Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT

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

FOR THE FISCAL YEAR ENDED JUNE 30, 2011

COMMISSION FILE NUMBER 001-34144

CUBIC ENERGY, INC.

(Exact Name of Registrant as Specified in its Charter)

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:

Securities registered under Section 12(g) of the Act: None

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 o 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. o

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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, or the average bid and asked prices of such common stock, as of the last business day of the registrant’s most recently completed second fiscal quarter: As of December 31, 2010 the aggregate market value held by non-affiliates was $31,958,504.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: As of September 9, 2011, there were 76,815,908 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

Table of Contents

Special note regarding forward-looking statements

This annual report on Form 10-K contains forward-looking statements, as defined in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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;

·                  the outcome of our dispute with the counterparties of certain drilling credits owed to us;

·                  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.

ii

Table of Contents

CUBIC ENERGY, INC.

TABLE OF CONTENTS

iii

Table of Contents

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, 2011, our total proved reserves were 57,699,279 Mcfe.

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 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.

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 an interest in the right-of-ways, 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 our shared acreage. As a result of this activity, we saw improved production volumes in each of the last three fiscal years.

Our financial results depend largely upon our third-party Hosston, Cotton Valley and Bossier/Haynesville Shale operators along with many factors, which are largely driven by the volume of our natural gas production and the price that we receive for that production. Our natural gas production volumes will decline as reserves are depleted unless we obtain and expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

Management believes in the value of our assets, which are being drilled by third-party operators, and will continue to explore strategic alternatives that allow us to leverage those assets to gain full stockholder value.

1

Table of Contents

Texas Acreage

Our Texas properties are situated in Eastland and Callahan Counties. The 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, 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. At this time, we are not the operator for any of our properties. We believe that attractive opportunities remain for development of our remaining assets and acquisition of future assets.

On February 6, 2006, the Company entered into a Purchase Agreement with Tauren Exploration, Inc. (“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 Wells Fargo Energy Capital (“Wells Fargo”) 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 Wells Fargo 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. The revolving note is subject to a borrowing base (the “Borrowing Base”), initially set at $4,000,000. On July 27, 2007, Wells Fargo increased the Borrowing Base to $6,600,000 in order to fund the drilling and casing costs of two new wells in the Company’s Johnson Branch acreage in Caddo Parish, Louisiana. On September 7, 2007, Wells Fargo increased the Borrowing Base to $8,600,000 in order to fund the remaining drilling and casing costs of five wells drilled since the beginning of fiscal 2008, the drilling and casing costs of two new wells, and the costs of installing a gathering/sales line and associated equipment in the Company’s Johnson Branch acreage. On November 19, 2007, Wells Fargo increased the Borrowing Base to $14,500,000 in order to fund the completion costs and

2

Table of Contents

casing of eight wells already successfully drilled and the drilling of four additional wells located in the Company’s Johnson Branch acreage. On May 8, 2008, Wells Fargo increased the Borrowing Base to $20,000,000 in order to fund the completion costs and casing of the four wells located in the Company’s Johnson Branch acreage (including two vertical wells drilled into the Bossier/Haynesville shales) and the drilling of two additional wells located in the Company’s Bethany Longstreet acreage in Caddo and DeSoto Parishes. On December 18, 2009, the Company entered into a Second Amendment to Credit Agreement with Wells Fargo, providing for a revolving credit facility of up to $40 million subject to Borrowing Base limits 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, matures 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 Wells Fargo additional warrants, expiring on December 1, 2014, for the purchase of up to 5,000,000 shares of Company common stock at an exercise price of $1.00 per share, and extended the expiration date of the warrants to purchase 2,500,000 shares of Company common stock that were previously issued to Wells Fargo to December 1, 2014.

In August 2010, we increased the revolver by $5,000,000 from $25,000,000 and our Borrowing Base and borrowings under the revolving credit facility to $30 million. As of June 30, 2011, the revolver had $30 million outstanding with a maturity date of July 1, 2012.

The terms of the Amended Credit Agreement, among other things, prohibit the Company from merging with another company or paying dividends, and limit additional indebtedness, sales of certain assets and investments. Upon the repayment in full of the indebtedness under the Amended Credit Agreement, and with respect to certain properties, upon the occurrence of the conditions set forth in Section 2.14 of the Amended Credit Agreement, the Company agreed to convey a net profits interest to Wells Fargo in an amount equal to 5% of Cubic’s net interest in certain of its Louisiana properties.

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

As of June 30, 2011, the Company used the Drilling Credits to fund $13,189,494 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, 2011 a total of $17,763,316 of the Drilling Credits remain. The counterparties (EXCO and BG) on the Drilling Credits have asserted certain offsets against their obligations under the Drilling Credits. We are aggressively defending our rights under the Drilling Credits. For additional information, see below under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources”.

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 bears interest at the prime rate plus one percent (1%), with interest payable monthly. The outstanding principal balance is due and payable on September 30, 2012 and is subordinated to the indebtedness under the Amended Credit Agreement. The proceeds of the Wallen Note were used to repay a previously outstanding promissory note.

3

Table of Contents

STRATEGY

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 focus is primarily 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 our undeveloped leasehold opportunities in Louisiana. Currently we have exploration opportunities and seek to acquire additional leasehold interests in Caddo and DeSoto Parishes in Louisiana.  These areas are a part of geologic studies utilizing regional trend surface analysis, 2-D and 3-D seismic data and/or vast sub-surface control. Prospects have been developed from approximately 4,000 to 12,000 feet in depth in the following reservoirs: Bossier/Haynesville shales; Cotton Valley; Hosston; Gloyd; Pettet; Glen Rose and Paluxy.

PRINCIPAL OIL AND GAS PROPERTIES

The following table summarizes certain information with respect to our principal areas of operation at June 30, 2011:

Our Texas properties are situated in Eastland and Callahan Counties and represent 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, 2011, the Louisiana properties contained substantially all of our proved reserves, a situation that is expected to continue, unless we are able to execute on our strategy to acquire additional oil and gas properties. The Texas properties consist 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 Louisiana properties 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, 2011 for all of the Company’s wells averaged approximately 4,058 Mcf of natural gas per day, 4 barrels of oil per day and 145 gallons of natural gas liquids per day as compared to approximately 2,171 Mcf of natural gas per day, 4 barrels of oil per day and 105 gallons of natural gas liquids per day in the fiscal year ended June 30, 2010.

RECENT DEVELOPMENTS

Indigo Minerals has re-worked a well in Section 15-T15N-R15W and re-entered certain wells in the Cotton Valley formation in which the Company has interests. Indigo Minerals now operates the Cotton Valley wells previously operated by Chesapeake in which the Company has an interest during physical 2011.

Chesapeake has drilled and completed twelve horizontal Haynesville Shale wells on our acreage, most recently the Burford 21-H2 in Section 21-T14N-R15, the Western 18-H1 in Section 18-T15N-R16W and the Slaughter 6-H1 in Section 6-T15N-R15W. These wells were completed during fiscal 2011.

4

Table of Contents

Petrohawk drilled and completed 1 horizontal Haynesville Shale well during fiscal 2011, the DHD 35 H-1, located in Section 35-T16N-R15W of our acreage in the Johnson Branch field.

El Paso drilled and completed 1 horizontal Haynesville Shale well, the Fisher 20 H-1, in Section 20-T14N-R15W of our acreage in the Bethany Longstreet field during fiscal 2011.

EXCO has completed 2 wells, the Crow 8 H-1 in Section 8-T14N-R15W and the Crow 5 H-1 in Section 5-T14N-R15W, during fiscal 2011; each are located in the Bethany Longstreet field.

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

Our production consists mainly of natural gas. During fiscal 2011, 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 condensate (“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 (“Martin”). During fiscal 2011, 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 operating by them.  Of these third-party producers, our total revenues during fiscal 2011 were generated as follows: EXCO — 66%, Chesapeake - 14% and Goodrich - 13%, with others producing 7%.  Purchases by Atmos Energy through Fossil totaled 4% of our total revenues. We do not have any gas marketing agreements, commitments or contracts; we sell our crude oil, NGL and natural gas at the prevailing market prices. We have not engaged in crude oil hedging or trading activities. 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 $6,133,299 for fiscal 2011 primarily from the sale of natural gas. Natural gas totaled $5,928,198 and represented 97%, oil totaled $120,030 and represented 2% and NGL totaled $85,071 and represented 1% of our total oil and gas revenues, respectively for fiscal 2011.

Price Considerations

Natural gas and natural gas liquids 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 2011 was $4.00 as compared to $4.21 in fiscal 2010. The average natural gas liquids price per gallon received by us in fiscal 2011 was $1.60 compared to $1.27 in fiscal 2010. Crude oil prices are established in

5

Table of Contents

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 2011 was $83.13 as compared to $73.18 in fiscal 2010.

6

Table of Contents

OIL AND GAS RESERVES

The following tables set forth our proved developed and proved undeveloped reserves at June 30, 2011, 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, 2011, 2010 and 2009:

(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. 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.

7

Table of Contents

During fiscal 2011, we incurred total expenditures of $7.4 million relating to development and exploration activities that resulted in 5,945,586 Mcf of proved undeveloped reserves being converted to proved developed. We have not held any of our proved undeveloped reserves for longer than five years. All reserve information is located in the Haynesville Shale and Cotton Valley plays in Louisiana.

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 Cambrian Consultants America, Inc., d/b/a RPS (“RPS”), an independent petroleum engineering firm, for fiscal years 2011, 2010 and 2009. The reservoir engineer at RPS who oversaw the preparation of the reserve estimates has a Master’s of Science Degree in Geology, is certified by the State of Texas Professional Geologists as a Licensed Geologist and has thirty-two years of experience in the upstream oil and gas industry. The estimates of this independent petroleum engineering firm 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, 2011, was prepared in-house, was not reviewed by an independent engineering firm, and due to the immaterial size was not reported in Cubic’s reserve report for the period ended June 30, 2011. Cubic’s internal geologist reviews all data that is provided to RPS for the reserve reports. He has a Master’s of Science Degree in Geology, is an American Association of Petroleum Geologists’ Certified Petroleum Geologist and has twenty-eight years of experience in the upstream oil and gas industry.  He also reviews and approves the reports from RPS. In accordance with guidelines of the SEC, our estimates of proved reserves and the future net revenues from which present values are derived are made using an average price mechanism based on the first day of each of the last twelve months and a differential based on amount per Mcf received, by the Company. Operating costs, development costs and certain production-related taxes were deducted in arriving at estimated future net cash flows, 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.

The estimates of proved reserves at June 30, 2011, 2010, and 2009 were prepared by our independent petroleum consultant, RPS, 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 RPS in its reserves estimation process. Inputs to our reserves estimation process are based on historical results for production history, oil and natural gas prices, lease operating expenses, development costs, ownership interest and other

8

Table of Contents

required data. Our technical team meets regularly with representatives of RPS to review properties and discuss methods and assumptions used in RPS’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 the RPS 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.

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 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.

9

Table of Contents

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, 2011, 2010 and 2009:

PRODUCTIVE WELLS AND ACREAGE

Productive Wells

The following table sets forth our productive wells at June 30, 2011:

We have no oil wells at this time. The oil we produce is a by-product of our gas wells.

Acreage

The following table sets forth our undeveloped and developed gross and net leasehold acreage at June 30, 2011. 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.

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.

10

Table of Contents

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. The majority of our production is operated by non-affiliated third-party operators. The balance of our production is 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 9, 2011, the Company had ten (10) employees, eight (8) full-time and two (2) 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. 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.

COMPETITION

Currently our acreage is 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. 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.

Recent increased oil and natural gas drilling activity in East Texas and Northwest Louisiana has resulted in increased demand for drilling rigs and other oilfield equipment and services. At various times, we have and may continue to 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

11

Table of Contents

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.

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

12

Table of Contents

“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 environmental impacts of hydraulic fracturing, the results of which are anticipated to be available by late 2012. Last year, a committee of the U.S. House of Representatives commenced investigations into hydraulic fracturing practices. The U.S. Department of the Interior has announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. 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 current operations have been concentrated largely in Louisiana, and 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.

13

Table of Contents

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 federal 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 beginning in 2011. Facilities triggering permit requirements may be required to reduce greenhouse gas emissions consistent with “best available control technology” standards if deemed to be cost-effective. Such changes will affect state air permitting programs in states that administer the Clean Air Act under a delegation of authority, including states in which we have operations. In the last Congress, numerous legislative measures were introduced that would have imposed restrictions or costs on greenhouse gas emissions, including from the oil and gas industry. It is uncertain whether similar measures will be introduced in, or passed by, the current Congress. In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change. In addition, certain U.S. states or regional coalitions of states have adopted measures regulating or limiting greenhouse gases from certain sources or have adopted policies seeking to reduce overall emissions of greenhouse gases. The adoption and implementation of any international treaty or federal or state legislation or regulations, imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to comply with such requirements and possibly require the reduction or limitation of emissions of greenhouse gases associated with our operations. Such legislation or regulations could adversely affect demand for the oil and natural gas we produce or the cost of transportation and processing our production. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases may produce changes in climate or weather, such as increased frequency and severity of storms, floods and other climatic events, which if any such effects were to occur, could have adverse physical effects on our exploration and production operations or associated infrastructure or disrupt markets for our products.

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.

14

Table of Contents

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

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

Natural Gas Marketing and Transportation. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the Federal Energy Regulatory Commission (“FERC”). The FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. Beginning in 1992, the FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

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

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, or the 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

15

Table of Contents

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.

“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.

16

Table of Contents

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

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

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

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

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

“Gas” means natural gas.

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

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

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

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

“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.

17

Table of Contents

“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.

“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.

18

Table of Contents

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

“Reserves” means proved reserves.

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

“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

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

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

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

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

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

“Undeveloped Reserves” means reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

“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.

19

Table of Contents

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.

20

Table of Contents

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.

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 flow and results of operations depend upon the prices we receive for our oil and natural gas. We are particularly dependent on prices for natural gas. 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 2011, the Henry Hub spot price for natural gas fluctuated from a high of $4.94 per Mcf to a low of $3.18 per Mcf, while the NYMEX West Texas Intermediate crude oil price ranged from a high of $113.39 per Bbl to a low of $71.24 per Bbl.

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

21

Table of Contents

EXCO Operating Company, LP (“EXCO”) and BG US Production Company, LLC (“BG”) claim that they have no further obligations to us under the Drilling Credits.  If this dispute is resolved in favor of EXCO and BG, we will be required to fund our share of drilling and completion costs on wells operated by EXCO and BG from other sources, or we could incur substantial penalties.

During November 2009, we acquired $30.9 million of pre-paid Drilling Credits from EXCO applicable towards payment of our share of the drilling and completion costs for horizontal Haynesville Shale wells in Northwest Louisiana that were to be operated by EXCO.  Subsequently, EXCO assigned to BG certain of its rights and obligations with respect to the properties transferred to EXCO in exchange for the Drilling Credits. On May 18, 2011, EXCO and BG sent a letter to us claiming that they have no further obligations under the Drilling Credits. At the time of their letter, the remaining balance of the Drilling Credits was approximately $18 million.  We intend to vigorously defend our rights to the remaining balance of the Drilling Credits.  We entered into mediation with respect to this matter, but no resolution was achieved. Subsequently, we filed a demand to have this matter resolved through binding arbitration, as provided in the agreement governing the issuance of the Drilling Credits. We have filed a court action to compel arbitration.

If we are not successful in defending our rights to the Drilling Credits, we could be required to fund our share of the drilling and completion costs for horizontal Haynesville Shale wells operated by EXCO and BG on a current basis, or we could be forced to go “non-consent” on current and future wells.  If we are not able to fund those costs, thereby being deemed to be non-consent, we would incur significant penalties, which would significantly reduce our revenues from these wells. In addition, we would be required to pay royalty owners their share of revenues, which we estimate would be approximately $590,000 during fiscal 2012.  Reductions in our revenues, or the requirement to pay royalty owners, could have a material adverse effect on our results of operations, financial position and cash flows.

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 natural gas liquids. 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 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

22

Table of Contents

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.

We may not identify all risks associated with the acquisition of oil and natural gas properties, or existing wells, and any indemnifications we receive from sellers may be insufficient to protect us from such risks, which may result in unexpected liabilities and costs to us.

Our business strategy focuses on acquisitions of undeveloped oil and natural gas properties that we believe are capable of production.  We may make additional acquisitions of undeveloped oil and gas properties from time to time, subject to available resources.  Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and other liabilities and other factors.  Generally, it is not feasible for us to review in detail every individual property involved in a potential acquisition.  In making acquisitions, we generally focus most of our title and valuation efforts on the properties that we believe to be more significant, or of higher-value.  Even a detailed review of properties and records may not reveal all existing or potential problems, nor would it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities.  In addition, we do not inspect in detail every well that we acquire.  Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we perform a detailed inspection.  Any unidentified problems could result in material liabilities and costs that negatively impact our financial condition and results of operations.

Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems.  Even if a seller agrees to provide indemnity, the indemnity may not be fully enforceable or may be limited by floors and caps, and the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses.  Any limitation on our ability to recover the costs related any potential problem could materially impact our financial condition and results of operations.

We have a history of operating losses and may not be 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 of $(11,149,991) and $(5,176,625) for the fiscal years ended June 30, 2011 and 2010, respectively. Our accumulated deficit as of June 30, 2011 was $(65,540,677). 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 have no assurance that we will be able to obtain an increase in our borrowing base to permit us to access any of the remaining $10,000,000 capacity under our current Wells Fargo Credit Agreement.  By July 1, 2012, we must repay or refinance all amounts payable to Wells Fargo under the Credit Agreement. Our success in obtaining the necessary capital resources to fund the repayment to Wells Fargo 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.

The majority of our oil and gas reserves are undeveloped. At June 30, 2011, we had proved undeveloped reserves of 51,057,850 Mcfe, which represent approximately 89% of our total proved reserves of 57,699,279 Mcfe. Recovery of the Company’s future undeveloped reserves will require significant capital expenditures

23

Table of Contents

to further develop these reserves during fiscal 2012 and for the foreseeable future. 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, any failure to see increases in natural gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled and/or reworked. No assurance can be given that any wells will produce oil or gas in commercially profitable quantities.

As of June 30, 2011, we had a Drilling Credit balance of $17,763,316 with EXCO and BG to fund the drilling and completion of Company acreage being operated by EXCO or BG.  EXCO and BG claim that they have no further obligations under the Drilling Credits. Once this Drilling Credit is exhausted, or earlier if we are not successful in defending our rights to the Drilling Credits, we will be obligated to pay our share of the drilling and completion costs for wells operated by EXCO and BG on our acreage, on a current basis.  Further, we maintain material leaseholds in units operated by Goodrich, Chesapeake, El Paso, Petrohawk and Indigo Minerals and it is expected that we will be required to expended significant monies in the near term in order to participate in the drilling and completion of wells operated by these other companies.

Development of our properties will require additional capital resources. 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. 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.

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

This report contains estimates of our oil and gas reserves 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 of the first day of each month of the last 12 months and a differential of the price per Mcf received by the Company, and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. 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. Furthermore, our reserves may be subject to downward or upward revision based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors. See “Item 1. Business — Oil and Gas Reserves.”

24

Table of Contents

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

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

From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which we own an interest have been subject to production curtailments. The 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, 2011, third parties operate wells that represent almost all of our proved reserves. 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 these 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.

New SEC and GAAP reserve reporting requirements may affect the results of our reserve estimates and could change our relative positioning in the industry with regard to reserve estimates.

On December 31, 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting”, amending and expanding its disclosure requirements for oil and natural gas producing companies. The new rules and disclosure requirements were effective as of December 31, 2009. On January 16, 2010, the Financial Accounting Standards Board adopted rules conforming GAAP to the new SEC definitions and rules. These changes are the first major modifications to the accounting-based reserve reporting requirements since 1982. Among other things, the new SEC rules modify various definitions impacting categories of oil and natural gas reserves and replace the previous pricing mechanism of using the last day of our fiscal year by using an average price mechanism based on the first day of each of the last twelve months for purposes of computing reserve quantities as of December 31, 2009 and subsequent periods. In addition, these new requirements not only require oil and gas companies to report proved reserves, but also permit voluntary disclosure of ‘probable’ and ‘possible’ reserves. While the new rules are intended to provide investors with a more complete picture of the reserves of reporting companies, and were made with an eye towards continuing to recognize new technologies and knowledge about the geology and extent of oil and natural gas fields, these changes will potentially affect the results of our reserve estimates and application of these new reserve reporting rules by competitors may change our relative positioning in the industry as a whole with regards to reserve estimates.

25

Table of Contents

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. We have not obtained key personnel life insurance on Mr. Wallen.

Certain of our affiliates control a majority of our outstanding common stock, which may affect other stockholders’ ability to influence matters submitted to a vote of stockholders.

As of September 9, 2011, our executive officers, directors and their affiliates and certain 5% stockholders hold approximately 51.7% of our outstanding shares of common stock. As a result, officers, directors and their affiliates and such stockholders have the ability to exert significant influence or control over our business affairs, including the ability to control the election of directors and results of voting on all matters requiring stockholder approval. This concentration of voting power may delay or prevent a potential change in control.

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

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

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

Our common stock is traded on the NYSE Amex, LLC (the “AMEX”). The liquidity of our common stock may be adversely affected, and purchasers of our common stock may have difficulty selling our common stock, if our common stock does not continue to trade on the AMEX or another suitable trading market. The AMEX maintains certain minimum continued listing standards. If we are not able to continue to satisfy the continued listing standards, or qualify for an exemption to such standards, then we could be subject non-compliance status or de-listing.

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.

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.

26

Table of Contents

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.

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

Our Board of Directors presently intends to retain all of our earnings 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.

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 prior to drilling.  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, 2011, 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 exists 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

27

Table of Contents

the mineral owner, our total acreage position 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 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.

28

Table of Contents

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 or our customers, 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.

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.

29

Table of Contents

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

A description of our properties 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. 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 mineral rights, including pursuit of claims of lease expiration by asserting that production does not exist in paying quantities. In the normal course of our business, title defects and lease issues of varying degrees will arise, and, if practicable, reasonable efforts will be made to cure any such defects and issues.

A lawsuit was filed on or about June 15, 2010, styled, “Gloria’s Ranch, LLC v. Tauren Exploration, Inc., Cubic Energy, Inc., Wells Fargo Energy Capital, Inc. & 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 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.

On May 18, 2011, EXCO and BG informed the Company that they do not intend to honor the balance of the Drilling Credits, which was approximately $18 million at that time. The Company believes that there is no valid basis to dispute the remaining balance of the Drilling Credits.  This dispute was submitted to mediation on August 26, 2011, but was not resolved. The Company has submitted this dispute to binding arbitration, and has filed a court action in District Court in Dallas County, Texas to compel such arbitration. The Company intends to continue to vigorously defend its rights to the remaining balance of the Drilling Credits.

Item 4.  (Removed and Reserved).

30

Table of Contents

PART II

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

Common Stock and Market

The common stock of the Company is traded on the AMEX under the trading symbol “QBC”. At September 9, 2011, there were 76,815,908 shares of common stock outstanding held by approximately 799 stockholders of record.

Under its Amended and Restated Certificate of Formation, the Company is authorized to issue one class of up to 120,000,000 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 September 9, 2011, there were 109,123 preferred shares of the Company 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 AMEX. 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:

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

Through the exercises of warrants, between January 7 and January 19, 2011, the Company issued an aggregate of 954,315 shares of common stock. Aggregate proceeds to the Company of the aforementioned stock issuances were $642,780, all of which has been or is expected to be used for working capital purposes.

On November 30, 2010, the Board of Directors of the Company 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 our 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 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 AMEX of the Company’s common stock. Such amounts were recorded as compensation expense upon issuance.

On January 18, 2011, the Company issued 460,000 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

31

Table of Contents

was $538,200 based on the last sale price ($1.17 per share) on January11, 2011, on the AMEX of the Company’s common stock. Such amount was expensed upon issuance to compensation expense.

The aforementioned issuances were made in reliance upon an exemption from registration set forth in Section 4(2) of the Securities Act of 1993, as amended, which exempts transactions by an issuer not involving a public offering.

We did not purchase any of our equity securities during the fourth quarter of fiscal 2011.

Stockholder Return Performance Graph

The following graph compares the cumulative total stockholder return on our common stock during the five years ended June 30, 2011 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 Abraxas Petroleum Corporation, GMX Resources Inc., Petrohawk Energy 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, Delta Petroleum Corporation,  and SM Energy Company (collectively referred to as the “Peer Group Index”). The comparison assumes an investment of $100 on June 30, 2006 in each of our common stock, the Russell 2000 Index and the Peer Group Index.

32

Table of Contents

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 Amended Credit Agreement prohibit the payment of dividends on our common stock.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of June 30, 2011 with respect to compensation plans (including individual compensation arrangements) under which equity securities of the registrant are authorized for issuance:

33

Table of Contents

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.