10-K/A 1 a14-14406_310ka.htm AMENDMENT TO ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

ANNUAL REPORT

FORM 10-K/A

(Amendment No.4)

PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED JUNE 30, 2013

COMMISSION FILE NUMBER 001-34144

CUBIC ENERGY, INC.

(Exact Name of Registrant as Specified in its Charter)

TEXAS		87-0352095
(State of Incorporation)		(I.R.S. Employer Identification No.)

9870 PLANO ROAD, DALLAS, TEXAS 75238

(Address of Principal Executive Offices)

972-686-0369

(Registrant’s Telephone Number)

Securities registered pursuant to Section 12(b) of the Act:

Title of Class		Name of Exchange on Which Registered
None		Not Applicable

Securities registered under Section 12(g) of the Act: Common Stock, $0.05 par value

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No x

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 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		Smaller reporting company x

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

State the aggregate market value of the common stock, par value $0.05 per share, held by non-affiliates computed by reference to the price at which the common stock was last sold, as of the last business day of the registrant’s most recently completed second fiscal quarter: As of December 31, 2012 the aggregate market value held by non-affiliates was $7,612,332.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: As of October 8, 2013, there were 77,505,908 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

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Explanatory Note

This Amendment No. 4 to the Annual Report on Form 10K/A amends Note J - Oil and gas reserves information (unaudited) in the Notes to Financial Statements.

Special note regarding forward-looking statements

This annual report on Form 10-K 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 of this report and other sections of this report, 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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CUBIC ENERGY, INC.

TABLE OF CONTENTS

		Page
PART I

Item 1.	Business	1
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 8.	Financial Statements and Supplementary Data	51
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	51
Item 9A.	Controls and Procedures	51
Item 9B.	Other Information	52

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	52
Item 11.	Executive Compensation	55
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	62
Item 13.	Certain Relationships and Related Transactions, and Director Independence	64
Item 14.	Principal Accounting Fees and Services	66

PART IV

Item 15.	Exhibits and Financial Statement Schedules	67

iii

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PART I

Item 1. Business.

GENERAL

Cubic Energy, Inc. (referred to as “Cubic”, “we”, “our”, “us” or the “Company”) 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, 2013, our total proved reserves were 45,177,522 Mcfe.

RECENTLY COMPLETED FINANCING AND ACQUISITIONS

On October 2, 2013, the Company consummated all of the following transactions, which are referred to herein, collectively, as the “Recent Transactions.” This date will be considered as the effective date for the purposes of recording the acquisitions and new operations on the books and records of Cubic.

Formation of New Subsidiaries

The Company 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

The Company entered into a Note Purchase Agreement dated October 2, 2013 (the “Note Purchase Agreement”), pursuant to which the Company issued an aggregate of $66.0 million of senior secured notes due October 2, 2016 (the “Notes”) to certain purchasers. The Notes bear 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 shall be paid 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 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.

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 32,917,275 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 98,751.824 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.

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Investment Agreement and Voting Agreement

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 Calvin A. Wallen, III, the Company’s 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 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.

Registration Rights Agreement

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.

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.

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, the Company assigned all of its previously held oil and gas interests that it held in Northwest Louisiana to Cubic Louisiana (the “Legacy Louisiana Assets”). 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 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,

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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. The other oil and gas properties of Cubic and its other subsidiaries, 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

The Company 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. 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 the 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.

Acquisition of Properties from Gastar

The Company consummated the transactions contemplated by the previously announced 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 $39,118,830, 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 Cubic, such amounts were netted effective January 1, 2013 and will be recorded as an adjustment to the purchase price.

Acquisition of Properties from Navasota

On September 27, 2013, the Company 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, the Company acquired proven 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 by the Company was $19,400,000, prior to certain post-closing adjustments.

Acquisition of Properties from Tauren

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., an entity controlled by 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 properties include approximately 5,600 net acres of leasehold interests. 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 $708,000. The

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Tauren Agreement was unanimously approved by the Company’s board of directors, excluding Mr. Wallen. In addition, the Company obtained an opinion from Blackbriar Advisors, LLC, which concluded that the terms of the Tauren Agreement were fair, from a financial perspective, to the Company.

LEGACY 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.

We share our Bossier/Haynesville formation acreage with Goodrich Petroleum Corporation (“Goodrich”), Chesapeake Energy Corporation (“Chesapeake”), Petrohawk Energy Corporation (“Petrohawk”), El Paso E&P Company, L.P. (“El Paso”), 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. As a result of this activity, we saw improved production volumes in two of the last three fiscal years. However due to lower natural gas prices and depleting production volumes, there was a decrease in production volumes during fiscal 2013.

Legacy Texas Acreage

Prior to the Recent Transactions, and as of June 30, 2013, 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.

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.

In December 1997, we entered into a Stock Purchase Agreement (the “Agreement”) pursuant to which the Company issued 12,500,000 shares of our Common Stock in exchange for the conveyance to the Company of certain oil and gas properties by Calvin A. Wallen, III and his affiliates. In connection with the Agreement, three of the five members of the Board of Directors resigned and new directors were appointed, including Mr. Wallen, who also became President and CEO of the Company.

Prior to the Agreement, we focused primarily on the acquisition of non-operated working interests and overriding royalty interests in oil and gas properties. Subsequent to entering into the Agreement, we moved our headquarters from Tulsa, Oklahoma to Garland, Texas in order to utilize Mr. Wallen’s assembled team of experienced management whose substantial expertise lay in acquisition, exploitation and development and the ability to manage both operated and non-operated oil and gas properties. In addition, after reviewing our existing property portfolio and refining our new business strategy, the management team initiated a divestment strategy to dispose of our non-strategic assets in non-core areas in order to concentrate on building core reserves. Pursuant to this strategy, we have acquired additional properties in our core areas, which as of June 30, 2013, were primarily in Louisiana, as well as pursuing an operated and a non-operated drilling program for the drilling of exploratory, development and infill wells, a strategy previously unavailable to us due to the technical expertise and experience required and the lack of available resources. As of June 30, 2013, we were not the operator for any of our properties.

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On February 6, 2006, the Company entered into a Purchase Agreement with Tauren, an entity wholly owned by Mr. Wallen, with respect to the purchase by the Company of certain Cotton Valley leasehold interests (approximately 11,000 gross acres; 5,000 net acres) held by Tauren. Pursuant to the Purchase Agreement, the Company acquired from Tauren a 35% working interest in approximately 2,400 acres and a 49% working interest in approximately 8,500 acres located in DeSoto and Caddo Parishes, Louisiana, along with an associated Area of Mutual Interest (“AMI”) and the right to acquire at “cost” (as defined in the Purchase Agreement) a working interest in all additional mineral leases obtained by Tauren in the AMI, in exchange for (a) $3,500,000 in cash, (b) 2,500,000 shares of Company common stock, (c) an unsecured 12.5% short-term promissory note in the amount of $1,300,000 and (d) a drilling credit of $2,100,000.

On March 5, 2007, Cubic entered into a Credit Agreement with 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”). Subsequently, we issued to WFEC additional warrants for the purchase of up to 1,000,000 shares of our common stock, at an original exercise price of $1.00 per share. 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 3,500,000 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, 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 an affiliate of the Company 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 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 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 by EXCO and BG in order to reduce the borrowings under the Company’s revolving credit facility with the balance of the cash being received by the Company.

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STRATEGY

As of June 30, 2013, 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 recent 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 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 highly production dry natural gas of 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, including those acquired in the Recent Transactions, and (ii) 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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PRINCIPAL OIL AND GAS PROPERTIES

The following table summarizes certain information with respect to our principal areas of operation at June 30, 2013:

		Natural		Total Gas	Estimated
	Oil	Gas Liquids	Gas	Equivalent	Future Net		10%
Category	(Bbls)	(Bbls)	(Mcf)	(Mcfe)	Cash Flows		Discount
Proved Producing	1,835	11,205	4,899,388	4,977,698	$	8,852,800	$	6,075,300
Proved Non-Producing	—	—	—	—	—		—
Proved Developed Reserves	1,835	11,205	4,899,388	4,977,698	$	8,852,800	$	6,075,300
Proved Undeveloped	393,673	1,624,269	28,092,172	40,199,824	79,982,200		$	32,972,500
Total Proved Reserves	395,508	1,635,474	32,991,560	45,177,522	$	88,835,000	$	39,047,800

As of June 30, 2013, our Texas properties were situated in Eastland and Callahan Counties and represented an immaterial amount of reserves and are excluded from our SEC reserve report. Our Louisiana properties are situated in Caddo Parish and in DeSoto Parish. At June 30, 2013, the Louisiana properties contained substantially all of our proved reserves. The Texas properties owned as of June 30, 2013, 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 vast majority of the Legacy Louisiana Assets 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, 2013 for all of the Company’s wells averaged approximately 3,127 Mcf of natural gas per day, 2 barrels of oil per day and 7 barrels of natural gas liquids per day as compared to approximately 6,149 Mcf of natural gas per day, 3 barrels of oil per day and 3.5 barrels of natural gas liquids per day in the fiscal year ended June 30, 2012.

FISCAL 2013 DRILLING

During fiscal 2013, Indigo Minerals drilled and completed three wells, all of which are in the Cotton Valley formation in which the Company has interests.

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 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.

MARKETING OF PRODUCTION

Crude Oil and Natural Gas

During fiscal 2013, our production consisted mainly of natural gas. During fiscal 2013, we marketed our production of natural gas that was produced from wells operated by our affiliate Fossil Operating (“Fossil”), an entity controlled by our President and Chief Executive Officer, Calvin A. Wallen III, to three purchasers: (i) in Texas, Enbridge G & P, LP, and (ii) in Louisiana, EROC Gathering Company, LP and 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 Transoil Marketing, Inc. (“Transoil”), Eastex Crude Company (“Eastex”), and Martin Gas Sales

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(“Martin”). During fiscal 2013, all of our production was generated by Fossil and seven third-party operators: Chesapeake, Indigo Minerals, EXCO, El Paso, BG, Petrohawk and Goodrich. Pursuant to the terms of our operating agreements, these third-party operators have the right to market our production from wells operated by them. Of these third-party operators, our total revenues during fiscal 2013 were generated as follows: EXCO — 72%, Chesapeake - 9% and Goodrich - 7%, with others producing 12%. Purchases by Atmos Energy through Fossil totaled 3.5% of our total revenues. 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. We had not engaged in crude oil hedging or trading activities, as of June 30, 2013. The majority of our production and our revenue is now generated by wells drilled and operated by non-affiliated third-party operators.

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 $3,843,420 for fiscal 2013 primarily from the sale of natural gas. Natural gas totaled $3,661,677 and represented 95%, NGL totaled $104,103 and represented 3% and oil totaled $77,640 and represented 2% of our total oil and gas revenues, respectively for fiscal 2013.

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 operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us in fiscal 2013 was $3.21 as compared to $3.01 in fiscal 2012. The average NGL price per barrel received by us in fiscal 2013 was $41.16 compared to $66.78 in fiscal 2012. 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 2013 was $90.00 as compared to $93.25 in fiscal 2012.

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OIL AND GAS RESERVES

The following tables set forth our proved developed and proved undeveloped reserves at June 30, 2013, 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, 2013, 2012 and 2011:

	At June 30,
	2013		2012		2011
Proved Developed Reserves:
Oil (Bbl)	1,835		443		1,199
Natural Gas Liquids (Bbl)	11,205		35		—
Gas (Mcf)	4,899,388		3,982,265		6,634,236
Mcfe	4,977,698		3,985,203		6,641,429
Estimated future net cash flows (before income tax)	$	8,852,800	$	6,827,246	$	23,523,649
Standardized Measure (1)	$	6,075,300	$	5,504,209	$	18,418,254

Proved Undeveloped Reserves:
Oil (Bbl)	393,673		427,190		—
Natural Gas Liquids (Bbl)	1,624,269		1,313,531		—
Gas (Mcf)	28,092,172		19,357,720		51,057,850
Mcfe	40,199,824		29,802,000		51,057,850
Estimated future net cash flows (before income tax)	$	79,982,200	$	62,895,890	$	63,411,720
Standardized Measure (1)	$	32,972,500	$	24,472,000	$	28,492,490

Total Proved Reserves:
Oil (Bbl)	395,508		427,633		1,199
Natural Gas Liquids (Bbl)	1,635,474		1,313,566		—
Gas (Mcf)	32,991,560		23,339,985		57,692,086
Mcfe	45,177,522		33,787,203		57,699,279
Estimated future net cash flows (before income tax)	$	88,835,000	$	69,723,136	$	86,935,369
Standardized Measure (1)	$	39,047,800	$	29,976,209	$	46,910,744

Average price used to calculate reserves:
Oil (Bbl)	$	85.13	$	96.59	$	87.24
Natural Gas Liquids (Bbl)	$	54.99	$	47.46	$	65.94
Gas (Mcf)	$	3.62	$	3.25	$	4.53

(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 report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 2012 through June 2013.See “Note J - Oil and gas reserves information (unaudited)” in the Notes to the Financial Statements of the Company included elsewhere in this Report 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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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 Annual Report 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 year 2013 and relied on the previous firms reserve reports. This information for fiscal 2012 was provided by NPC Engineering Group, LLC (“NPC-ENG”) and in fiscal 2011 was provided by Cambrian Consultants America, Inc., d/b/a RPS (“RPS”), all are independent petroleum engineering firms. The reservoir engineer at NSAI, and previously NPC-ENG, and RPS, respectively, who oversaw the preparation of the reserve estimates for NSAI’s firm has a Master’s of Science Degree and is licensed Professional Engineer in the State of Texas. The persons from the two previous firms each had a Master’s of Science Degree and is certified by the State of Texas Professional Geologists as a Licensed Geologist and has more than thirty years of experience in the upstream oil and gas industry. The estimates of these 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 Texas as of June 30, 2013, 2012 and 2011 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 period ended June 30, 2013, 2012 and 2011. 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 report for purposes of calculating the Standardized Measure are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period July 2012 through June 2013. For oil and NGL volumes, the average West Texas Intermediate posted price of $88.13 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 $3.444 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 $85.13 per barrel of oil, $54.99 per barrel of NGL, and $3.618 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 Annual Report 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 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

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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,
	2013			2012		2011
Property acquisition costs	$	178,685		$	109,076	$	448,432
Exploratory costs	—			—		—
Development costs	(290,569		)	8,224,013		10,175,986
Total	$	(111,884	)	$	8,333,089	$	10,624,418

The Company received several credits from EXCO after June 30, 2012 thus creating negative costs incurred total for the year ended June 30, 2013.

Drilling Results

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. 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,
	2013		2012		2011
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	3	0.04	1	—	7	1.51
Dry	—	—	—	—	—	—
Total development	3	0.04	1	—	7	1.51
Exploratory wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total exploratory	—	—	—	—	—	—
Total wells:
Productive	3	0.04	1	—	7	1.51
Dry	—	—	—	—	—	—
Total wells	3	0.04	1	—	7	1.51

Subsequent to June 30, 2012, we had a net increase in proved undeveloped reserves of 10,397,824 Mcfe. This net increase includes both (i) an increase of 14,938,685 Mcfe due to an "Extensions & Discoveries" increase stemming from new proved undeveloped offset locations in which the Company maintains a working interest and are operated by an affiliate, based on the ability to utilize 160 acre spacing per unit for horizontally-drilled and completed Cotton Valley wells; partially offset by (ii) a downward "Revision of Previous Estimates" of 4,540,861 Mcfe, which downward revision includes a loss of 6,153,099 Mcfe due to wells not being drilled and dropping off of our drilling schedule, combined with a gain of 1,612,238 Mcfe due to an increase in estimated ultimate recoveries for pre-existing proved undeveloped locations based on the report of our third party reservoir engineers.

None of our reserves were converted from proved undeveloped reserves to proved developed reserves during the fiscal year ended June 30, 2013. The three new wells drilled in fiscal 2013 by our third party operator, Indigo Minerals, were proved developed as of June 30, 2012. The reserves calculated at June 30, 2013 for these three wells were included in “Revision of Previous Estimates” of proved developed reserves.

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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, 2013, 2012 and 2011:

	Year Ended June 30,
	2013		2012			2011
Production Volumes:
Oil (Bbl)	863		1,100			1,444
Natural gas liquids (Bbls)	2,525		1,277			1,262
Natural gas (Mcf)	1,141,474		2,244,315			1,481,430
Total oil, natural gas liquids, and natural gas (Mcfe)	1,161,802		2,258,577			1,497,666

Weighted Average Sales Prices:
Oil (per Bbl)	$	90.00	$	93.25		$	83.13
Natural gas liquids (per Bbl)	$	41.16	$	66.78		$	67.20
Natural gas (per Mcf)	$	3.21	$	3.01		$	4.00

Selected Expenses per Mcfe:
Production costs	$	0.65	$	0.43		$	0.60
Workover expenses (non-recurring)	$	0.04	$	0.07		$	0.01
Severance taxes	$	0.16	$	(0.06	)	$	0.07
Other revenue deductions	$	0.76	$	0.43		$	0.56
Total lease operating expenses	$	1.61	$	0.87		$	1.24
General and administrative expenses	$	2.01	$	1.58		$	2.11
Depreciation, depletion and amortization	$	2.80	$	2.70		$	2.48

We had one field that exceeded 15% of our total Proved Reserves as of June 30, 2013 and 2012. Our Johnson Branch field represented approximately 95% of our total Proved Reserves. We had two fields that exceeded 15% of our total Proved Reserves as of June 30, 2011. Our Bethany Longstreet and Johnson Branch fields represented approximately 23% and 73% of our total Proved Reserves, respectively.

The following table sets forth our production quantities, by final product sold, for each field that contains 15% or more of our total proved reserves.

Louisiana

	Year Ended June 30,
	2013		2012		2011
Johnson Branch field
Oil (Bbl)	223		629		916
Average price per (Bbl)	$	88.47	$	96.94	$	81.77

Natural gas production (Mcf)	649,132		1,271,948		462,088
Average price per (Mcf)	$	3.20	$	2.91	$	3.99

NGL’s per (Bbl)	1,048		1,277		1,262
Average price per (Mcf)	$	55.77	$	66.78	$	67.40
Average production cost per (Mcfe)
(excluding severance and ad valorem taxes)	$	1.58	$	0.69	$	1.59

Bethany Longstreet field
Oil (Bbl)					191
Average price per (Bbl)					$	81.94

Natural gas production (Mcf)					838,578
Average price per (Mcf)					$	2.20

NGL’s per (Bbl)					—
Average price per (Mcf)					$	—
Average production cost per (Mcfe)
(excluding severance and ad valorem taxes)					$	.89

PRODUCTIVE WELLS AND ACREAGE

Productive Wells

The following table sets forth our productive wells at June 30, 2013:

Oil		Gas		Total
Gross	Net	Gross	Net	Gross	Net
—	—	64	13.41	64	13.41

We had no oil wells at June 30, 2013. The oil we produced during fiscal 2013 was a by-product of our gas wells. The Company had 3 new wells drilled and completed during fiscal 2013; however our working interest on all 3 new wells combined was less than 8%, so that small percentage increase and the gain of some newly acquired acreage caused our net well number to decline.

Acreage

The following table sets forth our undeveloped and developed gross and net leasehold acreage at June 30, 2013. The only 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. 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.

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Undeveloped		Developed		Total
Gross	Net	Gross	Net	Gross	Net
9,758	3,770	3,365	1,330	13,123	5,100

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.

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 well bore in each section, or one Haynesville Shale well bore in that section, all of which are operated by a third party. 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.

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, 2013, the majority of our production was operated by non-affiliated third-party operators. 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.

EMPLOYEES

At September 24, 2013, the Company had eight (8) employees, seven (7) full-time and one (1) part-time. 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. The offices were leased on a month-to-month basis for an average monthly amount charged to the Company, from July 1, 2010 until December 31, 2010, of $2,229. Effective January 1, 2011, the Company signed a 2-year lease that charges the Company a monthly fee of $8,000 per month. Effective January 1, 2013, the lease was extended through September 30, 2013, and has been further extended to March 31, 2014. The Company believes that there is other appropriate space

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available in the event the Company should terminate its current leasing arrangement, though the Company believes the monthly rental fee would likely exceed $8,000 per month.

COMPETITION

As of June 30, 2013, our acreage was being operated by affiliated and non-affiliated third-party operators. There is limited, if any, competition in this non-operated position, so our focus is on reducing costs and expenses where possible. We have in the past operated and developed oil and natural gas plays and our strategy is to operate and develop additional properties, in the future, including those acquired in the Recent Transactions. In that environment, we compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

At various times, we have experienced temporary or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and gas drilling and completing. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

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 and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In this regard, some states 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 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 report 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.

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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 severable 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 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

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environmental impacts of hydraulic fracturing. In December 2012, the EPA issued a progress report on its hydraulic fracturing study with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review. The agency also announced that one of its enforcement initiatives for 2011 to 2013 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 prior to the Recent Transactions have been concentrated largely in Louisiana. 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 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 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

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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 greenhouse gases (“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. GHGs are certain gases, including carbon dioxide, a product of the combustion of natural gas, and methane, a primary component of natural gas, that may be contributing to warming of the Earth’s atmosphere resulting in climatic changes. 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.

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.

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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.

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, or the FTC. 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 Report.

“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.

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“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.

“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.”

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“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.

“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” 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.

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“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 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.

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“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.

“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.

AVAILABILITY OF INFORMATION

We file annual, quarterly and current reports and proxy statements with the Securities and Exchange Commission (the “SEC”). The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding Cubic Energy, Inc. and other companies that file electronically with the SEC.

Our website address is www.cubicenergyinc.com. We make available on our website free of charge copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

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Item 1A. Risk Factors.

You should carefully consider the following risk factors, in addition to the other information set forth in this Report, 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 Report 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.

Servicing our debt requires a significant amount of cash.

The Company entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66,000,000 of senior secured notes due October 2, 2016, to certain purchasers. In addition, our prior debt of approximately $21,000,000 was renegotiated and assumed by one of our newly created subsidiaries.

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 the assets acquired in the Recent Transactions and our legacy assets, generate cash flows therefrom and collect amounts owed to us by our third-party operators.

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

We recently consummated the acquisition of certain assets of Gastar and Navasota, respectively. 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;

· Stockholder reaction to the acquisitions;

· Risks associated with the ownership and operation of the acquired assets, which differ from those that we currently hold, in that the acquired assets are primarily oil producing, while our legacy assets are primarily gas producing;

· 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.

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

As part of the transactions consummated on October 2, 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, and the exercise price of warrants exercisable into an aggregate of 787,294 shares of common stock was adjusted to $0.6764 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 stockholders’ 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 Recent Transactions, we will 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;

· 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 the Organization of Petroleum Exporting Countries 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 2013, the Henry Hub spot price for natural gas fluctuated from a high of $4.38 per Mcf to a low of $2.66 per Mcf, while the NYMEX West Texas Intermediate crude oil price ranged from a high of $98.46 per Bbl to a low of $83.72 per Bbl.

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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, 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;

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· 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.

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

We incurred losses available to common shareholders of $6,851,518 and $13,364,871 for the fiscal years ended June 30, 2013 and 2012, respectively. Our accumulated deficit as of June 30, 2013 was $85,757,066. 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.

Prior to the Recent Transactions and as of June 30, 2013, the majority of our oil and gas reserves were undeveloped. At June 30, 2013, we had proved undeveloped reserves of 40,200 MMcfe, which represented approximately 90% of our total proved reserves of 45,178 MMcfe. Recovery of our future undeveloped reserves will require significant capital expenditures to further develop these reserves during fiscal 2014 and 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.

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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 as a result of our Recent Transactions. 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.

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 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, 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

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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.

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

This report contains estimates of our oil and gas reserves as of June 30, 2013 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 report 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 report. 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 report 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 $88.13 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 $3.45 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 $85.13 per barrel of oil, $55.02 per barrel of NGL, and $3.62 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.

Hedging of 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.

We entered into New York Mercantile Exchange (“NYMEX”) futures contracts as hedges on natural gas production and crude oil production, as part of the Recent Transactions, in the form of a Call Option Structured Derivative with a third party. Although these hedges may partially protect us from declines in commodity prices, the use of these arrangements also may limit our ability to benefit from significant increases in the prices of natural gas and oil.

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If the counterparties to the derivative instruments we use to hedge 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.

Following the end of fiscal 2013, as part of the Recent Transactions, we began to use hedges 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.

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

Recently enacted 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 although the CFTC has stated that it is appealing 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

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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 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, 2013, third parties operated wells that represented substantially all of our proved reserves as of that date. Following the end of fiscal 2013, third-parties continue to operate a significant portion of our properties. 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. As a result of the Recent Transactions, we are required to obtain key personnel life insurance on Mr. Wallen, the proceeds from which would be used for repayment of the Company’s debts.

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 October 8, 2013, Mr. Wallen and the Investors, collectively, control over 70% or 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, our President, Chairman of the Board and Chief Executive Officer, 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.

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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 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 Wallen control all votes, 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 may not be 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.

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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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, 2013, we believe that our leaseholds for all of our net acreage were being kept in force by virtue of production in paying quantities. The majority of our acreage is in Northwest Louisiana, and the legal climate in Northwest Louisiana 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 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, 2013, could decrease by a maximum of 17%. 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 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

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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.

Climate change legislation, regulation and litigation could materially adversely affect us.

There is an increased focus by local, state and national regulatory bodies on greenhouse gas (“GHG”) emissions and climate change. Various regulatory bodies have announced their intent to regulate GHG emissions, including the United States Environmental Protection Agency, which promulgated several GHG regulations in 2010 and late 2009. As these regulations are under development or are being challenged in the courts, we are unable to predict the total impact of these potential regulations upon our business, and it is possible that we could face increases in operating costs in order to comply with GHG emission legislation.

Passage of legislation or regulations that regulate or restrict emissions of GHG, or GHG-related litigation instituted against us, could result in direct costs to us and could also result in changes to the consumption and demand for natural gas and carbon dioxide produced from our oil and natural gas properties, any of which could have a material adverse effect on our business, financial position, results of operations and prospects.

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.

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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.

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 broker-dealers 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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Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

A description of our properties as of June 30, 2013 is included in “Part I. Item 1. Business” and is incorporated herein by reference.

Item 3. 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. As of June 30, 2013,the majority of our acreage in Northwest Louisiana and the legal climate in Northwest Louisiana has become increasingly hostile and litigious towards oil and gas companies. Many 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., WFEC , Inc. & 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, of a maximum of 17%, on the acreage position of the Company, as of June 30, 2013, if ultimately adjudicated entirely in favor of the mineral owner. The Company intends to vigorously defend its position and believes it will prevail regarding a majority, if not all, of the acreage at issue in this lawsuit.

Item 4. Mine Safety Disclosures.

None

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock and Market

During fiscal 2013 and 2012, the common stock of the Company traded on the NYSE-MKT under the trading symbol “QBC”. On July 17, 2013, after the end of fiscal 2013, the Company’s common stock began being quoted on the OTCQB under the symbol “CBNR”. At October 8, 2013, there were 77,505,908 shares of common stock outstanding held by approximately 772 stockholders of record.

Under its Amended and Restated Certificate of Formation, the Company is authorized to issue one class of up to 200,000,000 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 October 8, 2013, there were 120,470 preferred shares of the Company’s Series A Convertible Preferred Stock held in treasury, 16,162 shares of Series B Convertible Preferred Stock issued and outstanding and 98,751.824 shares of Series C Redeemable Voting Preferred Stock issued and outstanding.

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. 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 2012	High		Low
1st Quarter	$	0.80	$	0.53
2nd Quarter	$	0.74	$	0.50
3rd Quarter	$	0.69	$	0.50
4th Quarter	$	0.53	$	0.27

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

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

During fiscal 2013, the Company did not sell any of its equity securities that were not registered under the Securities Act of 1933.

We did not purchase any of our equity securities during the fourth quarter of fiscal 2013.

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Stockholder Return Performance Graph

The following graph compares the cumulative total stockholder return on our common stock during the five years ended June 30, 2013 with the cumulative total stockholder return of the Russell 2000 Index and a peer group of 14 oil and gas exploration and production companies comprised of us and Abraxas Petroleum Corporation, Magnum Hunter Resources Corporation, Chesapeake Energy Corporation, Goodrich Petroleum Corporation, Northern Oil & Gas Inc., Comstock Resources Inc., EXCO Resources Inc., Penn Virginia Corporation, Quicksilver Resources Inc., Range Resources Corporation, Southwestern Energy Company, Royale Energy, Inc., and SM Energy Company (collectively referred to as the “Peer Group Index”). The comparison assumes an investment of $100 on June 30, 2008 in each of our common stock, the Russell 2000 Index and the Peer Group Index.

	6/30/2008		6/30/2009		6/30/2010		6/30/2011		6/30/2012		6/30/2013
Cubic Energy, Inc.	$	100.00	$	25.78	$	21.48	$	16.95	$	10.02	$	7.16
Russell 2000 Index	$	100.00	$	73.70	$	87.65	$	119.98	$	115.78	$	141.73
Peer Group Index	$	100.00	$	39.83	$	43.28	$	57.73	$	41.76	$	45.21

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. 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.

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Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of June 30, 2013 with respect to compensation plans (including individual compensation arrangements) under which equity securities of the registrant are authorized for issuance:

	Number of	Weighted
	securities to be	average		Number of shares
	issued upon	exercise price		of common stock
	exercise of	of outstanding		remaining available
	outstanding	options,		for future issuance
	options, warrants	warrants and		under equity
	and rights	rights		compensation plans
2005 Stock Option Plan approved by shareholders	288,667	$	1.20	1,435,805
Equity compensation plans not approved by shareholders	—	$	—	—
Total	288,667			1,435,805

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Item 6. Selected Financial Data.

The following table presents a summary of our financial information for the periods indicated. It should be read in conjunction with our Financial Statements and related notes (beginning on page F-1 at the end of this report) and other financial information included herein.

	Year ended June 30,
(In thousands, except per share data)	2013			2012			2011			2010			2009
Statements of Operations Data:
Total oil and gas sales revenues	$	3,843		$	6,940		$	6,133		$	3,486		$	1,858
Costs and expenses:
Oil and gas production, operating and development costs	1,872			1,972			1,858			1,845			1,372
General and administrative expenses	2,333			3,572			3,157			2,389			1,940
Depreciation, depletion and amortization	3,248			6,091			3,707			1,153			772
Impairment loss on oil and gas properties	—			—			—			—			20,391
Total costs and expenses	7,453			11,635			8,722			5,387			24,475
Operating income (loss)	(3,610		)	(4,695		)	(2,588		)	(1,901		)	(22,617		)
Non-operating income (expense):
Other income, net	666			3			8			5			34
Interest expense, net	(2,471		)	(7,730		)	(7,649		)	(4,714		)	(2,045		)
Amortization of loan costs	(520		)	(69		)	(60		)	(73		)	(135		)
Total non-operating income (expense)	(2,324		)	(7,796		)	(7,701		)	(4,783		)	(2,146		)
Loss on extinguishment of debt, net	—			—			—			1,748			—
Loss from operations before income taxes	(5,934		)	(12,491		)	(10,289		)	(4,937		)	(24,763		)
Income tax expense (benefit)	—			—			—			—			—
Net income (loss)	$	(5,934	)	$	(12,491	)	$	(10,289	)	$	(4,937	)	$	(24,763	)
Dividends on preferred shares	$	(917	)	$	(874	)	$	(861	)	$	(240	)	$	—
Net loss available to common shareholders	$	(6,851	)	$	(13,365	)	$	(11,150	)	$	(5,177	)	$	(24,763	)
Net loss per common share - basic and diluted	$	(0.09	)	$	(0.17	)	$	(0.15	)	$	(0.08	)	$	(0.40	)
Weighted average common shares outstanding	77,263			77,009			76,049			67,584			61,150

Statements of Cash Flow Data:
Cash provided by (used in) operating activities	$	54		$	(395	)	$	(2,567	)	$	(682	)	$	(2,152	)
Cash provided by (used in) investing activities	$	7,326		$	(89	)	$	(1,412	)	$	(5,736	)	$	(5,589	)
Cash provided by (used in) financing activities	$	(7,395	)	$	(783	)	$	5,130		$	6,738		$	5,668

Balance Sheet Data (at end of period):
Working capital (deficit)	$	(30,191	)	$	(35,768	)	$	2,320		$	(1,436	)	$	(27,823	)
Oil and gas properties, and equipment, net	$	14,724		$	18,083		$	15,840		$	8,923		$	11,710
Total assets	$	18,030		$	30,539		$	37,057		$	38,196		$	12,127
Long-term liabilities, net of discounts	$	—		$	—		$	31,197		$	20,984		$	—
Total liabilities	$	31,197		$	38,708		$	32,262		$	24,434		$	2,815
Shareholders’ equity	$	(13,167	)	$	(8,169	)	$	4,795		$	13,762		$	(16,023	)

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Item 7. 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 in this Annual Report on Form 10-K. 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 in this Annual Report on Form 10-K.

Overview

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 formations.

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,
	2013		2012			2011		2010		2009
Operating Data:
Proved Reserves (Bcfe)	45.2		33.8			57.7		29.2		21.1
Production (Mcfe)	1,161,802		2,258,577			1,497,666		806,102		300,712
Producing wells at end of period, gross	64		60			58		40		43
Producing wells at end of period, net	13.41		13.52			13.47		11.81		21.44
Acreage, gross	13,123		13,123			13,239		13,594		14,466
Acreage, net	5,100		5,100			5,149		5,324		6,077

Production:
Oil (Bbl)	863		1,100			1,444		1,364		1,681
Natural gas (Mcf)	1,141,474		2,244,315			1,481,430		792,433		279,516
Natural gas liquids (Bbl)	2,525		1,277			1,262		915		1,852
Total oil, gas and liquids (Mcfe)	1,161,802		2,258,577			1,497,666		806,102		300,712
Average daily (Mcfe)	3,183		6,188			4,103		2,208		824

Weighted Average Sales Prices:
Oil (per Bbl)	$	90.00	$	93.25		$	83.13	$	73.18	$	66.52
Natural gas (per Mcf)	$	3.21	$	3.01		$	4.00	$	4.21	$	3.72
Natural gas liquids (per Bbl)	$	41.16	$	66.78		$	67.20	$	53.34	$	42.84
Natural gas equivalent (per Mcfe)	$	3.31	$	3.07		$	4.10	$	4.32	$	6.18

Selected Expenses per Mcfe:
Production costs	$	0.65	$	0.43		$	0.60	$	1.27	$	3.98
Workover expenses (non-recurring)	$	0.04	$	0.07		$	0.01	$	0.05	$	0.12
Severance taxes	$	0.16	$	(0.06	)	$	0.07	$	0.15	$	0.20
Other revenue deductions	$	0.76	$	0.43		$	0.56	$	0.65	$	0.27
Total lease operating expenses	$	1.61	$	0.87		$	1.24	$	2.12	$	4.57
General and administrative expenses:
Non-cash stock-based compensation	$	0.05	$	0.10		$	0.38	$	0.49	$	1.28
Other general and administrative	$	1.96	$	1.48		$	1.72	$	2.47	$	5.17
Total general and administrative	$	2.01	$	1.58		$	2.10	$	2.96	$	6.45
Depreciation, depletion and amortization	$	2.80	$	2.70		$	2.48	$	1.43	$	2.55

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RESULTS OF OPERATIONS

Comparison of Fiscal 2013 to Fiscal 2012

Revenues

OIL AND GAS SALES decreased 45% to $3,843,420 for fiscal 2013 from $6,939,999 for fiscal 2012 primarily due to decreased gas volumes resulting from the rapid depletion rate of our existing Haynesville Shale wells. This was mitigated by 3 new Cotton Valley horizontal wells that came online during fiscal 2013, all of which are operated by Indigo Minerals. The average price of natural gas was $3.21 per Mcfe for fiscal 2013, as compared to $3.01 per Mcfe for fiscal 2012.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as “LEASE OPERATING EXPENSES” elsewhere herein) decreased 5% to $1,872,186 (49% of oil and gas sales) for fiscal 2013 from $1,972,223 (28% of oil and gas sales) for fiscal 2012. This decrease was primarily due to a $95,618 decrease in other O&G deductions, which are costs passed-through to the Company by the purchaser of the Company’s gas. The increase as a percentage of oil and gas sales was primarily due to no credit received in fiscal 2012 for severance taxes.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) decreased 35% to $2,332,946 for fiscal 2013 from $3,572,260 in fiscal 2012. This decrease of $1,239,313 was primarily due to a decrease in legal fees of $1,010,171 incurred during fiscal 2012 due to the EXCO and BG arbitration and settlement. In addition there was a decrease in stock compensation of $236,295 created by the Company’s reduced stock price and reduction in number of shares issued to directors.

DEPRECIATION, DEPLETION AND NON-LOAN RELATED AMORTIZATION (“DD&A”) decreased 47% to $3,248,260 in fiscal 2013 from $6,090,529 in fiscal 2012, primarily due to a decrease in the depletion percentage rate for fiscal 2013 of 2.51% versus 6.27% for fiscal 2012, which was primarily the result of an approximate 12.5 million Mcf increase to our reserves. This reduction was created by smaller full cost pool additions and a decreased depletion rate. The depletion rate is a result of a change in beginning reserves, full cost pool to deplete, accumulated depletion and annual production.

INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT decreased 68% to $2,470,516 in fiscal 2013 from $7,729,992 in fiscal 2012. Our debt decreased as a result of the paydown with a portion of the funds received in the EXCO/BG settlement. We had total outstanding balances of $29,865,110 at the end of fiscal 2013 and $37,000,000 at the end of fiscal 2012. The Credit Facility with WFEC resulted in a loan discount being recorded. The discount was fully amortized over the original three-year term of the debt as additional interest expense, with $902,161 as an increase in additional paid-in-capital as a result of the revaluation of the WFEC warrants from $1.00 to $0.20 in fiscal 2013 as compared to $5,803,459 in fiscal 2012. There was no change in the capitalization of interest expense to the full cost pool for oil and gas properties during fiscal 2013 or 2012.

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Comparison of Fiscal 2012 to Fiscal 2011

Revenues

OIL AND GAS SALES increased 13% to $6,939,999 for fiscal 2012 from $6,133,299 for fiscal 2011 primarily due to increased gas volumes resulting from 19 Haynesville Shale wells being online for the entire fiscal year, of which eleven are operated by Chesapeake, three are operated by Goodrich and five are operated by EXCO. This increase was mitigated by the average price of natural gas being $3.07 per Mcfe for fiscal 2012, as compared to $4.10 per Mcfe for fiscal 2011.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as “LEASE OPERATING EXPENSES” elsewhere herein) increased 6% to $1,972,223 (28% of oil and gas sales) for fiscal 2012 from $1,857,528 (30% of oil and gas sales) for fiscal 2011. This increase was primarily due to a $135,741 increase in workover expenses on existing wells, which was necessitated by the age of the wells.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) increased 13% to $3,572,260 for fiscal 2012 from $3,156,860 in fiscal 2011. This increase of $415,399 was primarily due to increased legal fees of $928,205 incurred primarily in the EXCO and BG arbitration. This increase was somewhat offset by a $286,052 decrease in stock compensation, a franchise tax decrease of $148,471, and overall decreased marketing expenses of $86,087.

DEPRECIATION, DEPLETION AND NON-LOAN RELATED AMORTIZATION (“DD&A”) increased 64% to $6,090,529 in fiscal 2012 from $3,707,255 in fiscal 2011, primarily due to an increase in the depletion percentage rate for fiscal 2012 of 6.27% versus 2.53% for fiscal 2011, which was primarily the result of an approximate 23.2 million Mcf reduction to our reserves. This reduction created a smaller full cost pool and increased the depletion rate accordingly. The depletion rate is a result of a change in beginning reserves, full cost pool to deplete, accumulated depletion and annual production.

INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 1% to $7,729,992 in fiscal 2012 from $7,648,622 in fiscal 2011; we had no increase in debt (before discounts), since August 2010 when it was increased $5,000,000 to a total outstanding balance of $37,000,000 for fiscal 2011 and all of fiscal 2012. The Credit Facility with WFEC also resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense with $5,803,459 being recorded in fiscal 2012 as compared to $5,740,440 in fiscal 2011. There was no change in the capitalization of interest expense to the full cost pool for oil and gas properties of during fiscal 2012 as compared to a decrease of $5,221 in fiscal 2011.

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Liquidity and Capital Resources

Overview

The Company’s primary resource is its 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 recent 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. The Company is exploring acquiring additional properties with this similar development profile.

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. 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 that will help the Company achieve its transition away from dry natural gas. The high production of dry natural gas from the various Bossier sands has the opportunity to provide the Company a significant 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 the Company’s borrowing capacity. Within the confines of product pricing, the Company needs to be able 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 its capital expenditure program.

As a result of the acquisitions of properties from Gastar, 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 $39,118,830, 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 Cubic, such amounts were netted effective January 1, 2013 and will be recorded as an adjustment to the purchase price.

On September 27, 2013, the Company entered into the Navasota Agreement. On October 2, 2013, 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 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 by the Company was $19,400,000, prior to certain post-closing adjustments.

The Company entered into and consummated the Tauren Agreement dated as of October 2, 2013. 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 De Soto and Caddo Parishes, Louisiana. The acquired properties include approximately 5,600 net acres of leasehold interests. The

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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.

Working Capital and Cash Flow

The Company had a working capital deficit of $30,191,399 at June 30, 2013, down from a working capital deficit of $35,768,341 at June 30, 2012. This decrease in deficit was primarily due to the $9,134,980 paydown on the Credit Agreement with WFEC with funds received from the proceeds of the EXCO/BG settlement.

The Company recently entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66,000,000 of senior secured notes due October 2, 2016, to certain purchasers. Pursuant to the terms of the Credit Agreement with WFEC, 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 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. As part of the Recent Transactions, the Company entered into a Call Option Structured Derivative that provided the Company approximately $35,000,000 and together with the proceeds from the issuance of the senior secured notes, a total of $101,000,000. These funds, net of amounts paid for the acquisition of the assets from Gastar, Navasota and Tauren, the repayment of the term loan payable to WFEC and various expenses relating to the Recent Transactions, are available for capital expenditures and working capital for operations.

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.

Operating activities - During the twelve months ended June 30, 2013, the Company generated cash flows from operating activities of $54,204 as compared to cash used of $395,058 in fiscal 2012 and $2,567,159 in fiscal 2011. 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, 2013 the Company generated cash flows from investing activities of $7,325,735 as compared to cash used of $88,634 in fiscal 2012 and $1,412,406 in fiscal 2011. Cash provided by investing activities for 2013 consisted primarily of amounts received for the repayment of the remaining unused prepaid drilling credits required as part of the EXCO/BG settlement offset by deposits paid toward acquisitions and capital spending for the acquisition and development of oil and gas properties. Cash used in investing activities for 2012 and 2011consisted of capital spending for the acquisition and development of oil and gas properties.

Financing activities - During the twelve months ended June 30, 2013 the Company used cash flows from financing activities of $7,394,890 as compared to cash used of $783,029 in fiscal 2012 and cash provided of $5,129,915 in fiscal 2011. 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 used by financing activities for 2012 consisted of payment of dividends on preferred stock. Cash provided by financing activities for 201l consisted of borrowings under the credit facility and proceeds from the issuance of stock offset by dividends and loan costs paid.

Capital Expenditures

The majority of our oil and gas reserves are undeveloped. As such, recovery of the Company’s future undeveloped proved reserves will require significant capital expenditures. The Company recently raised

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$101,000,000 to consummate the Recent Transactions. The funds were provided through a Note Purchase Agreement totaling approximately $66,000,000 and a Call Option Structured Derivative of approximately $35,000,000. Management estimates that aggregate capital expenditures ranging from a minimum of approximately $15,000,000 and a maximum of approximately $35,000,000 will be made to further develop these reserves, closing fees, debt repayment and general operating fees during fiscal 2014. Moreover, additional capital expenditures may be required for exploratory drilling on our undeveloped acreage. The Company may increase its planned activities for fiscal 2014, 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 may 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

The Company plans to fund its development and exploratory activities through cash on hand, cash provided from operations, and recently secured funds in the Recent Transactions, 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, the Company’s 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 the Company’s development and exploration program, there can be no assurance that the Company’s capital resources will be sufficient to sustain the Company’s 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, the Company may need to curtail its planned development and exploratory activities. If a well is proposed by a third-party operator and the Company does not have the capital resources to participate in that well, the Company 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 the Company’s capital resources will be sufficient to sustain the Company’s development and exploration activities.

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.

We prepared our consolidated financial statements for inclusion in this report in accordance with 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.

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Estimates of Proved Reserves

The proved reserves data included in this Annual Report on Form 10-K 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 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 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.

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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

The accounting for and disclosure of, oil and natural gas producing activities requires that we choose between two GAAP alternatives: the full cost method or the successful efforts method.

We use 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. We capitalize the portion of general and administrative costs, including share-based compensation that is attributable to our acquisition, exploration, exploitation and development activities.

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 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.

Prior to our December 31, 2009 adoption of Release No. 33-8995, at the end of each quarterly period the unamortized cost of oil and natural gas properties, net of related deferred income taxes, was limited to the full cost ceiling, computed as the sum of the estimated future net revenues from our proved reserves using period-end prices, discounted at 10%, and adjusted for related income tax effects (ceiling test). In the event our capitalized costs exceeded the ceiling limitation at the end of the reporting period, we subsequently evaluated the limitation for price changes occurring after the balance sheet date to assess impairment. Beginning December 31, 2009, Release No. 33-8995 requires that the full cost ceiling be computed as the sum of the estimated future net revenues from proved reserves using the average, first-day-of-the-month price during the previous 12-month period, discounted at 10% and adjusted for related income tax effects. The new rule no longer allows a company to subsequently evaluate the limitation for subsequent price changes. Under full cost accounting rules, any ceiling test write-downs of oil and natural gas properties may not be reversed in subsequent periods.

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

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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 related long-lived asset 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.

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 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

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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

In January 2013, the FASB issued ASU No. 2013-01— “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities”. The main objective in developing this update is to address implementation issues about the scope of ASU No. 2011-11. This ASU clarifies the scope of the offsetting disclosures and addresses any unintended consequences. The scope of Update 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This ASU is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the required disclosures retrospectively for all comparative periods presented. This ASU was adopted on January 1, 2013 and the adoption did not have a material impact on our financial position or results of operations.

On January 21, 2010, the FASB issued Accounting Standards Update No. 2010-06—Fair Value Measurement and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires transfers, and the reasons for the transfers, between Levels 1 and 2 be disclosed, Level 3 reconciliations for fair value measurements using significant unobservable inputs should be presented on a gross basis, the fair value measurement disclosure should be reported for each class of asset and liability, and disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring transactions will be required for fair value measurements that fall in either Level 2 or 3. The update was effective for interim and annual reporting periods beginning after December 15, 2009. This update currently has had no impact to our financial position.

On December 31, 2008, the SEC issued Release No. 33-8995, amending its oil and natural gas reporting requirements for oil and natural gas producing companies. On January 16, 2010, the FASB issued Update No. 2010-03—Extractive Activities—Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, or Update No. 2010-03, to align the oil and gas reserve estimation and disclosure requirements of the Codification with Release No. 33-8995.

The effective date of the new accounting and disclosure requirements was for annual reports filed for fiscal years ending on or after December 31, 2009.

Among other things, Release No. 33-8995 and Update No. 2010-03:

· Revises a number of definitions relating to oil and natural gas reserves to make them consistent with the Petroleum Resource Management System, which includes certain non-traditional resources in proved reserves;

· Permits the use of new technologies for determining oil and natural gas reserves;

· Requires the use of the simple average spot prices for the trailing twelve month period using the first day of each month in the estimation of oil and natural gas reserve quantities and, for companies using the full cost method of accounting, in computing the ceiling limitation test, in place of a single day price as of the end of the fiscal year;

· Permits the disclosure in filings with the SEC of probable and possible reserves and sensitivity of our proved oil and natural gas reserves to changes in prices;

· Requires additional disclosures (outside of the financial statements) regarding the status of undeveloped reserves and changes in status of these from period to period; and

· Requires a discussion of the internal controls in place in the reserve estimation process and disclosure of the technical qualifications of the technical person having primary responsibility for preparing the reserve estimates.

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Other Accounting Policies and Recent Accounting Pronouncements

Please see “Notes to Financial Statements — 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 2013.

Related Party Transactions

A description of our related party transactions is included in “Note F — Related party transactions” in the Notes to the Financial Statements of the Company included elsewhere in this Report, 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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk

We are subject to price fluctuations for natural gas, NGL and crude oil. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Reductions in crude oil, natural gas and NGL prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. Any reduction in reserves, including reductions due to price fluctuations, can adversely affect our liquidity and our ability to obtain capital for our acquisition and development activities. Prior to the end of fiscal 2013, and the Recent Transactions, we have not entered into futures contracts or other hedging agreements to manage the commodity price risk for any portion of our production.

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Interest Rate Risk

As of June 30, 2013, we had an aggregate of approimately$29,800,000 of current debt outstanding under our Credit Facility and the Wallen Note. The Credit Facility matured on May 31, 2013 and bears interest at the prime rate plus 2.0% and the Wallen Note bears interest at the prime rate plus 1%. As a result, our interest costs fluctuate based on short-term interest rates. Based on the aforementioned borrowings outstanding at June 30, 2013, a 100 basis point change in interest rates would change our annual interest expense by approximately $298,000. Following the end of fiscal 2013,$2,000,000 of the Wallen Note was converted into Series B Convertible Preferred Stock, the debt under the credit agreement was paid down by $5,000,000 and the remaining debt with WFEC was assumed by a subsidiary and extended to October 2016. We had no interest rate derivatives during fiscal 2013.

Item 8. Financial Statements and Supplementary Data.

The Report of Independent Accountants, Financial Statements and any supplementary financial data required by this Item are set forth beginning on page F-1, and are incorporated herein by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. 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 this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were 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.

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, 2013 based on the criteria set forth in Internal Control—Integrated Framework 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.

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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 effective as of June 30, 2013. This Annual Report 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 Annual Report.

Changes in Internal Control Over Financial Reporting

Subsequent to our evaluation, there were no changes in internal controls or other factors that could materially affect, or are reasonably likely to materially affect, these internal controls. We maintain a system of internal control over financial reporting. There were no changes in our internal control over financial reporting during the fourth quarter of fiscal 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

Certifications

Our chief executive officer and chief financial officer have completed the certifications required to be filed as an exhibit to this Report (see Exhibits 31.1 and 31.2) relating to the design of our disclosure controls and procedures and the design of our internal control over financial reporting.

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Directors

The following table provides information concerning each of our directors as of October 8, 2013:

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			Director
Name	Age	Position(s) Held with Cubic	Since
Calvin A. Wallen, III	58	Chairman of the Board, President and Chief Executive Officer	1997

Jon S. Ross	49	Corporate Secretary and Director	1998

Gene C. Howard	87	Director	1991

Bob L. Clements	70	Director	2004

David B. Brown	50	Director	2010

Paul R. Ferretti	66	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 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

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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, the World Affairs Council 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*	58	Chairman of the Board, President and Chief Executive Officer	1997

Larry G. Badgley	57	Chief Financial Officer	2008

Jon S. Ross*	49	Corporate Secretary and Director	1998

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. 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, 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.

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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.

Compliance with Section 16(a) of the Exchange Act

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, the Company believes that all filings were on time during fiscal 2013.

Director Independence

As of June 30, 2013, our Board had two members from management, Calvin A. Wallen, III, our Chairman, President and Chief Executive Officer and Jon S. Ross, the 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.

Item 11. 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 Secretary. The Compensation Committee does not delegate any of its functions to others in setting compensation.

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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 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. One such study, published in September 2010 by Salary.com was a blind survey of over 1,000 companies located in the Dallas metropolitan area in the “Energy & Utilities” industry with less than 25 full-time equivalent employees. Another study, published in December 2010, included data from a survey of the following comparable companies: Abraxas Petroleum Corporation, ATP Oil & Gas, Berry Petroleum Company, Canadian Superior Energy, Edge Petroleum and Goodrich Petroleum Corporation.

In addition, during fiscal 2011, a study was done of the compensation practices of GMX Resources, Inc. (approximately twice the market cap of the Company at the time of the study) and of NGAS Resources, Inc. (approximately one-half the market cap of the Company at the time of the study). These studies were used to corroborate the compensation levels for each of the officers.

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.

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 2013 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

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knowledge, contribution to business results, existing equity holdings, executive pay for similar positions in other companies, and executive pay within our company.

The base salaries paid to our named executive officers during fiscal 2013 are set forth below in the Summary Compensation Table. There were no increases in executive officers base salaries during fiscal 2013.

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. No bonuses were paid to our named executive officers during fiscal 2013, 2012 or 2011. 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 Secretary’s recommendations;

· Management role and contribution to the management team;

· Job responsibilities and past performance;

· Future anticipated contributions;

· 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, 2013, 2012 and 2011, expressed as percentages of total compensation.

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		Percentage of Total Compensation

Name and	Fiscal					Option		All Other
Principal Position	Year	Salary		Bonus		Awards		Compensation		Total
Calvin A. Wallen, III	2013	97.0	%	0.0	%	0.0	%	3.0	%	100.0	%
Chairman of the Board,	2012	97.2	%	0.0	%	0.0	%	2.8	%	100.0	%
President and Chief Executive Officer	2011	97.1	%	0.0	%	0.0	%	2.9	%	100.0	%

Larry G. Badgley	2013	96.3	%	0.0	%	0.0	%	3.7	%	100.0	%
Chief Financial Officer	2012 2011	96.6 59.8	% %	0.0 0.0	% %	0.0 38.0	% %	3.4 2.3	% %	100.0 100.0	% %


Jon S. Ross	2013	96.0	%	0.0	%	0.0	%	4.0	%	100.0	%
Secretary and Director	2012	96.3	%	0.0	%	0.0	%	3.7	%	100.0	%
	2011	96.2	%	0.0	%	0.0	%	3.8	%	100.0	%

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 Secretary, Jon S. Ross. The agreement with Mr. Wallen provides for a base salary of $200,000 per year, while the agreement with Mr. Ross provides 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” 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.

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, 2013. There can be no assurance that

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these scenarios would produce the same or similar results as those disclosed if a termination occurs in the future.

Without Just Cause/	Severance
For Good Reason	Payment		Total
Calvin A. Wallen, III (1)	$	600,000	$	600,000

Jon S. Ross (1)	$	450,000	$	450,000

(1) Represents 36 months of base salary.

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 2013 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 $191,667 in base salary during fiscal 2013. During fiscal 2013, Mr. Wallen received an amount 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 2013 or 2012.

Chief Financial Officer Compensation

Mr. Badgley’s salary has been established at $163,800 per year, plus a $500 per month health insurance subsidy. Mr. Badgley’s prior employment agreement also provided for the grant of options for the purchase of an aggregate of 288,667 shares of Company common stock.

Summary Compensation Table

The following table shows information regarding the compensation earned during the fiscal years ended June 30, 2013, 2012 and 2011 by our Chief Executive Officer, our Chief Financial Officer, and our other most highly compensated executive officer who was employed by us as of June 30, 2013 and whose total compensation exceeded $100,000 during the most recent fiscal year (the “Named Executive Officers”):

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Name and	Fiscal					Option		All Other
Principal Position	Year	Salary		Bonus		Awards		Compensation (1)		Total
Calvin A. Wallen, III	2013	$	191,667	$	—	$	—	$	6,000	$	197,667
Chairman of the Board,	2012	$	208,333	$	—	$	—	$	6,000	$	214,333
President and Chief Executive Officer	2011	$	200,000	$	—	$	—	$	6,000	$	206,000

Larry G. Badgley	2013	$	156,975	$	—	$	—	$	6,000	$	162,975
Chief Financial Officer	2012 2011	$ $	170,625 159,100	$ $	— —	$ $	— 100,997	$ $	6,000 6,000	$ $	176,625 266,097


Jon S. Ross	2013	$	143,750	$	—	$	—	$	6,000	$	149,750
Secretary and Director	2012	$	156,250	$	—	$	—	$	6,000	$	162,250
	2011	$	150,000	$	—	$	—	$	6,000	$	156,000

(1) All Other Compensation consists solely of a $500 per month, reimbursement towards each officer’s medical insurance premiums. The Company does not provide group health insurance coverage to its employees.

(2) On January 14, 2011, Mr. Badgley received a grant of options for the purchase of an aggregate of 288,667 shares, exercisable at $1.20 per share of Company common stock.

Fiscal 2013 Grants of Plan-Based Awards

No grants, of any plan-based awards were made to our executive officers during fiscal 2013.

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.

Outstanding Equity Awards at Fiscal Year-End

The following table set forth certain information, as of June 30, 2013, regarding stock option grants by the Company:

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	Number of Securities	Number of Securities
	underlying unexercised options	underlying unexercised options	Option		Option
Name	exercisable	unexercisable	exercise price		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 2013.

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 2013

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.

Our director compensation was modified by the Compensation Committee for the Company during fiscal 2013, and had been modified by the Compensation Committee in fiscal 2012.

· On January 4, 2012, the Compensation Committee amended non-management Director Compensation to include: 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.

· On 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

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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 2013.

	Fees Earned
	or Paid in		Stock
Name	Cash		Awards (1)		Total
Gene C. Howard	$	13,500	$	9,500	$	23,000
Bob L. Clements	13,500		8,313		21,813
David B. Brown	15,500		9,500		25,000
Paul R. Ferretti	12,500		7,125		19,625
Totals	$	55,000	$	34,438	$	89,438

(1) The market value of these stock awards is based on the closing price on the grant date, which was $0.21 on January 24, 2013 and $0.265 on April 4, 2013, respectively.

Item 12. 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 October 8, 2013 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

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currently or within 60 days of October 8, 2013 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.

			Approximate
	Number		Percent of
Name and Address	of Shares		Class (1)
5% Stockholders
Funds managed by Anchorage Capital Group, LLC 610 Broadway, 6th Floor, New York, NY 10012	74,811,987	(2)	49.1	%
Funds managed by O-Cap Management, L.P. 600 Madison Ave., 14th Floor, New York, NY 10022	23,939,836	(2)	23.6	%
William L. Bruggeman, Jr. 20 Anemone Circle, North Oaks, MN 55127	17,666,471	(3)	22.8	%
Wells Fargo Energy Capital, Inc. 1000 Louisiana 9th Floor, Houston, TX 77002	8,900,000	(4)	10.3	%

Named Executive Officers and Directors
Calvin A. Wallen, III 9870 Plano Road, Dallas, TX 75238	50,131,548	(5)	45.8	%
Bob L. Clements 9870 Plano Road, Dallas, TX 75238	1,360,027	(6)	1.8	%
Gene C. Howard 2402 East 29th St., Tulsa, OK 74114	1,020,180	(7)	1.3	%
Jon S. Ross 9870 Plano Road, Dallas, TX 75238	433,000	(8)		*
Paul R. Ferretti 8 Edgewood Road, Yardley, PA 19067	183,507			*
David B. Brown 4823 Ellensburg Drive, Dallas, TX 75244	243,507			*
Larry G. Badgley 9870 Plano Road, Dallas, TX 75238	288,667	(9)		*

All officers and directors as a group (7 persons)	53,660,436		48.9	%

* Denotes less than one percent

(1) Based on a total of 77,505,908 shares of common stock issued and outstanding on October 8, 2013.

(2) Consists of warrants to purchase shares of common stock. The holders of such warrants also hold Series C 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 400,000 shares issuable upon conversion of the 200 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) 674,000 shares held by certain children of Mr. Wallen; (d) 700,000 shares held by Tauren Exploration,

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Inc., a corporation wholly owned by Mr. Wallen; (e) 3,600,000 shares issuable upon conversion of 1,800 shares of Series B Convertible Preferred Stock of the Company held by Tauren; (f) 24,094,000 shares issuable upon conversion of 12,047 shares of Series B Convertible Preferred Stock of the Company held by Langtry Mineral & Development, LLC, an entity controlled Mr. Wallen; and (g) 4,230,000 shares issuable upon conversion of 2,115 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.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships and Related Transactions

Effective January 1, 2002, the Company’s principal executive and administrative offices are located at 9870 Plano Road, Dallas, Texas, in offices that are owned by an affiliate that is controlled by Mr. Wallen. From July 1, 2010 through December 31, 2010 the offices were leased on a month-to-month basis for an average monthly amount charged to the Company of $2,229, which was the same amount per month charged during all of fiscal 2010 and 2009. Effective, January 1, 2011, the Company signed a 2 year lease that charges the Company a monthly fee of $8,000 per month. Effective, January 1, 2013, the Company signed a 9 month lease extension that charges the Company a monthly fee of $8,000 per month. 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 $8,000 per month.

Tauren owns a working interest in the wells in which the Company owns a working interest. For fiscal 2013 the Company owed $6,166 to Tauren, for fiscal 2012 Tauren owed the Company $2,730 and the Company owed $14,537 to Tauren for miscellaneous general and administrative expenses and royalties for fiscal 2011. Tauren owed the Company $38,756, $1,551 and $5,127 for royalties paid by a third-party operator for fiscal year 2013, 2012 and 2011, 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 2013, 2012 and 2011, the Company owed Fossil $27,949, $56,123 and $43,143, respectively, for drilling costs and lease and operating expenses, and was owed by Fossil $28,897, $22,770 and $80,674, respectively, for oil and gas sales.

In addition, during fiscal 2013, 2012 and 2011, 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 $439,874, $493,188 and $1,250,430 during fiscal 2013, 2012 and 2011, respectively; and Fossil paid Cubic an aggregate of $252,532, $344,383 and $131,573 during fiscal 2013, 2012 and 2011, respectively for oil and gas sales.

On November 24, 2009, the Company entered into transactions with Tauren and Langtry Mineral & Development, LLC (“Langtry”), both of which are entities controlled by Calvin Wallen III, the Chief Executive Officer of the Company, 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. The Company expected to use the Drilling Credits to fund $30,952,810 of its share of the drilling and completion costs for those horizontal Haynesville Shale wells drilled in sections previously operated by an affiliate of the Company, which are now operated by a third party. As consideration for the Drilling Credits, the Company, (a) has 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) has issued to Langtry 10,350,000 Company common shares and preferred stock in the amount of $10,350,000, convertible into Company common shares at $1.20 per common share, with a five year conversion term. The preferred

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stock is entitled to cumulative dividends equal to 8% per annum, payable quarterly, which dividends may be paid in cash or in additional shares of preferred stock, in the Company’s discretion. As of June 30, 2013, the Company issued preferred stock in the amount of 118,113 in lieu of cash dividends. The preferred stock may be redeemed by the Company at any time, at a redemption price equal to 20% over the original issue price. The consideration described above was determined based upon negotiations between Tauren and a Special Committee of the Company’s directors, excluding Mr. Wallen. The Special Committee obtained an “fairness opinion” from its independent financial advisor with respect to the fairness, from a financial point of view, to the public stockholders of the Company, of such transactions.

On October 2, 2013, Mr. Wallen and Langtry Mineral & Development, LLC, an entity controlled by Mr. Wallen, pursuant to the terms of the Conversion Agreement, 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.

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 bore interest at the prime rate plus one percent (1%), and originally provided for interest payable monthly. The outstanding principal balance was originally payable on September 30, 2012 and was subordinated to the indebtedness under the Amended Credit Agreement. The proceeds of this note were used to repay prior indebtedness of the Company. As part of the Recent Transactions, 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 the Wallen Note, which included $114,986 of accrued and unpaid interest. In addition, in order to pay certain deposits in connection with the purchase of assets from Gastar, Mr. Wallen, through an affiliate, advanced $2,000,000 to the Company, which advances were repaid on October 2, 2013. Also as part of the Recent Transactions, Tauren sold certain working interests in its Northwest Louisiana acreage to the Company for $6,000,000, which was paid in Series B Convertible Preferred Stock with an aggregate stated value of $2,000,000, plus $4,000,000 in cash.

It is the Company’s policy that any transactions between us and related parties will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.

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Item 14. Principal Accountant Fees and Services.

	July 1, 2012 -		July 1, 2011 -
	June 30, 2013		June 30, 2012
Audit fees	$	46,000	$	45,000
Audit-related fees	17,300		15,200
Tax fees	10,600		7,000
All other fees	2,200		—
Total	$	76,100	$	67,200

Audit Fees

Aggregate audit fees billed for professional services rendered by Philip Vogel & Co., PC were $46,000 for the year ended June 30, 2013 and $45,000 for the year ended June 30, 2012. Such fees were primarily for professional services rendered for the audits of our consolidated financial statements during the fiscal years ended June 30, 2013 and 2012.

Audit-Related Fees

Aggregate audit-related fees billed for professional services rendered by Philip Vogel & Co., PC were $17,300 for the year ended June 30, 2013 and $15,200 for the year ended June 30, 2012. Such fees were for limited reviews of our unaudited condensed consolidated interim financial statements.

Tax Fees

Aggregate income tax compliance and related services fees billed for professional services rendered by Philip Vogel & Co., PC were $10,600 for the year ended June 30, 2013 and $7,000 for the year ended June 30, 2012.

All Other Fees

In addition to the fees described above, aggregate fees of: $2,200, of which $1700 related to review of acquisition documents and $500 related to attendance at our annual shareholders’ meeting, were billed by Philip Vogel & Co., PC during the year ended June 30, 2013. Philip Vogel & Co., PC did not bill any other fees during the year ended June 30, 2012.

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 Philip Vogel & Co., PC during the years ended June 30, 2013 and June 30, 2012 were pre-approved in accordance with the policies of our Audit Committee.

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PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) (1) and (2) Financial Statements and Financial Statement Schedules

See “Index to Financial Statements”.

(a) (3) Exhibits

See the Exhibit Index immediately preceding the Exhibits filed with this report.

SIGNATURES

Pursuant to requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned; thereunto duly authorized, on June 26, 2014.

	CUBIC ENERGY, INC.

	By:	/s/ Calvin A. Wallen, III
		Calvin A. Wallen, III
		President and Chief Executive Officer

	By:	/s/ Larry G. Badgley
		Larry G. Badgley
		Vice President, Finance and Compliance (acting principal financial and accounting officer)

Pursuant to requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Calvin A. Wallen, III	Chairman, President and Chief Executive Officer (principal executive officer)	June 26, 2014
Calvin A. Wallen, III		June 26, 2014

/s/ Larry G. Badgley	Vice President, Finance and Compliance (acting principal financial and accounting officer)	June 26, 2014
Larry G. Badgley		June 26, 2014

/s/ Jon S. Ross	Secretary and Director	June 26, 2014
Jon S. Ross	Secretary and Director	June 26, 2014

/s/ Gene C. Howard	Director	June 26, 2014
Gene C. Howard	Director	June 26, 2014

/s/ Bob L. Clements	Director	June 26, 2014
Bob L. Clements	Director	June 26, 2014

/s/ David B. Brown	Director	June 26, 2014
David B. Brown	Director	June 26, 2014

/s/Paul R. Ferretti	Director	June 26, 2014
Paul R. Ferretti	Director	June 26, 2014

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CUBIC ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

JUNE 30, 2013

	Page

Report of Independent Registered Public Accounting Firm	F-1

Financial Statements:

Balance Sheets	F-2

Statements of Operations	F-3

Statements of Changes in Stockholders’ Equity	F-4

Statements of Cash Flows	F-5

Notes to Financial Statements	F-6
Note A — Background and general	F-6
Note B — Significant accounting policies	F-6
Note C — Stockholders’ equity	F-14
Note D — Loss per common share	F-18
Note E — Long-term debt	F-18
Note F — Related party transactions	F-22
Note G — Income taxes	F-23
Note H — Commitments and contingencies	F-25
Note I — Cost of oil and gas properties	F-27
Note J — Oil and gas reserves information (unaudited)	F-28
Note K — Selected quarterly financial data (unaudited)	F-33
Note L — Subsequent events	F-33
Note M — Liquidity	F-37

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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 balance sheets of Cubic Energy, Inc., a Texas corporation, as of June 30, 2013 and 2012, and the related statements of operations, of changes in stockholders’ equity and of cash flows for each of the three years in the period ended June 30, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cubic Energy, Inc. as of June 30, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended June 30, 2013, in conformity with accounting principles generally accepted in the United States of America.

	/s/ PHILIP VOGEL & CO. PC


	Certified Public Accountants

Dallas, Texas

October 15, 2013

F-1

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CUBIC ENERGY, INC.

BALANCE SHEETS

JUNE 30, 2013 AND 2012

	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	260,576		$	275,527
Accounts receivable - trade	586,174			2,568,249
Due from affiliate	1,678			1,178
Other prepaid expenses	156,892			94,517
Total current assets	1,005,320			2,939,471
Property and equipment (at cost):
Oil and gas properties, full cost method:
Proved properties (including wells and related equipment and facilities)	33,828,079			33,939,964
Office and other equipment	30,227			28,420
Oil and gas properties, and equipment, at cost	33,858,306			33,968,384
Less accumulated depreciation, depletion and amortization	19,134,081			15,885,822
Oil and gas properties, and equipment, net	14,724,225			18,082,562
Other assets:
Deposit on acquisition	2,300,000			—
Drilling credit	—			9,517,258
Total other assets	2,300,000			9,517,258
	$	18,029,545		$	30,539,291
Liabilities and stockholders’ equity
Current liabilities:
Notes payable - WFEC - term note	$	5,000,000		$	5,000,000
Notes payable - WFEC - revolver	20,865,110			30,000,000
Notes payable to affiliate	2,000,000			2,000,000
Advance from affilliate	2,000,000			—
Accounts payable and accrued expenses	1,331,609			1,674,459
Due to affiliates	—			33,353
Total current liabilities	31,196,719			38,707,812
Commitments and contingencies (Note H)	—			—
Stockholders’ equity:
Preferred stock - $.01 par value, authorized 10,000,000 shares; Series A - 8% preferred stock,$100 stated value, redeemable at $120 and covertible at $1.20 per common share, authorized 165,000 shares, 118,113 shares issued and outstanding at June 30,2013, and 109,124 issued and outstanding at June 30, 2012	1,181			1,091
Additional paid-in capital	11,810,119			10,911,309
Common stock - $.05 par value, authorized 200,000,000 shares, issued 77,360,908 shares at June 30, 2013 and 77,215,908 shares at June 30, 2012	3,868,047			3,860,797
Additional paid-in capital	56,910,545			55,963,830
Retained earnings’ (deficit)	(85,757,066		)	(78,905,548		)
Total stockholders’ equity	(13,167,174		)	(8,168,521		)
Total liabilities and stockholders’ equity	$	18,029,545		$	30,539,291

The accompanying notes are an integral part of these statements.

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CUBIC ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED JUNE 30, 2013, 2012, AND 2011

	2013			2012			2011
Revenues:
Oil and gas sales	$	3,843,420		$	6,939,999		$	6,133,299
Total revenues	$	3,843,420		$	6,939,999		$	6,133,299
Operating costs and expenses:
Oil and gas production, operating and development costs	1,872,186			1,972,223			1,857,528
General and administrative expenses	2,332,946			3,572,260			3,156,860
Depreciation, depletion and non-loan-related amortization	3,248,260			6,090,529			3,707,255
Total operating costs and expenses	7,453,392			11,635,012			8,721,643
Operating income (loss)	(3,609,972		)	(4,695,013		)	(2,588,344		)
Non-operating income (expense):
Other income	666,270			2,927			8,098
Interest expense, including amortization of loan discount	(2,470,516		)	(7,729,992		)	(7,648,622		)
Amortization of loan costs	(520,000		)	(68,554		)	(60,368		)
Total non-operating income (expense)	(2,324,246		)	(7,795,619		)	(7,700,892		)
Loss before income taxes	(5,934,218		)	(12,490,632		)	(10,289,236		)
Provision for income taxes	—			—			—
Net loss	$	(5,934,218	)	$	(12,490,632	)	$	(10,289,236	)
Dividends on preferred shares	(917,300		)	(874,239		)	(860,755		)
Net loss available to common shareholders	(6,851,518		)	(13,364,871		)	(11,149,991		)
Net loss per common share - basic and diluted	$	(0.09	)	$	(0.17	)	$	(0.15	)
Weighted average common shares outstanding	77,263,381			77,009,351			76,048,925

The accompanying notes are an integral part of these statements.

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CUBIC ENERGY, INC.

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED JUNE 30, 2013, 2012, AND 2011

	Cumulative Preferred Stock			Additional		Common Stock			Additional					Total
	Shares	Par		paid-in		Shares	Par		paid-in		Accumulated			stockholders’
	Outstanding	Value		capital		Outstanding	Value		capital		deficit			equity

Balance, June 30, 2010	103,500	$	1,035	$	10,348,965	75,394,579	$	3,769,730	$	54,032,985	$	(54,390,686	)	$	13,762,029

Stock issued for warrant exercise	—					954,315	47,716		595,064		—			642,780
Pref. Stock issued for dividends	4,491	45		449,055		—					—			449,100
Warrant valuations for loan extension	—					—	—		516,882		—			516,882
Stock issued under compensation plan	—					467,014	23,351		519,268		—			542,619
Stock option compensation	—					—	—		31,531		—			31,531
Preferred stock dividends	—					—	—		—		(860,755		)	(860,755		)

Net loss, year ended June 30, 2011	—					—	—		—		(10,289,236		)	(10,289,236		)

Balance, June 30, 2011	107,991	$	1,080	$	10,798,020	76,815,908	$	3,840,797	$	55,695,730	$	(65,540,677	)	$	4,794,950

Pref. Stock issued for dividends	1,133	11		113,289		—					—			113,300
Stock issued under compensation plan	—					400,000	20,000		216,000		—			236,000
Stock option compensation	—					—	—		52,100		—			52,100
Preferred stock dividends	—					—	—		—		(874,239		)	(874,239		)

Net loss, year ended June 30, 2012	—					—	—		—		(12,490,632		)	(12,490,632		)

Balance, June 30, 2012	109,124	$	1,091	$	10,911,309	77,215,908	$	3,860,797	$	55,963,830	$	(78,905,548	)	$	(8,168,521	)

Pref. Stock issued for dividends	8,989	90		898,810		—	—		—		—			898,900
Warrant issued for loan costs	—					—	—		902,161		—			902,161
Stock issued under compensation plan	—					145,000	7,250		27,188		—			34,438
Stock option compensation	—					—	—		17,366		—			17,366
Preferred stock dividends	—					—	—		—		(917,300		)	(917,300		)

Net loss, year ended June 30, 2013	—					—	—		—		(5,934,218		)	(5,934,218		)

Balance, June 30, 2013	118,113	$	1,181	$	11,810,119	77,360,908	$	3,868,047	$	56,910,545	$	(85,757,066	)	$	(13,167,174	)

The accompanying notes are an integral part of these statements.

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CUBIC ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED JUNE 30, 2013, 2012, AND 2011

	2013			2012			2011
Cash flows from operating activities:
Net (loss)	$	(5,934,218	)	$	(12,490,632	)	$	(10,289,236	)
Adjustments to reconcile net (loss) to cash provided (used) by operating activities:
Depreciation, depletion and amortization	4,410,420			11,962,542			9,508,063
Stock issued for compensation	51,805			288,100			574,150
Change in assets and liabilities:
(Increase) decrease in accounts receivable - trade	1,982,075			(808,059		)	(180,141		)
(Increase) decrease in other prepaid expenses	(62,375		)	(40,353		)	(11,639		)
Increase (decrease) in accounts payable and accrued liabilities	(361,252		)	631,446			(1,964,987		)
Increase (decrease) in due to affiliates	(32,251		)	61,898			(203,369		)
Net cash provided (used) by operating activities	54,204			(395,058		)	(2,567,159		)
Cash flows from investing activities:
Acquisition and development of oil and gas properties	(450,440		)	(87,032		)	(1,168,574		)
Increase (decrease) in capital portion of due to affiliates	(1,602		)	(1,602		)	(243,832		)
Purchase of office equipment	(1,806		)	—			—
Deposit on Acquisition	(2,300,000		)	—			—
Reimbursement of advances on development costs	10,079,583			—			—
Net cash provided (used) by investing activities	7,325,735			(88,634		)	(1,412,406		)
Cash flows from financing activities:
Issuance of common stock, net	—			—			642,780
Payments on credit facility	(9,134,890		)	—			5,000,000
Dividends paid	—			(783,029		)	(412,865		)
Advance from affiliate	2,000,000			—			—
Loan costs incurred and other	(260,000		)	—			(100,000		)
Net cash provided (used) by financing activities	(7,394,890		)	(783,029		)	5,129,915
Net increase (decrease) in cash and cash equivalents	$	(14,951	)	$	(1,266,721	)	$	1,150,350
Cash and cash equivalents:
Beginning of year	275,527			1,542,248			391,898
End of year	$	260,576		$	275,527		$	1,542,248
Other information:
Cash interest paid on debt	$	1,521,180		$	1,919,863		$	1,891,828
Non-cash investing and financing activities:
Preferred stock dividends accrued	$	917,300		$	874,239		$	860,755
Use of prepaid drilling credits	$	—		$	8,246,058		$	9,455,844
Warrants issued for loan costs	$	902,161		$	—		$	516,882
Conversion of accrued Preferred stock dividend	$	898,900		$	113,300		$	449,100

The accompanying notes are an integral part of these statements.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note A - Background and general:

Cubic Energy, Inc. (the “Company”) is engaged in domestic crude oil, natural gas and NGL exploration, development and production, with primary emphasis on the production of oil and gas reserves through the acquisition and development of proved, producing oil and gas properties in the states of Texas and Louisiana.

Note B - Significant accounting policies:

Cash equivalents

For purposes of the statements of cash flows, the Company considers all certificates of deposit and other financial instruments with original maturity dates of three months or less to be cash equivalents.

Accounts Receivable

The Company has receivables from affiliated and non-affiliated third-party operators and oil and gas purchasers that are generally uncollateralized. The Company reviews these parties for creditworthiness and general financial condition. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. If necessary, the Company would determine an allowance by considering the length of time past due, previous loss history and the payor’s ability to pay its obligation, among other things. The Company writes off accounts receivable when they are determined to be uncollectible.

The Company establishes provisions for losses on accounts receivable if it determines that it will not collect all or part of the outstanding balance. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. There was no allowance for doubtful accounts at June 30, 2013, 2012 and 2011.

Office and other equipment

Office and other equipment are stated at cost and depreciated by the straight-line method over estimated useful lives ranging from five to seven years. Depreciation and amortization of office and other equipment amounted to $3,372, $4,146 and $4,070 for the years ended June 30, 2013, 2012 and 2011, respectively.

Impairment of long-lived assets and long-lived assets to be disposed of

The Company follows the provisions of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 360-10, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets, which provides guidance for the financial accounting and reporting of impairment or disposal of long-lived assets. In addition, the Company is subject to the rules of the Securities and Exchange Commission with respect to impairment of oil and gas properties accounted for under the full cost method of accounting, as described below.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Full cost method of accounting for oil and gas properties

The Company has adopted the full cost method of accounting for oil and gas properties. Management believes adoption of the full cost method more accurately reflects management’s exploration objectives and results by including all costs incurred as integral for the acquisition, discovery and development of whatever reserves ultimately result from its efforts as a whole. Under the full cost method of accounting, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs related to exploratory and development activities, and directly related overhead costs, are capitalized into the full cost pool.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

In addition, the capitalized costs are subject to a “full cost ceiling test,” which generally limits such costs to the aggregate of the “estimated present value” (discounted at a 10 percent (10%) interest rate) of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties. No impairment of oil and gas properties charge was recorded for fiscal 2013, 2012 and 2011, respectively.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.

Depletion of producing oil and gas properties amounted to $3,244,887, $6,086,383 and $3,703,185 for the years ended June 30, 2013, 2012 and 2011, respectively.

Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates that will apply in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Under ASC No. 740, Income Tax Consequences of Issuing Convertible Debt with a Beneficial Conversion Feature, the issuance of convertible debt with a beneficial conversion feature results in a temporary difference for purposes of applying ASC No. 740. The deferred taxes recognized for the temporary difference should be recorded as an adjustment to paid-in capital. ASC No. 740 requires that the non-detachable conversion feature of a convertible debt security be accounted for separately if it is a “beneficial conversion feature.”

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

A beneficial conversion feature is recognized and measured by allocating to additional paid-in capital a portion of the proceeds equal to the conversion feature’s intrinsic value. A discount on the convertible debt is recognized for the amount that is allocated to additional paid-in capital. The debt discount is accreted from the date of issuance to the stated redemption date of the convertible instrument or through the earliest conversion date if the instrument does not have a stated redemption date. The U.S. Internal Revenue Code includes the entire amount of proceeds received at issuance as the tax basis of the convertible debt security. ASC 740 also provides guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions in an enterprise’s financial statements and requires an entity to recognize the financial statement impact of a tax position when it is more likely than not that the position will be sustained upon examination. If the tax position meets the more-likely-than-not recognition threshold, the tax effect is recognized at the largest amount of the benefit that is greater than 50% likely of being realized upon ultimate settlement. Interest expense and penalties related to tax liabilities will be recognized in the first period that it would begin to accrue according to the relevant tax law, and will be classified as an operating expense.

The Company is no longer subject to income tax examinations by the Internal Revenue Service for years prior to 2009. For state tax jurisdictions, the Company is no longer subject to income tax examinations for years prior to 2009.

Oil and gas revenues

The Company recognizes oil and gas revenues when oil and gas production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. Due to a decrease in the number of third-party operated Haynesville Shale wells being drilled and completed during fiscal 2013, and declining production from existing wells, sales and production volumes decreased 49% from fiscal 2012 to fiscal 2013, versus the increased number of wells drilled and completed during fiscal 2012 that created an increase of 13% from fiscal 2011 to fiscal 2012.

Earnings (loss) per common share

The Company has adopted the provisions of ASC No. 260, Earnings per Share. ASC No. 260 requires the presentation of basic earnings (loss) per share (“EPS”) and diluted EPS. Basic EPS is calculated by dividing net income or loss, less preferred dividends (income available to common stockholders), by the weighted average number of common shares outstanding for the period. Diluted EPS is calculated by dividing net income or loss, less preferred dividends (income available to common stockholders), by the weighted average number of common shares outstanding plus any dilutive shares (i.e., preferred dividends, stock warrants or other convertible debt) during the period.

As discussed in Note D, there were no dilutive securities outstanding during the years ended June 30, 2013, 2012 and 2011. The weighted average number of common and common equivalent shares outstanding was 77,263,381, 77,009,351 and 76,048,925 for the years ended June 30, 2013, 2012 and 2011, respectively.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Concentration of customers and credit risk

Financial instruments which potentially subject the Company to a concentration of credit risk consist primarily of trade accounts receivable with a variety of local, national, and international oil and natural gas companies. Such credit risks are considered by management to be limited due to the financial resources of the oil and natural gas companies.

Our cash accounts at our financial institution, which are only FDIC insured to a total balance of $250,000, had a balance of $313,205 as of June 30, 2013. Therefore, there is $63,205 customer/credit risk to the Company, as the remaining balance was fully insured by FDIC.

Our revenue of $3,843,420 was partially generated by three producers with 5% or greater of that total. They are as follows: Goodrich totaled $259,108 or 7%, Chesapeake totaled $338,516 or 9%, and EXCO totaled $2,774,919 or 72%.

As noted earlier, the Company has receivables from non-affiliated operators for oil and gas sales. It also has accounts payable to such operators for its share of development, production, and operating costs. As of June 30, 2013, a single operator owed the Company approximately $182,643 which is included in accounts receivable. As of June 30, 2012, a single operator owed the Company approximately $2,228,983 which is included in accounts receivable. The receivable as of June 30, 2012, as well as the arbitration award, was received during fiscal 2013. Revenues attributed to this operator amounted to approximately $330,697 for the year ended June 30, 2011.

Reporting comprehensive income (loss) and operating segments

The Company has adopted the provisions of ASC No. 220, Comprehensive Income, and ASC No. 280, Segment Reporting. ASC No. 220 requires that an enterprise report, by major components and as a single total, the change in its net assets during the period from non-owner sources. ASC No. 280 establishes annual and interim reporting standards for an enterprise’s operating segments and related disclosures about its products, services, geographic areas and major customers. Adoption of ASC No. 220 and ASC No. 280 has had no impact on the Company’s financial position, results of operations, cash flows, or related disclosures because the Company’s operations are considered to be in a single segment.

Use of 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 estimate. 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 these estimates will change materially in the near term, no estimate can be made of the range of possible changes that might occur.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Fair value of financial instruments

The Company has adopted the provisions of ASC No. 825, Financial Instruments. ASC No. 825 allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. ASC No. 825 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities.

The Company defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties. Financial instruments included in the Company’s financial statements include cash and cash equivalents, short-term investments, accounts receivable, other receivables, other assets, accounts payable, notes payable and due to affiliates. Unless otherwise disclosed in the notes to the financial statements, the carrying value of financial instruments is considered to approximate fair value due to the short maturity and characteristics of those instruments. The carrying value of debt approximates fair value as terms approximate those currently available for similar debt instruments.

Asset retirement obligations

We have asset retirement obligations primarily for the future abandonment of oil and gas wells, and we maintain reserve accounts for part of these obligations under our operating agreements with the operators of wells in which we have an interest. We account for these obligations under ASC No. 410-20, Asset Retirement and Environmental Obligations, which requires the fair value of an asset retirement obligation to be recognized in the period when it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement cost is capitalized as part of the carrying amount of the underlying long-lived asset. ASC No. 410-20 also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation is generally determined on a units-of-production basis over the life of the asset, while the accretion escalates over the life of the asset, typically as production declines. The amounts recognized are based on numerous estimates and assumptions, including recoverable quantities of oil and gas, future retirement and site reclamation costs, inflation rates and credit-adjusted risk-free interest rates.

Stock-based compensation

The Company accounts for its stock-based employee compensation plans pursuant to ASC No. 718, Stock Compensation. ASC No. 718 requires the Company to recognize compensation costs related to stock-based payment transactions (i.e., the granting of stock options and warrants, and awards of shares of common stock) in the financial statements. With limited exceptions, the amount of compensation is measured based on the grant-date fair value of the equity issued. Compensation cost is recognized over the period that an employee provides services in exchange for the award.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Exit or disposal activities

The Company has adopted the provisions of ASC No. 420, Exit or Disposal Cost Obligations. ASC No. 420 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operations, or other exit or disposal activities. No exit or disposal activities have been entered into by the Company.

Financial instruments with characteristics of both liabilities and equity

The Company has adopted the provisions of ASC No. 480, Distinguishing Liabilities from Equity. ASC No. 480 established standards for how a company classifies and measures certain financial instruments with characteristics of both liabilities and equity. The statement requires that a company classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) if certain criteria are met. Freestanding financial instruments that obligate the issuer to redeem the holder’s shares, or are indexed to such an obligation, and are settled in cash or settled with shares meeting certain conditions would be treated as liabilities. Many of those instruments were previously classified as equity.

ASC No. 480-10-05, Distinguishing Liabilities from Equity, clarifies that freestanding warrants and similar instruments on shares that are redeemable should be accounted for as liabilities under ASC No. 480 regardless of the timing of the redemption feature or price, even though the underlying shares may be classified as equity. Although the Company had outstanding warrants as of June 30, 2013, the shares issuable upon exercise of the warrants are not redeemable; consequently, adoption of ASC No. 480 has not had an impact on the Company’s financial position, results of operations or cash flows.

Guarantee of debt

The Company has adopted the provisions of ASC No. 460, Guarantees. ASC No. 460 clarifies that a guarantor is required to recognize, at the inception of certain types of guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee, and requires additional disclosures on existing guarantees even if the likelihood of future liability under the guarantees is deemed remote. The Company has not issued any guarantees and, therefore, the adoption of ASC No. 460 has not had any impact on the Company’s financial statements.

Accounting changes and error corrections

The Company has adopted the provisions of ASC No. 250, Accounting Changes and Error Corrections. ASC No. 250 applies to all voluntary changes in accounting principles and changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Under previous guidance, changes in accounting principle were recognized as a cumulative effect in the net income of the period of the change. ASC No. 250 requires retrospective application of changes in accounting principle, limited to the direct effects of the change, to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change in accounting principle. The adoption of ASC No. 250 did not have a material impact on the Company’s financial position, results of operations or cash flows.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Debt modifications

The Company has adopted the provisions of ASC No. 470, Debt Modifications and Extinguishment. ASC No. 470 requires an issuer that modifies a debt instrument to compare the present value of the original debt instrument’s cash flows to the present value of the cash flows of the modified debt. If the present value of those cash flows varies by more than 10 percent (10%), the modification is considered significant and extinguishments accounting is applied to the original debt. If the change in the present value of the cash flows is less than 10 percent (10%), the debt is considered to be modified and is subject to ASC No. 470 modification accounting. ASC No. 470 requires that in applying the 10 percent (10%) test the change in the fair value of the conversion option be treated in the same manner as a current period cash flow. ASC No. 470 also requires that, if a modification does not result in an extinguishment, the change in fair value of the conversion option be accounted for as an adjustment to interest expense over the remaining term of the debt. The issuer should not recognize a beneficial conversion feature or reassess an existing beneficial conversion feature upon modification of the conversion option of a debt instrument that does not result in an extinguishment.

Certain hybrid financial instruments

The Company has adopted the provisions of ASC No. 815, Derivatives and Hedging. ASC No. 815 improves the financial reporting of certain hybrid financial instruments by requiring more consistent accounting that eliminates exemptions and provides a means to simplify the accounting for these instruments. Specifically, ASC No. 815 allows financial instruments that have embedded derivatives to be accounted for as a whole (eliminating the need to bifurcate the derivative from its host) if the holder elects to account for the whole instrument on a fair value basis.

Reporting taxes collected

The Company has adopted the provisions of ASC No. 605, Taxes Collected from Customers and Remitted to Governmental Authorities. Taxes collected should be presented in the income statement (gross versus net presentation). ASC No. 605 addresses income statement classification and disclosure requirements of externally-imposed taxes on revenue-producing transactions.

Subsequent Events

The Company has adopted the provisions of ASC No. 855, Subsequent Events. ASC No. 855 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. ASC No. 855 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.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Other recent accounting pronouncements

In January 2013, the FASB issued ASU No. 2013-01— “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities”. The main objective in developing this update is to address implementation issues about the scope of ASU No. 2011-11. This ASU clarifies the scope of the offsetting disclosures and addresses any unintended consequences. The scope of update to ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This ASU is effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods. An entity should provide the required disclosures retrospectively for all comparative periods presented. This ASU was adopted on January 1, 2013 and the adoption did not have a material impact on our financial position or results of operations.

In September 2011, the FASB issued ASU No. 2011-08, Testing Goodwill for Impairment. ASU 2011-08 provides entities an option of assessing qualitative factors when testing goodwill for impairment before calculating the fair value of a reporting unit in step 1 of the goodwill impairment test. If an entity determines that the fair value of a reporting unit is more likely than not less than its carrying value, then performing the two step impairment test is required after performing a qualitative assessment. Otherwise, the two step impairment test is not necessary. ASU 2011-08 was effective for the Company as of January 1, 2012. This standard on annual goodwill impairment test did not have any material impact to the Company’s Consolidated Financial Statements.

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. The issuance of ASU 2011-05 is intended to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance in ASU 2011-05 supersedes the presentation options in ASC Topic 220 and facilitates convergence of U.S. generally accepted accounting principles and International Financial Reporting Standards by eliminating the option to present components of other comprehensive income as part of the statement of changes in shareholders’ equity and requiring that all non-owner changes in shareholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This guidance will be applied retrospectively and early adoption is permitted. This guidance was effective for fiscal years and interim periods within those years, beginning after December 15, 2011. The adoption of this guidance did not have a material impact on the Company’s Consolidated Financial Statements.

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S GAAP and IFRS. This amendment of the FASB Accounting Standards Codification is to ensure that fair value has the same meaning in U.S. GAAP and IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective during the interim and annual periods beginning after December 15, 2011. This authoritative guidance does not any material effect on the Company’s Consolidated Financial Statements.

In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures for the Company was to align the definition of

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NOTES TO FINANCIAL STATEMENTS

proved reserves with the Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008 and effective for fiscal periods ending on or after December 31, 2009. The accounting standards revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period preceding the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities for 2013, 2012 and 2011 has been presented following these new reserve estimation and disclosure rules.

Note C — Stockholders’ equity:

The Company’s authorized capital is 200,000,000 shares of $0.05 par value common stock and 10,000,000 shares of $0.01 par value preferred stock. 118,113 shares of preferred stock were issued and outstanding at June 30, 2013 and 109,124 shares of preferred stock were issued and outstanding at June 30, 2012.

Stock and warrants

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 currently at an exercise price of $0.20 per share, which were re-priced in March 2013 from $0.9911 as partial consideration for the maturity date extension. The term loan is also convertible into 5,044,900 shares of Company common stock at a conversion price of $0.9911 per share. None of the above-referenced warrants had been exercised and all remained outstanding at June 30, 2013. The Company allocated the proceeds from the issuance of the debt to the warrants, the debt and net profits interest (see “Note E — Long-term debt”) based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,314,289 was recorded as an increase in additional paid-in capital and the value assigned to the net profits interest of $213,148 was recorded as a credit to the full cost pool for oil and gas properties.

On December 18, 2009, the Company entered into a Second Amendment to the Credit Agreement with WFEC, providing for a revolving credit facility of up to $40 million and a convertible term loan of $5 million (the “Amended Credit Agreement”). The borrowing base under the revolving credit facility was initially established at $25 million. The indebtedness bears interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, was originally scheduled to mature on July 1, 2012 and is secured by substantially all of the assets of the Company. 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, as of June 30, 2013 at an exercise price of $0.9911 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, 2014.

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NOTES TO FINANCIAL STATEMENTS

the assets of the Company. In connection with entering into the Third Amendment, the Company issued to WFEC additional warrants, expiring on December 1, 2017, for the purchase of up to 1,000,000 shares of the Company’s common stock at an exercise price of $0.20 per share. Loan costs of $89,451 and loan discounts of $527,430 were recognized.

On June 18, 2012, the Company entered into a Fourth Amendment to Credit Agreement (the “Fourth Amendment”) with WFEC providing for, among other things, an extension of the required repayment date to December 31, 2012 and subsequently extended to May 31, 2013 (see Note E-Long-Term Debt). The Fourth Amendment also provides that the borrowing base under the Company’s revolving credit facility with WFEC shall be reduced by seventy-five percent (75%) of the total amount of cash or other readily available funds received by the Company as part of the arbitration award in connection with the arbitration involving the Company, EXCO Operating Company, L.P. and BG US Production Company LLC. The Fourth Amendment also limits the Company’s ability to pay certain general and administrative expenses and to make certain dividends on its capital stock.

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) on March 16, 2010 issued to Langtry 10,350,000 Company common shares and preferred stock with a stated value of $10,350,000, convertible into Company common shares at $1.20 per common share, with a five year conversion term. The preferred stock is entitled to cumulative dividends equal to 8% per annum, payable quarterly, which dividends may be paid in cash or in additional shares of preferred stock, in the Company’s discretion. The preferred stock may be redeemed by the Company at any time, at a redemption price equal to 20% over the original issue price, plus accrued and unpaid dividends.

In connection with the following common stock issuances, the Company entered into Subscription and Registration Rights Agreements (“Subscription Agreements”) with certain investors. Pursuant to the Subscription Agreements, the Company issued an aggregate of 2,104,001 shares of common stock and warrants exercisable into 1,052,000 shares of common stock. On August 18, 2009, four investors acquired 804,000 shares of common stock and warrants exercisable into 402,000 shares of common stock, through the payment of $683,400. On August 26, 2009, six investors acquired 1,300,001 shares of common stock and warrants exercisable into 650,000 shares of common stock, through the payment of $1,105,001. The warrants are exercisable through July 31, 2014, at $0.85 per share. With respect to certain of such issuances, the Company paid broker-dealer commissions in the aggregate amount of $59,500 to Avalon Group, Ltd. The aggregate consideration, net of commissions, from such issuances has been used for working capital purposes. Warrants for 264,706 shares of common stock were exercised during 2011, and 787,294 warrants remain outstanding at June 30, 2013. These expire in July 2014.

Stock-based compensation

On December 29, 2005, the stockholders of the Company approved the 2005 Stock Option Plan (the “Plan”) and 3,750,000 shares of common stock were reserved. At the 2010 Annual Stockholder Meeting, stockholders approved an increase in the number of shares under the Plan by 2,000,000 shares, or a total of 5,750,000 shares, of which 4,314,195 shares had been issued through June 30, 2013. Total shares available under the Plan are 1,435,805, as of June 30, 2013.

On November 30, 2010, the Board of Directors increased the number of directors of the Company and appointed David B. Brown and Paul R. Ferretti to fill the vacancies created by such increase, in accordance with the provisions of the Company’s bylaws. The Board authorized stock grants of 3,507 shares of common stock to each of Messrs. Brown and Ferretti, which number of shares is equal to the number of shares granted to other non-management directors for calendar year 2010, on a prorated basis, with an aggregate market value

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NOTES TO FINANCIAL STATEMENTS

of the common stock granted of $4,418 based on at the last sale price ($0.63 per share) on the aforementioned date, on the NYSE MKT of the Company’s common stock. Such amounts were recorded as compensation expense upon issuance.

On January 14, 2011, the Company entered into an employment agreement with its Chief Financial Officer, Larry G. Badgley. The agreement provides for the grant of stock options, under the Plan, for the purchase of an aggregate of 288,667 shares of Company common stock. These options have an exercise price $1.20 per share and expire five years from their issue date. One option, for the purchase of 15,667 shares, was fully vested upon grant. The other option, for the purchase of 273,000 shares vested on October 1, 2012. We estimated the fair value of the options on the date of grant using the Black-Scholes valuation model to be $100,997. We recorded $17,366 and $52,100 and $31,531 of compensation expense for the years ending June 30, 2013, 2012 and 2011, respectively.

The weighted-average fair value at the grant date using the Black-Scholes valuation model for options issued during fiscal 2011 was $0.35 per share. The fair value of options at the date of grant was estimated using the following weighted-average assumptions for fiscal 2011: (a) no dividend yield on our common stock, (b) expected stock price volatility of 73%, (c) a discount rate of 2.04% and (d) an expected option term of 5 years.

The expected term of the options represents the estimated period of time until exercise and is based on consideration to the contractual terms, vesting schedules and expectations of future employee behavior. For fiscal 2013, expected stock price volatility is based on the historical volatility of our common stock.

The risk-free interest rate is based on the U.S. Treasury bill rate in effect at the time of grant with an equivalent expected term or life.

Information regarding activity for stock options under the Plan is as follows:

`		Weighted-average		Weighted-average	Aggregate
		exercise price per		remaining contractual	intrinsic
	Number of shares	share		term (years)	value

Outstanding, June 30, 2013	288,667	$	1.20	2.25
Options granted	—	—
Options exercised	—	—
Options forfeited/expired	—	—

Outstanding, June 30, 2013	288,667	1.20		2.25	$	—

Exercisable, June 30, 2013	288,667	$	1.20	2.25	$	—

Information related to the Plan during fiscal June 30, 2013 is as follows:

Intrinsic value of options exercised		$	—
Weighted-average fair value of options granted		$	100,997

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NOTES TO FINANCIAL STATEMENTS

On January 4, 2012, the Company issued 400,000 shares of common stock to seven directors of the Company pursuant to the Plan. As of such date, the aggregate market value of the common stock granted was $236,000 based on the last sale price ($0.59 per share), on the NYSE MKT of the Company’s common stock. Such amount was expensed upon issuance to compensation expense.

On January 24, 2013, the Company paid cash of $13,000 and issued 72,500 shares of common stock to four directors of the Company pursuant to 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 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.

The following table provides information related to stock-based compensation for the years ended June 30, 2013, 2012 and 2011:

	Fiscal Year Ended June 30,
	2013		2012		2011
Officer and employee restricted stock grants:
Pretax compensation expense	$	—	$	—	$	—
Tax benefit	$	—	$	—	$	—
Restricted stock expense, net of tax	$	—	$	—	$	—

Director stock grants:
Pretax compensation expense	$	34,438	$	236,000	$	542,619
Tax benefit	$	—	$	—	$	—
Director stock grants expense, net of tax	$	34,438	$	236,000	$	542,619

Stock options:
Pretax compensation expense	$	17,366	$	52,100	$	31,531
Tax benefit	$	—	$	—	$	—
Stock option expense, net of tax	$	17,366	$	52,100	$	31,531

Total stock-based compensation:
Pretax compensation expense	$	51,804	$	288,100	$	574,150
Tax benefit	$	—	$	—	$	—
Total share based compensation expense, net of tax	$	51,804	$	288,100	$	574,150

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note D — Loss per common share:

	2013			2012			2011
Net loss attributable to common stockholders	$	(6,851,518	)	$	(13,364,871	)	$	(11,149,991	)
Weighted average number of shares of common stock	77,263,381			77,009,351			76,048,925
Income (loss) per common share	$	(0.09	)	$	(0.17	)	$	(0.15	)

Potential dilutive securities (e.g., convertible preferred stock, stock warrants and convertible debt) have not been considered because the Company reported a net loss and, accordingly, their effects would be anti-dilutive.

Note E — Long-term debt:

March 2007 debt issue

On March 5, 2007, Cubic entered into a Credit Agreement with WFEC providing for a revolving credit facility of $20,000,000 (the “Revolving Note”) and a convertible term loan of $5,000,000 (the “Term Loan”; and together with the Revolving Note, the “Credit Facility”). The indebtedness bore interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, was originally scheduled to mature on March 1, 2010, and was secured by substantially all of the assets of the Company.

The Term Loan of $5,000,000 is convertible into shares of Cubic common stock, as of June 30, 2013, at a conversion price of $0.9911 per share. Approximately $5,000,000 of the funded amount was used, together with cash on hand, to retire the Company’s previously outstanding senior debt that was due February 6, 2009.

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. As of December 31, 2012, the exercise price was reduced to $0.20 per share, and the expiration date was extended to December 1, 2017.

On December 18, 2009, the Company entered into a Second Amendment to the Credit Agreement with WFEC, providing for a revolving credit facility of up to $40 million and a convertible term loan of $5 million (the “Amended Credit Agreement”). The borrowing base under the revolving credit facility was initially established at $25 million. The indebtedness bears interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, was originally scheduled to mature on July 1, 2012 and was secured by substantially all of the assets of the Company. In connection with entering into the Amended Credit Agreement, the Company issued to WFEC additional warrants, originally scheduled to expire on December 1, 2014, for the purchase of up to 5,000,000 shares of Company common stock and extended the expiration date of warrants to purchase 2,500,000 shares of common stock that were previously issued to WFEC. As of December 31, 2012, the exercise price for each of those warrants was reduced to $0.20 per share, and the expiration date was extended to December 1, 2017.

In connection with entering into the Amended Credit Agreement, the Company allocated the proceeds from the issuance of the debt to the warrants, the debt and the beneficial conversion feature based on their fair market values at the date of issuance. The fair market value assigned to the extension of warrants to

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NOTES TO FINANCIAL STATEMENTS

purchase 2,500,000 shares of Company common stock was $923,302 and the value assigned to the issuance of the warrant to purchase the additional 5,000,000 shares of Company common stock was $8,031,896, which was recorded as an increase in additional paid-in capital relating to common stock. The difference in the fair value of the Term Loan and the face amount of $1,877,494 was recorded as an extinguishment of debt, offset by the amount of unamortized deferred loan cost and discounts associated with the original debt of $129,871. The beneficial conversion feature equaled $5,027,494, which was reduced to $3,122,506 based on the limitation to the fair value of debt. The assignment of a value to the warrants and beneficial conversion feature as well as the write-down of the Term Loan to the fair value resulted in a total loan discount in the amount of $13,955,198 being recorded. Amortization for the fiscal year ended June 30, 2012 was $5,515,769, at which time it was fully amortized, and was $5,500,699 for the fiscal year ended June 30, 2011.

In connection with the modification of the indebtedness pursuant to the Amended Credit Agreement, the Company recorded a gain on extinguishment of debt of $1,747,623. Such amount includes the write-off of the unamortized deferred loan cost ($26,947), and the write-off of the remaining loan discount ($102,924).

Cubic incurred loan costs of $50,000 on the issuance of the debt and warrants. The amount was capitalized and allocated to the debt and was amortized over the original term of the debt. Amortization for the fiscal year ended June 30, 2012 was $19,762, at which time it was fully amortized, and was $19,708 for the fiscal year ended June 30, 2011.

On August 30, 2010, the Company entered into a Third Amendment to the Credit Agreement (the “Third Amendment”) with WFEC providing for an increase in the borrowing base for the Company’s revolving credit facility from $25 million to $30 million. The Company borrowed the full amount of the increase in the borrowing base. The indebtedness under the Credit Facility bore interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, was originally scheduled to mature on July 1, 2012 and was secured by substantially all of the assets of the Company. In connection with entering into the Third Amendment, the Company issued to WFEC additional warrants, scheduled to expire on December 1, 2014, for the purchase of up to 1,000,000 shares of the Company’s common stock, originally at an exercise price of $1.00 per share. As of December 31, 2012, the exercise price was reduced to $0.20 per share. Loan discounts of $527,430 were recognized.

The Company allocated the proceeds from the issuance of the debt to the warrants and the debt. The value assigned to the warrants of $516,882 was recorded as an increase in additional paid-in-capital relating to common stock. The assignment of a value to the warrants resulted in a loan discount being recorded. The discount amortization is over the two-year term of the debt as additional interest expense. Amortization for the fiscal year ended June 30, 2012 was $287,689, at which time it was fully amortized, and was $239,741 for the fiscal year ended June 30, 2011.

Cubic incurred loan costs of $100,000 on the issuance of the debt and warrants. The amount allocable to the debt of $89,451 has been capitalized and was amortized over the term of the debt. Amortization for the fiscal year ended June 30, 2012 was $48,791, at which time it was fully amortized, and was $40,660 for the fiscal year ended June 30, 2011.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Effective December 31, 2012, the Company received an extension until March 31, 2013, of the due date of debt under the Credit Facility, including both the $5,000,000 Term Loan and the outstanding amounts of approximately $20,870,000 under the Revolving Note. The amendment, among other things, required that the Company pay a renewal fee/loan costs of $260,000. These fees were amortized during the quarter ended March 31, 2013. 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. The fair value assigned to the modification in exercise price on the warrants was $902,161 and was recorded as additional debt discount to be amortized over the remaining term. The discount was fully amortized during the year ended June 30, 2013.

The amendment also provided that if the Company did not consummate a substantive transaction involving the acquisition of leases and/or minerals with oil and/or NGL by March 31, 2013, the Company would be required to pay of an additional loan fee of $260,000, which amount was paid on March 31, 2013 and will be amortized over the remaining term of the debt. The amendment also provided that if the Term Loan and Revolving Note are not repaid by March 31, 2013, the Company would re-price the conversion price of the Term Loan to $0.20 per share. As part of the March 28, 2013 extension the re-pricing of the Term Loan was waived and extended to May 31, 2013.

On March 28, 2013, the Company received an extension until May 31, 2013, as to the due date of the debt under the Credit Facility, including both the $5,000,000 Term Loan and the outstanding amounts of approximately $20,870,000 under the Revolving Credit Facility, as well as the re-pricing of the conversion price of the Term Loan. As provided in the previous amendment the Company paid WFEC an additional loan fee of $260,000. However, if the Term Loan is not repaid by May 31, 2013 and the Company does not consummate the foregoing issuance of Common Stock, then the conversion price will be reduced to $0.20 per share. This agreement matured on May 31, 2013, without additional fees being paid or being re-priced to $0.20. We restructured this agreement as part of an overall capital refinancing of the Company following June 30, 2013. (see Note-L Subsequent Events).

December 2009 subordinated debt issue and refinancing

On December 18, 2009, the Company issued a subordinated promissory note payable to Calvin A. Wallen, III, (the “Wallen Note”) the Company’s Chairman of the Board and Chief Executive Officer, in the principal amount of $2,000,000 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 Wallen Note was entered into with the consent of WFEC. The proceeds of the Wallen Note were used to repay other indebtedness to the Company. On March 28, 2013, the Company received an extension until June 1, 2013, as to the due date of its debt of $2,000,000 plus interest currently being accrued at 4.25% annually, under the Wallen Note. There was no consideration paid to Mr. Wallen in connection with this extension. This note was extended in conjunction with the extension of the Credit Facility (see Note-L Subsequent Events).

In addition an entity controlled by Mr. Wallen advanced the Company $2,000,000 during 2013 to provide short-term working capital. This advance was paid without interest pursuant to the series of transactions discussed in Note-L Subsequent Events.

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NOTES TO FINANCIAL STATEMENTS

Maturity of debt

Our debt to WFEC and the Wallen Note were current, as of June 30, 2013.

The Company recently entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66,000,000 of senior secured notes due October 2, 2016, to certain purchasers. Pursuant to the terms of the Credit Agreement with WFEC, 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 Bank 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. As part of the Recent Transactions, the Company entered into a Call Option Structured Derivative that provided the Company approximately $35,000,000 and together with the proceeds from the issuance of the senior secured notes, a total of $101,000,000. These funds, net of amounts paid for the acquisition of the assets from Gastar, Navasota and Tauren, the repayment of the term loan payable to WFEC and various expenses relating to the Recent Transactions, are available for capital expenditures and working capital for operations.

	as of June 30,
Principal Amount Outstanding	2013		2012
Total long-term debt (including current portion)	$	27,865,110	$	37,000,000
Less current portion	27,865,110		37,000,000

Total long-term debt	$	0	$	0

Maturities of Debt

Fiscal 2013	$	27,865,110
Fiscal 2014 and thereafter	101,000,000

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note F — Related party 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 7 full-time employees and one part-time employee and its offices are leased from Tauren. During fiscal 2011, the Company’s only expense under the office sharing arrangement was the lease rent. The offices were leased on a month-to-month basis for an average monthly amount charged to the Company, from July 1, 2010 until December 31, 2010, of $2,229. Effective, January 1, 2011, the Company signed a 2-year lease that charges the Company a monthly fee of $8,000 per month, with an affiliate controlled by Mr. Wallen and the offices are owned by this affiliate. Effective, January 1, 2013, the Company signed a lease extension through September 30, 2013 that charges the Company $8,000 per month. Charges to the Company under the contracts and subsequent arrangements were $96,000, $96,000 and $61,374 for the fiscal years 2013, 2012 and 2011, respectively.

Tauren owned a working interest in the wells in which the Company owns a working interest. As of the end of fiscal 2013 the Company owed $6,166 to Tauren, as of the end of fiscal 2012 Tauren owed the Company $2,730 and the Company owed $14,537 to Tauren for miscellaneous general and administrative expenses and royalties for fiscal 2011. Tauren owed the Company $38,756, $1,551 and $5,127 for royalties paid by a third-party operator for fiscal years 2013, 2012 and 2011, respectively.

On November 24, 2009, the Company entered into transactions with Tauren and Langtry Mineral & Development, LLC (“Langtry”), both of which are entities controlled by Calvin A. Wallen III, the Chief Executive Officer of the Company, 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. The Company expected to use the Drilling Credits to fund $30,952,810 of its share of the drilling and completion costs for those horizontal Haynesville Shale wells drilled in sections previously operated by an affiliate of the Company, which are now operated by a third party. As a result of the arbitration and settlement with EXCO and BG, the unused Drilling Credits were paid to Cubic, on a dollar for dollar basis.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

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 L — Subsequent Events).

The Special Committee obtained an opinion from its independent financial advisor with respect to the fairness, from a financial point of view, to the public stockholders of the Company, of such transactions.

Note G — Income taxes:

Deferred tax assets and liabilities are computed by applying the effective U.S. federal income tax rate to the gross amounts of temporary differences and other tax attributes. Deferred tax assets and liabilities relating to state income taxes are not material. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. As of June 30, 2013, 2012 and 2011, the Company believed it was more likely than not that future tax benefits from net operating loss carryforwards and other deferred tax assets would not be realizable through generation of future taxable income; therefore, they were fully reserved.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The components of the net deferred federal income tax assets (liabilities) at June 30 were as follows:

	2013			2012			2011
Deferred tax assets:
Net operating loss carryforwards	$	15,154,000		$	10,596,300		$	8,352,700
Depreciation basis of assets	4,600			2,700			1,900
	$	15,158,600		$	10,599,000		$	8,354,600
Deferred tax liabilities:
Depletion basis of assets and related accounts	$	(85,800	)	$	(1,012,600	)	$	(785,200	)
	$	(85,800	)	$	(1,012,600	)	$	(785,200	)
Net deferred tax (liabilities) assets before valuation allowance	$	15,072,800		$	9,586,400		$	7,569,400
Valuation allowance	(15,072,800		)	(9,586,400		)	(7,569,400		)
Net deferred tax (liabilities) assets	$	—		$	—		$	—

The following table summarizes the difference between the actual tax provision and the amounts obtained by applying the statutory tax rates to the income or loss before income taxes for the years ended June 30, 2013, 2012 and 2011:

	2013			2012			2011
Tax (benefit) calculated at statutory rate	$	(1,484,000	)	$	(3,123,000	)	$	(2,572,000	)
Losses not providing tax benefits	1,484,000			3,123,000			2,572,000
Current federal income tax provision (benefit)	$	—		$	—		$	—
Change in valuation allowance	$	(5,486,400	)	$	(2,017,000	)	$	(416,100	)

As of June 30, 2013, the Company had net operating loss carryforwards of approximately $44,570,500, which are available to reduce future taxable income. These carryforwards expire as follows:

	Net operating
Year	losses

2028	$	10,389,100
2029	11,065,900
2031	11,934,200
2032	8,923,800
2033	2,257,500
	$	44,570,500

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note H — Commitments and contingencies:

Key personnel

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

On February 29, 2008, the Company entered into employment agreements with Mr. Wallen and its Secretary, Jon S. Ross. The agreement with Mr. Wallen provides for a base salary of $200,000 per year, while the agreement with Mr. Ross provides for a base salary of $150,000 per year. The other terms and conditions of the agreements are substantially consistent.

On January 14, 2011, the Company entered into an employment agreement with its Chief Financial Officer, Larry G. Badgley. The agreement provides for the grant of stock options, under the Plan, for the purchase of an aggregate of 288,667 shares of Company common stock. These options have an exercise price $1.20 per share and expire five years from their issue date. One option, for the purchase of 15,667 shares, was fully vested upon grant. The other option, for the purchase of 273,000 vested on October 1, 2012. We estimated the fair value of the options on the date of grant using the Black-Scholes valuation model to be $100,997.

Environmental matters

The Company’s operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and gas and the discharge of materials into the environment. The Company generates typical oil and gas field wastes, including hazardous wastes that are subject to the federal Resources Conservation and Recovery Act and comparable state statutes. Furthermore, certain wastes generated by the Company’s oil and gas operations that are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes” and therefore be subject to more rigorous and costly operating and disposal requirements. All of the Company’s properties are operated by third parties over whom the Company has limited control. In addition to the Company’s lack of control over properties operated by others, the failure of previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact the Company.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Office Lease

Effective, January 1, 2013, the Company signed a 9 month lease that charges the Company a monthly fee of $8,000. 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 $8,000 per month. Rental expense was $96,000, $96,000 and $61,374 for fiscal years 2013, 2012 and 2011, respectively.

Legal proceedings

On May 18, 2011, EXCO and BG informed the Company that they did not intend to honor the balance of the Drilling Credits, which was approximately $18 million at that time. This dispute was submitted to binding arbitration during the week of January 9, 2012 and a ruling was issued on March 9, 2012.

In addition to dismissing all claims of EXCO and BG with prejudice, the Arbitrators’ Award provides the following:

· EXCO/BG shall place the Company in “consent” status on wells drilled by EXCO/BG through March 9, 2012, and pay the Company the proceeds to which it is entitled;

· EXCO/BG shall apply the Drilling Credits to wells drilled by EXCO/BG through March 9, 2012;

· The remaining Drilling Credits are accelerated and immediately due and payable to the Company; and

· The Company is awarded attorneys’ fees, costs and interest.

On June 13, 2012, the 298th Judicial District Court in Dallas County, Texas (the “Court”) entered an Order confirming this Arbitration Award, and asked the arbitrators to determine the amount of attorney fees owed to the Company. On July 27, 2012, the arbitrators issued their Award of Attorney Fees and Costs. On September 12, 2012, the Court entered a final judgment in favor of the Company and against EXCO and BG in the amount of approximately $12,800,000.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note I - Cost of oil and gas properties:

Costs incurred

Costs (capitalized and expensed) incurred in oil and gas property acquisition, exploration, and development activities for the years ended June 30, 2013, 2012 and 2011 were as follows:

	2013			2012		2011
Property acquisitions	$	178,685		$	109,076	$	448,432
Exploration	—			—		—
Development	(290,569		)	8,224,013		10,175,986
	$	(111,884	)	$	8,333,089	$	10,624,418

The Company received several credits from EXCO after June 30, 2012 thus creating a negative costs incurred total for the year ended June 30, 2013.

Capitalized costs

The aggregate amounts of capitalized costs relating to oil and gas producing activities and the aggregate amounts of the related accumulated depreciation, depletion, and amortization at June 30, 2013, 2012 and 2011 were as follows:

	2013			2012			2011
Proved properties	$	56,009,780		$	56,121,665		$	47,788,575
Unproved properties	—			—			—
	56,009,780			56,121,665			47,788,575
Less: accumulated depreciation, depletion and amortization of oil and gas properties	19,105,645			15,860,758			9,774,375
Total properties	36,904,135			40,260,907			38,014,200
Less: accumulated impairment of oil and gas properties due to full cost ceiling test	(22,181,701		)	(22,181,701		)	(22,181,701		)
Net properties	$	14,722,434		$	18,079,206		$	15,832,499

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Results of operations

The results of operations from oil and gas producing activities for the years ended June 30, 2013, 2012 and 2011 were as follows:

	2013			2012			2011
Revenues:
Revenues	$	3,843,420		$	6,939,999		$	6,133,299
Preferred return	—			—			—
	3,843,420			6,939,999			6,133,299
Expenses (excluding G&A and interest expense):
Production, operating and development costs	1,872,186			1,972,223			1,857,528
Depreciation, depletion and amortization	3,248,260			6,090,529			3,707,255
Impairment loss on oil and gas properties	—			—			—
	5,120,446			8,062,752			5,564,783
Results before income taxes	(1,277,026		)	(1,122,753		)	568,516
Provision for income taxes	—			—			—
Results of operations (excluding corporate overhead and interest expense)	$	(1,277,026	)	$	(1,122,753	)	$	568,516

Note J - Oil and gas reserves information (unaudited):

The estimates of proved oil and gas reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations over prices and costs existing at year-end except by contractual arrangements.

The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company’s policy is to amortize capitalized oil and gas costs on the unit of production method, based upon these reserve estimates. The amortization was $2.80 per Mcf during the twelve month period ended June 30, 2013, as compared to $2.70 per Mcf and $2.48 per Mcf during the same periods in 2012 and 2011, respectively. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and gas reserves, the remaining estimated lives of the oil and gas properties, or any combination of the above may be increased or reduced in the near term.

If reduced, the carrying amount of capitalized oil and gas properties may be reduced materially in the near term.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The following unaudited table sets forth proved oil and gas reserves, all within the United States, at June 30, 2013, 2012 and 2011 together with the changes therein:

Proved reserves

	Natural Gas (Mcf)
	2013		2012		2011
Proved developed and undeveloped reserves:
Beginning of year	23,339,985		57,692,086		29,157,280
Revisions of previous estimates	353,722		(51,465,506	)	(2,429,214	)
Extensions and discoveries	10,439,327		19,357,720		32,445,450
Less: Production	(1,141,474	)	(2,244,315	)	(1,481,430	)
Disposals of reserves in place	—		—		—
End of year	32,991,560		23,339,985		57,692,086

	Oil, condensate (Bbls)
	2013		2012		2011
Proved developed and undeveloped reserves:
Beginning of year	427,633		1,199		8,647
Revisions of previous estimates	(177,553	)	344		(4,742	)
Extensions and discoveries	146,291		427,190		—
Less: Production	(863	)	(1,100	)	(2,706	)
Disposals of reserves in place	—		—		—
End of year	395,508		427,633		1,199

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

	Natural Gas Liquids (Bbls)
	2013		2012		2011
Proved developed and undeveloped reserves:
Beginning of year	1,313,566		—		—
Revisions of previous estimates	(279,169	)	1,312		—
Purchases of reserves in place	—		—		—
Extensions and discoveries	603,602		1,313,531		—
Less: Production	(2,525	)	(1,277	)	—
Disposals of reserves in place	—		—		—
End of year	1,635,474		1,313,566		—

	Natural Gas (Mcfs)
	2013	2012	2011

Proved developed reserves:
Beginning of year	3,982,265	6,634,236	2,666,610
End of year	4,899,388	3,982,265	6,634,236

Proved undeveloped reserves:
Beginning of year	19,357,720	51,057,850	26,490,670
End of year	28,092,173	19,357,720	51,057,850

	Oil (Bbls)
	2013	2012	2011

Proved developed reserves:
Beginning of year	443	1,199	1,166
End of year	1,835	44	1,199

Proved undeveloped reserves:
Beginning of year	427,190	—	7,481
End of year	393,673	427,190	—

	Natural Gas Liquids (Bbls)
	2013	2012	2011

Proved developed reserves:
Beginning of year	35	—	—
End of year	11,205	35	—

Proved undeveloped reserves:
Beginning of year	1,313,531	—	—
End of year	1,624,269	1,313,531	—

The Company’s Louisiana acreage lies atop the center of what is known in our industry as the “Haynesville Shale Play” (which we refer to as the “Bossier/Haynesville shale” elsewhere herein), one of the most prolific dry gas recent field discoveries in the United States; and also includes the Cotton Valley sand formation, a formation with gas, NGL and oil. The discovery of the existence of the Bossier/Haynesville shale formations in the Company’s acreage in fiscal 2008, in an environment of strong pricing for dry natural gas, led to a shift in strategy away from concentrating solely on the development of the Cotton Valley and other shallow formations in our Bethany Longstreet and Johnson Branch fields, and to commencement of the development of the Bossier/Haynesville shale acreage. Development slowed in fiscal 2009, due to deteriorated economic conditions, a harsh debt and equity environment, stubbornly high field operation costs, and a collapse in the pricing of natural gas.

The strategic transactions consummated by the Company in the first half of fiscal 2010 repositioned the Company for increased development of the Bossier/Haynesville shale on its acreage. And, development activity did gain some momentum by the second half of fiscal 2010, with increased activity and development undertaken by EXCO as well as other third party operators of the Bossier/Haynesville shale through fiscal 2011, despite a depressed commodity market for natural gas. The continued deterioration of pricing for dry natural gas, which has persisted through fiscal 2013, brought a halt to additional development of the Bossier/Haynesville shale on Company acreage. As in fiscal 2012, in fiscal 2013, dry natural gas pricing was so low that the Company could not recognize any Proven Undeveloped locations in the Bossier/Haynesville shale; however, the Bossier/Haynesville shale remains a prolific dry gas field and a significant asset to the Company upon a correction in commodity pricing.

While natural gas commodity pricing reached lows not seen in recent history, oil and NGL pricing was relatively strong for fiscal 2013. Due to the increase in NGL prices, we are now for the second year listing

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

them separately from oil and natural gas in the notes to our financial statements. A variety of horizontal development in the Cotton Valley sand in and around our Northwest Louisiana acreage commenced in fiscal 2013. Based upon production for the horizontal development, and the oil being produced along with dry natural gas and NGL, the Company has approximately 36 Proven Undeveloped locations in the Cotton Valley sand for its June 30, 2013, SEC Reserve Report.

The “Revisions of previous estimates” amount of 353,722 Mcf in fiscal 2013 was primarily due to the increased estimated ultimate recovery of the Bossier/Haynesville shale Proved Producing horizontal wells, from approximately 4 Bcf to 6 Bcf of natural gas, based on performance rates.

The “Extensions and discoveries” amount of 10,439,327 Mcf in fiscal 2013 was primarily due to new proved undeveloped offset locations in which the Company maintains a working interest based upon the ability to utilize 160 acre spacing per unit for horizontally-drilled and completed Cotton Valley wells. The reserve estimates attributable to these new proved undeveloped locations were listed under “Extensions and discoveries.”

Standardized measure of discounted future net cash flows relating to proved reserves:

The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:

· An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

· In accordance with SEC guidelines, the engineers’ estimates of future net revenues from our proved properties and the present value thereof for fiscal 2013 are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Prior year estimates were not required to be restated and reflect previously disclosed estimates using year-end prices. These prices are held constant throughout the life of the properties. Oil and natural gas prices are adjusted for each lease for quality, contractual agreements, lease use shrinkage and regional price variations.

· The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs in effect at June 30 of the year presented and held constant throughout the life of the properties.

· Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

At June 30, 2013, future plugging and abandonment costs, on a present value basis, are estimated to be approximately $169,300, which was less than 0.5% of the PV-10 value shown on our June 30, 2013 Reserve Report of $39,025,000. Therefore, it was determined that the plugging and abandonment costs were not a material disclosure in the filing.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The resulting future net cash flows were discounted using a rate of 10% per annum (Table 1). The standardized measure of discounted net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of the Company’s oil and gas proved by drilling or production history. There are significant uncertainties inherent in estimating timing and amount of future costs. In addition, the method of valuation utilized is based on current prices and costs and the use of a 10% discount rate, and is not necessarily appropriate for determining fair value (Table 2).

The following is the estimated standardized measure relating to proved oil and gas reserves at June 30, 2013, 2012 and 2011:

Table 1	2013			2012			2011
Future cash flows	$	242,990,435		$	179,704,719		$	261,446,375
Future production costs	(29,432,000		)	(32,485,700		)	(43,345,400		)
Future development costs	(111,455,400		)	(72,969,420		)	(126,835,250		)
Future severance tax expense	(13,268,035		)	(4,526,463		)	(4,330,356		)
Future income taxes	—			—			—
Future net cash flows	$	88,835,000		$	69,723,136		$	86,935,369
Ten percent annual discount for estimated timing of net cash flows	(49,787,200		)	(39,746,927		)	(40,024,625		)
Standardized measure of discounted future net cash flows	$	39,047,800		$	29,976,209		$	46,910,744

The following is an analysis of changes in the estimated standardized measure of proved reserves during the years ended June 30, 2013, 2012 and 2011:

Table 2	2013			2012			2011
Changes from:
Sale of oil and gas produced	$	(1,971,234	)	$	(4,967,776	)	$	(4,275,771	)
Net changes in prices and production costs	(695,805		)	(56,534,586		)	(12,465,909		)
Extensions and discoveries	12,195,100			24,472,000			19,367,520
Revision of previous quantity estimates	11,285,959			(17,572,834		)	(6,450,989		)
Accretion of discounts	2,997,621			4,691,074			6,475,729
Net change in income taxes	526,854			1,975,312			(2,178,009		)
Disposals of reserves in place	—			—			—
Development costs incurred that reduced future development costs	—			—			(321,688		)
Changes in future development costs	48,872,306			(42,558,894		)	(604,579		)
Changes in timing of production and other	(64,139,210		)	73,561,169			(17,392,850		)
Change in standardized measure	$	9,071,591		$	(16,934,535	)	$	(17,846,546	)

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note K — Selected quarterly financial data (unaudited):

Summarized unaudited quarterly financial data for fiscal 2013 and 2012 are as follows:

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter			Total
Fiscal 2013
Revenues	$	1,003,660		$	1,039,376		$	968,980		$	831,404		$	3,843,420
Loss before income taxes	$	(1,762,885	)	$	(439,586	)	$	(2,188,397	)	$	(1,543,350	)	$	(5,934,218	)
Net loss	$	(1,762,885	)	$	(439,586	)	$	(2,188,397	)	$	(1,543,350	)	$	(5,934,218	)
Net loss available to common shareholders	$	(1,987,285	)	$	(668,486	)	$	(2,416,897	)	$	(1,778,850	)	$	(6,851,518	)
Net loss per common share - basic and diluted (1)	$	(0.03	)	$	(0.01	)	$	(0.03	)	$	(0.02	)	$	(0.09	)
Weighted average common shares outstanding	77,215,908			77,215,908			77,265,047			77,360,908			77,263,381

Fiscal 2012
Revenues	$	1,416,036		$	3,303,365		$	1,273,919		$	946,679		$	6,939,999
Loss before income taxes	$	(2,598,783	)	$	(2,661,177	)	$	(3,580,358	)	$	(3,650,314	)	$	(12,490,632	)
Net loss	$	(2,598,783	)	$	(2,661,177	)	$	(3,580,358	)	$	(3,650,314	)	$	(12,490,632	)
Net loss available to common shareholders	$	(2,818,825	)	$	(2,881,219	)	$	(3,797,413	)	$	(3,867,413	)	$	(13,364,870	)
Net loss per common share - basic and diluted (1)	$	(0.03	)	$	(0.04	)	$	(0.05	)	$	(0.05	)	$	(0.17	)
Weighted average common shares outstanding	76,815,908			76,815,908			77,193,930			77,215,908			77,009,351

(1) The sum of the per share amounts per quarter does not equal the total year amount due to changes in the weighted average number of common shares outstanding in each quarter.

Note L — Subsequent Events:

On July 5, 2013, the Company paid cash of $13,000 and issued 72,500 shares of common stock to four 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) on July 5, 2013, on the NYSE-MKT of the Company’s common stock. Such amount was expensed upon issuance to compensation expense.

Exchange Delisting

As previously disclosed, the Company was notified by NYSE MKT, LLC (the “Exchange”) staff (the “Staff”) that it was not in compliance with certain of the Exchange’s continued listing standards as set forth in the Exchange’s Company Guide. Specifically, the Company was advised that it was not in compliance with Sections 1003(a)(i)-(iv) of the Company Guide.

The Company submitted a plan of compliance advising the Exchange of actions it had taken, or intended to take, to regain compliance with the continued listing standards (the “Plan”). Based on the Plan, the Exchange deferred further action pending a review of the Company’s operations through May, 31, 2013. The Staff completed this review on June 26, 2013. On July 10, 2013, the Company received written notification from the Staff (the “Staff Determination”) stating that the Company’s Common Stock is subject to delisting from the Exchange.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The Company did not request an appeal of the Staff Determination, and trading in the Company’s Common Stock on the Exchange was discontinued effective at the opening of trading on July 17, 2013. The Company intends to remain current in its reporting obligations with the Securities and Exchange Commission, and the Common Stock began being quoted on the OTCQB Marketplace on Wednesday, July 17, 2013 under the symbol “CBNR”. The OTCQB is the mid-tier market operated by the US OTC Markets.

RECENTLY COMPLETED FINANCING AND ACQUISITIONS

On October 2, 2013, the Company consummated the following transactions:

Formation of New Subsidiaries

The Company approved the formation and capitalization of two new, wholly owned direct subsidiaries Cubic Asset Holding, LLC, and Cubic Louisiana Holding, LLC, and two new, wholly owned indirect subsidiaries Cubic Asset, LLC, a direct subsidiary of Cubic Asset Holding, LLC and Cubic Louisiana, LLC, a direct subsidiary of Cubic Louisiana Holding, LLC.

Senior Secured Notes Financing

The Company entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66.0 million of Notes due October 2, 2016 to certain purchasers. The Notes bear 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 shall be paid 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 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.

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, 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, to 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 32,917,275 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”).

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Investment Agreement and Voting Agreement

The Investors and Calvin A. Wallen, III, the Company’s Chairman, President and Chief Executive Officer, also entered into a Voting Agreement, dated as of October 2, 2013, 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.

Registration Rights Agreement

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. 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.

Wells Fargo Debt Restructuring

Cubic Louisiana and WFEC entered into a Credit Agreement dated October 2, 2013. In conjunction with entering into the Credit Agreement, the Company assigned all of its previously held oil and gas interests that it held as the Legacy Louisiana Assets. 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 higher of (i) the Wells Fargo Bank prime rate, plus 2%, per annum and (ii) the Federal Funds Rate, plus 1%, 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. The other oil and gas properties of Cubic and its other subsidiaries, including the assets acquired from Gastar, Navasota and Tauren, as described below, do not secure the indebtedness under the Credit Agreement.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

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

The Company entered into and consummated the transactions contemplated by a Conversion and Preferred Stock Purchase Agreement dated as of October 2, 2013 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.

Acquisition of Properties from Gastar

The Company consummated the transactions contemplated by the previously announced the Gastar Agreement dated as of April 19, 2013 with 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 $39,118,830, 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 Cubic, such amounts were netted effective January 1, 2013 and will be recorded as an adjustment to the purchase price.

Acquisition of Properties from Navasota

On September 27, 2013, the Company entered into the Navasota Agreement with Navasota. On October 2, 2013, 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 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 by the Company was $19,400,000, prior to certain post-closing adjustments.

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CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Acquisition of Properties from Tauren

The Company entered into and consummated the Purchase and Sale Agreement dated as of October 2, 2013 with Tauren. 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 properties include approximately 5,600 net acres of leasehold interests. 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 $708,000. The Tauren Agreement was unanimously approved by the Company’s board of directors, excluding Mr. Wallen. In addition, the Company obtained an opinion from Blackbriar Advisors, LLC, which concluded that the terms of the Tauren Agreement were fair, from a financial perspective, to the Company.

Note M — Liquidity:

During the year ended June 30, 2013, the Company incurred a net loss of $5,934,218 and provided $54,204 of cash from operations. At June 30, 2013 the Company’s liabilities substantially exceed its assets. The Company had a working capital deficit of $30,191,399 at June 30, 2013, down from a working capital deficit of $35,768,341 at June 30, 2012. This decrease in deficit was primarily due to the $9,134,980 paydown on the Credit Agreement with WFEC with funds received from the proceeds of the EXCO/BG settlement.

The Company recently entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66,000,000 of senior secured notes due October 2, 2016, to certain purchasers. Pursuant to the terms of the Credit Agreement with WFEC, 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 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. As part of the Recent Transactions, the Company entered into a Call Option Structured Derivative that provided the Company approximately $35,000,000 and together with the proceeds from the issuance of the senior secured notes, a total of $101,000,000. These funds, net of amounts paid for the acquisition of the assets from Gastar, Navasota and Tauren, the repayment of the term loan payable to WFEC and various expenses relating to the Recent Transactions, approximately $21,000,000 are available for capital expenditures and working capital for operations. Management believes cash on hand following the transactions discussed in Note-L-Subsequent Events along with cash flows from operations will be sufficient to fund operations for the next 12 months.

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EXHIBIT INDEX

No.		Description

2.1		Purchase and Sale Agreement, dated as of April 19, 2013, by and among Cubic Energy, Inc., Gastar Exploration Texas, LP and Gastar Exploration USA, Inc. (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

2.2		Purchase and Sale Agreement, dated as of September 27, 2013, by and among Cubic Energy, Inc. and Navasota Resources Ltd., LLP (filed as Exhibit 2.2 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

2.3		Purchase and Sale Agreement, dated as of October 2, 2013, by and among Cubic Energy, Inc. and Tauren Exploration, Inc. (filed as Exhibit 2.3 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

3.1		Amended and Restated Certificate of Formation (filed as Exhibit 3.1 to the Registrant’s Form 8-K filed with the SEC on March 10, 2010).

3.2		Certificate of Amendment to the Amended and Restated Certificate of Formation (filed as Exhibit 3.2 to Company’s Form 10-K filed with the SEC on September 28, 2012)

3.3		Certificate of Designation (filed as Exhibit 3.2 to Registrant’s Form 8-K filed with the SEC on March 10, 2010).

3.4		Bylaws (filed as Exhibit 3.2 of the Company’s Form 10-KSB for the period ended June 30, 2000).

3.5		Certificate of Designations Establishing a Series of Preferred Stock (Series B Convertible Preferred Stock) of Cubic Energy, Inc. filed with the Secretary of State of Texas on October 2, 2013 (filed as Exhibit 3.1 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

3.6		Certificate of Designations Establishing a Series of Preferred Stock (Series C Redeemable Voting Preferred Stock) of Cubic Energy, Inc. filed with the Secretary of State of Texas on October 2, 2013 (filed as Exhibit 3.2 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.1		Credit Agreement dated March 5, 2007 by and between Cubic Energy, Inc. and Wells Fargo Capital, Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed March 9, 2007).

10.2		Warrant to Purchase Shares of Common Stock of Cubic Energy, Inc. dated March 5, 2007, issued to Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.4 to the Company’s Form 8-K on March 9, 2007).

10.3		First Amendment to Credit Agreement with Wells Fargo Energy Capital dated May 8, 2008 (filed as Exhibit 10.2 to the Company’s Form 10-QSB for the quarter ended March 31, 2008).

10.4		Second Amendment to Credit Agreement, dated December 18, 2009, by and between Cubic Energy, Inc. and Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 23, 2009).

10.5		Third Amendment to Credit Agreement dated August 30, 2010, by and between Cubic Energy, Inc. and Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed

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		September 1, 2010).

10.6		Fourth Amendment to Credit Agreement, dated June18, 2012, by and between Cubic Energy, Inc. and Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 20, 2012).

10.7		Form of Subscription and Registration Rights Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed September 1, 2009).

10.8		Form of Warrant (filed as Exhibit 10.2 to the Company’s Form 8-K filed September 1, 2009).

10.9		Amended and Restated Warrant to Purchase Shares of Common Stock of Cubic Energy, Inc., dated December 18, 2009, issued to Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.4 to the Company’s Form 8-K filed December 23, 2009).

10.10		Warrant to Purchase Shares of Common Stock of Cubic Energy, Inc., dated December 18, 2009, issued to Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.5 to the Company’s Form 8-K filed December 23, 2009).

10.11		Warrant to Purchase Shares of Common Stock of Cubic Energy, Inc., dated August 30, 2010, issued to Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.2 to the Company’s Form 8-K filed September 1, 2010).

10.12		Second Amended and Restated Registration Rights Agreement, dated as of August 30, 2010, by and between Cubic Energy, Inc. and Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.3 to the Company’s Form 8-K filed September 1, 2010).

10.13		Employment Agreement with Calvin A. Wallen, III, dated February 29, 2008 (filed as Exhibit 10.1 to the Company’s Form 8-K on March 5, 2008) +.

10.14		Employment Agreement with Jon S. Ross dated February 29, 2008 (filed as Exhibit 10.1 to the Company’s Form 8-K on March 5, 2008) +.

10.15		Subordinated Promissory Note, dated as of September 12, 2012, by Cubic Energy, Inc., payable to Calvin A. Wallen, III (filed as Exhibit 10.1 to the Company’s Form 8-K filed September 12, 2012).

10.16		Convertible Promissory Note payable to Wells Fargo Energy Capital, Inc. in the principal amount of $5,000,000 date June 18, 2012 (filed as Exhibit 10.2 to the Company’s Form 8-K filed June 20, 2012).

10.17		Promissory Note payable to Wells Fargo Energy Capital, Inc. in the maximum principal amount of $40,000,000 dated June 18, 2012 (filed in Exhibit 10.3 to the Company’s Form 8-K filed June 20, 2012).

10.18		Settlement Agreement and Mutual Release effective as of October 2, 2012 by and between Cubic Energy, Inc., Tauren Exploration, Inc., EXCO Operating Company, LP and BG US Production Company, LLC (filed as Exhibit 10.1 to the Company’s Form 8-K filed October 9, 2012).

10.19		Cubic Energy, Inc. 2005 Stock Option Plan (filed as Exhibit D to the Company’s Definitive Schedule 14A filed with the SEC on December 12, 2005) +.

10.20		Amendment to Cubic Energy, Inc. 2005 Stock Option Plan effective as of May 7, 2010(filed as Exhibit 10.37 to the Company’s Form 10-K filed September 28, 2010) +.

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10.21		Note Purchase Agreement (15.5% Senior Secured First Lien Notes due 2016), dated as of October 2, 2013, among the Company, each guarantor listed on Schedule I thereto, and each other guarantor from time to time party thereto, certain note purchasers, and Wilmington Trust National Association, as noteholder agent, the Company Collateral Agent, the New Asset Collateral Agent and the Old Asset Collateral Agent (each such terms, as defined therein) (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.22		Form of Series A Note (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.23		Form of Series B Note (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.24		Amended and Restated Credit Agreement by and between Cubic Louisiana, LLC and Wells Fargo Energy Capital, Inc., dated as of October 2, 2013(filed as Exhibit 10.4 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.25		Registration Rights Agreement, dated as of October 2, 2013, by and among Cubic Energy, Inc. and the Investors. (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.26		Investment Agreement, dated as of October 2, 2013, by and among Cubic Energy, Inc. and the Investors. (filed as Exhibit 10.6 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.27		Warrant and Preferred Stock Agreement, dated as of October 2, 2013, by and among Cubic Energy, Inc. and the Investors. (filed as Exhibit 10.7 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.28		Form of Class A Warrant (filed as Exhibit 10.8 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.29		Form of Class B Warrant (filed as Exhibit 10.9 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.30		Conversion and Preferred Stock Purchase Agreement, dated as of October 2, 2013, by and among Cubic Energy, Inc., Langtry Mineral & Development, LLC and Calvin A. Wallen, III (filed as Exhibit 10.10 to the Registrant’s Form 8-K filed with the SEC on October 3, 2013).

10.31		Operational Agency Agreement (filed as Exhibit 10.11 to the Company’s Form 8-K/A filed March 17, 2014).

10.32		ISDA 2002 Master Agreement Cubic Louisiana ISDA Master Agreement File LLC, 81915185(filed as Exhibit 10.12 to the Company’s Form 8-K/A filed March 17, 2014).

10.33		Agreement — Cubic Asset LLC BP Operating Agency Agreement File (filed as Exhibit 10.13 to the Company’s Form 8-K/A filed March 17, 2014).

10.34		ISDA 2002 Master Agreement Cubic Louisiana LLC Cubic Louisiana ISDA Master Agreement File, 81915189_1(filed as Exhibit 10.14 to the Company’s Form 8-K/A filed March 17, 2014).

10.35		ISDA 2002 Master Agreement — Cubic Asset LLC, Cubic Asset LLC ISDA Without Gas Annex File(filed as Exhibit 10.15 to the Company’s Form 8-K/A filed March 17, 2014).

23.1		Consent of Philip Vogel & Co., PC*

23.2		Consent of NSAI*

23.3		Consent of Blackbriar Advisors, LLC.*

31.1		Rule 13a-14(a)/15d-14(a) Certification of Calvin A. Wallen, III*

31.2		Rule 13a-14(a)/15d-14(a) Certification of Larry G. Badgley*

32.1		Section 1350 Certification of Calvin A. Wallen, III*

32.2		Section 1350 Certification of Larry G. Badgley*

99.1		NSAI Reserve Report summary letter (filed as Exhibit 99.1 to the Registrant’s Form 10-K filed with the SEC on October 15, 2013).

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101.INS		XBRL Instance Document.**

101.SCH		XBRL Taxonomy Extension Schema Document.**

101.CAL		XBRL Taxonomy Calculation Linkbase Document.**

101.DEF		XBRL Taxonomy Definition Linkbase Document. **

101.LAB		XBRL Taxonomy Label Linkbase Document.**

101.PRE		XBRL Taxonomy Presentation Linkbase Document.**

* Filed herewith

** Furnished with this report. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

+ These exhibits are management contracts