Summary of CUBIC ENERGY INC

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Annual Report on Form 10-K. In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our results and the timing of selected events may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under "risk factors" and elsewhere in this Annual Report on Form 10-K.

Overview

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

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

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Summary Operating, Reserve and Other Data



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



                                                      Year ended June 30,
                                    2011          2010         2009         2008        2007
Operating Data:
Proved Reserves (Bcfe)                  57.7         29.2         21.1         6.6         4.3
Production (Mcfe)                  1,497,666      806,102      300,712     244,665      76,214
Producing wells at end of
period, gross                             58           40           43          32          22
Producing wells at end of
period, net                            13.47        11.81        21.44       18.42       14.42
Acreage, gross                        13,239       13,594       14,466      14,711      17,542
Acreage, net                           5,149        5,324        6,077       6,151       7,364

Production:
Oil (Bbl)                              1,444        1,364        1,681       1,682         967
Natural gas (Mcf)                  1,481,430      792,433      279,516     228,219      70,412
Natural gas liquids (gallons)         53,008       38,411       77,772      44,476           -
Total oil, gas and liquids
(Mcfe)                             1,497,664      806,100      300,712     244,665      76,214
Average daily (Mcfe)                   4,103        2,208          824         668         209

Weighted Average Sales
Prices:
Oil (per Bbl)                    $     87.24    $   70.08    $   66.52    $ 102.15    $  61.68
Natural gas (per Mcf)            $      4.53    $    5.08    $    3.72    $   9.01    $   7.44
Natural gas liquids (per
gallon)                          $      1.57    $    1.25    $    1.02    $   1.66         n/a
Natural gas equivalent (per
Mcfe)                            $      4.10    $    4.32    $    6.18    $   9.41    $   7.65

Selected Expenses per Mcfe:
Production costs                 $      0.60    $    1.27    $    3.98    $   3.60    $   4.18
Workover expenses
(non-recurring)                  $      0.01    $    0.05    $    0.12    $   0.11    $   1.40
Severance taxes                  $      0.07    $    0.15    $    0.20    $   0.29    $   0.39
Other revenue deductions         $      0.56    $    0.65    $    0.27    $   0.75    $   0.35
Total lease operating
expenses                         $      1.24    $    2.12    $    4.57    $   4.75    $   6.32
General and administrative
expenses:
Non-cash stock-based
compensation                     $      0.38    $    0.49    $    1.28    $   5.13    $   6.43
Other general and
administrative                   $      1.72    $    2.47    $    5.17    $   5.04    $  10.96
Total general and
administrative                   $      2.10    $    2.96    $    6.45    $  10.17    $  17.39
Depreciation, depletion and
amortization                     $      2.48    $    1.43    $    2.55    $   8.79    $   4.76

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RESULTS OF OPERATIONS

Comparison of Fiscal 2011 to Fiscal 2010

Revenues

OIL AND GAS SALES increased 76% to $6,133,299 for fiscal 2011 from $3,486,171 for fiscal 2010 primarily due to increased gas volumes resulting from 19 new Haynesville Shale wells, of which eleven are operated by Chesapeake, three are operated by Goodrich and five are operated by EXCO. This increase was mitigated by the average price of natural gas being $4.14 per Mcf for fiscal 2011 and $4.32 per Mcf for fiscal 2010.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as "LEASE OPERATING EXPENSES" elsewhere herein) increased 1% to $1,857,528 (30% of oil and gas sales) for fiscal 2011 from $1,845,153 (53% of oil and gas sales) for fiscal 2010.

GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") increased 32% to $3,156,860 for fiscal 2011 from $2,389,073 in fiscal 2010. This increase of $767,787 was primarily due to increased stock compensation of $178,235, franchise tax increase of $159,604, contract landmen increase of $75,888, a one-time legal settlement of $82,500 and overall increased marketing expenses of the Company, which includes travel expense increase of $24,610, office supplies increase of $10,888, reserve reports increase of $29,567 and maps and logs increase of $20,355.

DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") increased 222% to $3,707,255 in fiscal 2011 from $1,153,065 in fiscal 2010, primarily due to an increase in projected capital costs of $94,022,190 caused by a 20% increase in well costs and an increase in the total number of offset wells allowed per section, which costs were added to the full cost pool, thereby increasing amortization, which is based on the unit-of-production method.

GAIN ON DEBT EXTINGUISHMENT was $0 for fiscal 2011 and was $1,747,623 for fiscal 2010.

INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 62% to $7,648,622 in fiscal 2011 from $4,714,386 in fiscal 2010 primarily due to an increase in debt (before discounts) to $37,000,000 at June 30, 2011 from $32,000,000 at June 30, 2010. This increase resulted from the drawing down of our revolving credit line of $5,000,000 (before discounts) of our Amended Wells Fargo Credit Facility. The weighted average debt balance (before discounts) for fiscal 2011 was $36,164,384 as compared to $29,616,438 in fiscal 2010. The Credit Facility with Wells Fargo also resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense with $5,740,440 being recorded in fiscal 2011 as compared to $3,178,416 in fiscal 2010. There was a decrease in the capitalization of interest expense to the full cost pool for oil and gas properties of $5,221 in fiscal 2011 as compared to $12,737 in fiscal 2010.

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Comparison of Fiscal 2010 to Fiscal 2009

Revenues

OIL AND GAS SALES increased 88% to $3,486,171 for fiscal 2010 from $1,858,139 for fiscal 2009 primarily due to increased gas volumes resulting from 14 new Haynesville Shale wells, of which nine are operated by Chesapeake, three are operated by Goodrich and two are operated by EXCO, Inc. This increase was mitigated by the average price of natural gas being $4.32 per Mcf for fiscal 2010 and $6.18 per Mcf for fiscal 2009.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as "LEASE OPERATING EXPENSES" elsewhere herein) increased 34% to $1,845,153 (53% of oil and gas sales) for fiscal 2010 from $1,372,041 (74% of oil and gas sales) for fiscal 2009 primarily due to more wells being on-line in Louisiana, which resulted in: a $439,379 increase in costs passed-through to the Company by the purchaser of the Company's gas, a $65,000 increase in production taxes and a $53,660 increase in non-operated property expenses. These increases were somewhat offset by a $151,724 decrease in common facility costs and $128,098 decrease in salt water hauling.

GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") increased 23% to $2,389,073 for fiscal 2010 from $1,940,025 in fiscal 2009 as a result of: a $128,965 increase in marketing expense, a $165,597 increase in legal fees due in part to the support needed to address the AMEX non-compliance issue discussed below, related expenses in connection with the November 2009 transaction between the Company, Tauren and Langtry and costs of amending the Wells Fargo Credit Facility. There was also a $63,054 increase in contracted professional services; $20,000 of which went to NYSE Amex non-compliance support and $23,000 went to Sarbanes-Oxley 404 compliance.

On June 26, 2009, the Company received a letter from AMEX stating that the Company was not in compliance with Section 1003(a)(iv) of AMEX's Company Guide because AMEX believed that it appeared questionable, in its opinion, as to whether the Company would be able to continue operations and/or meet its obligations as they mature. On March 5, 2010, the Company received notice from AMEX that the Company had regained full compliance. The Company was able to regain full compliance by executing the compliance plan submitted to AMEX that included the measures taken by the Company to acquire the Drilling Credits and restructuring the Company's debt with Wells Fargo through the Second Amendment.

DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") increased 49% to $1,153,065 in fiscal 2010 from $771,861 in fiscal 2009 primarily due to an increase in capital expenditures in fiscal 2010 related to the non-operated development of oil and gas properties.

IMPAIRMENT OF OIL AND GAS PROPERTIES decreased to $0 in fiscal 2010 from $20,390,819 in fiscal 2009. The fiscal 2009 impairment resulted from a downward revision of our reserve estimates, which was effected by the following events:
(i) we experienced delays related to third party providers in our Bethany Longstreet acreage, including not receiving contracted-for compression services, which temporarily delayed our ability to produce from these wells; (ii) we did not effectuate final completion of certain wells due to a shift in our focus to the development of our Johnson Branch acreage in Caddo Parish, Louisiana; and,
(iii) the lack of production history in wells recently brought online lead to a sharper decline curve being utilized by RPS in formulating the reserve estimates.

GAIN ON DEBT EXTINGUISHMENT was realized in December 2009 as a result of the refinancing of the debt with Wells Fargo. The existing loan balance of $1,877,494 was decreased (written off) as a term of the amendment of the Wells Fargo credit facility that was extinguished, which was partially offset by debt extinguishment costs of $129,871. This created an overall gain on debt extinguishment of $1,747,623 for fiscal 2010.

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INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 131% to $4,714,386 in fiscal 2010 from $2,044,718 in fiscal 2009 primarily due to an increase in debt (before discounts) to $32,000,000 at June 30, 2010 from $27,000,000 at June 30, 2009. This increase resulted from the drawing down of our revolving credit line of $5,000,000 (before discounts) of our Amended Wells Fargo Credit Facility. The weighted average debt balance (before discounts) for fiscal 2010 was $29,616,438 as compared to $26,565,452 in fiscal 2009. The Credit Facility with Wells Fargo also resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense with $3,178,416 being recorded in fiscal 2010 as compared to $514,620 in fiscal 2009. There was a decrease in the capitalization of interest expense to the full cost pool for oil and gas properties of $12,737 in fiscal 2010 as compared to $30,682 in fiscal 2009.

Liquidity and Capital Resources

Overview

The Company's primary resource is its oil and gas reserves.

On November 24, 2009, the Company entered into transactions with Tauren and Langtry, both of which are entities controlled by Calvin Wallen III, the Chief Executive Officer of the Company, under which the Company acquired $30,952,810 in pre-paid Drilling Credits applicable towards the development of its Haynesville Shale rights in Northwest Louisiana. The Company expects to use the Drilling Credits to fund $30,952,810 of its share of the drilling and completion costs for those horizontal Haynesville Shale wells drilled in sections previously operated by an affiliate of the Company which are now operated by a third party. As of June 30, 2011, $17,763,316 was the remaining balance of the Drilling Credits.

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. If the Company is not successful in defending its rights, it expects to fund its share of expenses from wells drilled by EXCO and BG through one of the other sources of funds described above.

Management believes we will prevail, but if not, we have the option of going "non-consent" or being deemed non-consent on current and future horizontal Haynesville Shale wells operated by EXCO and BG. By being deemed to be non-consent, or opting to be non-consent, in addition to penalties we would reduce our share of revenues from these wells, we would be required to pay the royalty owners their share of revenues, which we anticipate to be up to approximately $65,000 per well per month, or an aggregate of approximately$590,000 based on the current number of EXCO and BG operated wells for the balance of fiscal 2012. Other than this $590,000, we do not expect any additional royalties to be paid out of pocket by Cubic during fiscal 2012, with respect to EXCO and BG operated wells. With future strategies to obtain additional financing, funds generated through existing wells and cash on hand, we expect to be able to continue to pay our expenses as they come due. It is possible that EXCO and BG exhaust the remaining balance of the Drilling Credits during fiscal 2012. The balance of the Drilling Credits not exhausted is due and payable in cash early in fiscal 2013.

Product prices, over which we have no control, have a significant impact on revenues from production and the value of such reserves and thereby on the Company's borrowing capacity, in the event the Company determines to borrow additional funds. Within the confines of product pricing, the Company needs to be able to find and develop or acquire oil and gas reserves in a cost effective manner in order to generate sufficient financial resources through internal means to complete the financing of its capital expenditure program.

During the twelve months ended June 30, 2011, the Company used cash flows from operating activities of $2,567,159 as compared to $681,713 in fiscal 2010. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas.

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Working Capital and Cash Flow

The Company's working capital increased to $2,319,621 at June 30, 2011 from ($1,435,908) at June 30, 2010. This increase was primarily due to revenue increase of $2,647,128, exercised warrants providing cash of $642,700 and a $5,000,000 increase to our revolving line of credit. The Amended Credit Agreement contains material covenants that include, but are not limited to, a right to Borrowing Base redeterminations, which can be made by Wells Fargo at any time. Any redetermination can reduce our revolving credit limit with any excess borrowings being due within 30 days or, at the Company's option, in five equal monthly installments. As of June 30, 2011, we are in full compliance with the Wells Fargo Credit Agreement.

Operating activities - During the twelve months ended June 30, 2011, the Company used cash flows from operating activities of $2,567,159 as compared to $681,713 in fiscal 2010 and $2,152,187 in fiscal 2009. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas.

Investing activities - During the twelve months ended June 30, 2011, the Company used cash flows from investing activities of $1,412,406 as compared to $5,735,839 in fiscal 2010 and $5,588,927 in fiscal 2009. Cash used in investing activities were for drilling and working interest participation during the three years to develop our assets.

Financing activities - During the twelve months ended June 30, 2011, the Company had cash flows from financing activities of $5,129,915 as compared to $6,738,400 in fiscal 2010 and $5,668,152 in fiscal 2009. Cash provided by financing activities for fiscal periods 2011, 2010 and 2009 were from borrowings under the credit facility, borrowings from affiliates and issuances of stock. See the Note C-Stockholders' equity and Note E- Long-term debt for further discussion.

Capital Expenditures

The majority of our oil and gas reserves are undeveloped. As such, recovery of the Company's future undeveloped proved reserves will require significant capital expenditures. Management estimates that aggregate capital expenditures ranging from a minimum of approximately $15,000,000 to a maximum of approximately $20,000,000 will be made to further develop these reserves during fiscal 2012 (from currently available funds, Drilling Credits and projected cash from operating activities). Moreover, additional capital expenditures may be required for exploratory drilling on our undeveloped acreage. The Company may increase its planned activities for fiscal 2012, if product prices improve. The Company anticipates that its share of expenses with respect to the drilling and completion of wells during fiscal 2012 will be approximately $15 million, but the Company has little or no control with respect to the timing of drilling wells and the timing of drilling expenses incurred. Moreover, additional capital expenditures may be required for exploratory drilling on our undeveloped acreage. The Company may increase its planned activities for fiscal 2012 if product prices improve. If product prices remain flat or go lower such activities and our capital expenditures, may be restricted, although we have little or no control over expenditures incurred by our third-party operators.

The Company is considering acquiring leaseholds in additional properties, including properties that are expected to produce primarily oil. However, the Company cannot give any assurance that any such acquisition will be completed.

No assurance can be given that all or any of these anticipated or possible capital expenditures will be completed as currently anticipated. We believe that cash on hand, the remaining balance of the Drilling Credits and revenues from operations and availability under our revolving note will enable us to continue to meet our obligations and fund our projected capital expenditures for fiscal 2012. Any acquisition of additional leaseholds would require that we obtain additional capital resources.

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Capital Resources

The Company plans to fund its development and exploratory activities through cash on hand, the Drilling Credits, cash provided from operations; and one of, or a combination of, the following potential transactions: a private placement of common stock; a public offering of common stock; a joint venture with an industry partner in which we would or could farm-out a to-be-determined percentage of our working interests in certain properties; a disposition of assets; or other transactions.

We are negotiating with Wells Fargo to extend the maturity date of our Credit Agreement, which currently is July 1, 2012. There can be no assurance that the Company will be able to negotiate such extension.

We expect production from wells drilled and completed in fiscal 2009, 2010, 2011, together with additional wells that are expected to be completed during fiscal 2012, to provide cash flow to support additional drilling. However, the Company cannot be certain that adequate funds will be available from cash on hand, the Drilling Credits, operating cash flow, and the aforementioned potential transactions to fully fund the projected capital expenditures for fiscal 2012. Additionally, because future cash flows, the availability of borrowings, and the ability to consummate any of the aforementioned potential transactions are subject to a number of variables, such as prevailing prices of oil and gas, actual production from existing and newly-completed wells, the Company's success in developing and producing new reserves, the uncertainty of financial markets and joint venture and merger and acquisition activity, and the uncertainty with respect to the amount of funds which may ultimately be required to finance the Company's development and exploration program, there can be no assurance that the Company's capital resources will be sufficient to sustain the Company's development and exploratory activities.

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

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Critical Accounting Policies

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

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

Estimates of Proved Reserves

The proved reserves data included in this Annual Report on Form 10-K was prepared in accordance with SEC guidelines. The accuracy of a reserve estimate is a function of:

� the quality and quantity of available data;

� the interpretation of that data;

� the accuracy of various mandated economic assumptions; and

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

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

. . .