The following discussion of operations for the three months ended September 30, 2012 and 2011 should be read in conjunction with our condensed financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and with the financial statements, notes and management's discussion and analysis included in our Annual Report on Form 10-K for the year ended June 30, 2012.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

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.

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.

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.

Results of Operations



                                             Three months ended
                                               September 30,
                                              2012         2011
Production Volumes:
Oil (Bbl)                                         111         181
Natural gas liquids (gallons)                   6,389      13,218
Natural gas (Mcf)                             353,540     360,422
Total (Mcfe)                                  355,118     363,393

Weighted Average Sales Prices:
Oil (per Bbl)                              $    88.04    $  93.89
Natural gas liquids (per gallon)           $     1.36    $   1.84
Natural gas (per Mcf)                      $     2.79    $   3.81

Selected Expenses per Mcfe:
Production costs                           $     0.61    $   0.64
Workover expenses (non-recurring)          $        -    $      -
Severance taxes                            $     0.39    $  (0.22 )
Other revenue deductions                   $     1.25    $   0.50
Total lease operating expenses             $     2.25    $   0.91
General and administrative expenses        $     1.49    $   2.19
Depreciation, depletion and amortization   $     2.68    $   2.55

Revenues

OIL AND GAS SALES decreased 29% to $1,003,660 for the quarter ended September 30, 2012 from $1,416,036 for the quarter ended September 30, 2011 primarily due to a decrease in natural gas prices during the 2012 quarter versus the 2011 quarter. The weighted average natural gas price we received in the 2012 quarter was $2.79 per Mcf versus $3.81 per Mcf in the 2011 quarter.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as "LEASE OPERATING EXPENSES" elsewhere herein) increased 141% to $799,528 (80% of oil and gas sales) for the 2012 quarter from $331,909 (23% of oil and gas sales) for the 2011 quarter. This increase is primarily due to increases of $262,992 of transportation and pipeline fees for the two new EXCO wells that went online during fiscal 2012 and $219,942 in natural gas production taxes due to the State of Louisiana's two-year abatement period ending during fiscal 2011.

GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") decreased 33% to $529,947 for the 2012 quarter from $795,394 in the 2011 quarter primarily as a result of a decrease of $127,103 in legal fees needed to defend our assets against the EXCO/BG claims to not honor the Drilling Credits owed the Company; and a 20,397 reduction in travel expenses, an $18,816 reduction in salaries, a $11,133 reduction in reserve report fees and a $47,339 reduction in tax penalties for the quarter ended September 30,2012.

DEPRECIATION, DEPLETION AND NON-LOAN RELATED AMORTIZATION ("DD&A") increased 3% to $953,490 in the 2012 quarter from $927,982 in the 2011 quarter primarily due to no new wells on line. No impairment loss was recognized during the quarters ended September 30, 2012 or 2011.

INTEREST EXPENSE decreased 75% to $483,599 in the 2012 quarter from $1,943,666 in the 2011 quarter primarily due to the full amortization of the debt discount on our debt to Wells Fargo prior to the 2012 quarter. The note payable discount amortization was $0 for the 2012 quarter and $1,458,793 for the 2011 quarter.

Capital Resources and Liquidity

Working Capital

The Company's working capital deficit increased to $36,727,196 at September 30, 2012 from $35,768,341 at June 30, 2012, primarily due to the downturn in natural gas prices and increase in accounts payable.

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: a private placement of common or preferred 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.

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. On October 2, 2012, the Company entered into a Settlement Agreement and Mutual Release with Tauren, EXCO and BG. This agreement provides that EXCO and BG shall (a) apply the Company's prepaid drilling credits as provided in the agreement and place the Company in consent status on specified wells and (b) pay to the Company $12,179,853 in cash. Pursuant to the Fourth Amendment to Credit Agreement between the Company and Wells Fargo Energy Capital, Inc., $9,134,890 of such total amount was paid to Wells Fargo in order to reduce the borrowings under the Company's revolving credit facility. This agreement also provides for mutual releases among the parties.

Our debt to Wells Fargo, with a principal amount of $35,000,000, as of September 30, 2012 and prior to the repayment of $9,134,890 referred to above, is due on December 31, 2012, and the Wallen Note, with a principle of $2,000,000, is due January 1, 2013, and both are classified as current debt. As of September 30, 2012, we had a working capital deficit of $36,727,196. This level of negative working capital creates two additional concerns. One, it creates substantial doubt as to our ability to pay our obligations as they come due and remain a 'going concern'. Secondly, it might cause us to fail to regain compliance with the NYSE-MKT listing standards, and cause us to face potential delisting.

We successfully negotiated with Wells Fargo and Mr. Wallen to extend the maturity date of our Credit Agreement and the Wallen Note, which currently is December 31, 2012 and January 1, 2013, respectively. There can be no assurance that the Company will be able to negotiate further extensions.

We expect production from wells drilled and completed in fiscal 2011 and 2012, together with additional wells that are expected to be completed during fiscal 2013, to provide cash flow to support additional drilling. However, the Company cannot be certain that adequate funds will be available from cash on hand, operating cash flow, and the aforementioned potential transactions to fully fund the projected capital expenditures for fiscal 2013. 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 not have the ability to fund its share of the development and exploratory activities being conducted by third-party operators. If a well is proposed by a third-party operator and the Company does not have the funds 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.

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, additional borrowings, proceeds from the issuance of equity securities and projected cash from operating activities). Currently, our debt with Wells Fargo is approximately $26,000,000 and is due December 31, 2012, and our debt under the Wallen Note is $2,000,000 and is due January 1, 2013. We are continuing discussion to renegotiate these debts. 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 drilling by any of our third-party operators and the timing of drilling expenses incurred. Additional capital expenditures may be required for exploratory drilling on our undeveloped acreage.

The Company remains diligent in its pursuit of our strategic plan to restructure our debt and raise additional operating capital for leasehold acquisitions and development during fiscal 2013. 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 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.

Cash Flow



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



                                                         Three months ended
                                                            September 30,
                                                          2012         2011
Net cash provided (used) by operating activities       $  (12,072 ) $  (63,810 )
Net cash provided (used) by investing activities         (153,425 )    (27,548 )
Net cash provided (used) by financing activities                -     (125,890 )
Net increase (decrease) in cash and cash equivalents   $ (165,497 ) $ (217,248 )

Operating Activities - During the quarter ended September 30, 2012, the Company used cash flows from operating activities of $12,072 as compared to $63,810 in the prior year period. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas.

Investing Activities - The primary driver of cash used in investing activities is capital expenditures related to the drilling and completion of new wells and the acquisition and development of additional oil and gas properties. In the quarter ended September 30, 2012, we used net cash of $153,425 in investing activities. For the quarter ended September 30, 2011, we used net cash of $27,548 in investing activities.

Financing Activities - Net cash flows (used) and provided by financing activities were $0 and ($125,890) in the quarters ended September 30, 2012 and 2011, respectively. During the 2011 quarter, we received no proceeds, but we did pay accrued dividends on our preferred stock of $125,890.

Contractual Obligations

We have no long-term commitments associated with our capital expenditure plans or operating agreements other than those described above. Our level of capital expenditures will vary in future periods depending on: the success we experience in our acquisition, developmental and exploration activities; oil and natural gas price conditions; and other related economic factors. Currently, no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities. Other than operating agreements with our third-party operators, we have no contractual obligations pertaining to exploration, development and production activities.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the condensed financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the year ended June 30, 2012.