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

Overview

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

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

Summary Operating, Reserve and Other Data



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



                                                       Year ended June 30,
                                    2012           2011          2010         2009         2008
Operating Data:
Proved Reserves (Bcfe)                  33.8           57.7         29.2         21.1         6.6
Production (Mcfe)                  2,258,577      1,497,666      806,102      300,712     244,665
Producing wells at end of
period, gross                             60             58           40           43          32
Producing wells at end of
period, net                            13.52          13.47        11.81        21.44       18.42
Acreage, gross                        13,123         13,239       13,594       14,466      14,711
Acreage, net                           5,100          5,149        5,324        6,077       6,151

Production:
Oil (Bbl)                              1,100          1,444        1,364        1,681       1,682
Natural gas (Mcf)                  2,244,315      1,481,430      792,433      279,516     228,219
Natural gas liquids (gallons)         53,623         53,008       38,411       77,772      44,476
Total oil, gas and liquids
(Mcfe)                             2,258,577      1,497,666      806,102      300,712     244,665
Average daily (Mcfe)                   6,188          4,103        2,208          824         668

Weighted Average Sales
Prices:
Oil (per Bbl)                    $     93.25    $     83.13    $   73.18    $   66.52    $ 102.15
Natural gas (per Mcf)            $      3.01    $      4.00    $    4.21    $    3.72    $   9.01
Natural gas liquids (per
gallon)                          $      1.59    $      1.60    $    1.27    $    1.02    $   1.66
Natural gas equivalent (per
Mcfe)                            $      3.07    $      4.10    $    4.32    $    6.18    $   9.41

Selected Expenses per Mcfe:
Production costs                 $      0.43    $      0.60    $    1.27    $    3.98    $   3.60
Workover expenses
(non-recurring)                  $      0.07    $      0.01    $    0.05    $    0.12    $   0.11
Severance taxes                  $     (0.06 )  $      0.07    $    0.15    $    0.20    $   0.29
Other revenue deductions         $      0.43    $      0.56    $    0.65    $    0.27    $   0.75
Total lease operating
expenses                         $      0.87    $      1.24    $    2.12    $    4.57    $   4.75
General and administrative
expenses:
Non-cash stock-based
compensation                     $      0.10    $      0.38    $    0.49    $    1.28    $   5.13
Other general and
administrative                   $      1.48    $      1.72    $    2.47    $    5.17    $   5.04
Total general and
administrative                   $      1.58    $      2.10    $    2.96    $    6.45    $  10.17
Depreciation, depletion and
amortization                     $      2.70    $      2.48    $    1.43    $    2.55    $   8.79

RESULTS OF OPERATIONS

Comparison of Fiscal 2012 to Fiscal 2011

Revenues

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

Costs and Expenses

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

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

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

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

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 $4.10 per Mcfe for fiscal 2011 and $4.32 per Mcfe 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, 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 NON-LOAN RELATED 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.

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 has used approximately $21,435,551of the Drilling Credits to fund 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 EXCO and/or BG. As of June 30, 2012, $9,517,258 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. This dispute was submitted to binding arbitration during the week of January 9, 2012 and a ruling was issued on March 9, 2012.

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

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

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

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

† The Company is awarded attorneys' fees, costs and interest.

On June 13, 2012, the Judge for the 298th Judicial District Court in Dallas County, Texas (the "Court") entered an Order Confirming this Arbitration Award, and asked the Arbitrators to determine the amount of attorney fees owed to the Company. On July 27, 2012, the Arbitrators issued their Award of Attorney Fees and Costs by Arbitration Panel. On September 12, 2012, the Court entered a final judgment in favor of the Company and against EXCO and BG in the amount of approximately $12,800,000, which includes $9,750,000 in dollars accelerated as due based on outstanding drilling credits, $250,000 in interest, $1,100,000 of attorney's fees, and $1,700,000 of past-due revenue.

EXCO/BG retains a right to appeal this final judgment from September 12, 2012 and retains the right to post a bond to forestall any collection efforts to enforce the final judgment. Ultimate resolution of the claims supporting the final judgment is thus still pending.

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

Working Capital and Cash Flow

The Company's had a working capital deficit of $35,768,341 at June 30, 2012 down from positive working capital of $2,319,620 at June 30, 2011. This decrease was primarily due to the Wells Fargo Credit Agreement and the Wallen Note, both originally long term liabilities totaling $37,000,000, becoming current liabilities.

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, 2012, we are in full compliance with the Wells Fargo Credit Agreement.

Operating activities - During the twelve months ended June 30, 2012, the Company used cash flows from operating activities of $395,058 as compared to $2,567,159 in fiscal 2011 and $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.

Investing activities - During the twelve months ended June 30, 2012, the Company used cash flows from investing activities of $88,634 as compared to $1,412,406 in fiscal 2011 and $5,735,839 in fiscal 2010. 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, 2012, the Company had cash flows from financing activities of $(783,029) as compared to $5,129,915 in fiscal 2011 and $6,738,400 in fiscal 2010. Cash provided by financing activities for fiscal periods 2011 and 2010 were primarily from borrowings under the credit facility, borrowings from affiliates and issuances of stock. Cash used in 2012 was for payment of cash dividends on preferred stocks. See 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 $35,000,000 will be made to further develop these reserves during fiscal 2013 (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 2013, if the Company acquires oil properties or of natural gas. The Company has little or no control with respect to the timing of EXCO drilling wells and the timing of drilling expenses incurred. Additional capital expenditures may be required for exploratory drilling on our undeveloped acreage.

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 we will need substantive additional financing to continue to meet our obligations and fund our projected capital expenditures for fiscal 2013. Any acquisition of additional leaseholds would require that we obtain additional capital resources.

Capital Resources

The Company plans to fund its development and exploratory activities through cash on hand, cash provided from operations, and one of, or a combination of, the following potential transactions: an offering of common stock, preferred stock and/or debt; 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.

As future cash flows, the availability of borrowings, and the ability to consummate any of the aforementioned potential transactions are subject to a number of variables, such as prevailing prices of oil and gas, actual production from existing and newly-completed wells, the Company's success in developing

and producing new reserves, the uncertainty of financial markets and joint venture and merger and acquisition activity, and the uncertainty with respect to the amount of funds which may ultimately be required to finance the Company's development and exploration program, there can be no assurance that the Company's capital resources will be sufficient to sustain the Company's development and exploratory activities. With future strategies to obtain additional financing, funds generated through existing wells and cash on hand, we expect to be able to continue to pay our expenses as they come due.

We negotiated with Wells Fargo an extension of the maturity date of our Credit Agreement, from July 1, 2012 to December 31, 2012. As part of this extension, we are required to repay our revolving credit facility in an amount equal to 75% of our recovery from EXCO and BG. We continue to negotiate a restructuring of our Credit Agreement with Wells Fargo. There can be no assurance that the Company will be able to negotiate such a restructuring of its Credit Agreement.

If we are unable to obtain sufficient capital resources on a timely basis, the Company will 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.

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.

You should not assume that the present value of future net cash flows represents the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves according to the requirements in the SEC's Release No. 33-8995

"Modernization of Oil and Gas Reporting," or Release No. 33-8995. Actual future prices and costs may be materially higher or lower than the prices and costs used in the preparation of the estimate. Further, the mandated discount rate of 10% may not be an accurate assumption of future interest rates.

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

Proved reserves are defined as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimates are deterministic estimates or probabilistic estimates. To be classified as proved reserves, the project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

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

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

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

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

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

Accounting for oil and natural gas properties

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

We use the full cost method of accounting, which involves capitalizing all acquisition, exploration, exploitation and development costs of oil and natural gas properties. Once we incur costs, they are recorded in the depletable pool of proved properties or in unproved properties, collectively, the full cost pool. Unproved property costs are not subject to depletion. We review our unproved oil and natural gas property costs on a quarterly basis to assess possible impairment or the need to transfer unproved costs to proved properties as a . . .