The following discussion of operations for the three and six months ended December 31, 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 Northwest Louisiana acreage with Goodrich Petroleum Corporation, Chesapeake Energy Corporation, Petrohawk Energy Corporation, El Paso E&P Company, L.P., Indigo Minerals, LLC and to the greatest extent with both BG and EXCO, and all of these companies are third-party operators 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 currently depend upon our third-party Northwest Louisiana acreage 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



For the Three Months ended December31, 2012 and 2011



                                             Three months ended
                                                December 31,             Change
                                              2012         2011      Amount      %
Production Volumes:
Oil (Bbl)                                         264         153         111     73 %
Natural gas liquids (gallons)                  12,729       9,498       3,231     34 %
Natural gas (Mcf)                             306,729     990,242    (683,513 )  -69 %
Total (Mcfe)                                  310,132     992,518    (682,386 )  -69 %

Weighted Average Sales Prices:
Oil (per Bbl)                              $    83.85    $  98.13   $  (14.28 )  -15 %
Natural gas liquids (per gallon)           $     1.33    $   1.71   $   (0.38 )  -22 %
Natural gas (per Mcf)                      $     3.26    $   3.30   $   (0.04 )   -1 %

Selected Expenses per Mcfe:
Production costs                           $     0.83    $   0.31   $    0.52    164 %
Workover expenses (non-recurring)          $     0.05    $   0.03   $    0.02     78 %
Severance taxes                            $     0.05    $  (0.05 ) $    0.10   -187 %
Other revenue deductions                   $     0.52    $   0.40   $    0.12     31 %
Total lease operating expenses             $     1.45    $   0.70   $    0.77    110 %
General and administrative expenses        $     1.58    $   0.73   $    0.86    118 %
Depreciation, depletion and amortization   $     2.69    $   2.61   $    0.08      3 %

Revenues

OIL AND GAS SALES decreased 69% to $1,039,376 for the quarter ended December 31, 2012 from $3,303,365 for the quarter ended December 31, 2011 primarily due to lower gas volumes resulting from no additional non-operated wells being online in the 2012 quarter versus the 2011 quarter. We received an average natural gas price of $3.26 per Mcf in the 2012 quarter versus $3.30 in the 2011 quarter.

OTHER INCOME

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS decreased 34% to $453,787 (44% of oil and gas sales) for 2012 from $691,438 (21% of oil and gas sales) for 2011, primarily due to no new wells coming on-line during the 2012 quarter.

GENERAL AND ADMINISTRATIVE EXPENSES decreased 32% to $488,812 for 2012 from $721,560 in 2011, primarily due to a decrease of $283,147 in legal fees/expenses directly related to the EXCO/BG arbitration activities which was partially offset by $100,000 application fee paid to Durham Capital as part of the Company's debt restructuring efforts during the three months ended December 31, 2012 as compared to the 2011 period. During this 2012 quarter, the Company received $677,330 of reimbursement for legal and arbitration expenses. These were recorded as other income.

DEPRECIATION, DEPLETION AND NON-LOAN RELATED AMORTIZATION decreased 68% to $833,318 in 2012 from $2,591,304 in 2011. The decrease was primarily due to no new drilling and production by our third-party operators during the three months ended December 31, 2012 as compared to December 31, 2011.

INTEREST EXPENSE decreased 81% to $368,564 in 2012 from $1,941,972 in 2011 primarily due to the loan discount becoming fully amortized in June 2012 and our reduced weighted-average debt (before discounts) of $28,361,571 for the 2012 quarter from $37,000,000 during the 2011 quarter. The fourth amendment of the Credit Facility with Wells Fargo resulted in a loan discount being recorded. The discount had been amortized over the amended three-year term of the debt as additional interest expense, with $1,458,793 being recorded in the 2011 quarter.

For the Six Months ended December 31, 2012 and 2011



                                               Six months ended
                                                 December 31,              Change
                                              2012         2011        Amount       %
Production Volumes:
Oil (Bbl)                                         375           334          41      12 %
Natural gas liquids (gallons)                  19,118        22,716      (3,598 )   -16 %
Natural gas (Mcf)                             660,269     1,350,663    (690,395 )   -51 %
Total (Mcfe)                                  665,249     1,355,910    (690,660 )   -51 %

Weighted Average Sales Prices:
Oil (per Bbl)                              $    85.09   $     95.83   $  (10.74 )   -11 %
Natural gas liquids (per gallon)           $     1.34   $      1.78   $   (0.44 )   -25 %
Natural gas (per Mcf)                      $     3.01   $      3.44   $   (0.43 )   -13 %

Selected Expenses per Mcfe:
Production costs                           $     0.68   $      0.40   $    0.28      72 %
Workover expenses (non-recurring)          $     0.06   $      0.03   $    0.03      84 %
Severance taxes                            $     0.23   $     (1.00 ) $    1.22    -211 %
Other revenue deductions                   $     0.91   $      0.42   $    0.49     131 %
Total lease operating expenses             $     1.87   $     (0.15 ) $    2.03   -1321 %
General and administrative expenses        $     1.88   $      0.75   $    1.14     151 %
Depreciation, depletion and amortization   $     2.69   $      2.60   $    0.08       3 %

Revenues

OIL AND GAS SALES decreased 57% to $2,043,036 for the six months ended December 31, 2012 from $4,719,401 for the six months ended December 31, 2011, primarily due to decreased gas production by our third-party operators in the 2012 period versus the 2011 period. We received an average natural gas price of $3.01 per Mcf in the 2012 period versus $3.44 in the 2011 period.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS increased 22% to $1,253,315 (61% of oil and gas sales) for 2012 from $1,023,347 (22% of oil and gas sales) for 2011, primarily due to a $288,834 increase in production/severance taxes created by the ending of a two-year abatement period and a $30,269 increase in transportation and pipeline fees. These increases were partially offset by decreases in the lease operating, field operating and workover expenses totaling $89,242.

GENERAL AND ADMINISTRATIVE EXPENSES decreased 33% to $1,018,759 for 2012 from $1,516,954 for 2011 primarily due to a decrease of $410,250 in legal fees/expenses directly related to the EXCO/BG arbitration activities and a reduction in salaries of $39,605 during the six months ended December 31, 2012 as compared to the 2011 period. During this 2012 period, the Company received $677,330 of reimbursement for legal and arbitration expenses. These were recorded as other income.

DEPRECIATION, DEPLETION AND AMORTIZATION decreased 49% to $1,786,808 in 2012 from $3,519,286 in 2011. The decrease was primarily due to decreased drilling and production by our third-party operators during the six months ended December 31, 2012 as compared to December 31, 2011.

INTEREST EXPENSE decreased 78% to $852,163 in 2012 from $3,887,418 in 2011 primarily due to the loan discount becoming fully amortized in June 2012 and to our reduced weighted average debt balance (before discounts) for the six months ended December 31, 2012 of $32,680,786, as compared to $37,000,000

in the six months ended December 31, 2011. The fourth amendment of the Credit Facility with Wells Fargo resulted in a loan discount being recorded. The discount had been amortized over the amended three-year term of the debt as additional interest expense, with $2,917,586 being recorded for the six months ended December 31, 2011.

Capital Resources and Liquidity

Working Capital

The Company's working capital deficit decreased to $26,312,271 at December 31, 2012 from $35,768,341 at June 30, 2012, primarily due to the receipt of the refund of the prepaid drilling credits of $10,079,583.

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

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

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

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

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

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

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

On October 2, 2012, the Company entered into a Settlement Agreement and Mutual Release with Tauren Exploration, Inc. ("Tauren", which was a party to the dispute and is an entity wholly owned by Calvin A. Wallen, III, our Chairman and Chief Executive Officer), EXCO and BG. This agreement provides that EXCO and BG shall (a) apply the Drilling Credits as provided in the agreement and place the Company in consent status on specified wells and (b) pay to the Company $12,179,853 in cash. The agreement also provides for mutual releases among the parties. Pursuant to the Fourth Amendment to Credit Agreement between the Company and Wells Fargo Energy Capital, Inc., $9,134,890 of such amount was paid to Wells Fargo when received by EXCO and BG in order to reduce the borrowings under the Company's revolving credit facility with the balance of the cash received by the company. The settlement included reimbursement of legal and arbitration expenses in the amount $677,303, which are reported as other income in the interim financial statements.

Our debt to Wells Fargo, with a principal amount of $25,865,110, as of December 31, 2012, and the Wallen Note, with a principle of $2,000,000, are classified as current debt. As of December 31, 2012, we had a working capital deficit of $26,312,271. 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 caused us to fail to regain compliance with the Exchange listing standards, and we face potential delisting, The Panel has scheduled the Company's hearing for April 3, 2013. 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 March 31, 2013 and April 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.

If Exchange compliance is not achieved, the Company will be limited in our ability to issue equity to refinance debt obligations as they come due or raise monies to fund ongoing operation needs in excess of cash on hand.

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 $5,000,000 to a maximum of approximately $15,000,000 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 March 31, 2013, and our debt under the Wallen Note is $2,000,000 and is due April 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) increase in cash and cash equivalents is summarized as
follows:



                                                           Six months ended
                                                             December 31,
                                                          2012          2011
Net cash provided (used) by operating activities       $   747,327   $  181,947
Net cash provided (used) by investing activities         9,867,769       (9,640 )
Net cash provided (used) by financing activities        (9,134,890 )   (345,932 )
Net increase (decrease) in cash and cash equivalents   $ 1,480,206   $ (173,625 )

Operating Activities - During the six months ended December 31, 2012, the Company generated cash flows from operating activities of $747,327 as compared to $181,947 cash used in operating activities 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 cash used in investing activities consists of capital expenditures related to the drilling and completion of new wells and the acquisition and development of additional oil and gas properties. In the six months ended December 31, 2012, we had capital spending related to the acquisition and development of oil and gas properties of $211,609 and were reimbursed for $10,079,583 of prepaid drilling credits and had cash provided of $9,867,769 by investing activities. In the six months ended December 31, 2011, we had capital spending related to the acquisition and development of oil and gas properties of $7,889,780 and utilized $7,880,140 of prepaid drilling credits and used net cash of $9,640 in investing activities.

Financing Activities - Net cash flows were $9,134,890 used and $345,932 provided by financing activities during the six month periods ended December 31, 2012 and 2011, respectively.

During the 2012 period, we used $9,134,890 for funding financing activities. These funds were received as part of the EXCO/BG settlement and were used to reduce our Credit Facility. During the 2011 period, Cubic received an aggregate of $345,932 in proceeds from the issuance of stock (resulting from the exercise of warrants) and drew upon an additional $5,000,000 from Wells Fargo under the revolving line of credit component of our Credit Facility in order to pay past due invoices and working interest expenses on our non-operated acreage. As a result, the Company has borrowed $30,000,000 of the $40,000,000 potentially available under the Credit Facility's Revolving Note, but the Company has borrowed the maximum available at this time, due to borrowing base limitations.

Contractual Obligations

We have no material changes in our 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, development 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. We have no contractual commitments pertaining to exploration, development and production activities.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operation 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.