UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q/A

(Amendment No. 2)

x QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the quarterly period ended December 31, 2013

o TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

for the transition period from to

Commission File Number 001-34144

CUBIC ENERGY, INC.

(Exact name of registrant as specified in its charter)

Texas		87-0352095
(State or other jurisdiction of incorporation)		(IRS Employer Identification No.)

9870 Plano Road

Dallas, TX 75238

(Address of principal executive offices)

(972) 686-0369

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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

Large accelerated filer o		Accelerated filer o
Non-accelerated filer o		Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of February 7, 2013, the registrant had 77,505,908 shares of common stock, $0.05 par value, outstanding.

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Explanatory Note

This amendment to Quarterly Report on Form 10-Q/A amends our disclosure regarding derivative transactions to which we are a party. This amended disclosure is reflected in (i) our Condensed Consolidated Balance Sheet, (ii) our Condensed Consolidated Statements of Cash Flows, (iii) Note H “Derivative Instruments and Hedging Activity”, and (iv) Part I, Item 2 —Management’s Discussion and Analysis of Financial Condition and Results of Operations. Note I to our Condensed Consolidated Financial Statements has been deleted. We have also amended the disclosure in Note B “Acquisition of Properties”.

Special note regarding forward-looking statements

This quarterly report on Form 10-Q contains forward-looking statements. All statements, other than statements of historical facts, are forward-looking statements. These forward-looking statements relate to, among other things, the following: our future financial and operating performance and results; our business strategy; market prices; and our plans and forecasts.

Forward-looking statements are identified by use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “will,” “continue,” “potential,” “should,” “could” and similar words and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements. You should consider carefully the statements in the “Risk Factors” section of our Annual Report on Form 10-K for our fiscal year ended June 30, 2013 and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements, including, but not limited to, the following factors:

· our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to service our debt and fully develop our undeveloped acreage positions;

· our ability to integrate our recently consummated acquisitions;

· the volatility in commodity prices for oil and natural gas;

· the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes);

· the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

· the ability to replace oil and natural gas reserves;

· lease or title issues or defects to our oil and gas properties;

· environmental risks;

· drilling and operating risks;

· exploration and development risks;

· competition, including competition for acreage in oil and natural gas producing areas;

· management’s ability to execute our plans to meet our goals;

· our ability to retain key members of senior management;

· our ability to obtain goods and services, such as drilling rigs and other oilfield equipment, and access to adequate gathering systems and pipeline take-away capacity, to execute our drilling program;

· general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than expected, including that the United States economic slow-down might continue to negatively affect the demand for natural gas, oil and natural gas liquids;

· continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

· other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our business, operations or pricing.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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CUBIC ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

	December 31,
	2013 (unaudited)			June 30, 2013
Assets
Current assets:
Cash and cash equivalents	$	15,274,662		$	260,576
Accounts receivable - trade	2,829,855			586,174
Due from affiliate	—			1,678
Other prepaid expenses	544,854			156,892
Total current assets	18,649,371			1,005,320
Property and equipment:
Oil and gas properties, full cost method:
Proved properties (including wells and related equipment and facilities)	123,626,739			33,828,079
Unproven properties	8,881,589			—
Office and other equipment	37,487			30,227
Property and equipment, at cost	132,545,815			33,858,306
Less accumulated depreciation, depletion and amortization	22,175,523			19,134,081
Property and equipment, net	110,370,292			14,724,225
Other assets:
Cash restricted under loan agreement	5,000,000			—
Deferred loan costs, net	3,706,881			—
Prepaid drilling costs	2,964,342
Acquisition costs - deposits	—			2,300,000
Total other assets	11,671,223			2,300,000

Total Assets	$	140,690,886		$	18,029,545

Liabilities and stockholders’ equity (deficit)
Current liabilities:
Notes payable - WFEC - term note	$	—		$	5,000,000
Note payable - WFEC - revolver	—			20,865,110
Notes payable - due to affiliate	—			2,000,000
Fair value of derivatives	3,993,177			—
Due to affiliates	555,742			2,000,000
Accounts payable and accrued expenses	3,585,180			1,331,609
Total current liabilities	$	8,134,099		$	31,196,719
Long-term liabilities
Long-term debt, net of discounts	$	85,700,786		$	—
Total long-term liabilities	$	85,700,786		$	—

Asset Retirement Obligation	5,536,182			—
Fair value of derivatives	37,652,634			—
Total Liabilities	$	137,023,701		$	31,196,719

Redeemable Preferred stock - Series C, authorized 98,751.823 shares; $0.01 stated value, voting, redeemable at $0.01; 98,751.823 shares issued and outstanding at December 31, 2013 and none at June 30, 2013	$	988		$	—
Stockholders’ equity (deficit):
Preferred stock - $.01 par value; authorized 10,000,000 shares;
Preferred stock - 8% Series A, authorized 165,000 shares $100 stated value, voting, redeemable at $120, convertible at $1.20 per common share, canceled February 2014	$	—		$	1,181
Additional paid-in capital - Preferred Stock - Series A (see Note D)	—			11,810,119
Preferred stock - 9.5% Series B, authorized 35,000 shares $1,000 stated value, voting, convertible at $0.50 per common share; with 16,162 outstanding at December 31, 2013 and none at June 30, 2013	162			—
Additional paid-in capital - Preferred Stock - Series B (see Note D)	15,112,624			—
Common stock - $.05 par value; authorized 120,000,000 shares; issued and outstanding 77,505,908 shares at December 31, 2013 and 77,360,908 shares at June 30, 2013	3,875,295			3,868,047
Additional paid-in capital - Common Stock	63,730,455			56,910,545
Accumulated deficit	(79,052,339		)	(85,757,066		)
Total stockholders’ equity (deficit)	3,666,197			(13,167,174		)
	$	140,690,886		$	18,029,545

The accompanying notes are an integral part of these statements.

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CUBIC ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

	Three months ended						Six months ended
	December 31,						December 31,
	2013			2012			2013			2012
Revenues:
Oil and gas sales	$	5,047,665		$	1,039,376		$	5,914,367		$	2,043,036
Total revenues	$	5,047,665		$	1,039,376		$	5,914,367		$	2,043,036
Costs and expenses:
Oil and gas production, operating and development costs	2,987,880			453,787			3,303,508			1,253,315
Accretion of asset retirement obligations	86,928			—			86,928			—
General and administrative expenses	1,301,515			488,812			2,509,342			1,018,759
Depreciation, depletion and non-loan-related amortization	2,349,589			833,318			3,041,442			1,786,808
Total operating costs and expenses	6,725,912			1,775,917			8,941,220			4,058,882
Operating income (loss)	(1,678,247		)	(736,541		)	(3,026,853		)	(2,015,846		)
Non-operating income (expense):
Other income	5,485			665,519			5,494			665,538
Interest expense, including amortization of loan discount	(3,429,784		)	(368,564		)	(4,690,443		)	(852,163		)
Loss on derivatives	(6,913,622		)	—			(6,913,622		)	—
Gain on acquisition of assets at fair market value	22,238,000			—			22,238,000			—
Amortization of loan costs	(286,264		)	—			(286,264		)	—
Total non-operating expense	11,613,815			296,955			10,353,165			(186,625		)
Income (loss) before income taxes	9,935,568			(439,586		)	7,326,312			(2,202,471		)
Provision for income taxes	—			—			—			—
Net income (loss)	$	9,935,568		$	(439,586	)	$	7,326,312		$	(2,202,471	)
Dividends on preferred shares	(378,589		)	(228,900		)	(621,589		)	(453,300		)
Net income (loss) available to common stockholders	$	9,556,979		$	(668,486	)	$	6,704,723		$	(2,655,771	)
Net income (loss) per common share
Basic	$	0.12		$	(0.01	)	$	0.09		$	(0.03	)
Diluted	$	0.05		(0.01		)	$	0.05		(0.03		)
Weighted average common shares outstanding
Basic	77,500,392			77,215,908			77,466,112			77,215,908
Diluted	177,837,631			77,215,908			136,593,431			77,215,908

The accompanying notes are an integral part of these statements.

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CUBIC ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six months ended
	December 31,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	7,326,312		$	(2,202,471	)
Adjustments to reconcile net (loss) to cash provided (used) by operating activities:
Depreciation, depletion and amortization	3,617,165			1,786,808
Gain on acquisition of assets at fair market value	(22,238,000		)
Unrealized loss on derivative contracts	6,847,088			—
Stock issued for compensation	50,748			17,366
Change in assets and liabilities:
(Increase) decrease in accounts receivable - trade	(2,954,363		)	1,878,716
(Increase) decrease in other prepaid expenses	(387,962		)	1,089
Increase (decrease) in accounts payable and accrued liabilities	2,225,472			(704,507		)
Increase (decrease) in due to affiliates	557,420			(29,674		)
Net cash provided (used) by operating activities	$	(4,956,120	)	$	747,327
Cash flows from investing activities:
Acquisition and development of oil and gas properties	(9,906,102		)	(211,609		)
Prepaid drilling costs	(2,964,342		)	—
Increase (decrease) in capital portion of due to affiliates	—			1,602
Purchase of office equipment	(7,260		)	(1,807		)
Decrease (increase) in deposit on proposed acquisitions	2,300,000			—
Reimbursement of advances on development costs	—			10,079,583
Net cash paid for acquisitions of properties	(59,581,284		)	—
Net cash provided (used) by investing activities	$	(70,158,988	)	$	9,867,769
Cash flows from financing activities:
Proceeds from long-term debt	71,418,321			—
Proceeds from derivative contracts	35,091,536
Increase in restricted cash	(5,000,000		)
Repayment of advances from affiliates	(2,000,000		)	—
Payment of long-term debt	(5,000,000		)	(9,134,890		)
Loan costs incurred and other	(4,380,663		)	—
Net cash provided (used) by financing activities	$	90,129,194		$	(9,134,890	)
Net increase (decrease) in cash and cash equivalents	$	15,014,086		$	1,480,206
Cash and cash equivalents:
Beginning of period	260,576			275,527
End of period	$	15,274,662		$	1,755,733
Other information:
Cash interest paid on debt	$	3,730,961		$	844,317
Non-cash investing and financing activities:
Issuance of preferred stock in connection with acquisition of properties		708,000			—
Note payable and accrued interest due to affiliate converted to preferred stock	2,114,986			—
Increase in prepaid drilling credit for acquisition and development of oil and gas properties	—			562,325
Fair value of warrants issued in connection with debt	7,107,686			—
Fair value of change in warrant exercise price	56,244
Forgiveness of accrued dividends	243,000
Preferred stock dividends accrued	621,589			453,300
Conversion of accrued dividend to preferred stock	235,500			217,100

The accompanying notes are an integral part of these statements.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

Note A — Organization:

Cubic Energy, Inc., a Texas corporation (the “Company” or “Cubic”), has two wholly owned direct subsidiaries (Cubic Asset Holding, LLC, a Delaware limited liability company (“Cubic Asset Holding”), and Cubic Louisiana Holding, LLC, a Delaware limited liability company (“Cubic Louisiana Holding”)) and two wholly owned indirect subsidiaries (Cubic Asset LLC, a Delaware limited liability company and a direct subsidiary of Cubic Asset Holding (“Cubic Asset”), and Cubic Louisiana, LLC, a Delaware limited liability company and a direct subsidiary of Cubic Louisiana Holding (“Cubic Louisiana”)). Except where otherwise indicated, references to the Company or Cubic include its subsidiaries. The Company is an independent, upstream energy company engaged in the development and production of, and exploration for, crude oil and natural gas. The Company’s oil and gas assets and activities are concentrated in Louisiana and Texas.

The Company’s corporate strategy with respect to its asset acquisition and development efforts is to position the Company in low risk opportunities while building mainstream high yield reserves. The acquisition of its legacy acreage in DeSoto and Caddo Parishes, managed by Cubic Louisiana, put the Company in a reservoir rich environment in the Hosston, Cotton Valley and Bossier/Haynesville Shale formations, with additional shallow formations to exploit as well. The Company has had success on this acreage with wells drilled, achieving production from the Hosston formation, the Cotton Valley formation and the Bossier/Haynesville Shale formation. The Company’s bolt-on working interests in DeSoto and Caddo Parishes, managed by Cubic Asset, expand the Company’s investment in this environment.

The Company’s recent acquisition of acreage in Leon and Robertson Counties, Texas, puts the Company in the additional reservoir rich environments in the Bossier, Eagle Ford, Woodbine, Austin Chalk, Buda, Glen Rose and Georgetown formations, with additional shallow formations to exploit as well.

Note B — Acquisition of Properties

Acquisition of Properties from Gastar

On October 2, 2013, the Company consummated the transactions contemplated by the Purchase and Sale Agreement dated as of April 19, 2013 (the “Gastar Agreement”) with Gastar Exploration Texas, LP (“Gastar”) and Gastar Exploration USA, Inc. Pursuant to the Gastar Agreement, the Company acquired proved reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The acquired properties include approximately 17,400 net acres of leasehold interests. The acquisition price paid by the Company at closing was $39,118,830, following various adjustments set forth in the Gastar Agreement, and net of the various deposits paid prior to the closing date. For purposes of allocating revenues and expenses and capital costs between Gastar and us, such amounts we netted effective January 1, 2013 and have been recorded as an adjustment to the purchase price.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

Acquisition of Properties from Navasota

On September 27, 2013, the Company entered into a Purchase and Sale Agreement (the “Navasota Agreement”) with Navasota Resources Ltd., LLP (“Navasota”). On October 2, 2013, pursuant to the Navasota Agreement, the Company acquired proved reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The leasehold interests acquired from Navasota generally consist of additional fractional interests in the properties acquired pursuant to the Gastar Agreement, comprising approximately 6,400 net acres. The acquisition price paid by the Company was $19,400,000, prior to certain post-closing adjustments.

Acquisition of Properties from Tauren

The Company entered into and consummated the transactions contemplated by a Purchase and Sale Agreement dated as of October 2, 2013 (the “Tauren Agreement”) with Tauren Exploration, Inc. (“Tauren”), an entity controlled by Calvin A. Wallen, III, the Chairman of the Board, President and Chief Executive Officer of the Company. Pursuant to the Tauren Agreement, the Company acquired well bores, proved reserves, oil & natural gas production and undeveloped leasehold interests in the Cotton Valley formation in DeSoto and Caddo Parishes, Louisiana. The acquired properties include approximately 5,600 net acres of leasehold interests. The acquisition price paid by the Company was $4,000,000 in cash and 2,000 shares of the Company’s Series B Convertible Preferred Stock with an aggregate fair market value of $708,000 and a stated value of $2,000,000. The Tauren Agreement was unanimously approved by the Company’s board of directors, excluding Mr. Wallen. This transaction resulted in a $22,238,000 bargain purchase gain for the Company that was recorded in the statement of operations for the quarter ended December 31, 2013.

			Gastar Acquired		Navasota Acquired		Tauren Acquired
Purchase Price Allocation - ($000’s)	Total		Properties		Properties		Properties
Assets acquired:
Unproved oil and natural gas properties	$	7,101	$	6,029	$	1,072	$	—
Proved developed and undeveloped oil and natural gas properties		87,873		42,098	18,829		26,946
Liabilities assumed:
Asset retirement obligations	5,450		4,290		1,160		—
Net assets acquired	$	89,524	$	43,837	$	18,741	$	26,946

*Pro forma Results of Operations

	Six Months				Three Months
	Ended December 31,				Ended December 31,
	2013		2012		2012
Oil and natural gas revenues	$	9,784,896	$	10,779,630	$	5,189,674
Net income (loss)	$	6,523,733	$	3,222,422	$	2,382,030
Basic earnings (loss) per share	$	0.08	$	0.04	$	0.03
Diluted earnings (loss) per share	$	0.05	$	0.04	$	0.03

* Pro forma Results of Operations include direct revenues and expenses from all acquired properties (i.e. Gastar, Navasota and Tauren), and revenues and net loss for Cubic during the respective periods.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. The Company's assessment of the fair value of the properties acquired from Tauren, along with consideration of data prepared by third party, resulted in a fair market valuation of $26,946,000. As a result of incorporating the valuation information into the purchase price allocation, a bargain purchase gain of $22,238,000 was recognized. Because the fair market value of the acquired properties was determined to be in excess of the consideration paid, in accordance with the provisions of ASC 805-30-25-4, the Company reassessed whether it had fully identified all of the assets and liabilities obtained in the acquisition. Further, it instructed certain of its advisors to do the same. As part of its reassessment, the Company also reevaluated the consideration transferred and whether there were any non-controlling interests in the acquired property. No additional assets or liabilities were identified. The consideration transferred consisted of cash and preferred stock; no additional consideration was given, including any such consideration as contemplated by ASC 805-30-30-7. The Company had a valuation of the preferred stock performed by our advisors. It revisited the terms, assumptions and conditions used in that valuation and found that the preferred stock was appropriately valued. The Company also determined that there were no non-controlling interests in the acquired property. The bargain purchase gain was primarily attributable to the non-strategic nature of the divestiture to the seller, coupled with favorable economic trends in the industry and the geographic region in which the acquired properties are located. The Company believes the estimates used in the fair market valuation and purchase price allocation are reasonable and that the significant effects of the acquisition are properly reflected.

Note C — Summary of Significant Account Policies:

Basis of presentation

The accounting policies followed by the Company are set forth in the Company’s financial statements that are a part of its Annual Report on Form 10-K for the fiscal year ended June 30, 2013 and should be read in conjunction with the financial statements contained herein.

The financial information included herein as of December 31, 2013, and for the three and six month periods ended December 31, 2013, and 2012, are unaudited, pursuant to accounting principles for interim financial information generally accepted in the United States of America, and the rules of the Securities and Exchange Commission.

The Company believes that the disclosures are adequate to make the information presented not misleading. The information presented reflects all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair statement of results for the periods.

Earnings per share

The Company has adopted the provisions of Financial Accounting Standards Board, Accounting Standards Codification (“FASB ASC”) 260, “Earnings per Share”. FASB ASC 260 reporting requirements replace primary and fully-diluted earnings per share (“EPS”) with basic and diluted EPS. Basic EPS is calculated by dividing net income (available to common stockholders) by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

Potential dilutive securities (e.g., convertible preferred stock, stock warrants and convertible debt) have been considered, but the Company reported net losses for the three and six month periods ended December 31, 2012, and, accordingly, their effects would be anti-dilutive. See the table below for a reconciliation of basic and diluted earnings per share.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

	For the three months ended December 31, 2013			For the six months ended December 31, 2013
	Income	Shares	Per-Share	Income	Shares	Per-Share
	(Numerator)	(Denominator)	Amount	(Numerator)	(Denominator)	Amount

Income available to common shareholders - basic earnings per share	9,556,979	77,500,392	0.12	6,704,723	77,466,112	0.09

Effect of dilutive securities
Warrants	—	68,013,239		—	35,423,286
Convertible debt	719	—		66,883	2,522,450
Convertible preferred	—	32,324,000		243,000	21,181,583

Income available to common shareholders - diluted earnings per share	9,557,698	177,837,631	0.05	7,014,606	136,593,431	0.05

Note D — Stockholders’ Equity:

Stock issuances

In August 2009, the Company entered into Subscription and Registration Rights Agreements with certain investors pursuant to which the Company issued an aggregate of 2,104,001 shares of common stock and warrants exercisable into 1,052,000 shares of common stock. The remaining unexercised warrants are currently exercisable into 787,294 shares of common stock at $0.8389 per share and expire July 31, 2014.

Preferred Stock

The Company’s board has the power, without further vote of shareholders, to authorize the issuance of up to 10,000,000 shares of preferred stock and to fix and determine the terms, limitations and relative rights and preferences of any shares of the preferred stock. This power includes the authority to establish voting, dividend, redemption, conversion, liquidation and other rights of any such shares. The preferred stock may be divided into such number of series as the board determines.

As of December 31, 2013, the board of directors has established three series of preferred stock:

Series A Convertible Preferred Stock — The Series A Convertible Preferred Stock has a stated value of $100 per share, was entitled to dividends in the amount of 8% per annum, was convertible into the common stock at $1.20 per share of common stock and was redeemable by the Company at $120 per share. All Series A convertible preferred stock is due to be canceled in February 2014.

Series B Convertible Preferred Stock — The Series B Convertible Preferred Stock has a stated value of $1,000 per share, is entitled to dividends in the amount of 9.5% per annum and is convertible into our common stock at $0.50 per share of common stock. The holders of the Series B Convertible Preferred Stock are entitled to vote (on an as-converted basis), together with holders of common stock, as a single class with respect to all matters presented to holders of common stock. As of December 31, 2013, there were 16,162 shares of Series B Convertible Preferred Stock outstanding.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

Series C Redeemable Voting Preferred Stock — The Series C Redeemable Voting Preferred Stock has a stated value of $0.01 per share. The holders of Series C Voting Preferred Stock are entitled to vote, together with the holders of our common stock, as a single class with respect to all matters presented to holders of common stock. The holders of Series C Redeemable Voting Preferred Stock are entitled, in the aggregate, to a number of votes equal to the number of shares of common stock that would be issuable upon the exercise of all of the outstanding Class A Warrants and Class B Warrants (as defined below) on a Full Physical Settlement basis (as defined in the Warrant and Preferred Stock Agreement). The holders of Series C Redeemable Voting Preferred Stock are not entitled to receive any dividends. The Series C Redeemable Voting Preferred Stock may be redeemed at the option of the holders thereof at any time at the stated value per share. There were 98,751.823 shares of Series C preferred stock issued and outstanding as of December 31, 2013.

On November 24, 2009, the Company entered into transactions with Tauren and Langtry Mineral & Development, LLC (“Langtry”), both of which are entities controlled by Calvin A. Wallen III, the Chief Executive Officer of the Company, under which the Company acquired $30,952,810 in pre-paid drilling credits (the “Drilling Credits”) applicable towards the development of its Haynesville Shale rights in Northwest Louisiana through wells drilled by EXCO Operating Company, LP (“EXCO”) and BG US Production Company, LLC (“BG”).

As consideration for the Drilling Credits, the Company (a) conveyed to Tauren a net overriding royalty interest of approximately 2% in its leasehold rights below the Taylor Sand formation of the Cotton Valley and (b) issued to Langtry 10,350,000 shares of Company common stock and 103,500 shares of Series A preferred stock. Through October 2, 2013, the Company had issued 16,968 additional shares of preferred stock in lieu of dividends, totaling 120,468 shares owned by Langtry. All of the Series A Convertible Preferred Stock were converted into 12,047 shares of Series B Convertible Preferred Stock.

The consideration with respect to the transactions among the Company, Tauren and Langtry was determined pursuant to negotiations among the Company, Tauren and Langtry, and not pursuant to any formula. These transactions were approved by a special committee of the board of directors of the Company comprised exclusively of the Company’s non-employee directors.

Conversion of Wallen Note and Series A Convertible Preferred Stock into Series B Convertible Preferred Stock

The Company entered into and consummated the transactions contemplated by a Conversion and Preferred Stock Purchase Agreement dated as of October 2, 2013 with Mr. Wallen and Langtry (the “Conversion Agreement”). Pursuant to the terms of the Conversion Agreement, (a) Langtry was issued 12,047 shares of Series B Convertible Preferred Stock, with an aggregate stated value of $12,047,000, in exchange for the cancellation of all of the issued and outstanding shares of Series A preferred stock held by Langtry and (b) Mr. Wallen was issued 2,115 shares of Series B preferred stock, with an aggregate stated value of $2,115,000, in exchange for the cancellation of the Wallen Note and accrued interest (See Note F). No gain or loss was recognized as a result of the conversion, based on a third-party fairness opinion that was approved by the board of directors.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

The risk-free interest rate is based on the U.S. Treasury bill rate in effect at the time of grant with an equivalent expected term or life. Information regarding activity for stock options under the Plan is as follows:

		Weighted-average		Weighted-average	Aggregate
		exercise price per		remaining contractual	intrinsic
	Number of shares	share		term (years)	value

Outstanding, June 30, 2013	288,667	$	1.20
Options granted	—	—
Options exercised	—	—
Options forfeited/expired	—	—

Outstanding, December 31, 2013	288,667	1.20		1.75	$	—

Exercisable, December 31, 2013	288,667	$	1.20	1.75	$	—

On October 1, 2013, the Company paid cash of $13,000 and issued 72,500 shares of common stock to four directors of the Company pursuant to the Plan. As of such date, the aggregate market value of the common stock granted was $27,550 based on the last sale price ($0.38 per share) on October 1, 2013, on the OTC Markets of the Company’s common stock. Such amount was expensed upon issuance to compensation expense.

Note E — Oil and Gas Properties:

The capitalized costs included in the full cost pool are subject to a “ceiling test”, which limits such costs to the aggregate of the estimated present value, using a ten percent discount rate, of the future net revenues from proved reserves, based on current economic and operating conditions plus the lower of cost and estimated net realizable value of unproven properties.

The Company recorded no impairment loss on oil and gas properties for the three or six months ended December 31, 2013 or 2012.

Note F — Long-term debt:

Senior Secured Notes Financing

The Company entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66.0 million of notes due October 2, 2016 (the “Notes”) to certain of the Investors. The Notes bear interest at the rate of 15.5% per annum, in cash, payable quarterly; provided, however, that interest for the first six months following the closing shall be paid 7.0% per annum in cash and 8.5% per annum in additional Notes. The indebtedness under the Note Purchase Agreement is secured by substantially all of the assets of the Company, including a first priority lien over all of the assets of the Company, Cubic Asset and Cubic Asset Holding and a second priority lien over all of the assets of Cubic Louisiana and Cubic Louisiana Holding. Under the Note Purchase Agreement as a liquidity covenant Cubic must maintain a $5,000,000 minimum cash balance through December 31, 2013 and, thereafter, $10,000,000 through October 2, 2016.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

The Company allocated the proceeds from the issuance of the Notes to the Warrants and the Notes, based on their relative fair market values at the date of issuance. The value assigned to the Class A Warrants was $5,627,861 and the value assigned to the Class B Warrants was $1,479,825, both of which were recorded as an increase in additional paid-in capital relating to common stock. The assignment of a fair value to the Warrants resulted in a loan discount being recorded. The discount will be amortized over the original three-year term of the Notes as additional interest expense. Amortization for the three and six months ended December 31, 2013 was $563,713. Because the Notes were issued on October 2, 2013, no amortization during the prior year periods was recorded.

Cubic incurred loan costs of $3,598,395 on the issuance of the Notes and Warrants. The amount allocable to the debt of $3,210,876 has been capitalized and will be amortized over the original term of the Notes. Amortization for the three and six months ended December 31, 2013 was $260,975. Because the Notes and the Warrants were issued on October 2, 2013, no amortization during the prior year periods was recorded.

Wells Fargo debt

On March 5, 2007, Cubic entered into a credit agreement with Wells Fargo Energy Capital, Inc. (“WFEC”) providing for a revolving credit facility of $20,000,000 (the “Revolving Note”) and a convertible term loan of $5,000,000 (the “Term Loan”; and together with the Revolving Note, the “Credit Facility”). Subsequently, the Revolving Note was increased to $40 million. The indebtedness bore interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, was originally scheduled to mature on March 1, 2010, subsequently extended to October 2, 2013, and was secured by substantially all of the assets of the Company.

Contemporaneously with entering into the Note Purchase Agreement, the Company repaid the $5 million Term Loan payable to WFEC, and Cubic Louisiana assumed the remaining unpaid debt to WFEC, which amount was $20,865,110 as of that date. That debt is reflected in a term loan bearing interest at the Wells Fargo Bank prime rate, plus 2%, per annum, due October 2, 2016. In the event that Cubic Louisiana does not have available cash to pay interest on the Credit Facility, accrued and unpaid interest will be paid in kind via an additional promissory note. As part of the new credit agreement, WFEC is providing a revolving credit facility in the amount of up to $10,000,000, bearing interest at the same rate, with all advances under that revolving credit facility to be made in the sole discretion of WFEC. During the quarter ended December 31, 2013, the Company borrowed $4,015,826 under the revolving credit facility for two new natural gas wells to be drilled and completed by EXCO, leaving $5,984,174 available for future borrowing. Interest expense for the quarters ended December 31, 2013 and 2012 was $276,825 and $368,563, respectively, and for the six-months ended December 31, 2013 and 2012 it was $619,094 and $808,726, respectively.

December 2009 subordinated debt issue and refinancing

On December 18, 2009, the Company issued a subordinated promissory note (the “Wallen Note”) payable to Mr. Wallen, the Company’s Chairman of the Board and Chief Executive Officer, in the principal amount of $2,000,000 which was subordinated to all WFEC indebtedness. The Wallen Note bore interest at the prime rate plus one percent (1%), and originally provided for interest payable monthly. The proceeds of the Wallen Note were used to repay other indebtedness to the Company. The Wallen Note was converted into shares of Series B preferred stock on October 2, 2013.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

·	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

·	Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

·	Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge natural gas, oil and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets.

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2013 and 2012 periods.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013:

	Fair value as of December 31, 2013
	Level 1		Level 2		Level 3			Total
	(in thousands)
Assets:
Liabilities:
Commodity derivative contracts	—		—		(41,646		)	—
Total	$	—	$	—	$	(41,646	)	$	—

The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. (See Note H).

Note H — Derivative Instruments and Hedging Activity

From time to time, we utilize commodity derivatives to attempt to reduce exposure to fluctuations in the price of crude oil and natural gas. A description of the Company’s derivative financial instruments is provided below:

Fixed price swaps		The Company receives a fixed price for the contract and pays a floating market price to the counterparty.

Fixed price call options		The Company sells fixed price call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, the Company pays the counterparty such excess on sold fixed price call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Call Option Structured Derivative arrangement with a third party that resulted in the receipt of an upfront payment at closing of approximately $35,000,000, through the sale of calls, which upfront payment approximated fair value of the calls sold at inception. As a result, the Call Option Structured Derivative arrangement was initially recognized and measured at the amount of its upfront payment. Under the terms of the Call Option Structured Derivative arrangement, Cubic Asset sold calls to the third party covering (i) approximately 556,000 barrels of oil at a strike price set between $80 per barrel and $90 per barrel, and (ii) approximately 51.3 million MMBtu’s of gas at a strike price set between $3.45 per MMBtu and $3.90 per MMBtu. The scheduled volumes subject to the calls sold relate to production months from November 2013 through December 2018. The Company is subject to the price risks associated with product price changes that differ from the specified call prices. If the market price during the applicable production month is above the applicable strike price, Cubic Asset would be required to pay the third party the difference between the market price and strike price for the amount of production subject to the call. This arrangement does not hedge the Company’s risk associated with product price decreases.

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

On October 2, 2013, the Company, through its subsidiary Cubic Asset, entered into a Fixed Price Swap arrangement. Under the terms of the Fixed Price Swap arrangement, Cubic Asset sold calls to a third party covering approximately 18,000 barrels of oil at a price of $92 per barrel. The scheduled volumes subject to the calls sold relate to production months from November 2013 through October 2016. Cubic Asset is subject to the price risks associated with product price increases above the specified fixed prices. This third parties have a junior lien position on both of the assets of Cubic Asset and Cubic Louisiana. Cubic Asset is using swaps to hedge some of its natural gas production. Cubic Asset receives the fixed price and pays the third party the floating market price during the applicable production month for the amount of production subject to the call

All derivative contracts are carried at their fair value on the balance sheet and all unrealized gains and losses as well as realized gains and losses related to contract settlements are presented in the statement of operations as a gain or (loss) on derivatives. For the three and six months ended December 31, 2013, the Company reported a net loss of $6,913,622 in the condensed consolidated statement of operations related to its commodity derivative instruments.

As of December 31, 2013, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Strike Price
		In MMBtu
2014	Call Option	10,000	9,733,236	$	3.90
2015	Call Option	15,000	10,696,392	$	3.70
2016	Call Option	20,000	11,056,752	$	3.65
2017	Call Option	25,000	11,184,600	$	3.55
2018	Call Option	25,000	8,252,340	$	3.45

As of December 31, 2013, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices:

Settlement Period	Derivative Instrument	Average Daily Volume	Total of Notional Volume	Strike Price
		In Bbls
2014	Fixed Price Swap	23	8,268	$	92.00
2015	Fixed Price Swap	15	5,532	$	92.00
2016	Fixed Price Swap	8	2,900	$	92.00

2014	Call Option	289	105,624	$	90.00
2015	Call Option	312	113,952	$	80.00
2016	Call Option	361	131,796	$	80.00
2017	Call Option	328	119,868	$	80.00
2018	Call Option	218	79,452	$	80.00

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

Oil derivatives. Our oil derivatives are swap and call option contracts for notional Bbls of oil at interval NYMEX oil index prices. The asset and liability values attributable to our oil derivatives as of the end of the reporting period are based on (i) the contracted notional volumes, (ii) independent active NYMEX future quotes for oil index prices, (iii) the applicable estimated credit-adjusted risk free rate curve, and (iv) the implied rate of volatility inherent in the swap and call option contracts. The implied rates of volatility were determined based on average NYMEX oil index prices.

Natural gas derivatives. Our natural gas derivatives are option contracts for notional MMBtu of natural gas at NYMEX Penultimate index prices. The asset and liability values attributable to our natural gas derivatives as of the reporting period are based on (i) the contracted notional volumes and (ii) the applicable credit-adjusted risk-free rate curve and implied rate of volatility inherent in the call option contracts.

Additional Disclosures about Derivative Instruments and Hedging Activities

The tables below provide information on the location and amounts of derivative fair values in the condensed consolidated balance sheet and derivative gains and losses in the condensed consolidated statement of operations for derivative instruments that are not designated as hedging instruments:

	Fair Values of Derivative Instruments
	Derivative Assets(Liabilities)
		Fair Value
	Balance Sheet Location	December 31, 2013			December 31, 2012
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Assets	$	—		$	—
Commodity derivative contracts	Current Liabilities	(3,993		)	—
Commodity derivative contracts	Long-term Liabilities	(37,653		)	—
Total derivatives not designated as hedging instruments		$	(41,646	)	$	—

	Amount of Gain (Loss) Recognized in Income on Derivatives
	Location of Gain (Loss)	Amount of Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended
	Recoginized in Income of Derivatives	December 31, 2013			December 31, 2012
		(in thousands)
Derivatives not designated as hedging instruments
Commodity derivative contracts	Loss on derivatives	$	(6,913	)	$	—
Total derivatives not designated as hedging instruments		$	(6,913	)	$	—

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

(in thousands, except prices)	Volume Mmbtus/Bbls (in thousands)	Fair Value per MMBtu / Bbl			Fair value at December 31, 2013 (in thousands)
Natural gas:

Call Options:
2014	9,733	$	0.35		$	3,432
2015	10,696	$	0.61		$	6,541
2016	11,057	$	0.71		$	7,805
2017	11,185	$	0.84		$	9,421
2018	8,252	$	1.04		$	8,588
Total natural gas					$	35,787

Oil:
Swaps:
2014	8,268	4.55			$	38
2015	5,532	(3.14		)	$	(17	)
2016	2,900	(7.50		)	$	(21	)

Call Options:
2014	106	$	5.31		$	561
2015	114	$	10.91		$	1,244
2016	132	$	11.75		$	1,549
2017	120	$	12.23		$	1,467
2018	79	$	13.07		$	1,038
Total oil					$	5,859
Total oil and natural gas derivatives					$	41,646

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CUBIC ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2013

(Unaudited)

Note I — Asset Retirement Obligations

We record asset retirement obligations (“ARO”) associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO liability. The fair value of the asset retirement cost and the ARO liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.

The following table reflects the assumed ARO liability from the acquisition of assets, on October 2, 2013 for the six months ended December 31, 2013:

Asset retirement obligations, at June 30, 2013	$	—
Activity during the period:	—
Liabilities incurred during the period	—
Liabilities settled during the period	—
Adjustment to liability due to acquisitions	5,449,254
Adjustment to liability due to divestitures	—
Accretion of discount	86,928
Asset retirement obligations, at December 31, 2013	5,536,182
Less current portion	—
Long-term portion	$	5,536,182

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion of operations for the three and six months ended December 31, 2013 and 2012 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, 2013.

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 acreage is held in two wholly owned indirect subsidiaries, Cubic Louisiana, LLC, a direct subsidiary of Cubic Louisiana Holding, LLC, which holds our legacy Louisiana acreage, and Cubic Asset, LLC, a direct subsidiary of Cubic Asset Holding, LLC, which holds our newly acquired Texas acreage, our legacy Texas acreage and bolt-on working interests in our Louisiana acreage. Our oil and gas assets and activities are concentrated exclusively in Louisiana and Texas.

Legacy Louisiana Acreage

The Company’s corporate strategy with respect to its asset acquisition and development efforts is to position the Company in low risk opportunities while building mainstream high yield reserves. The acquisition of its legacy acreage in DeSoto and Caddo Parishes, managed by Cubic Louisiana, put the Company in reservoir rich environment in the Hosston, Cotton Valley and Bossier/Haynesville Shale formations, with additional shallow formations to exploit as well. The Company has had success on its acreage with wells drilled achieving production from the Hosston formation, the Cotton Valley formation and the Bossier/Haynesville Shale formation.

We share our Bossier/Haynesville formation acreage with Goodrich Petroleum Corporation (“Goodrich”), Chesapeake Energy Corporation (“Chesapeake”), Petrohawk Energy Corporation (“Petrohawk”), EP Energy E&P Company, L.P. (“El Paso”), BG US Production Company, LLC (“BG”), EXCO Operating Company, LP (“EXCO”) and Indigo Minerals, LLC (“Indigo Minerals”), several if which are actively working on parts of our shared acreage. As a result of this activity, we saw improved production volumes in two of the last three fiscal years. However due to lower natural gas prices and depleting production volumes, there was a decrease in production volumes during fiscal 2013.

Legacy Texas Acreage

Our legacy Texas properties are situated in Eastland and Callahan Counties. These 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.

Newly Acquired Texas Acreage and Louisiana Working Interests

Our recent acquisition of acreage in Leon and Robertson Counties, Texas, along with the bolt-on working interests acquired in our legacy DeSoto and Caddo Parishes, Louisiana properties, managed through Cubic Asset, puts us in the additional reservoir rich environments in the Bossier, Eagle Ford, Woodbine, Austin Chalk, Buda, Glen Rose and Georgetown formations, with additional shallow formations to exploit as well. We have seen success on our acquired acreage and Louisiana legacy acreage with wells drilled by achieving production from the Bossier formation.

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The legacy Texas acreage is operated by Fossil Operating, Inc. (“Fossil”), an entity controlled by Calvin A. Wallen, our Chairman of the Board and Chief Executive Officer.

Results of Operations

For the Three Months ended December31, 2013 and 2012

	Three months ended
	December 31,
	2013		2012
Production Volumes:
Oil (Bbl)	4,132		264
Natural gas liquids (Bbl)	874		303
Natural gas (Mcf)	1,291,844		306,729
Total (Mcfe)	1,321,879		310,132

Weighted Average Sales Prices:
Oil (per Bbl)	$	91.76	$	83.85
Natural gas liquids (Bbl)	$	44.10	$	55.86
Natural gas (per Mcf)	$	3.36	$	3.26

Selected Expenses per Mcfe:
Production costs	$	0.91	$	0.83
Workover expenses (non-recurring)	$	0.09	$	0.05
Severance taxes	$	0.03	$	0.05
Other revenue deductions	$	1.23	$	0.52
Total lease operating expenses	$	2.25	$	1.45
General and administrative expenses	$	0.98	$	1.58
Depreciation, depletion and amortization	$	1.78	$	2.69

Revenues

OIL AND GAS SALES increased 386% to $5,047,665 for the quarter ended December 31, 2013 from $1,039,376 for the quarter ended December 31, 2012 primarily due to increased oil and gas volumes resulting from the acquisitions during the 2013 quarter. We received an average natural gas price of $3.36 per Mcf in the 2013 quarter versus $3.26 in the 2012 quarter.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS increased 558% to $2,987,880 (56% of oil and gas sales) for 2013 from $453,787 (44% of oil and gas sales) for 2012, primarily due to the expenses incurred from the increased number of wells brought online post-acquisition during the 2013 quarter. Other revenue deduction expenses increased $1,460,440. These are costs passed-through to the Company by the purchaser of the Company’s gas. Such costs are deducted from the Company’s gross revenue by the purchaser and include, but are not limited to: costs to market the Company’s gas, compression fees, and the cost of fuel used by the purchaser to convey the Company’s gas; lease operating expense increased $945,554, workovers expenses increased $96,573, and production taxes increased $25,121.

GENERAL AND ADMINISTRATIVE EXPENSES increased 166% to $1,301,515 for 2013 from $488,812 in 2012, primarily due to an increase of $334,787 in legal fees/expenses, a $163,458 increase in consulting and management fees, a $90,367 increase in cash compensation (due to new hires) and a $97,303 increase in contracted professional services, directly related to the Company’s acquisitions and debt restructuring efforts, during the three months ended December 31, 2013 as compared to the 2012 quarter.

DEPRECIATION, DEPLETION AND NON-LOAN RELATED AMORTIZATION increased 182% to $2,349,589 in 2013 from $833,318 in 2012. The increase was primarily due to the $90,037,491 increase in the full cost pool due to the acquisitions during the three months ended December 31, 2013 as compared to December 31, 2012.

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INTEREST EXPENSE increased 831% to $3,429,784 in 2013 from $368,564 in 2012 primarily due to interest incurred on the Notes issued on October 2, 2013, as well as interest on borrowings from WFEC. The Company’s total debt (net of discounts) is $85,700,786 for the 2013 quarter from $28,361,571 for the 2012 quarter.

For the Six Months ended December 31, 2013 and 2012

	Six months ended
	December 31,
	2013		2012
Production Volumes:
Oil (Bbl)	4,272		375
Natural gas liquids (Bbl)	1,366		455
Natural gas (Mcf)	1,535,688		660,269
Total (Mcfe)	1,569,517		665,249

Weighted Average Sales Prices:
Oil (per Bbl)	$	92.14	$	85.09
Natural gas liquids (Bbl)	$	44.10	$	56.28
Natural gas (per Mcf)	$	3.37	$	3.01

Selected Expenses per Mcfe:
Production costs	$	0.87	$	0.68
Workover expenses (non-recurring)	$	0.07	$	0.06
Severance taxes	$	0.04	$	0.23
Other revenue deductions	$	1.13	$	0.91
Total lease operating expenses	$	2.09	$	1.87
General and administrative expenses	$	1.60	$	1.53
Depreciation, depletion and amortization	$	1.94	$	2.69

Revenues

OIL AND GAS SALES increased 189% to $5,914,367 for the six months ended December 31, 2013 from $2,043,036 for the six months ended December 31, 2012, primarily due to increased oil and gas volumes resulting from the acquisitions during the 2013 period versus the 2012 period. We received an average natural gas price of $3.37 per Mcf in the 2013 period versus $3.01 in the 2012 period.

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS increased 164% to $3,303,508 (56% of oil and gas sales) for 2013 from $1,253,315 (61% of oil and gas sales) for 2012, primarily due to the expenses recognized from the increased number of wells brought online post-acquisition during the six months ended December 31, 2013. Other revenue deduction expenses increased $1,165,624. These are costs passed-through to the Company by the purchaser of the Company’s gas. Such costs are deducted from the Company’s gross revenue by the purchaser and include, but are not limited to: costs to market the Company’s gas, compression fees, and the cost of fuel used by the purchaser to convey the Company’s gas. Lease operating expense increased $928,929, and workover expenses increased $70,412, but were partially offset by a $94,453 decrease in production taxes.

GENERAL AND ADMINISTRATIVE EXPENSES increased 373% to $2,509,342 for 2013 from $1,018,759 for 2012 primarily due to an increase of $636,582 in legal fees/expenses, a $463,458 increase in consulting and management fees, a $311,022 increase in cash compensation (due to new hires), and a $196,825 increase in contracted professional services, directly related to the Company’s acquisitions and debt restructuring efforts, during the six months ended December 31, 2013 as compared to the 2012 period.

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DEPRECIATION, DEPLETION AND AMORTIZATION increased 70% to $3,041,442 in 2013 from $1,786,808 in 2012. The increase was primarily due to the $90,037,491 increase in the full cost pool due to the acquisitions during the six months ended December 31, 2013 as compared to December 31, 2012.

INTEREST EXPENSE increased 450% to $4,690,443 in 2013 from $852,163 in 2012 primarily due to interest incurred on the Notes issued on October 2, 2013, as well as interest on borrowings from WFEC. The Company’s total debt (net of discounts) is $85,700,786 for the six months ended December 31, 2013 from $28,361,571 for the same 2012 period.

Capital Resources and Liquidity

Overview

The Company’s primary resource is its oil and gas reserves. Our strategy with respect to our domestic exploration program seeks to maintain a balanced portfolio of drilling opportunities that range from lower risk, field extension wells to the smaller scale pursuit of Company appropriate higher risk, high reserve potential prospects.

Our recent acquisition of East Texas Basin assets is at the core of our current strategy, providing lower risk development opportunities and high yield opportunities within the same property. The Company is exploring acquiring additional properties with this similar development profile.

Additionally, our focus is on exploration opportunities that can benefit from advanced technologies, including 3-D seismic, designed to reduce risks and increase success rates. We develop prospects in-house with an affiliate and through strategic alliances with exploration companies that have expertise in specific target areas. In addition, we evaluate externally generated prospects and look to participate in certain of these opportunities to enhance our portfolio.

We are currently focusing our domestic exploration activities to develop, re-enter, and re-complete existing well bores with respect to our recently acquired East Texas Basin assets; as well as developing our recently augmented leasehold interests in Louisiana. Our East Texas Basin prospects have been developed from the top of the Cretaceous formations all the way to the bottom of the Deep Bossier Shale. The various Cretaceous zones all have strong oil and liquids component that will help the Company achieve its transition away from dry natural gas. The high production of dry natural gas from the various Bossier sands has the opportunity to provide us a significant increase in short term cash flow without substantial out-of-pocket expenditures, even at current commodity prices, through the re-recompletion and work over of existing wells. Prospects in our Louisiana leaseholds are focused on the Cotton Valley and the Haynesville Shale, but also include the Hosston; Gloyd; Pettet; Glen Rose and Paluxy.

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 our borrowing capacity. Within the confines of product pricing, we need 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.

As a result of the acquisition of properties from Gastar Exploration Texas, LP (“Gastar”), we acquired proved reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The acquired properties include approximately 17,400 net acres of leasehold interests. The acquisition price paid by us at closing was $39,118,830, following various adjustments set forth in the purchase agreement with Gastar, and including the various deposits paid prior to the closing date.

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On September 27, 2013, the Company entered into a purchase agreement with Navasota Resources Ltd., LLP (“Navasota”). On October 2, 2013, pursuant to the Navasota Agreement, the Company acquired proved reserves, oil & natural gas production and undeveloped leasehold interests in Leon and Robertson Counties, Texas. The leasehold interests acquired from Navasota generally consist of additional fractional interests in the properties acquired pursuant to the Gastar Agreement, comprising approximately 6,400 net acres. The acquisition price paid by the Company was $19,400,000.

On October 2, 2013, the Company entered into a purchase agreement with Tauren Exploration, Inc. (“Tauren”). Pursuant to this agreement, the Company acquired well bores, proved reserves, oil & natural gas production and undeveloped leasehold interests in the Cotton Valley formation in DeSoto and Caddo Parishes, Louisiana. The acquired properties include approximately 5,600 net acres of leasehold interests. The acquisition price paid by the Company was $4,000,000 in cash and 2,000 shares of the Company’s Series B preferred stock with an aggregate stated value of $2,000,000 and a fair value of $708,000. The acquisition was valued at $26,946,000.

Working Capital and Capital Expenditures

Working capital as of December 31, 2013 was over $10 million, up from a working capital deficit of over $30 million at June 30, 2013, as a result of proceeds from the issuance of the Notes, Call Options and the refinancing of the WFEC debt. The debt to WFEC is now classified as long-term debt.

The Company entered into a Note Purchase Agreement dated October 2, 2013, pursuant to which the Company issued an aggregate of $66,000,000 (see Note F to the condensed consolidated financial statements) of senior secured notes due October 2, 2016, to certain purchasers. Pursuant to the terms of the Credit Agreement with WFEC, the Company repaid the $5 million term loan, and Cubic Louisiana assumed the remaining unpaid debt to WFEC, which amount was $20,865,110 as of that date. That debt is reflected in a term loan bearing interest at the Wells Fargo Bank prime rate, plus 2%, per annum and is due October 2, 2016. In the event that Cubic Louisiana does not have available cash to pay interest on the debt under the Credit Agreement, accrued and unpaid interest will be paid in kind via an additional promissory note. As part of the Credit Agreement, WFEC is providing a revolving credit facility in the amount of up to $10,000,000, bearing interest at the same rate, with all advances under that revolving credit facility to be made in the sole discretion of WFEC. Also on October 2, 2013, the Company entered into a Call Option Structured Derivative (see Note H to the condensed consolidated financial statements) that provided the Company approximately $35,000,000 and together with the proceeds from the issuance of the senior secured notes, a total of $101,000,000. These funds, net of amounts paid for the acquisition of the assets from Gastar, Navasota and Tauren, the repayment of the term loan payable to WFEC and various expenses relating to these transactions, are available for capital expenditures and working capital for operations.

On October 2, 2013, Mr. Wallen was issued 2,115 shares of Series B preferred stock, with an aggregate stated value of $2,115,000, in exchange for the cancellation of a promissory note payable to Mr. Wallen in the principal amount of $2,000,000, plus $114,986 of accrued and unpaid interest.

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 $45,000,000 and a maximum of approximately $60,000,000 will be made to further develop our reserves during fiscal 2014 and for exploratory drilling on our undeveloped acreage. The Company may increase its planned activities for fiscal 2014, if the Company acquires additional oil or natural gas properties. The new Texas acreage is approximately 99% operated by Fossil and approximately 1% operated by Indigo on Cotton Valley wells.

No assurance can be given that all or any of these anticipated or possible capital expenditures will be completed as currently anticipated. Any material acquisition of additional leaseholds would require that we obtain additional capital resources.

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The Company plans to fund its development and exploratory activities through cash on hand, cash provided from operations, and a possible disposition of assets, if needed, 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 funds generated through existing wells and cash on hand, we expect to be able to continue to pay our expenses as they come due.

If we are unable to obtain sufficient capital resources on a timely basis, the Company may need to curtail its planned development and exploratory activities. If a well is proposed by a third-party operator and the Company does not have 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.

Cash Flow

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

	Six months ended
	December 31,
	2013			2012
Net cash provided (used) by operating activities	$	(4,956,120	)	$	747,327
Net cash provided (used) by investing activities	(70,158,988		)	9,867,769
Net cash provided (used) by financing activities	90,129,194			(9,134,890		)
Net increase (decrease) in cash and cash equivalents	$	15,014,086		$	1,480,206

Operating Activities — During the six months ended December 31, 2013, the Company used cash flows from operating activities of $4,956,120 as compared to $747,327 of cash provided by 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, 2013, we had capital spending related to the development of oil and gas properties of $9,906,102 and incurred acquisition costs of $59,581,284 and total cash used of $70,158,988 by investing activities. 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.

Financing Activities — Net cash flows were $90,129,194 provided by, and $9,134,890 used in, financing activities during the six month periods ended December 31, 2013 and 2012, respectively.

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These funds provided by financing activities in the 2013 period were primarily related to the issuance of the Notes and the proceeds from entering into the volumetric production payment contract. 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.

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, 2013.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk

We are subject to price fluctuations for natural gas and crude oil. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Reductions in crude oil, natural gas and natural gas liquids prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis. Any reduction in reserves, including reductions due to price fluctuations, can adversely affect our liquidity and our ability to obtain capital for our acquisition and development activities. We entered into a Call Option Structured Derivative (see Note H) agreement that provided $35 million of the financing needed to consummate the transactions, on October 2, 2013. This was strictly a financing tool and not intended to manage the commodity price risk for any portion of our production. However, the Company faces a risk related to the strike prices of these call options, which were $3.65 per Mmbtu for the 2013 calendar year, $3.90 per Mmbtu for the 2014 calendar year, and a to be determined price for calendar years 2015 through 2018, for natural gas, and $80 per barrel for the 2013 calendar year, $90 per barrel for the 2014 calendar year, and a to be determined price for calendar years 2015 through 2018, for oil. If the call options are exercised because the commodity price is above the stated strike price, we would owe a third party the difference between the stated strike price and the actual selling price of the respective commodities. If the selling price is lower than our stated strike price, it is expected that the option would expire unexercised and we would not owe any amount to the third party.

Interest Rate Risk

As of December 31, 2013, we had an aggregate of $85,700,786 (net of discounts) of long-term debt outstanding under our Credit Facility with WFEC and the Notes. The WFEC revolving credit facility, with borrowings of $24,880,936, bears interest at the prime rate plus 2.0% and the Notes, in the aggregate principal amount of $66,000,000, bear interest rate of 15.5% (interest payments are comprised of 7% cash and 8.5% in additional Notes for the first six months from October 2, 2013, then interest payments are all cash), respectively. As a result, our interest costs fluctuate based on short-term interest rates. Based on the aforementioned WFEC borrowings outstanding at December 31, 2013, a 100 basis point change in interest rates would change our annual interest expense by approximately $248,809. We had no interest rate derivatives during the second quarter of fiscal 2014.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

We are party to lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our financial position or results of operations. As of June 30, 2013, the majority of our acreage was in Northwest Louisiana and the legal climate in Northwest Louisiana has become increasingly hostile and litigious towards oil and gas companies. The majority of the properties recently acquired are in Texas, where the legal climate is also becoming more litigious towards oil and gas companies. Many mineral owners are seeking opportunities to make additional money from their mineral rights, including pursuit of claims of lease expiration by asserting that production does not exist in paying quantities. In the normal course of our business, title defects and lease issues of varying degrees will arise, and, if practicable, reasonable efforts will be made to cure any such defects and issues.

A lawsuit was filed on or about June 15, 2010, styled, “Gloria’s Ranch, LLC v. Tauren Exploration, Inc., Cubic Energy, Inc., Wells Fargo Energy Capital, Inc. & EXCO USA Asset, LLC”, filed in the 1st Judicial District Court, Caddo Parish, Louisiana, Cause No. 541-768, A. This lawsuit alleges that all or part of the Gloria’s Ranch mineral lease has lapsed, and seeks a finding that the mineral lease has lapsed, damages, attorney fees, and other equitable relief. This lawsuit would have a material effect, of a maximum of 3.6%, on the acreage position of the Company, as of December 31, 2013, if ultimately adjudicated entirely in favor of the mineral owner. The Company intends to vigorously defend its position and believes it will prevail regarding some, if not all, of the acreage at issue in this lawsuit.

Item 1A. Risk Factors

There have been material changes in the risk factors applicable to us from those disclosed in our Annual Report on Form 10-K for fiscal year ended June 30, 2013.

Our stock is categorized as a penny stock. Trading of our stock may be restricted by the SEC’s penny stock regulations which may limit a stockholder’s ability to buy and sell our stock.

Our stock is categorized as a “penny stock”. The SEC has adopted Rule 15g-9 which generally defines “penny stock” to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and accredited investors. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of our common stock.

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Item 6. Exhibits

No.	Description

15	*Letter Regarding Unaudited Interim Financial Information

31.1	*Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer

31.2	*Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer

32.1	*Certification of Chief Executive Officer pursuant to 18 U.S.C. § 1350

32.2	*Certification of Chief Financial Officer pursuant to 18 U.S.C. § 1350

101.INS**		XBRL Instance Document

101.SCH**		XBRL Taxonomy Extension Schema Document

101.CAL**		XBRL Taxonomy Calculation Linkbase Document

101.DEF**		XBRL Taxonomy Definition Linkbase Document

101.LAB**		XBRL Taxonomy Label Linkbase Document

101.PRE**		XBRL Taxonomy Presentation Linkbase Document

* Filed herewith.

** Furnished herewith. In accordance with Rule 406T of Regulation S-T, the information in these exhibits shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to liability under that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such filing.

	PHILIP VOGEL & CO., PC

	/s/ Philip Vogel & Co., PC
	Certified Public Accountants

Dallas, Texas
February 19, 2014

	CUBIC ENERGY, INC.
	(Registrant)


Date: May 9, 2014	By:	/s/ Calvin A. Wallen, III
		Calvin A. Wallen, III, President and Chief Executive Officer


Date: May 9, 2014	By:	/s/ Larry G. Badgley
		Larry G. Badgley, Vice President, Finance and Compliance (acting principal financial and accounting officer)

		Page

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Report of Independent Registered Public Accounting Firm		1

Condensed Consolidated Balance Sheets As of December 31, 2013 (unaudited) and June 30, 2013		2

Condensed Consolidated Statements of Operations (unaudited) For the three and six months ended December 31, 2013 and 2012		3

Condensed Consolidated Statements of Cash Flows (unaudited) For the six months ended December 31, 2013 and 2012		4

Notes to Condensed Consolidated Financial Statements (unaudited)		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3. Quantitative and Qualitative Disclosures About Market Risk		27

Item 4. Controls and Procedures		28

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		29

Item 1A. Risk Factors		29

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		30

Item 3. Defaults Upon Senior Securities		30

Item 4. Mine Safety Disclosures		30

Item 5. Other Information		30

Item 6. Exhibits		31

Signatures		32