

  $ 1.28   $ 4.88  

Depreciation, depletion and amortization

  $ 1.88   $ 2.79  

Comparison of Fiscal 2014 to Fiscal 2013

Revenues

        Oil and Gas Sales increased 312% to $15,849,482 for fiscal 2014 from $3,843,420 for fiscal 2013 primarily due to the increased number of producing oil and natural gas wells that were part of the acquisition of East Texas properties during fiscal 2014. Our total annual production increased 255% from 1,161,802 Mcfe to 4,121,418 Mcfe for the year ended June 30, 2014. The average price of oil was $95.58 per barrel and natural gas was $3.65 per Mcfe for fiscal 2014, as compared to $90.00 per barrel of oil and $3.21 per Mcfe of natural gas for fiscal 2013.

Costs and Expenses

        Oil and Natural Gas Production and Operating Costs (also referred to as "Lease Operating Expenses" elsewhere herein) increased 381% to $9,002,020 (57% of oil and gas sales) for fiscal 2014 from $1,872,186 (49% of oil and gas sales) for fiscal 2013. This increase was primarily due to the increased number of producing oil and natural gas wells. Lease operating expenses increased by $7,335,763. This increase was partially offset by a decrease of $205,929 in production taxes, due to abatements in place at the time of our acquisitions for fiscal 2014 versus fiscal 2013.

        Asset Retirement Obligation ("ARO") increased by $339,954 due to the accretion of ARO on the acquired properties in fiscal 2014.

        General and Administrative Expenses ("G&A") increased 168% to $6,244,861 for fiscal 2014 from $2,332,946 for fiscal 2013. This increase of $3,911,915 was primarily due to an increase of $1,085,562 in salaries and benefits due largely to additional new hires and salary increases, an increase of $870,496 in legal fees, an increase of $259,656 in contracted professional services and an increase of $363,458 in consulting and management fees. All of the increases were directly related to the acquisitions during fiscal 2014.

        Depreciation, Depletion And Amortization ("DD&A") increased 140% to $7,790,112 in fiscal 2014 from $3,248,260 in fiscal 2013, primarily due to the new production from the acquired East Texas properties. Also contributing to that increase was a slight increase in the depletion percentage rate for

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fiscal 2014 of 2.96% versus 2.51% for fiscal 2013, which was primarily the result of an approximate 31.6 million Mcf increase to our reserves. The depletion rate is a result of a change in beginning reserves, full cost pool to deplete, accumulated depletion and annual production.

        Derivatives Loss was $3,056,053 for the year ended June 30, 2014. There was no derivative gain or loss for the year ended June 30, 2013, as we had not engaged in any derivative transactions prior to fiscal 2014. The net derivative loss in fiscal 2014 was due to contract prices of $92 per barrel of oil and $3.90 per Mcf for natural gas generally being lower than the settlement prices.

        Gain on Acquisition of $22,578,000 was recognized as a bargain purchase gain, as a result of incorporating the valuation information into the purchase price allocation. The Company's assessment of the fair value of the properties acquired from Tauren, along with consideration of data prepared by a third party, resulted in a fair market valuation of $26,946,000. The acquisition price paid by the Company was $4,000,000 in cash and 2,000 shares of the Company's Series B Convertible Preferred Stock with an aggregate stated value of $2,000,000 and a fair value of $368,000.

        Interest Expense, Including Amortization Of Loan Discount increased 682% to $19,313,106 in fiscal 2014 from $2,470,516 in fiscal 2013. Our debt increased as a result of the financing for our acquisitions during fiscal 2014. We had total outstanding debt of $67,971,274 (net of discounts) at the end of fiscal 2014 and $29,865,110 at the end of fiscal 2013. As part of the refinancing of the Credit Facility with WFEC, the $5,000,000 convertible senior note was paid in full leaving a balance on the revolver of $20,865,110, the discount for which was fully amortized at closing in October 2013. During fiscal 2014, the Company borrowed $4,015,826 for drilling and completion, which increased our debt outstanding with WFEC to $24,880,936 at the end of fiscal 2014. Also as part of the refinancing we borrowed $66,000,000 through the issuance of the Notes. The aggregate face amount of the Notes increased by $2,834,798, as a result of making certain interest payments through issuing additional notes, which create a total outstanding to the Lenders of $68,834,798 (before discounts).The discounts on the additional $4,015,826 and the $68,834,798 aggregate amount of the Notes are being amortized over the three-year term of the debt as additional interest expense. We reported $432,346 in the capitalization of interest expense to the full cost pool for oil and gas properties during fiscal 2014. There was no increase in the capitalization of interest expense during fiscal 2013.

        Change in fair value of warrants liabilities of $17,120,692 was recognized for the year ended June 30, 2014. The fair value of warrants liability associated with the Company's Class A and B warrants, which were issued in connection with the issuance of the Notes issued on October 2, 2013, decreased as of June 30, 2014, resulting in a gain of $18,102,734 for the year ended June 30, 2014. This gain was slightly offset by the out-of-period charge of $1,805,898 to record the fair value of warrants held by WFEC as of July 1, 2013, offset by a gain resulting from the warrants' decrease in value during 2014, resulting in a net charge to income of $982,042 for the year ended June 30, 2014.

        Net Income Attributable to Common Shareholders for the year ended June 30, 2014 was $7,704,135, compared to a net loss of $6,851,518 for the year ended June 30, 2013. The increase in our net income was primarily due to the gain on acquisition of assets and the change in fair value of warrants liability.

Comparison of the Three Months ended September 30, 2014 and 2013

Revenues

        Oil And Gas Sales increased 374% to $4,105,494 for the quarter ended September 30, 2014 from $866,702 for the quarter ended September 30, 2013 primarily due to the increase in oil and natural gas production from acquired properties during the 2014 quarter versus the 2013 quarter, which was slightly offset by the decrease in the weighted average natural gas and oil prices we received in the 2014 quarter, which were $3.37 per Mcf of natural gas and $93.43 per barrel of oil, versus $3.41 per Mcf of natural gas and $103.22 per barrel of oil in the 2013 quarter.

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Costs and Expenses

        Oil And Gas Production And Operating Costs (also referred to as "LEASE OPERATING EXPENSES" elsewhere herein) increased 726% to $2,608,583 (64% of oil and gas sales) for the 2014 quarter from $315,628 (36% of oil and gas sales) for the 2013 quarter. This increase is primarily due to the new wells coming online, as a result of our acquisitions and the added costs to maintain those wells during the three month period ended September 30, 2014.

        Accretion of Asset Retirement Obligation ("ARO") was $80,931 related to the properties acquired in fiscal 2014.

        General And Administrative Expenses ("G&A") increased 19% to $1,434,175 for the 2014 quarter from $1,207,827 in the 2013 quarter primarily due to salary increases and compensation to new hires of $366,917. These increases were partially offset by a decrease of $169,715 in legal fees.

        Depreciation, Depletion And Amortization ("DD&A") increased 203% to $2,099,047 in the 2014 quarter from $691,853 in the 2013 quarter primarily due to the new wells on line. No impairment loss was recognized during the quarters ended September 30, 2014 or 2013.

        Derivatives Gain was $7,754,437 for the three months ended September 30, 2014. There was no derivative gain or loss for the three months ended September 30, 2013, as we had not engaged in any derivative transactions prior to the end of that quarter. The net derivative gain in the 2014 quarter was due to contract prices of $92 per barrel of oil and $3.90 per Mcf for natural gas generally being higher than the settlement prices.

        Interest Expense, Including Amortization Of Loan Discount increased 474% to $7,231,762 in the three months ended September 30, 2014 from $1,260,659 in the same period of 2013. Our debt increased as a result of the financing for our acquisitions during fiscal 2014. We had total outstanding debt of $70,842,061 (net of discounts) as of September 30, 2014 and $27,865,110 as of September 30, 2013. As part of the refinancing of the Credit Facility with WFEC, the $5,000,000 convertible senior note was paid in full leaving a balance on the revolver of $20,865,110, the discount for which was fully amortized at closing in October 2013. During fiscal 2014, the Company borrowed $4,015,826 for drilling and completion, which increased our debt outstanding with WFEC to $24,880,936 as of September 30, 2014. Also as part of the financing for the October 2013 acquisitions, we borrowed $66,000,000 through the issuance of the Notes. The aggregate face amount of the Notes increased by $2,834,798, as a result of making certain interest payments through issuing additional notes, which create a total outstanding to the lenders of $68,834,798 (before discounts).The discounts on the additional $4,015,826 and the $68,834,798 aggregate amount of the Notes are being amortized over the three-year term of the debt as additional interest expense. We reported $432,346 in the capitalization of interest expense to the full cost pool for oil and gas properties during fiscal 2014. There was no increase in the capitalization of interest expense for the period ended September 30, 2014 or 2013, respectively.

        Change in fair value of warrants liability of $1,018,006 was recognized for the three months ended September 30, 2014. The fair value of warrants liability associated with the Company's Class A and B warrants, which were issued in connection with the issuance of the Notes issued on October 2, 2013, decreased as of September 30, 2014, by $948,250. There was also decrease in fair value of warrants held by WFEC of $69,756 for the three months ended September 30, 2014.

        Net Loss Attributable to Common Shareholders for the three months ended September 30, 2014 was $989,555 compared to a net loss of $4,882,444 for the three months ended September 30, 2013. The decrease in our net loss attributable to common shareholders was primarily due to the gain on derivative contracts and change in fair value of warrants liability. These were partially offset by the increased lease operating and interest expenses for September 30, 2014 versus the same period in 2013.

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Financial Condition, Liquidity and Capital Resources

Financial Condition

        At September 30, 2014, we had a working capital deficit of $78,403,281 an increase from our working capital deficit of $34,517,649 as of September 30, 2014. The increase in our working capital deficit is primarily attributable to an increase in our borrowings which are classified as current due to our financial condition.

        Additionally, we are currently subject to a forbearance agreement in relation to the Note Purchase Agreement which requires us to, among others, enter into a definitive agreement with respect to a Strategic Transaction by October 17, 2014. The holders of the Notes have the ability to require the terms of the Strategic Transaction to permit us to repay all amounts owing to the holders of the Notes. Unless the requirement regarding a Strategic Transaction is waived, or we obtain an extension of time, the holders of the Notes could utilize all remedies available to them under the Note Purchase Agreement, including accelerating the indebtedness represented by the Notes and foreclosing on the assets securing the indebtedness.

        We are actively exploring various potential Strategic Transactions and believe we have complied with the other terms of the forbearance agreement; however, there can be no assurance that we will be successful in consummating a Strategic Transaction.

Overview

        Our primary resource is our oil and gas reserves. Our strategy with respect to our domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk, field extension wells to the smaller scale pursuit of Company appropriate higher risk, high reserve potential prospects.

        Our acquisition of East Texas Basin assets is at the core of our current strategy, providing the lower risk development opportunities and high yield opportunities within the same property. We are exploring acquiring additional properties with this similar development profile.

        Additionally, our focus is on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. We develop prospects in-house with an affiliate and through strategic alliances with exploration companies that have expertise in specific target areas. In addition, we evaluate externally generated prospects and look to participate in certain of these opportunities to enhance our portfolio.

        We are currently focusing our domestic exploration activities to develop, re-enter, and re-complete existing well bores with respect to our recently acquired East Texas Basin assets, as well as developing our recently augmented leasehold interests in Louisiana. Our East Texas Basin prospects have been developed from the top of the Cretaceous formations all the way to the bottom of the Deep Bossier Shale. The various Cretaceous zones all have a strong oil and liquids component, which are helping us transition away from dry natural gas. The high production of dry natural gas from the various Bossier sands has provided us an increase in short term cash flow without substantial out-of-pocket expenditures, even at current commodity prices, through the re-recompletion and work over of existing wells. Prospects in our Louisiana leaseholds are focused on the Cotton Valley and the Haynesville Shale, but also include the Hosston; Gloyd; Pettet; Glen Rose and Paluxy.

        Product prices, over which we have no control, have a significant impact on revenues from production and the value of such reserves and thereby on our borrowing capacity. Within the confines of product pricing, we seek to find and develop or acquire oil and gas reserves in a cost-effective manner in order to generate sufficient financial resources through internal means to finance our capital expenditure program.

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Financing Transactions

        In October 2013, we entered into the Note Purchase Agreement, pursuant to which we issued an aggregate of $66,000,000 of Notes due October 2, 2016, to certain purchasers. The aggregate face amount of the Notes increased by $2,834,798, as a result of making certain interest payments through issuing additional notes, which create a total outstanding to the Lenders of $68,834,798 (before discounts) at June 30, 2014. As part of the refinancing of the Credit Facility with WFEC, the $5,000,000 convertible senior note was paid in full leaving a balance on the revolver of $20,865,110, the discount for which was fully amortized at closing in October 2013. That debt is reflected in a term loan bearing interest at the Wells Fargo Bank prime rate, plus 2%, per annum. As part of the Credit Agreement, WFEC is providing a revolving credit facility in the amount of up to $10,000,000, bearing interest at the same rate, with all advances under that revolving credit facility to be made in the sole discretion of WFEC. During fiscal 2014, the Company borrowed $4,015,826 for drilling and completion, which increased our debt outstanding with WFEC to $24,880,936 at the end of fiscal 2014. In the event that Cubic Louisiana does not have available cash to pay interest on the Credit Facility, accrued and unpaid interest will be paid in kind via an additional promissory note. We are currently paying cash quarterly interest payments on the Credit Facility, at the Wells Fargo Bank prime rate, plus 2%.

        We also entered into an arrangement with a third party that resulted in the receipt of an upfront payment at closing of approximately $35,000,000, through the sale of calls, which upfront payment approximated fair value of the calls sold at inception. As a result, the Call Option Structured Derivative arrangement was initially recognized and measured at the amount of its upfront payment. Under the terms of the Call Option Structured Derivative arrangement, Cubic Asset sold calls to the third party covering (i) approximately 556,000 barrels of oil at a strike price set between $80 per barrel and $90 per barrel, and (ii) approximately 51.3 million MMBtu's of gas at a strike price set between $3.45 per MMBtu and $3.90 per MMBtu. The scheduled volumes subject to the calls sold relate to production months from November 2013 through December 2018. The Company is subject to the price risks associated with product price changes that are in excess of the specified call prices. If the market price during the applicable production month is above the applicable strike price, Cubic Asset would be required to pay the third party the difference between the market price and strike price for the amount of production subject to the call. This arrangement does not hedge the Company's risk associated with product price decreases. This together with the proceeds from the original issuance of the Notes, resulted in total proceeds to the Company of approximately $101,000,000.

        The Company, through its subsidiary Cubic Asset, entered into a Fixed Price Swap arrangement. Under the terms of the Fixed Price Swap arrangement, Cubic Asset will receive a fixed amount on approximately 18,000 barrels of oil at a price of $92 per barrel. The scheduled volumes subject to the swap related to production months from November 2013 through October 2016. Cubic Asset is subject to the price risks associated with product price increases above the specified fixed prices. Cubic Asset is using swaps to hedge some of its natural gas production. Cubic Asset receives the fixed price and pays the third party the floating market price during the applicable production month for the amount of production subject to the call.

Working Capital and Cash Flow

        At June 30, 2014, we had a working capital deficit of $72,997,802, which is an increase from our working capital deficit of $30,191,399 as of June 30, 2013. The increase in our working capital deficit is primarily attributable to an increase in our borrowings which are classified as current due to our financial condition. The Company's working capital deficit increased to $78,403,281 at September 30, 2014 from $72,997,802 at June 30, 2014, The increase in our working capital deficit is primarily attributable to an increase in our borrowings which are classified as current due to our financial condition.

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Cash Flows for Fiscal Years Ended June 30, 2014 and 2013

        Operating activities—During the twelve months ended June 30, 2014, the Company used $4,515,080 of cash for operating activities compared to generating cash flows from operating activities of $54,204 in fiscal 2013. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas.

        Investing activities—During the twelve months ended June 30, 2014 the Company used cash in the amount of $73,675,882 in cash flows from investing activities as compared to the generated cash flows from investing activities of $7,325,735 in fiscal 2013. Cash used by investing activities for 2014 consisted primarily of amounts used to make acquisitions in October 2013.

        Financing activities—During the twelve months ended June 30, 2014 the Company provided cash flows from financing activities of $84,788,356 as compared to used cash flows from financing activities of $7,394,890 in fiscal 2013. Cash provided by financing activities for 2014 consisted of borrowings from new lenders, the WFEC credit facility and proceeds from the issuance of stock offset by dividends and loan costs paid. Cash used by financing activities for 2013 consisted primarily of payments on the credit facility and loan costs incurred offset by additional borrowing on a note payable to an affiliate.

Cash Flow for Three Months Ended September 30, 2014 and 2013

        Our net decrease in cash and cash equivalents is summarized as follows:

 
  Three months ended
September 30,
 
 
  2014   2013  

Net cash provided (used) by operating activities

  $ 59,058   $ (156,894 )

Net cash used by investing activities

    (1,058,055 )   (2,421,644 )

Net cash provided by financing activities

        2,500,000  
           

Net decrease in cash and cash equivalents

  $ (998,997 ) $ (78,538 )
           
           

        Operating Activities—During the quarter ended September 30, 2014, the Company provided cash flows from operating activities of $59,060 as compared to cash used of $156,894 in the prior year period. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas. Also due to an increase in accounts payable.

        Investing Activities—The primary driver of cash used in investing activities is capital expenditures related to the drilling and completion of new wells and the acquisition and development of additional oil and gas properties. In the quarter ended September 30, 2014, we used net cash of $1,058,055. For the quarter ended September 30, 2013, we used net cash of $2,421,644 in investing activities.

        Financing Activities—Net cash flows provided by financing activities were $0 and $2,500,000 in the quarters ended September 30, 2014 and 2013, respectively. During the 2013 quarter, we received additional advances from an affiliate.

Capital Expenditures

        A significant portion of our oil and gas reserves are undeveloped. As such, recovery of our future undeveloped proved reserves will require significant capital expenditures. A portion of the proceeds from the issuance of the Notes and the Call Option Structured Derivative were used to consummate the acquisition of our East Texas Basin assets and additional working interests in our Louisiana properties. Management estimates that aggregate capital expenditures ranging from a minimum of

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approximately $5,000,000 and a maximum of approximately $25,000,000 will need to be made to further develop these reserves and provide for closing fees, debt repayment and general operating fees during fiscal 2015. The Company may increase its planned activities for fiscal 2015, if the Company acquires additional oil or natural gas properties. The Company has little or no control with respect to the timing of any third party operators drilling wells on acreage in which the Company has a working interest or the timing of drilling expenses incurred. Additional capital expenditures will be required for exploratory drilling on our undeveloped acreage.

        No assurance can be given that all or any of these anticipated or possible capital expenditures will be completed as currently anticipated. Any acquisition of additional leaseholds would require that we obtain additional capital resources.

Capital Resources

        We plan to fund our development and exploratory activities through cash on hand, cash provided from operations, and from the remaining funds secured in the financing transactions completed in October 2013, a possible disposition of assets, if needed, or other transactions.

        As future cash flows, the availability of borrowings, and the ability to consummate any of the aforementioned potential transactions are subject to a number of variables, such as prevailing prices of oil and gas, actual production from existing and newly-completed wells, our success in developing and producing new reserves, the uncertainty of financial markets and joint venture and merger and acquisition activity, and the uncertainty with respect to the amount of funds which may ultimately be required to finance our development and exploration program, there can be no assurance that our capital resources will be sufficient to sustain our development and exploratory activities. With future strategies to obtain additional financing, funds generated through existing wells and cash on hand, we expect to be able to continue to pay our expenses as they come due.

        If we are unable to obtain sufficient capital resources on a timely basis, we may need to curtail our planned development and exploratory activities. If a well is proposed by a third-party operator and we do not have the capital resources to participate in that well, we might not receive any revenue generated by that well, while still being required to fulfill the relevant royalty payment obligations to the mineral owner and other royalty holders. Additionally, because future cash flows and the availability of borrowings are subject to a number of variables, there can be no assurance that our capital resources will be sufficient to sustain our development and exploration activities.

Contractual Obligations

        On our East Texas properties, we have a midstream contract with Hilltop Resort GS, LLC that ran through October 31, 2024. This contract with Hilltop Resort GS, LLC has a penalty provision expiring on October 31, 2014, if, for the previous quarter, an average of 50,000 Mcf/day is not sent through the pipelines. Since the acquisitions on October 2, 2013, the Company has had to pay a quarterly penalty due to insufficient production. As of September 30, 2014, the Company accrued an obligation of $929,634 related to this contract.

Critical Accounting Policies

        In response to the SEC's Release No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting Policies," we have identified the most critical accounting policies used in the preparation of our consolidated financial statements. We determined the critical policies by considering accounting policies that involve our most complex or subjective decisions or assessments. We identified our most critical accounting policies to be those related to our proved reserves, accounts receivables, share-based payments, our choice of accounting method for oil and natural gas properties, goodwill, asset retirement obligations and income taxes.

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        We prepared our consolidated financial statements for inclusion in this Prospectus in accordance with accounting standards generally accepted in the United States("GAAP"). GAAP represents a comprehensive set of accounting and disclosure rules and requirements, and applying these rules and requirements requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP.

Estimates of Proved Oil and Gas Reserves

        The proved reserves data included in this Prospectus was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

    the quality and quantity of available data;

    the interpretation of that data;

    the accuracy of various mandated economic assumptions; and

    the technical qualifications, experience and judgment of the persons preparing the estimates.

        Because these estimates depend on many assumptions, all of which may substantially differ from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. The assumptions used for our East Texas, Bossier/Haynesville, Cotton Valley and Hosston well and reservoir characteristics and performance are subject to further refinement as more production history is accumulated.

        You should not assume that the present value of future net cash flows represents the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves according to the requirements in the SEC's Release No. 33-8995 "Modernization of Oil and Gas Reporting," or Release No. 33-8995. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates.

        Proved reserves quantities directly and materially impact depletion expense. If the proved reserves decline, then the rate at which we record depletion expense increases, reducing net income. A decline in the estimate of proved reserves may result from lower market prices, making it uneconomical to drill or produce if the costs to drill or produce are expected to exceed such market prices. In addition, a decline in proved reserves may impact the outcome of our assessment of our oil and natural gas properties and require an impairment of the carrying value of our oil and natural gas properties.

        Proved reserves are defined as those quantities of oil and 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 before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimates are deterministic estimates or probabilistic estimates. To be classified as proved reserves, 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.

        The area of the reservoir considered as proved includes both the area identified by drilling, but limited by fluid contacts, if any, and adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the deepest known hydrocarbons as seen in a well

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penetration unless geoscience, engineering, or performance data and reliable technology establish the deepest contact with reasonable certainty.

        Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

        Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and the project has been approved for development by all necessary parties and entities, including governmental entities.

        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.

        Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Accounting for oil and natural gas properties

        We follow the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the "full cost pool." Unproved property costs are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess possible impairment or the need to transfer unproved costs to proved properties as a result of extension or discoveries from drilling operations. We expect these costs to be evaluated in one to seven years and transferred to the depletable portion of the full cost pool during that time. The full cost pool is comprised of intangible drilling costs, lease and well equipment and exploration and development costs incurred plus costs of acquired proved and unproved leaseholds.

        During April 2004 we initiated leasing projects to acquire shale drilling rights in both the Johnson Branch and Bethany Longstreet fields in our Northeast Louisiana operating areas. In accordance with our policy and FASB ASC Subtopic 835-20 for Capitalization of Interest, we began capitalizing interest on unproved properties.

        We calculate depletion using the unit-of-production method. Under this method, the sum of the full cost pool and all estimated future development costs are divided by the total quantity of proved reserves. This rate is applied to our total production for the period, and the appropriate expense is recorded.

        Under the full cost method of accounting, sales, dispositions and other oil and natural gas property retirements are generally accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless the disposition would significantly alter the relationship between capitalized costs and proved reserves. Gain or loss recognition on divestiture or abandonment of oil and natural gas properties where disposition would result in a significant alteration of the depletion rate requires allocation of a portion of the amortizable full cost pool based on the relative estimated fair value of

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the disposed oil and natural gas properties to the estimated fair value of total proved reserves. As discussed under "Estimates of Proved Reserves," estimating oil and natural gas reserves involves numerous assumptions.

        The quarterly calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Use of estimates

        The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Certain significant estimates

        Management's estimates of oil and gas reserves are based on various assumptions, including constant oil and gas prices. It is reasonably possible that a future event in the near term could cause the estimates to change and such changes could have a severe impact. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. While it is at least reasonably possible that the estimates above will change materially in the near term, no estimate can be made of the range of possible changes that might occur.

Asset retirement obligations

        We follow FASB ASC Subtopic 410-20 for Asset Retirement Obligations to account for legal obligations associated with the retirement of long-lived assets. ASC 410-20 requires these obligations be recognized at their estimated fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the full cost pool and allocated to expense over the useful life of the asset. The costs of plugging and abandoning oil and natural gas properties fluctuate with costs associated with the industry. We periodically assess the estimated costs of our asset retirement obligations and adjust the liability according to these estimates.

Derivative financial instruments

        We use derivative financial instruments to as part of the financing of our acquisitions. We use mark-to-market valuation as estimate of fair value. We do not designate our derivative financial instruments as hedging instruments and, as a result, we recognize the change in the derivative's fair value as a component of current earnings.

Accounting for income taxes

        Income taxes are accounted for using the liability method of accounting in accordance with FASB ASC Topic 740 for Income Taxes. We must make certain estimates related to the reversal of temporary differences, and actual results could vary from those estimates. Deferred taxes are recorded to reflect the tax benefits and consequences of future years' differences between the tax basis of assets and

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liabilities and their financial reporting basis. We record a valuation allowance to reduce deferred tax assets if it is more likely than not that some portion or all of the deferred tax assets will not be realized.

Stock-based compensation

        We account for share-based payments to employees using the methodology prescribed in FASB ASC Topic 718 for Stock Compensation. ASC Topic 718 requires share-based compensation to be recorded with cost classifications consistent with cash compensation.

Subsequent Events

        The FASB issued new authoritative guidance for subsequent events. Such authoritative guidance establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this statement sets forth: (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. Adoption of this authoritative position did not have a material impact on the Company's condensed consolidated financial statements.

Other Accounting Policies and Recent Accounting Pronouncements

        Please see "Notes to Consolidated Financial Statements for the years ended June 30, 2014 and 2013—Note B—Significant accounting policies" elsewhere herein.

Inflation

        Although the level of inflation affects certain of the Company's costs and expenses, inflation did not have a significant effect on the Company's results of operations during fiscal 2014.

Related Party Transactions

        A description of our related party transactions is included in "Note E to Consolidated Financial Statements for the years ended June 30, 2014 and 2013—Related party transactions" in the Notes to the Financial Statements of the Company included elsewhere in this Prospectus, and is incorporated herein by reference.

Off-Balance Sheet Arrangements

        We do not currently use any off-balance sheet arrangements to enhance our liquidity and capital resource positions, or for any other purpose.

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DIRECTORS AND EXECUTIVE OFFICERS

Directors

        The following table provides information concerning each of our directors as of November 28, 2014:

Name
  Age   Position(s) Held with Cubic   Director
Since
 

Calvin A. Wallen, III

    59   Chairman of the Board, President and Chief Executive Officer     1997  

Jon S. Ross

    50   Executive Vice President, Corporate Secretary and Director     1998  

Gene C. Howard

    88   Director     1991  

Bob L. Clements

    72   Director     2004  

David B. Brown

    52   Director     2010  

Paul R. Ferretti

    67   Director     2010  

        CALVIN A. WALLEN, III has served as the President and Chief Executive Officer of the Company since 1997 and as Chairman of the Board of Directors since June 1999. Mr. Wallen has over 30 years of experience in the oil and gas industry working as a drilling and petroleum engineer. He was employed by Superior Oil and various other drilling contractors including Resource, Tom Brown and Rowan International. Mr. Wallen has considerable experience in drilling vertical, high-angle directional and horizontal wells in North and South American oil and gas fields and in the North Sea and Gulf of Mexico. Mr. Wallen is an active member of the Dallas Geological Society, the American Association of Petroleum Geologists, the American Association of Drilling Engineers, and the Society of Petroleum Engineers. In 1982, Mr. Wallen began acquiring and developing oil and gas properties, forming a production company that has evolved into Tauren Exploration, Inc. Mr. Wallen did his undergraduate engineering studies at Texas A&M University.

        JON S. ROSS has served as the Secretary and as a director of the Company since April 1998. Mr. Ross is a practicing attorney in Dallas, Texas representing over fifty business entities within the past nine years. He has served on several community and non-profit committees and boards and has been asked to speak to corporate and civic leaders on a variety of corporate law topics. Mr. Ross is a director of Oryon Technologies, Inc., a publicly traded company focused on products utilizing electroluminescent lamp technology. Mr. Ross graduated from St. Mark's School of Texas with honors in 1982 and graduated from the University of Texas at Austin in 1986 with a B.B.A. in Accounting. He then graduated from the University of Texas School of Law in 1989 attaining a Juris Doctorate degree.

        GENE C. HOWARD is the Senior Partner of Bonham & Howard, P.L.L.C. and has served on numerous boards including six banks, was Chair of the Oklahoma State & Education Group Insurance Board for eight years, was a Trustee of the Oklahoma College Savings Plan for four years, and was Chair of the Philadelphia Mortgage Trust (a REIT) for ten years. He served 22 years in the Oklahoma Legislature, with six years as the President Pro Tem of the Senate. Mr. Howard is also a veteran of the U.S. Air Force, obtaining the rank of Lieutenant Colonel.

        BOB L. CLEMENTS joined the Company's board in February 2004. Mr. Clements is the owner of both Leon's Texas Cuisine, the largest independent producer of corn dogs and stuffed jalapenos for the retail and food service industry, and Shoreline Restaurant Corporation, which operates two upscale dining locations in Rockwall, Texas. He has been in the restaurant and wholesale food business for more than 30 years. Mr. Clements received his education from Rutherford Business College. He also graduated in 1985 from Harvard Business School's highly selective OPM Program.

        DAVID B. BROWN currently performs financial consulting services for privately owned and publicly traded companies including filling interim Chief Financial Officer roles, leveraged debt

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refinancing and addressing material internal control and reporting deficiencies. He was the Senior Vice President & Chief Accounting Officer for MoneyGram International (NYSE: MGI), a provider of financial services, from January 2012 through May 2013. From 2007 until 2011, Mr. Brown was Chief Financial Officer for Dresser, Inc., a $2 billion subsidiary of General Electric that manufactured energy equipment serving the upstream, midstream and downstream oil, gas and power markets. Mr. Brown led the integration of Dresser into various business units of GE's Energy division and previously served Dresser as Chief Accounting Officer and Controller. From 2003 until 2007, Mr. Brown was divisional Vice President, Controller and Chief Audit Executive for the Brink's Company, a global security services company with operations in more than 130 countries. Prior to joining Brink's, Mr. Brown spent 8 years with LSG Sky Chefs, a $3 billion airline catering company owned by Lufthansa, in leadership roles with progressive responsibility including three years in Sao Paulo, Brazil as Vice President Finance—Latin America. Prior to that time, Mr. Brown spent 10 years with Price Waterhouse, where he advised multi-national clients primarily in the energy industry, while living in Moscow, London and the United States. He has also served in a variety of board of director capacities for several Dallas-based arts and humanities nonprofit organizations and is an active member of the Dallas Committee for Foreign Relations and the Boy Scouts of America. Mr. Brown has a Bachelor of Business Administration degree from The University of Texas—Austin and is a Certified Public Accountant.

        PAUL R. FERRETTI served as Managing Director—Head of Energy Investment Banking with Wunderlich Securities Inc., an investment banking firm, from 2008 through 2010. From 2005 until joining Wunderlich Securities, Mr. Ferretti served as Senior Vice President—Head of Energy Investment Banking at Ferris, Baker, Watts Inc., an investment banking firm. At Ferris, Baker, Watts, Mr. Ferretti established and lead a comprehensive energy team, including both equity research and investment banking. From 2004 until joining Ferris, Baker, Watts, Mr. Ferretti served as Managing Director of Ladenburg Thalmann & Company, an investment banking firm. Prior to 2004, Mr. Ferretti served with various companies as Sr. Vice President and as Senior Equity Analyst. During his equity research career, Mr. Ferretti was a member of the New York Society of Security Analysts. Mr. Ferretti was recently elected to the Board of Directors of NGAS Resources, Inc., an independent exploration and production company. Mr. Ferretti holds a Bachelor of Science degree in Economics from Brooklyn College and served in the United States Army, which included a one year tour of duty in Vietnam.

        There are no family relationships among any of the directors or executive officers of the Company. See "Certain Relationships and Related Transactions" for a description of transactions between the Company and its directors, executive officers or their affiliates.

Executive Officers

Name
  Age   Position(s) Held with Cubic   Since  

Calvin A. Wallen, III*

    59   Chairman of the Board, President and Chief Executive Officer     1997  

Jon S. Ross*

    50   Executive Vice President, Corporate Secretary and Director     1998  

Larry G. Badgley

    58   Chief Financial Officer     2008  

See Mr. Wallen's and Mr. Ross's biographies above.

        LARRY G. BADGLEY joined the Company in August 2008, as a consultant, and was appointed Chief Financial Officer in October 2008. He served in that capacity until March 2014, when he served as the Company's Vice President—Finance and Compliance. In August 2014, Mr. Badgley was re-appointed as the Company's Chief Financial Officer. Prior to joining the Company, from October 2005 through September 2006, Mr. Badgley served as Managing Director of BridgePoint Consulting, a provider of CFO services to venture capital-backed and early stage companies. In that capacity,

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Mr. Badgley was primarily responsible for strategic planning for growth companies. From July 1998 through October 2005, Mr. Badgley served as Director of Accounting and Finance for Jefferson Wells International, an international professional services firm. Prior to that time, Mr. Badgley served as Chief Operating Officer and Chief Financial Officer of a privately held national sign manufacturer until its sale in July 1998. Mr. Badgley received a BBA in Finance from Hardin-Simmons University and is a Certified Public Accountant.

Audit Committee; Financial Expert

        The Audit Committee is comprised of Messrs. Brown (Chairman), Howard and Clements. All of the members of the Audit Committee are "independent" under the rules of the SEC. The Board of Directors, after reviewing all of the relevant facts, circumstances and attributes, has determined that Messrs. Howard and Brown satisfy the requirements of an "audit committee financial expert" on the Audit Committee as that term is defined in Item 407(d)(5)(ii) of Regulation S-K promulgated under the Exchange Act by the SEC.

Section 16(a) Beneficial Ownership Reporting Compliance

        Section 16(a) of the Exchange Act requires the Company's directors, executive officers, and holders of more than 10% of the Common Stock to file with the SEC reports of ownership and changes in ownership of Common Stock. SEC regulations require those directors, executive officers, and greater than 10% stockholders to furnish the Company with copies of all Section 16(a) forms they file. Based on the Company's review of such reports, Messrs. Howard, Clements, Ferretti and Brown each filed one Form 4 late. Each such filing reported a single transaction. The Company believes that all other filings were on time during fiscal 2014.

Director Independence

        As of June 30, 2014, our Board had two members from management, Calvin A. Wallen, III, our Chairman, President and Chief Executive Officer and Jon S. Ross, our Executive Vice President and Secretary, and four non-management directors, Gene C. Howard, Bob L. Clements, David B. Brown and Paul R. Ferretti. The Board has determined that each of its non-management members meets the criteria for independence. Because of their management roles, Mr. Wallen and Mr. Ross are not considered independent directors and do not sit on any committees of the Board.

Code Of Business Conduct And Ethics

        The Company has adopted a Code of Business Conduct and Ethics that applies to its directors, officers and employees. A copy of the Code of Business Conduct and Ethics is available in the "Governance" section on the Company's website at www.CubicEnergyInc.com.

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EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

        General.    Our Board of Directors has established a Compensation Committee, comprised entirely of independent non-employee directors, with authority to set all forms of compensation of our executive officers. Messrs. Brown, Ferretti and Howard comprise the Compensation Committee, currently. The Compensation Committee has overall responsibility for our executive compensation policies as provided in a written charter adopted by the Board of Directors. The Compensation Committee is empowered to review and approve the annual compensation and compensation procedures for our executives: the President and Chief Executive Officer, the Chief Financial Officer, and the Executive Vice President and Secretary.When establishing base salaries, cash bonuses and equity grants for each of the executives, the Compensation Committee considers the recommendations of the President and Chief Executive Officer and the Executive Vice President and Secretary, the executive's role and contribution to the management team, responsibilities and performance during the past year and future anticipated contributions, corporate performance, and the amount of total compensation paid to executives in similar positions, and performing similar functions, at other companies for which data was available, as provided by third party compensation studies. The Compensation Committee engaged the compensation consulting practice of a national accounting firm to provide an Executive Compensation Study Proxy Benchmarking Analysis that included compensation for Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Executive Vice President, General Counsel and other management positions. This study, published in December 2013, was built on compensation data from a peer group of 14 companies in the oil and gas industry. It included data from the following companies: Matador Resources Company, Goodrich Petroleum Corporation, Mid-Con Energy Partners, L.P., LRR Energy, L.P., Isramco Incorporated, Abraxas Petroleum Corporation, Gastar Exploration Incorporated, Callon Petroleum Company, Panhandle Oil and Gas Incorporated, Warren Resources Incorporated, PrimeEnergy Corporation, Saratoga Resources Incorporated, Constellation Energy Partners LLC, and PostRock Energy Corporation. The Compensation Committee in setting compensation for Cubic's management team used this information. The Compensation Committee also relied on other outside resources available to them, as well as their general industry experience, in evaluating management compensation.

        The Compensation Committee relies upon its judgment in making compensation decisions, after reviewing the Company's performance and evaluating each executive's performance during the year. The Committee generally does not adhere to formulas or necessarily react to short-term changes in business performance in determining the amount and mix of compensation elements. We incorporate flexibility into our compensation programs and in the assessment process to respond to and adjust for the evolving business environment.

        Compensation Philosophy.    The Compensation Committee's compensation philosophy is to reward executive officers for the achievement of short and long-term corporate objectives and for individual performance. The objective of this philosophy is to provide a balance between short-term goals and long-term priorities to achieve immediate objectives while also focusing on increasing stockholder value over the long term. Also, to ensure that we are strategically and competitively positioned for the future, the Compensation Committee has the discretion to attribute significant weight to other factors in determining executive compensation, such as maintaining competitiveness, pursuing growth opportunities and achieving other long-range business and operating objectives. The level of compensation should also allow us to attract, motivate, and retain talented executive officers who contribute to our long-term success. The compensation of our President and Chief Executive Officer and other executive officers is comprised of cash compensation and long-term incentive compensation in the form of base salary, discretionary bonuses and stock awards.

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        Executive Compensation Components.    Our total compensation for the named executive officers consisted of:

    base salary,

    bonuses and

    long-term equity incentives.

        The Compensation Committee believes that each of these components is necessary to achieve Cubic's objective of retaining highly qualified executives and motivating the named executive officers to maximize stockholder return.

        In setting fiscal 2014 compensation, the Compensation Committee considered the specific factors discussed below:

        Base Salary.    In setting the executive officers' base salaries, the Compensation Committee considers the achievement of corporate objectives as well as individual performance. Because the Compensation Committee believes that executive compensation should be viewed in terms of a balanced combination of cash compensation (i.e., base salaries and bonuses) and long-term incentive (i.e., grants of stock and options), base salaries are targeted to approximate the low end of the range of base salaries paid to executives of similar companies for each position. To ensure that each executive is paid appropriately, the Compensation Committee considers the executive's level of responsibility, prior experience, overall knowledge, contribution to business results, existing equity holdings, executive pay for similar positions in other companies, and executive pay within our company.

        Discretionary Bonuses.    Executive bonuses are intended to link executive compensation with the attainment of Company goals. The actual payment of bonuses is primarily dependent upon the extent to which these Company-wide objectives are achieved. Determination of executive bonus amounts is not made in accordance with a strict formula, but rather is based on objective data combined with competitive ranges and internal policies and practices, including an overall review of both individual and corporate performance. Other than Scott M. Pinsonnault's signing bonus, in April 2014, no bonuses were paid to any other named executive officers during fiscal 2014 or 2013. The President and Chief Executive Officer has the discretion to recommend to the Compensation Committee to increase or decrease bonuses for all other executive officers, but any bonus amounts must be approved by the Compensation Committee.

        Long-Term Incentives.    On December 29, 2005, the stockholders of the Company approved the 2005 Stock Option Plan (the "Plan") under which our executive officers may be, among other forms of compensation, compensated through grants of shares of our Common Stock and/or grants of options to purchase shares of Common Stock. The Compensation Committee approves Plan grants that provide additional incentives and align the executives' long-term interests with those of the stockholders of the Company by tying executive compensation to the long-term performance of the Company's stock price. Annual equity grants for our executives are typically approved in January, but there have been no equity grants during the last 3 fiscal years.

        The Compensation Committee recommends equity to be granted to an executive with respect to shares of Common Stock based on the following principal elements including, but not limited to:

    President and Chief Executive Officer's and Executive Vice President and Secretary's recommendations;

    Management role and contribution to the management team;

    Job responsibilities and past performance;

    Future anticipated contributions;

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    Corporate performance; and

    Existing equity holdings.

        Determination of equity grant amounts is not made in accordance with a formula, but rather is based on objective data combined with competitive ranges, past internal policies and practices and an overall review of both individual and corporate performance. Equity grants may also be made to new executives upon commencement of employment and, on occasion, to executives in connection with a significant change in job responsibility. The Compensation Committee believes annual equity grants more closely align the long-term interests of executives with those of stockholders and assist in the retention of key executives. As such, these grants comprise the Company's principal long-term incentive to executives.

        The following table shows the components of executive compensation for the fiscal years ended June 30, 2014, 2013 and 2012, expressed as percentages of total compensation.

 
   
   
  Percentage of Total Compensation    
 
Name and Principal Position
  Fiscal
Year
  Salary   Bonus   Option
Awards
  All Other
Compensation
  Total  

Calvin A. Wallen, III

    2014     97.6 %           2.4 %   100.0 %

Chairman of the Board,

    2013     97.0 %           3.0 %   100.0 %

President and Chief

    2012     97.2 %           2.8 %   100.0 %

Executive Officer

                                     

Larry G. Badgley

   
2014
   
97.2

%
 
   
   
2.8

%
 
100.0

%

Chief Financial Officer

    2013     96.3 %           3.7 %   100.0 %

    2012     96.6 %           3.4 %   100.0 %

Jon S. Ross

   
2014
   
96.3

%
 
   
   
3.7

%
 
100.0

%

Executive Vice President,

    2013     96.0 %           4.0 %   100.0 %

Secretary and Director

    2012     96.3 %           3.7 %   100.0 %

Scott M. Pinsonnault

   
2014
   
22.4

%
 
75.8

%
 
   
1.8

%
 
100.0

%

Senior Vice President and

    2013                      

Chief Financial Officer (former)

    2012                      

Other Compensation Policies Affecting the Executive Officers

        Stock Ownership Requirements.    The Compensation Committee does not maintain a policy relating to stock ownership guidelines or requirements for our executive officers because the Compensation Committee does not feel that it is necessary to impose such a policy on our executive officers. If circumstances change, the Compensation Committee will review whether such a policy is appropriate for executive officers.

        Employment Agreements.    On February 29, 2008, the Company entered into employment agreements with its President and Chief Executive Officer, Calvin A. Wallen, III, and Executive Vice President and Secretary, Jon S. Ross. The agreement with Mr. Wallen provided for a base salary of $200,000 per year, while the agreement with Mr. Ross provided for a base salary of $150,000 per year. The other terms and conditions of the agreements are substantially consistent.

        Both agreements provide for a term of employment of 36 months from the effective date of February 1, 2008, which term shall be automatically extended by one additional month upon the expiration of each month during the term; provided, that the Company may terminate subsequent one-month extensions at any time. Each agreement is subject to early termination by the Company in the event that the employee dies, becomes totally disabled or commits an act constituting "Just Cause"

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under the agreement. The agreements provide that Just Cause includes, among other things, the conviction of certain crimes, habitual neglect of his duties to the Company or other material breaches by the employee of the agreement. Each agreement also provides that the employee shall be permitted to terminate his employment upon the occurrence of "Good Reason," as defined in the agreement. The agreements provide that Good Reason includes, among other things, a material diminution in the employee's authority, duties, responsibilities or salary, or the relocation of the Company's principal offices by more than 50 miles. If the employee's employment is terminated by (a) the Company other than due to the employee's death, disability or Just Cause, or (b) the employee for Good Reason, then the Company is required to pay all remaining salary through the end of the then-current term. The foregoing severance payment is subject to reduction under certain conditions.

        On January 14, 2011, the Company entered into an employment agreement with its Chief Financial Officer, Larry G. Badgley. The agreement provided for a base salary of $163,800, on an annual basis, and a term of employment of twenty-four (24) months from the effective date of October 1, 2010. The agreement expired on September 30, 2012. The agreement also provided for the grant of stock options for the purchase of an aggregate of 288,667 shares of Company Common Stock.

        On December 16, 2013, the Company entered into amendments to the employment agreements of Messrs. Wallen and Ross. The amendment with Mr. Wallen provides for a base salary of $400,000 per year, while the amendment with Mr. Ross provides for a base salary of $300,000 per year.

        On December 12, 2013, Mr. Badgley's salary increased to $250,000 per year and a health insurance reimbursement up to $1,500 per month. In June 2014, Mr. Badgley's salary decreased to $215,000 per year and a health insurance reimbursement up to $1,500 per month. Following the end of fiscal 2014, Mr Badgley's salary increased to $250,000.

        On March 24, 2014, the Company hired Scott M. Pinsonnault as its Chief Financial Officer and Senior Vice President. Concurrently with his hire, the Company entered into an employment agreement with Mr. Pinsonnault. The agreement provided for a base salary of $325,000, on an annual basis, and a term of employment of three years. The agreement also provided for commencement payments in the aggregate amount of $187,500, as well as eligibility for certain bonuses and incentive compensation. The agreement also provided for a monthly medical expense reimbursement of $1,500. On August 12, 2014, Mr. Pinsonnault resigned as the Company's Chief Financial Officer.

        The following table sets forth the estimated amounts that would be payable to each of the named executives upon a termination under the scenarios outlined above, excluding termination for Just Cause or on account of death or disability, assuming that such termination occurred on June 30, 2014. There can be no assurance that these scenarios would produce the same or similar results as those disclosed if a termination occurs in the future.

Without Just Cause/For Good Reason
  Severance
Payment
  Total  

Calvin A. Wallen, III(1)

  $ 1,200,000   $ 1,200,000  

Jon S. Ross(1)

 
$

900,000
 
$

900,000
 

Scott M. Pinsonnault(2)

 
$

893,750
 
$

893,750
 

(1)
Represents 36 months of base salary.

(2)
Represents base salary for the balance of Mr. Pinsonnault's employment agreement. Mr. Pinsonnault voluntarily resigned following June 30, 2014, with no severance payment by the Company.

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Tax Considerations

        Compliance with Section 162(m) of the Internal Revenue Code.    Section 162(m) disallows a federal income tax deduction to publicly held companies for certain compensation paid to our Named Executive Officers to the extent that compensation exceeds $1 million per executive officer covered by Section 162(m) in any fiscal year. The limitation applies only to compensation that is not considered "performance based" as defined in the Section 162(m) rules. In designing our compensation programs, the Compensation Committee considers the effect of Section 162(m) together with other factors relevant to our business needs. We have historically taken, and intend to continue taking, appropriate actions, to the extent we believe desirable, to preserve the deductibility of annual incentive and long-term performance awards. However, the Compensation Committee has not adopted a policy that all compensation paid must be tax-deductible and qualified under Section 162(m). We believe that the fiscal 2014 base salary, annual bonus and stock grants paid to the individual executive officers covered by Section 162(m) did not exceed the Section 162(m) limit and will be fully deductible under Section 162(m).

Chief Executive Officer Compensation

        Mr. Wallen received $316,667 in base salary during fiscal 2014. During fiscal 2013, Mr. Wallen received an amount of $191,667, slightly less than the base salary provided in his employment agreement, and he received slightly more during fiscal 2012, due to the timing of payroll dates. The excess amount received by Mr. Wallen during fiscal 2012 had the effect of him receiving a reduction in base salary during fiscal 2013 in an equal amount. Mr. Wallen received no Common Stock awards during fiscal 2014, 2013 or 2012.

Chief Financial Officer Compensation

        Mr. Badgley served as the Company's Chief Financial Officer until March 2014, at a salary of $250,000 per year and up to a $1,500 per month health insurance subsidy. In March 2014, Mr. Pinsonnault was retained as the Company's Chief Financial Officer, at a base salary of $325,000 per year, plus a $1,500 per month health insurance subsidy.

        On August 12, 2014, Mr. Pinsonnault, resigned. The Company and Mr. Pinsonnault agreed that his resignation would be effective immediately.

        Mr. Badgley was reappointed as the Company's Chief Financial Officer, contemporaneously with Mr. Pinsonnault's resignation, in August 2014. In connection with such appointment, Mr. Badgley's base salary was reestablished at $250,000, on an annual basis.

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Summary Compensation Table

        The following table shows information regarding the compensation earned during the fiscal years ended June 30, 2014 and 2013 by our Chief Executive Officer, each person who served as our Chief Financial Officer during 2014, and our other most highly compensated executive officer who was employed by us as of June 30, 2014 and whose total compensation exceeded $100,000 during the most recent fiscal year (the "Named Executive Officers"):

Name and Principal Position
  Fiscal
Year
  Salary   Bonus   Option
Awards
  All Other
Compensation(1)
  Total  

Calvin A. Wallen, III

    2014   $ 316,667   $   $   $ 7,706   $ 324,373  

Chairman of the Board, President

    2013   $ 191,667   $   $   $ 6,000   $ 197,667  

and Chief Executive Officer

    2012   $ 208,333   $   $   $ 6,000   $ 214,333  

Larry G. Badgley

   
2014
 
$

208,659
 
$

 
$

 
$

5,946
 
$

214,605
 

Chief Financial Officer

    2013   $ 156,975   $   $   $ 6,000   $ 162,975  

    2012   $ 170,625   $   $   $ 6,000   $ 176,625  

Jon S. Ross

   
2014
 
$

237,500
 
$

 
$

 
$

9,238
 
$

246,738
 

Executive Vice President, Secretary

    2013   $ 143,750   $   $   $ 6,000   $ 149,750  

and Director

    2012   $ 156,250   $   $   $ 6,000   $ 162,250  

Scott M. Pinsonnault(2)

   
2014
 
$

55,500
 
$

187,500
 
$

 
$

4,500
 
$

247,500
 

Senior Vice President and Chief

    2013   $   $   $   $   $  

Financial Officer (former)

    2012   $   $   $   $   $  

(1)
All Other Compensation consists solely of a reimbursement towards each officer's medical insurance premiums in an amount not to exceed $1,500 per month since December 2013 and $500 per month prior to December 2013,. The Company does not provide group health insurance coverage to its employees.

(2)
Mr. Pinsonnault served as the Company's Chief Financial Officer from March 2014 until August 2014.

Fiscal 2014 Grants of Plan-Based Awards

        No grants of any plan-based awards were made to our executive officers during fiscal 2014.

Stock Grants

        On January 24, 2013, the Company paid cash of $13,000 and issued 72,500 shares of Common Stock to four non-employee directors of the Company pursuant to the 2005 Stock Option Plan (the "Plan"). As of such date, the aggregate market value of the Common Stock granted was $15,225 based on the last sale price ($0.21 per share) on January 24, 2013, on the NYSE—MKT of the Company's Common Stock. Such amount was expensed upon issuance to compensation expense.

        On April 4, 2013, the Company paid cash of $13,000 and issued 72,500 shares of Common Stock to four non-employee directors of the Company pursuant to the Plan. As of such date, the aggregate market value of the Common Stock granted was $19,213 based on the last sale price ($0.265 per share) on April 4, 2013, on the NYSE-MKT of the Company's Common Stock. Such amount was expensed upon issuance to compensation expense.

        On July 5, 2013, the Company paid cash of $17,000 and issued 72,500 shares of Common Stock to four non-employee directors of the Company pursuant to the Plan. As of such date, the aggregate market value of the Common Stock granted was $20,300 based on the last sale price ($0.28 per share)

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on July 5, 2013, on the NYSE—MKT of the Company's Common Stock. Such amount was expensed upon issuance to compensation expense.

        On October 7, 2013, the Company paid cash of $17,000 and issued 72,500 shares of Common Stock to four non-employee directors of the Company pursuant to the Plan. As of such date, the aggregate market value of the Common Stock granted was $30,450 based on the last sale price ($0.42 per share) on October 7, 2013, on the OTC Markets of the Company's Common Stock. Such amount was expensed upon issuance to compensation expense.

Outstanding Equity Awards at Fiscal Year-End

        The following table set forth certain information, as of June 30, 2014, regarding stock option grants by the Company:

Name
  Number of
Securities
underlying
unexercised
options
exercisable
  Number of
Securities
underlying
unexercised
options
unexercisable
  Option
exercise
price
  Option
expiration date

Larry G. Badgley

    288,667       $ 1.20   October 1, 2015

Option Exercises and Stock Vesting

        No stock options were exercised or stock grants to our executive officers vested at any time during fiscal 2014.

Information Related to Stock-Based Compensation

        The Company accounts for its stock-based employee compensation plans pursuant to FASB ASC Topic 718—Stock Compensation. ASC Topic 718 requires all share-based payments to employees, including grants of employee stock options, to be recognized in our consolidated statements of operations based on their estimated fair values. We recognize expense on a straight-line basis over the vesting period of the option.

Pension Benefits and Non-Qualified Defined Contribution Plans

        The Company does not sponsor any qualified or non-qualified defined benefit plans or non-qualified defined contribution plans. The Compensation Committee, which is comprised solely of "outside directors" as defined for purposes of Section 162(m) of the Code, may elect to adopt qualified or non-qualified defined benefit or non-qualified defined contribution plans if the Compensation Committee determines that doing so is in our best interests.

Non-Employee Director Compensation for Fiscal 2014

        Our philosophy in determining director compensation is to align compensation with the long-term interests of the stockholders, adequately compensate the directors for their time and effort, and establish an overall compensation package that will attract and retain qualified directors. In determining overall director compensation, we seek to strike the right balance between the cash and stock components of director compensation. The Board's policy is that the directors should hold equity ownership in the Company and that a portion of the director fees should consist of Company equity in the form of stock grants. The policy of the Company is and has always been that only non-management Directors receive compensation for service as a Director.

        In June 2014, the Company's Board of Directors engaged a third party compensation consulting firm to study and review the Board's compensation practices. This study included a peer group of 17

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small-cap oil and gas companies to compare Cubic's compensation practices and policies. The companies included in the peer group study were: Abraxas Petroleum Corporation, Approach Resources Incorporated, Bonanza Creek Energy Incorporated, BPZ Resources Incorporated, Callon Petroleum Company, Emerald Oil Incorporated, Endeavour International Corporation, Forest Oil Corporation, Gastar Exploration Incorporated, Goodrich Petroleum Corporation, Matador Resources Company, Miller Energy Resources Incorporated, Panhandle Oil and Gas Incorporated, Penn Virginia Corporation, PetroQuest Energy Incorporated, Swift Energy Company and Warren Resources Incorporated. One of the key observations was that Cubic ranked near the bottom of the group in total director compensation. Based on the aforementioned study the Board modified its compensation, effective July 1, 2014. The Compensation Committee amended non-management Director Compensation to include a cash fee of $18,000 to be paid quarterly, at the beginning of each quarter. The Audit Committee Chair receives an additional cash payment of $2,500 to be paid quarterly, at the beginning of each quarter.

        Our director compensation during fiscal 2014 was as follows:

    Prior to January 24, 2013, director compensation included: A meeting fee of $1,000 when attending in person and $500 when attending via teleconference [not to exceed a fee of $1,000 in any one day] for each Board or committee meeting attended; and annual stock grants of 40,000 shares of Common Stock for service on the Board of Directors; 20,000 shares of Common Stock for service on the Audit Committee; 10,000 shares of Common Stock for service on the Compensation Committee and/or the Nominating Committee; and an additional 10,000 shares of Common Stock for serving as the financial expert and Chairman of the Audit Committee.

    Beginning January 24, 2013, the Compensation Committee amended non-management Director Compensation to include: A quarterly cash fee of $4,000 cash per quarter (meeting payments discontinued) and the Audit Committee Chair received an additional $1,000 cash per quarter; and quarterly stock grants of 10,000 shares of Common Stock for service on the Board of Directors; 5,000 shares of Common Stock for service on the Audit Committee; 2,500 shares of Common Stock for service on the Compensation Committee and/or the Nominating Committee; and an additional 2,500 shares of Common Stock for serving as the financial expert and Chairman of the Audit Committee.

        The following table sets forth the cash and other compensation paid to the non-employee members of our Board of Directors in fiscal 2014.

Name
  Fees Earned
or Paid in
Cash
  Stock
Awards(1)
  Total  

Gene C. Howard

  $ 36,080   $ 14,000   $ 50,080  

Bob L. Clements

    33,883     12,250     46,133  

David B. Brown

    39,080     14,000     53,080  

Paul R. Ferretti

    33,185     10,500     43,685  
               

Totals

  $ 142,228   $ 50,750   $ 192,978  
               
               

(1)
The market value of these stock awards is based on the closing price on the grant date, which was $0.28 on July 3, 2013 and $0.42 on October 7, 2013, respectively.

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CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE

        On July 14, 2014, following a competitive process undertaken by the Audit Committee, the Audit Committee approved the selection of BDO USA, LLP ("BDO") to serve as our independent registered public accounting firm for the fiscal year ended June 30, 2014. Vogel CPAs, PC (formerly Philip Vogel & Co. PC) ("Vogel") was notified on July 15, 2014 that it will not be retained as our independent registered public accounting firm for the fiscal year ended June 30, 2014.

        The audit reports of Vogel on our consolidated financial statements as of and for the fiscal years ended June 30, 2013 and 2012 did not contain an adverse opinion or disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope or accounting principles, except that as to its audit report for the fiscal year ended June 30, 2012, Vogel's report included a qualification as to its substantial doubt regarding our ability to continue as a going concern.

        During our two most recent fiscal years and the subsequent interim period prior to the engagement of BDO, we did not consult with BDO regarding (a) the application of accounting principles to a specified transaction, either completed or proposed; (b) the type of audit opinion that might be rendered on our financial statements; or (c) any matter that was the subject of a disagreement or reportable event as defined in Items 304(a)(1)(iv) and (v), respectively, of Regulation S-K with Vogel.

        There are no disagreements with our accounting and financial disclosure.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

        Our estimated audit fees for services provided by BDO USA, LLP, our independent registered accounting firm, are $255,000 for professional services rendered for the year ended June 30, 2014. There were no fees incurred by BDO USA, LLP for the year ended June 30, 2013.

Audit Committee Pre-Approval Policies and Procedures

        In accordance with Company policy, any additional audit or non-audit services must be approved in advance. All of the foregoing professional services provided by Vogel-CPAs, PC (formerly Philip Vogel & Co., PC) during the years ended June 30, 2014 and June 30, 2013 were pre-approved in accordance with the policies of our Audit Committee.

Family Relationships

        There are no family relationships between or among the directors and executive officers.

Compensation Committee Interlocks and Insider Participation

        No interlocking relationship exists between our Board of Directors and the Board of Directors or compensation committee of any other company, nor has any interlocking relationship existed in the past.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS.

        The following table sets forth the number of shares of the Company's Common Stock beneficially owned, as of November 28, 2014 by (i) each person known to the Company to beneficially own more than 5% of the Common Stock of the Company (the only class of voting securities now outstanding), (ii) each director and Named Executive Officer, and (iii) all directors and executive officers as a group. Unless otherwise indicated, we consider all shares of Common Stock that can be issued under convertible securities or warrants currently or within 60 days of November 28, 2014 to be outstanding for the purpose of computing the percentage ownership of the person holding those securities, but do not consider those securities to be outstanding for computing the percentage ownership of any other person. Each owner's percentage is calculated by dividing the number of shares beneficially held by that owner by the sum of 77,505,908, plus the number of shares that owner has the right to acquire within 60 days.

Name and Address
  Number
of Shares
  Approximate
Percent of
Class(1)
 

5% Stockholders

             

Funds managed by Anchorage Capital Group, LLC

   
74,811,987

(2)
 
49.1

%

610 Broadway, 6th Floor, New York, NY 10012

             

Funds managed by O-Cap Management, L.P. 

    23,939,836 (2)   23.6 %

600 Madison Ave., 14th Floor, New York, NY 10022

             

William L. Bruggeman, Jr. 

    17,666,471 (3)   22.8 %

20 Anemone Circle, North Oaks, MN 55127

             

Wells Fargo Energy Capital, Inc. 

    8,939,154 (4)   10.3 %

1000 Louisiana 9th Floor, Houston, TX 77002

             

Named Executive Officers and Directors

   
 
   
 
 

Calvin A. Wallen, III

   
53,188,482

(5)
 
47.3

%

9870 Plano Road, Dallas, TX 75238

             

Bob L. Clements

    1,360,027 (6)   1.8 %

9870 Plano Road, Dallas, TX 75238

             

Gene C. Howard

    1,020,180 (7)   1.3 %

2402 East 29th St., Tulsa, OK 74114

             

Jon S. Ross

    433,000 (8)   *  

9870 Plano Road, Dallas, TX 75238

             

Paul R. Ferretti

    183,507     *  

8 Edgewood Road, Yardley, PA 19067

             

David B. Brown

    243,507     *  

9870 Plano Road, Dallas, TX 75238

             

Larry G. Badgley

    288,667 (9)   *  

9870 Plano Road, Dallas, TX 75238

             

Scott M. Pinsonnault

        *  

9870 Plano Road, Dallas, TX 75238

             

All officers and directors as a group (8 persons)

    56,717,370     51.7 %

*
Denotes less than one percent

(1)
Based on a total of 77,505,908 shares of Common Stock issued and outstanding on November 28, 2014.

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(2)
Consists of warrants to purchase shares of Common Stock. The holders of such warrants also hold Series C Redeemable Voting Preferred Stock that gives the holders the right to vote the shares subject to such warrants on an "as-converted" basis. The holders of these securities are parties to a voting agreement with Mr. Wallen pursuant to which they have agreed to vote together on certain matters.

(3)
Includes 2,734,000 shares held by Diversified Dynamics Corporation, a company controlled by William Bruggeman; and, 14,932,471 shares owned by Mr. and Mrs. Bruggeman, as joint tenants with rights of survivorship.

(4)
Includes warrants to purchase 8,500,000 shares and 439,154 shares issuable upon conversion of the 219.577 shares of Series B Convertible Preferred Stock of the Company. The Series B Convertible Preferred Stock votes with the Common Stock, on an as-converted basis.

(5)
Includes: (a) 16,333,548 shares directly held by Mr. Wallen; (b) 500,000 shares held by Mr. Wallen's spouse, (c) 874,000 shares held by certain children of Mr. Wallen; (d) 700,000 shares held by Tauren Exploration, Inc., a corporation wholly owned by Mr. Wallen; (e) 3,952,368 shares issuable upon conversion of 1,976.184 shares of Series B Convertible Preferred Stock of the Company held by Tauren; (f) 24,974,568 shares issuable upon conversion of 12,487.284 shares of Series B Convertible Preferred Stock of the Company held by Langtry Mineral & Development, LLC, an entity controlled Mr. Wallen; and (g) 4,644,032 shares issuable upon conversion of 2,322.016 shares of Series B Convertible Preferred Stock of the Company directly held by Mr. Wallen. The Series B Convertible Preferred Stock votes with the Common Stock, on an as-converted basis.

(6)
Includes 390,287 shares held as joint tenants with rights of survivorship.

(7)
Includes 322,245 shares are held by Mr. Howard's spouse, of which Mr. Howard disclaims beneficial ownership.

(8)
Includes 6,000 shares held by minor children.

(9)
Includes 288,667 shares subject to a currently exercisable stock option.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Relationships and Related Transactions

        On December 1, 1997, as renewed and revised on January 1, 2002, the Company entered into a contract with Tauren to provide the necessary technical, administrative and management expertise needed to conduct its business. Tauren also paid various organization costs and consulting fees on behalf of the Company. The monthly amount charged to the Company was based on actual costs of materials and labor hours of Tauren that were used pursuant to the terms of the agreement. The agreement was terminated effective January 1, 2006, except as to the office sharing provisions, which were extended to June 30, 2007 and since continue on a month to month basis. The Company now has 13 full-time employees and one part-time employee and its offices are leased from Tauren. Effective, January 1, 2011, the Company signed a 2-year lease that charges the Company a monthly fee of $8,000 per month, with Tauren. Effective, January 1, 2013, the Company signed a lease extension through September 30, 2013 and then through March 31, 2014. The Company then agreed to a month-to-month lease that charges the Company $8,000 per month. Charges to the Company under the contracts and subsequent arrangements were $96,000 and $96,000 for the fiscal years 2014 and 2013.

        Tauren owned a working interest in the wells in which the Company owns a working interest. As of the end of fiscal 2014 Tauren owed $3,333 to the Company, and as of the end of fiscal 2013 the Company owed $6,166 to Tauren for miscellaneous general and administrative expenses and royalties.

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Tauren owed the Company $2,765 and $38,756 for royalties paid by a third-party operator for fiscal years 2014 and 2013, respectively.

        In addition, certain of the Company's working interests are operated by an affiliated company, Fossil Operating, Inc. ("Fossil"), which is owned 100% by the Company's President and Chief Executive Officer, Calvin A. Wallen III. At the end of fiscal years 2014 and 2013, the Company owed Fossil $33,533 and $0, respectively, for capital expenditures, the Company owed Fossil $264,705 and $27,949, respectively, for drilling costs and lease and operating expenses, and was owed by Fossil $65,650 and $28,897, respectively, for oil and gas sales.

        In addition, during fiscal 2014 and 2013, certain wells in which the Company owns a working interest were operated by Fossil. In consideration for Fossil serving as operator and to satisfy the Company's working interest obligations related to drilling costs and lease operating expenses, Cubic paid to Fossil an aggregate of $4,045,580 and $439,874, during fiscal 2014 and 2013, respectively; and Fossil paid Cubic an aggregate of $347,905 and $252,532, during fiscal 2014 and 2013, respectively for oil and gas sales.

        On December 18, 2009, the Company issued the Wallen Note, which is subordinated to all WFEC indebtedness. The Wallen Note bore interest at the prime rate plus one percent (1%), and originally provided for interest payable monthly. The proceeds of the Wallen Note were used to repay the previous indebtedness of the Company that was payable to a former director. The Wallen Note was cancelled as part of the overall capital refinancing of the Company following June 30, 2013 (see Note E to the Consolidated Financial Statements for the years ended June 30, 2014 and 2013—Long-Term Debt).

Review, Approval or Ratification of Transactions with Related Persons

        Although we have adopted a Code of Business Ethics and Control, we still rely on our Board to review related party transactions on an ongoing basis to prevent conflicts of interest. Our Board reviews a transaction in light of the affiliations of the director, officer or employee and the affiliations of such person's immediate family. Transactions are presented to our Board for approval before they are entered into or, if this is not possible, for ratification after the transaction has occurred. If our Board finds that a conflict of interest exists, then it will determine the appropriate remedial action, if any. Our Board approves or ratifies a transaction if it determines that the transaction is consistent with the best interests of the Company.

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DESCRIPTION OF SECURITIES

        The following is a summary of the current material terms of our capital stock. Because it is only a summary, it does not contain all information that may be important to you. Therefore, you should read carefully the more detailed provisions of our amended and restated certificate of formation and by-laws, as well as the certificates of designations establishing our three existing series of preferred stock. For information on how to obtain copies of our amended and restated certificate of formation and by-laws, see "Where You Can Find More Information."

General

        As of the date of this prospectus, our authorized capital stock consists of 400,000,000 shares of common stock, $0.05 par value per share, and 10,000,000 shares of preferred stock, $0.01 par value per share. No other classes of stock are authorized or expected to be authorized under our amended and restated certificate of formation.

Common Stock

        Each holder of our common stock is entitled to one vote for each share of common stock held of record by such holder. Holders of our common stock, voting as a single class, are entitled to elect all of the directors of the Company. Matters submitted for shareholder approval generally require a majority vote. Holders of our common stock are entitled to receive ratably such dividends as may be declared by our board out of funds legally available therefor. Upon our liquidation, dissolution or winding up, holders of our common stock would be entitled to share ratably in our net assets. Holders of our common stock have no preemptive, redemption, conversion or other subscription rights.

        As of the date of this prospectus, there are 77,505,908 issued and outstanding shares of our common stock, duly authorized, validly issued, fully paid and nonassessable.

        The registrar and transfer agent for our common stock is Securities Transfer Corporation, 2591 Dallas Parkway, Suite 102, Frisco, Texas 75034-8543, (469) 633-0101.

Preferred Stock

        Our board has the power, without further vote of shareholders, to authorize the issuance of up to 10,000,000 shares of our preferred stock and to fix and determine the terms, limitations and relative rights and preferences of any shares of our preferred stock. This power includes the authority to establish voting, dividend, redemption, conversion, liquidation and other rights of any such shares. Our preferred stock may be divided into such number of series as our board determines.

        Our board of directors has established three series of preferred stock, one of which has been cancelled:

    Series A Convertible Preferred Stock—Our Series A Convertible Preferred Stock was cancelled in February 2014.

    Series B Convertible Preferred Stock—Our Series B Convertible Preferred Stock has a stated value of $1000 per share, is entitled to dividends in the amount of 9.5% per annum and is convertible into our common stock at $0.50 per share of common stock. The holders of the Series B Convertible Preferred Stock are entitled to vote (on an as-converted basis), together with holders of our common stock, as a single class with respect to all matters presented to holders of our common stock. As of November 21, 2014, there are 17,748.933 shares of Series B Convertible Preferred Stock outstanding.

    Series C Redeemable Voting Preferred Stock—The Series C Redeemable Voting Preferred Stock has a stated value of $0.01 per share. The holders of Series C Redeemable Voting Preferred

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      Stock are entitled to vote, together with the holders of our common stock, as a single class with respect to all matters presented to holders of common stock. The holders of Series C Redeemable Voting Preferred Stock are entitled, in the aggregate, to a number of votes equal to the number of shares of common stock that would be issuable upon the exercise of all of the outstanding Class A Warrants and Class B Warrants (as defined below) on a Full Physical Settlement basis (as defined in the Warrant and Preferred Stock Agreement). The holders of Series C Redeemable Voting Preferred Stock are not entitled to receive any dividends. The Series C Redeemable Voting Preferred Stock may be redeemed at the option of the holders thereof at any time at the stated value per share. There were 98,751.823 shares of Series C preferred stock issued and outstanding as of September 30, 2014.

CONTROLS AND PROCEDURES.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

        Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by the financial statements included in this Prospectus. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were not effective to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

        In September and October 2014, we identified material weaknesses in our internal controls over financial reporting in connection with our (i) financial reporting and disclosure process (ii) accounting for asset retirement obligations and (iii) accounting for certain complex accounting transactions. The first material weakness, our financial reporting and disclosure process, resulted in additional disclosures and amendments to our quarterly reports for the quarterly periods ended September 30, 2013, December 31, 2013 and March 31, 2014 necessary to present the financial statements in accordance with accounting principles generally accepted in the United States. The second material weakness, our accounting for asset retirement obligations (ARO), resulted in our inappropriate estimation of the ARO related to the properties acquired in our acquisitions in Fiscal 2014. Our third material weakness, our accounting for certain complex accounting transactions, resulted in an incorrect accounting treatment related to the warrants that were issued together with the Notes. The warrants contained 'full-ratchet' anti-dilution adjustment provisions that were not properly accounted for. Additionally, certain warrants that were re-priced in 2013 and 2014 also contained certain anti-dilution provisions that were not accounted for correctly since their issuance date. Finally, we did not apply the proper accounting for the exchanges of certain related party debt and equity instruments in transactions that were deemed equity contributions.

        We note that there are inherent limitations on the effectiveness of internal controls, as they cannot prevent collusion, management override or failure of human judgment. If we fail to maintain an effective system of internal controls or if management or our independent registered public accounting firm were to discover material weaknesses in our internal controls, we may be unable to produce reliable financial reports or prevent fraud, and it could harm our financial condition and results of operations, result in a loss of investor confidence and negatively impact our share price.

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Management's Report on Internal Control Over Financial Reporting

        Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an assessment, including testing, of the effectiveness of our internal control over financial reporting as of June 30, 2014 based on the criteria set forth in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

        Based on our evaluation under the criteria set forth in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was not effective as of June 30, 2014. Management found the following material weaknesses: (i) financial reporting and disclosure process, (ii) accounting for asset retirement obligation and (iii) accounting for certain complex transactions. This Prospectus does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. We were not required to have, nor have we engaged our independent registered public accounting firm to perform, an audit on our internal control over financial reporting pursuant to the rules of the Securities and Exchange Commission that permit us to provide only management's report in this Prospectus.

Changes in Internal Control Over Financial Reporting

        We maintain a system of internal control over financial reporting. There were material weaknesses in our internal control over financial reporting during the fourth quarter of fiscal 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The Company needs to hire qualified experts to review complex transactions like those done, in October 2013, to insure all items are receiving proper accounting treatment.

Inherent Limitations on Internal Control

        A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple errors. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

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SELLING SHAREHOLDERS

        This prospectus relates to the registration of shares issuable upon exercise of warrants to purchase shares of our common stock. Because the shares issuable upon exercise of these warrants will be issued pursuant to an exemption from registration provided by Section 4(2) of the Securities Act and the issuance of those shares was not registered with the SEC, upon exercise the selling shareholders would hold "restricted stock." Prior to these transactions, none of the selling shareholders had any material relationship with the Company.

        The following table sets forth, to the best of our knowledge, information concerning the selling shareholders, the number of shares currently held by the selling shareholders, the number of shares to be offered and sold by the selling shareholders and the amount and percentage of common stock that will be owned by the selling shareholders following the offering (assuming the sale of all shares of common stock being offered) by the selling shareholders. Each selling shareholder's percentage is calculated by dividing the number of shares beneficially held by that selling shareholder by the sum of 77,505,908, the number of shares outstanding on November 21, 2014, plus the number of shares that selling shareholder has the right to acquire upon exercise of the Warrants.

 
  Number of Shares and Percent
Owned Before Offering
   
  Number of
Shares and
Percent Owned
After Offering
 
Name of Selling Shareholder
  No. of
Shares
  Warrant
Shares
  Percent
of Class
  Shares
Offered
  No. of
Shares
  Percent
of Class
 

Anchorage Illiquid Opportunities Offshore Master III, L.P.(1)

    -0-     12,341,658     13.7 %   12,341,658     -0-      

Anchorage Illiquid Opportunities III (B), L.P.(1)

    -0-     14,124,129     15.4 %   14,124,129     -0-      

AIO III AIV 3, LLC(1)

    -0-     48,346,200     38.4 %   48,346,200     -0-      

Corbin Opportunity Fund, L.P.(2)

    -0-     16,458,637     17.5 %   16,458,637     -0-      

O-CAP Partners, L.P.(3)

    -0-     4,286,727     5.2 %   4,286,727     -0-      

O-CAP Offshore Master Fund, L.P.(3)

    -0-     3,194,472     4.0 %   3,194,472     -0-      
                               

Total

    -0-     98,751,823           98,751,823     -0-        

(1)
Anchorage Capital Group LLC ("ACG") is the investment advisor to each of Anchorage Illiquid Opportunities Offshore Master III, L.P., Anchorage Illiquid Opportunities III (B), L.P. and AIO III AIV 3, L.L.C. (collectively, the "Anchorage Funds"). Anchorage Advisors Management LLC ("Anchorage Management") is the sole managing member of ACG. Mr. Anthony Davis is the president of ACG and a managing member of Anchorage Management. Mr. Kevin Ulrich is the chief executive officer of ACG and the senior managing member of Anchorage Management. The mailing address of each of the Anchorage Funds is 610 Broadway, 6th Floor, New York, NY 10012.

(2)
The address of such holder is 590 Madison Avenue, 31st Floor, New York, NY 10022. Michael E. Olshan and Jared S. Sturdivant have shared voting and dispositive power over these shares. Corbin Capital Partners, L.P ("Corbin Capital") is the investment manager of Corbin Opportunity Fund, L.P. ("Corbin") and pursuant to certain terms of the investment sub-advisory contract with O-CAP Management, L.P., Corbin Capital may also be deemed to have shared dispositive and shared voting power with respect to these shares.

(3)
The address of such holder is 600 Madison Avenue, 14th Floor, New York, NY 10022. Michael E. Olshan and Jared S. Sturdivant have shared voting and dispositive power over these shares.

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PLAN OF DISTRIBUTION

        As of the date of this prospectus, we have not been advised by the selling stockholders as to any plan of distribution. Distributions of the shares by the selling stockholders, or by their partners, pledgees, donees (including charitable organizations), transferees or other successors in interest, may from time to time be offered for sale either directly by such persons, or through underwriters, dealers or agents or on any exchange on which the shares may from time to time be traded, in the over-the-counter market, or in independently negotiated transactions or otherwise. The methods by which the shares may be sold include:

    a block trade (which may involve crosses) in which the broker or dealer so engaged will attempt to sell the securities as agent but may position and resell a portion of the block as principal to facilitate the transaction;

    purchases by a broker or dealer as principal and resale by such broker or dealer for its own account pursuant to this prospectus;

    exchange distributions and/or secondary distributions;

    sales in the over-the-counter market;

    underwritten transactions;

    ordinary brokerage transactions and transactions in which the broker solicits purchasers;

    and privately negotiated transactions.

        Such transactions may be effected by the selling stockholders at market prices prevailing at the time of sale or at negotiated prices. The selling stockholders may effect such transactions by selling the Common Stock to underwriters or to or through broker-dealers, and such underwriters or broker-dealers may receive compensations in the form of discounts or commissions from the selling stockholders and may receive commissions from the purchasers of the Common Stock for whom they may act as agent. The selling stockholders may agree to indemnify any underwriter, broker-dealer or agent that participates in transactions involving sales of the shares against certain liabilities, including liabilities arising under the Securities Act. We have agreed to register the shares for sale under the Securities Act and to indemnify the selling stockholders and each person who participates as an underwriter in the offering of the shares against certain civil liabilities, including certain liabilities under the Securities Act.

        In connection with sales of the Common Stock under this prospectus, the selling stockholders may enter into hedging transactions with broker-dealers, who may in turn engage in short sales of the Common Stock in the course of hedging the positions they assume. The selling stockholders also may sell shares of Common Stock short and deliver them to close out the short positions, or loan or pledge the shares of Common Stock to broker-dealers that in turn may sell them.

        The selling stockholders and any underwriters, dealers or agents that participate in distribution of the shares may be deemed to be underwriters, and any profit on sale of the shares by them and any discounts, commissions or concessions received by any underwriter, dealer or agent may be deemed to be underwriting discounts and commissions under the Securities Act.

        There can be no assurances that the selling stockholders will sell any or all of the shares offered under this prospectus.

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LEGAL MATTERS

        The validity of the shares of common stock offered hereby has been passed upon by Gray Reed & McGraw PC, Dallas, Texas.


WHERE YOU CAN FIND MORE INFORMATION

        We have filed with the SEC a registration statement on Form S-1 under the Securities Act that registers the common stock to be sold by this prospectus. This prospectus does not contain all of the information set forth in the registration statement and the exhibits filed as part of the registration statement. For further information with respect to us and our common stock, we refer you to the registration statement and the exhibits filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other document are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed. Each statement in this prospectus relating to a contract or document filed as an exhibit is qualified in all respects by the filed exhibit.

        In addition, we file annual, quarterly and periodic reports, proxy statements and other information with the SEC. You may read and copy any document we file with the SEC at the SEC's public reference room at 100 F Street NE, Washington, D.C. 20549. You may obtain information on the operation of the SEC's public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street NE, Washington, D.C. 20549-1004. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible through the Internet at that website. We maintain an Internet website at http://www.cubicenergyinc.com.

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CUBIC ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

 
  Page  

FINANCIAL STATEMENTS AT JUNE 30, 2014 AND 2013, AND FOR THE TWO YEARS ENDED JUNE 30, 2014

       

Report of Independent Registered Public Accounting Firms

   
F-2
 

Balance Sheets

   
F-4
 

Statements of Operations

   
F-5
 

Statements of Changes in Stockholders' Equity

   
F-6
 

Statements of Cash Flows

   
F-7
 

Notes to Financial Statements

   
F-8
 

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AT SEPTEMBER 30, 2014 AND JUNE 30, 2014, AND FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014

   
 
 

Condensed Consolidated Balance Sheets As of September 30, 2014 (unaudited) and June 30, 2014

   
F-43
 

Condensed Consolidated Statements of Operations (unaudited) For the three months ended September 30, 2014 and 2013

   
F-44
 

Condensed Consolidated Statements of Cash Flows (unaudited) For the three months ended September 30, 2014 and 2013

   
F-45
 

Notes to Condensed Consolidated Financial Statements (unaudited)

   
F-46
 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Cubic Energy, Inc.,

        We have audited the accompanying consolidated balance sheet of Cubic Energy, Inc., a Texas corporation, as of June 30, 2014, and the related consolidated statements of operations, of changes in stockholders' deficit and of cash flows for the year then ended. 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 audit.