10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT

PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED JUNE 30, 2008

COMMISSION FILE NUMBER 0-9355

CUBIC ENERGY, INC.

(Exact Name of Registrant as Specified in its Charter)

TEXAS	87-0352095
(State of Incorporation)	(I.R.S. Employer Identification No.)

9870 PLANO ROAD, DALLAS, TEXAS 75238

(Address of Principal Executive Offices)

972-686-0369

(Registrant’s Telephone Number)

Securities registered pursuant to Section 12(b) of the Act:

Title of Class	Name of Exchange on Which Registered
Common Stock, $0.05 par value	The American Stock Exchange

Securities registered under Section 12(g) of the Exchange Act: None

Indicate by check mark if registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o   No x

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No x

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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. Check one:

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 Act). Yes o   No x

Based upon the closing sales price on the Over-The-Counter Bulletin Board on December 31, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, the aggregate market value of common stock, par value $0.05 per share, held by non-affiliates, was $41,668,810. As of September 1, 2008, the registrant had outstanding 60,335,564 shares of common stock, which is the Registrant’s only class of common stock.

DOCUMENTS INCORPORATED BY REFERENCE: None.

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Such forward-looking statements are based on current expectations that involve a number of risks and uncertainties that could cause actual results to differ materially from the results discussed in the forward-looking statements. Generally, forward-looking statements include words or phrases such as “management anticipates,” “the Company believes,” “the Company anticipates,” and words and phrases of similar impact. The forward-looking statements are made pursuant to safe harbor provisions of the Private Securities Litigation Reform Act of 1995. The factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: (i) industry conditions and competition, (ii) the cyclical nature of the industry, (iii) domestic and worldwide supplies and demand for oil and gas, (iv) operational risks and insurance, (v) environmental liabilities which may arise in the future which are not covered by insurance or indemnity, (vi) the impact of current and future laws and government regulations, as well as repeal or modification of same, affecting the oil and gas industry and our operations in particular, (vii) production levels and other activities of OPEC and other oil and gas producers, and the impact that the above factors and other events have on the current and expected future pricing of oil and natural gas, and (viii) the risks described from time to time in our reports filed with the Securities and Exchange Commission.

AVAILABILITY OF INFORMATION

We file periodic reports and proxy statements with the Securities and Exchange Commission (the “SEC”). The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding Cubic Energy, Inc. and other companies that file electronically with the SEC.

Our website address is www.cubicenergyinc.com. We make available on our website free of charge copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably possible after we electronically file or furnish such material with the SEC.

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CUBIC ENERGY, INC.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	25
Item 2.	Properties	25
Item 3.	Legal Proceedings	25
Item 4.	Submission of Matters to a Vote of Security Holders	25
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data	30
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	41
Item 8.	Financial Statements and Supplementary Data	41
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	41
Item 9A.	Controls and Procedures	41
Item 9B.	Other Information	43
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	44
Item 11.	Executive Compensation	46
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	53
Item 13.	Certain Relationships and Related Transactions, and Director Independence	54
Item 14.	Principal Accountant Fees and Services	55
PART IV
Item 15.	Exhibits and Financial Statement Schedules	57

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PART I

Item 1.    Business.

GENERAL

Cubic Energy, Inc. (referred to as “Cubic”, “we”, “our, “us” or the “Company”) is an independent energy company engaged in the development and production of, and exploration for, crude oil, natural gas and natural gas liquids. Our oil and gas assets are concentrated principally in Texas and Louisiana. At June 30, 2008, our total proved reserves were 6,623,417 Mcfe.

Our predecessor was incorporated in October 1978. Cubic was incorporated in 1999 in the State of Texas. Our principal executive office is located at 9870 Plano Road, Dallas, Texas 75238, and our telephone number is (972) 686-0369.

In December 1997, we entered into a Stock Purchase Agreement (the “Agreement”) pursuant to which the Company issued 12,500,000 shares of our common stock in exchange for the conveyance to the Company of certain oil and gas properties by Calvin A. Wallen, III and his affiliates. In connection with the Agreement, three of the five members of the Board of Directors resigned and new directors were appointed, including Mr. Wallen, who also became President and CEO of the Company.

DESCRIPTION OF BUSINESS

Prior to the Agreement, we focused primarily on the acquisition of non-operated working interests and overriding royalty interests in oil and gas properties. Subsequent to the Agreement in December 1997, we moved our headquarters from Tulsa, Oklahoma to Garland, Texas in order to utilize an affiliate’s assembled team of experienced management whose substantial expertise lay in acquisition, exploitation and development and the ability to manage both operated and non-operated oil and gas properties. Current management believes that the ability to operate the vast majority of our own properties, through this affiliate, will result in significant cost savings to the Company. In addition, after reviewing our existing property portfolio and refining our new business strategy, the management team initiated a divestment strategy to dispose of our non-strategic assets in non-core areas in order to concentrate on building core reserves. Pursuant to this strategy, we have acquired additional properties in our core areas, primarily in Louisiana, as well as establishing a drilling program for the drilling of exploratory, development and infill wells, a strategy previously unavailable to us due to the technical expertise and experience required and the lack of available resources. We have made substantial progress in redirecting our strategic business efforts and believe that attractive opportunities remain for acquisition and development of our remaining and future assets.

On or about October 1, 2004, we closed a Securities Purchase Agreement and issued $2,635,000 in principal amount of 7% Senior Secured Convertible Debentures due September 30, 2009 (the “Debentures”), to a group of institutional and high net worth investors. The Debentures were secured by the collateral set forth in the Deed of Trust, Security Agreement, Assignment of Production and Fixture Filing attached to our Form 8-K filed October 12, 2004. The Debentures paid an annual interest rate of 7% on a quarterly basis and were convertible into shares of our common stock at a price of $0.50 per share. We had the option to pay the interest on the Debentures in common stock. The investors also received warrants to purchase an additional 2,635,000 shares of common stock with an exercise price of $1.00 per share. All of the above-referenced warrants had been exercised at June 30, 2008. The proceeds of the Debentures were used primarily for the acquisition of interests in oil and gas properties. The Debentures were retired on February 6, 2006, as set forth below.

On or about January 11, 2005, we issued 1,531,661 shares of common stock to Caravel Resources Energy Fund 2003-II, L.P. (the “Partnership”) in exchange for a 0.1914575033 working interest in the Kraemer 24-1 Well, DeSoto Parish, Township 14 N, Range 15 W, Section 24 (the “Well”). The Company also issued 468,339 shares

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of common stock to Mr. Wallen in exchange for a 0.0585424967 working interest in the Well. The common stock closed at a price of $0.90 on January 10, 2005.

On December 16, 2005, the Company entered into a Securities Purchase Agreement and issued 2,500,000 common shares at a price of $0.80 per share and issued warrants, with five year expirations, for the purchase of up to 1,000,000 shares of Company common stock at an exercise price of $1.00 per share. The proceeds of the offering were used for exploratory drilling and working capital.

On February 6, 2006, Cubic entered into a Credit Agreement with Petro Capital V, L.P. (“Petro Capital”) pursuant to which Petro Capital advanced to the Company $5,500,000. The indebtedness bore interest at a rate of 12.5% per annum, was to mature on February 6, 2009 and was secured by substantially all of the assets of the Company. Approximately $1,800,000 of the funded amount was used to retire the Debentures described above. In connection with the funding under the Credit Agreement, the Company issued to Petro Capital and Petro Capital Securities, LLC, warrants, with five-year expirations, for the purchase of up to 1,833,334 and 250,000 shares, respectively, of Company common stock at an exercise price of $1.00 per share. Pursuant to the anti-dilution adjustment provisions applicable to such warrants, the exercise price applicable to 283,334 of such warrants held by Petro Capital and 250,000 of such warrants held by Petro Capital Securities, LLC that had not been exercised as of June 30, 2008 is currently $0.9758 per share. The senior debt held by Petro Capital was retired on March 5, 2007, with proceeds from a new senior debt issue, as set forth below.

Concurrently, on February 6, 2006, the Company entered into a Purchase Agreement with Tauren Exploration, Inc. (“Tauren”), an entity wholly owned by Calvin A. Wallen III, the Company’s Chairman of the Board and Chief Executive Officer, with respect to the purchase by the Company of certain Cotton Valley leasehold interests (approximately 11,000 gross acres; 5,000 net acres) held by Tauren. Pursuant to the Purchase Agreement, the Company acquired from Tauren a 35% working interest in approximately 2,400 acres and a 49% working interest in approximately 8,500 acres located in DeSoto and Caddo Parishes, Louisiana, along with an associated Area of Mutual Interest (“AMI”) and the right to acquire at “cost” (as defined in the Purchase Agreement) a working interest in all additional mineral leases obtained by Tauren in the AMI, in exchange for (a) $3,500,000 in cash, (b) 2,500,000 unregistered shares of Company common stock, (c) an unsecured 12.5% short-term promissory note in the amount of $1,300,000, which note was convertible into Company common stock at a conversion price of $0.80 per share (the “Tauren Note”), and (d) a drilling credit of $2,100,000.

On July 28, 2006, Cubic entered into and consummated transactions pursuant to Subscription and Registration Rights Agreements (the “July 2006 Subscription Agreements”) with certain investors that are unaffiliated with the Company (the “Investors”). Pursuant to the July 2006 Subscription Agreements, the Investors paid aggregate consideration of $2,100,000 to the Company for 3,000,000 shares of the Company’s common stock and warrants, exercisable through July 31, 2011, into 1,500,000 shares of common stock at $0.70 per share. Pursuant to the anti-dilution adjustment provisions applicable to such warrants, the exercise price applicable to 1,500,000 of such warrants that had not been exercised as of June 30, 2008 is currently $0.6885 per share. In addition to reimbursement of certain expenses incurred in connection with this offering, the Company agreed to pay 2% of the aggregate consideration, in cash, plus 150,000 shares of common stock valued at $0.70 per share, to a placement agent.

On December 15, 2006, the Company entered into Subscription and Registrations Rights Agreements (the “December 2006 Subscription Agreements”) with certain investors. One of the investors, William Bruggeman (and entities affiliated with him), was the beneficial owner, prior to this transaction, of approximately 23.0% of the common stock of the Company. Another investor, Bob Clements, is a director of the Company. The remaining investors had no material relationship with the Company. Pursuant to the December 2006 Subscription Agreements, the investors paid aggregate consideration of $3,940,000 to the Company for 7,880,000 shares of the Company’s common stock and warrants exercisable into 3,940,000 shares of common stock. The warrants are exercisable through November 30, 2011, at $0.70 per share.

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On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital, Inc. (“Wells Fargo”) 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”). The indebtedness bears interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, matures on March 1, 2010, and is secured by substantially all of the assets of the Company. Approximately $5,000,000 of the funded amount was used, together with cash on hand, to retire the Company’s previously outstanding senior debt that was due February 6, 2009, described above.

The Term Loan of $5,000,000 is convertible into 5,000,000 shares of Cubic common stock at a conversion price of $1.00 per share. The Revolving Note is subject to a borrowing base (the “Borrowing Base”), initially set at $4,000,000, and is subject to periodic review. On July 27, 2007, Wells Fargo increased the Company’s Borrowing Base to $6,600,000 in order to fund the drilling and casing costs of two new wells in the Company’s Johnson Branch acreage in Caddo Parish, Louisiana. On September 7, 2007, Wells Fargo increased the Company’s Borrowing Base to $8,600,000 in order to fund the remaining drilling and casing costs of five wells drilled since the beginning of fiscal 2008, the drilling and casing costs of two new wells, and the costs of installing a gathering/sales line and associated equipment in the Company’s Johnson Branch acreage. On November 19, 2007, Wells Fargo increased the Company’s Borrowing Base to $14,500,000 in order to fund the completion costs and casing of eight wells already successfully drilled and the drilling of four additional wells located in the Company’s Johnson Branch acreage. On May 8, 2008, Wells Fargo increased the Company’s Borrowing Base to $20,000,000 in order to fund the completion costs and casing of the four recently-drilled wells located in the Company’s Johnson Branch acreage (including two vertical wells drilled into the Bossier/Haynesville shales) and the drilling of two additional wells located in the Company’s Bethany Longstreet acreage in Caddo and DeSoto Parishes.

The terms of the Credit Facility, among other things, prohibit the Company from merging with another company or paying dividends, and limit additional indebtedness, sales of certain assets and investments. Upon the repayment in full of the Credit Facility, and with respect to certain properties, upon the occurrence of the conditions set forth in Section 2.14 of the Credit Agreement, the Company agreed to convey a net profits interest to Wells Fargo in an amount equal to 5% of Cubic’s net interest in certain of its Louisiana properties.

On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 (the “Subordinated Note”) to Diversified Dynamics Corporation (the “Lender”), an entity controlled by William Bruggeman who beneficially owns more than 5% of the common stock of the Company. The Subordinated Note bears interest at a fluctuating rate equal to the sum of the prime rate plus two percent (2%) per annum, and matures on April 30, 2010. As consideration for the loan made by the Lender pursuant to the Subordinated Note, the Company agreed to convey to the Lender, upon the repayment in full of the indebtedness evidenced by the Subordinated Note and the repayment in full of the senior indebtedness evidenced by the Credit Facility with Wells Fargo, an undivided 0.375% (0.375 of one percent) net profits interest in the future production of hydrocarbons from or attributable to Cubic’s net interest in its Louisiana properties. The proceeds of the Subordinated Note are being used for general corporate and working capital purposes.

Issuing the Subordinated Note required the consent of the holder of the Company’s senior indebtedness, Wells Fargo, which consent it granted on May 5, 2008. Subsequently, on May 8, 2008, the Credit Facility with Wells Fargo was amended by the First Amendment to the Credit Agreement (the “First Amendment”). Material provisions of the First Amendment included the following: (i) the Company may not prepay all or any part of the principal balance outstanding on the Term Loan prior to its maturity on March 1, 2010; and (ii) the amount of the Borrowing Base was increased to $20,000,000, which amount was fully drawn upon, subsequent to the end of fiscal 2008, on August 20, 2008.

The shares of common stock and warrants described in the aforementioned transactions were issued by the Company in reliance upon an exemption from registration set forth in Regulation D and/or Section 4(2) of the Securities Act of 1933, as amended, which exempts transactions by an issuer not involving a public offering.

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PRINCIPAL OIL AND GAS PROPERTIES

The following table summarizes certain information with respect to our principal areas of operation at June 30, 2008:

	Proved Reserves
	Oil & Natural		Total Gas	Percent		Present Value
	Gas Liquids	Gas	Equivalent	of Proved		(Discounted
Area	(Bbls)	(Mcf)	(Mcfe)	Reserves		@ 10%)
Louisiana	88,756	5,980,119	6,512,655	98.3	%	$	32,698,257
Texas	192	109,610	110,762	1.7	%	412,399
Total	88,948	6,089,729	6,623,417	100.0	%	$	33,110,656

Our Texas properties are situated in Palo Pinto, Eastland and Callahan Counties. Our Louisiana properties are situated in Caddo Parish and in DeSoto Parish. At June 30, 2008, the Louisiana properties contained the vast majority of our proved reserves, a situation that is expected to continue. The Texas properties consist primarily of wells acquired by the Company in several transactions between 1991 and 2002 and through overriding royalty interests reserved in farm-out agreements in 1998 and 1999. The vast majority of the Louisiana properties were acquired on or about October 1, 2004, January 11, 2005 and February 6, 2006.

Our net production for the fiscal year ended June 30, 2008 for all of the Company wells averaged approximately 624 Mcf of natural gas per day, 5 barrels of oil per day and 122 gallons of natural gas liquids per day as compared to approximately 193 Mcf of natural gas per day, 3 barrels of oil per day and zero gallons of natural gas liquids per day in the fiscal year ended June 30, 2007.

EXPLORATION ACTIVITIES

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 higher risk, high reserve potential prospects. Our focus is primarily 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 some externally generated prospects and plan to participate in some of these opportunities to enhance our portfolio.

We are currently focusing our domestic exploration activities to develop our undeveloped leasehold opportunities in Louisiana and Texas. Currently we have exploration opportunities and seek to acquire additional leasehold interests in Caddo and DeSoto Parishes in Louisiana, and in Palo Pinto, Callahan and Eastland Counties in Texas.  These areas are a part of geologic studies utilizing regional trend surface analysis, 2-D and 3-D seismic data, AVO analysis and/or vast sub-surface control. Prospects have been developed from approximately 4,000 to 12,000 feet in depth in the: Bossier/Haynesville shales; Cotton Valley, Hosston, Gloyd, Pettet, Paluxy, and Strawn sandstones; Bend conglomerate; and Caddo limestone.

RECENT DEVELOPMENTS

Near the end of fiscal 2007, utilizing funds provided under the Credit Facility with Wells Fargo, we began accelerating our drilling pace. To illustrate, while we drilled three wells in fiscal 2007, we drilled 12 wells to total depth, began the drilling of a thirteenth well and completed 10 wells for production during fiscal 2008. Since the end of fiscal 2008, we have drilled our fourth and fifth wells into the Bossier/Haynesville shales, and

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completed four wells for production that reached total depth in fiscal 2008, including the Hudson 10-1 and the Daniels 3-1, which were drilled into the Bossier/Haynesville shales.

On September 25, 2007, the Company announced the results of three new wells delineating large impact reserves in the Cotton Valley interval. Preliminary log analysis, performed by an independent reservoir engineer, for the three wells drilled in Cubic’s Johnson Branch acreage (T15N, R15W) of Caddo Parish, Louisiana, determined the following results: a) the Tabor 4-1 well drilled to a total depth of 10,550’ and logged 163 feet of net pay in the Cotton Valley between depths of 8,901’-9,798’; b) the McDonnell 8-1 well drilled to a total depth of 10,500’ and logged 142 feet of net pay in the Cotton Valley between depths of 8,907’-9,803’; and c) the Luttrell 7-1 well drilled to a total depth of 10,522’ and logged 113 feet of net pay in the Cotton Valley between depths of 8,880’-9,648’. The aggregate net pay thickness in the three wells is 418 feet. In addition, Cubic is carefully analyzing Hosston intervals found in these new wells.

During January 2008, the Company completed and brought online for production six previously drilled wells and reached total drilling depth on two new wells in the Company’s Johnson Branch acreage. On January 30, 2008, the Company announced that one of these two new wells, the Hudson 10-1, was control flow drilled through the Bossier/Haynesville shales to a total depth of 11,650 feet, and that third-party mud logs showed a 1,100 foot interval of shale gas in the Hudson 10-1 well. During February 2008, the Company completed and brought online for production the two new wells drilled in the Company’s Johnson Branch acreage during January 2008.

Subsequent to the end of the fiscal year ended June 30, 2008, during July and August, 2008, the Company completed for production four wells in its Johnson Branch acreage, two of which were completed in the Bossier/Haynesville shales, bringing the Company’s number of producing wells in Louisiana to 20. Also, since the end of fiscal 2008, Cubic has drilled two wells, the Estes 7-1 and the Red Oak Timber 5-1 (our fourth and fifth wells to be drilled into the Bossier/Haynesville shales), to total depth of approximately 11,950 feet into the Bossier/Haynesville shales in its Bethany Longstreet acreage. Cubic has a 35% working interest in both wells. The Estes 7-1 was drilled using a casing program with 7 5/8” pipe for the intermediate string, which will allow the Company to drill horizontally into the Bossier/Haynesville shales at a later date, after being vertically completed initially in the Cotton Valley formation.

As of September 1, 2008, the Company had successfully drilled 22 wells in northwest Louisiana with 20 having been completed as producers of hydrocarbons; the two other wells are awaiting completion. As of such date, 10 Johnson Branch wells have been completed as hydrocarbon producers in the Cotton Valley sandstones and two into the Bossier/Haynesville shales. Cubic has a 49% working interest in its Johnson Branch acreage. Seven miles to the South, in its Bethany Longstreet acreage, Cubic has eight wells producing from the Cotton Valley and Hosston formations. Cubic has a 25% working interest in seven of these producing wells, and a 35% working interest in the Estes 8-1 well. Work is ongoing at the Bethany Longstreet and Johnson Branch wells to increase the average daily production from these areas. We also anticipate that we will complete and fracture stimulate additional zones of certain Johnson Branch wells.

Cubic has developed its infrastructure in Johnson Branch with approximately 16 miles of gathering lines and pipeline constructed for its currently producing wells and any further completions. In addition, a Johnson Branch tap, common point and compression facility were completed in November 2007 and are currently operational. The Company also owns two taps in its Bethany Longstreet acreage.

Recent increased oil and natural gas drilling activity in East Texas and Northwest Louisiana has resulted in increased demand for drilling rigs and other oilfield equipment and services. At various times, we have and may continue to experience occasional or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and gas drilling and completing. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

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MARKETING OF PRODUCTION

Crude Oil and Natural Gas

Our production consists mainly of natural gas. We market our operated production of natural gas to three purchasers (i) in Texas, Enbridge G & P, LP, and (ii) in Louisiana, EROC Gathering Company, LP and NGTS, LP. In fiscal 2007, we also marketed our production of natural gas, in Louisiana, to Crosstex Gulf Coast Marketing, Ltd., but no longer do so. We sell our crude oil and condensate production at or near the well-site, although in some cases it is gathered by us or others and delivered to a central point of sale. Our crude oil and condensate production is transported by truck or by pipeline and is typically committed to arrangements having a term of one year or less. We have not engaged in crude oil hedging or trading activities. We utilize short-term gas contracts with prices that are related to market conditions in varying degrees and have not engaged in natural gas hedging or futures trading.

We believe we would be able to locate alternate purchasers in the event of the loss of any one of these purchasers, and that any such loss would not have a material adverse effect on our financial condition or results of operations. Revenue from the sale of natural gas totaled $2,056,519 for fiscal 2008 and represented 89% of our total oil and gas revenues for that fiscal year.

Price Considerations

Crude oil prices are established in a highly liquid, international market, with average crude oil prices that we receive generally fluctuating with changes in the futures price established on the NYMEX for West Texas Intermediate Crude Oil (“NYMEX-WTI”). The average crude oil price per Bbl received by us in fiscal 2008 was $102.17 as compared to $61.68 in fiscal 2007.

Natural gas and natural gas liquids prices in the geographical areas in which we operate are closely tied to established price indices which are heavily influenced by national and regional supply and demand factors and the futures price per MMBtu for natural gas delivered at Henry Hub, Louisiana established on the NYMEX (“NYMEX-Henry Hub”). At times, these indices correlate closely with the NYMEX-Henry Hub price, but often there are significant variances between the NYMEX-Henry Hub price and the indices used to price our natural gas. Average natural gas prices received by us in each of our operating areas generally fluctuate with changes in these established indices. The average natural gas price per Mcf received by us in fiscal 2008 was $9.01 as compared to $7.44 in fiscal 2007. The average natural gas liquids price per gallon received by us in fiscal 2008 was $1.66; we produced no natural gas liquids volumes in fiscal 2007.

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OIL AND GAS RESERVES

The following tables set forth the proved developed, proved non-producing and proved undeveloped reserves at June 30, 2008, the estimated future net cash flows from such proved reserves and the Standardized Measure of Discounted Future Net Cash Flows attributable to our reserves at June 30, 2008, 2007 and 2006:

	Oil & Natural		Total Gas	Estimated
	Gas Liquids	Gas	Equivalent	Future Net		10%
Category	(Bbls)	(Mcf)	(Mcfe)	Cash Flows		Discount
Proved Producing	7,604	527,691	573,315	$	4,440,000	$	3,592,292
Proved Non-Producing	16,041	491,585	587,831	4,970,338		4,319,269
Proved Developed Reserves	23,645	1,019,276	1,161,146	$	9,410,338	$	7,911,561
Proved Undeveloped	65,303	5,070,453	5,462,271	37,656,434		25,199,095
Total Proved Reserves	88,948	6,089,729	6,623,417	$	47,066,772	$	33,110,656

	At June 30,
	2008		2007		2006
Proved Developed Reserves:
Oil & Natural Gas Liquids (Bbls)	23,645		3,062		2,893
Gas (Mcf)	1,019,276		1,037,238		807,057
Mcfe	1,161,146		1,055,610		824,415
Estimated future net cash flows (before income tax)	$	9,410,338	$	4,694,571	$	2,841,088
Standardized Measure (1)	$	7,911,561	$	3,704,011	$	2,343,348
Proved Undeveloped Reserves:
Oil & Natural Gas Liquids (Bbls)	65,303		9,768		5,970
Gas (Mcf)	5,070,453		3,204,813		1,989,843
Mcfe	5,462,271		3,263,421		2,025,663
Estimated future net cash flows (before income tax)	$	37,656,434	$	6,926,991	$	6,050,495
Standardized Measure (1)	$	25,199,095	$	3,125,699	$	4,104,037
Total Proved Reserves:
Oil & Natural Gas Liquids (Bbls)	88,948		12,830		8,863
Gas (Mcf)	6,089,729		4,242,051		2,796,900
Mcfe	6,623,417		4,319,031		2,850,078
Estimated future net cash flows (before income tax)	$	47,066,772	$	11,621,562	$	8,891,583
Standardized Measure (1)	$	33,110,656	$	6,829,710	$	6,447,385
Average price used to calculate reserves:
Oil (per Bbl)	$	138.80	$	64.46	$	70.09
Natural Gas Liquids (per Bbl)	$	93.86	n/a		n/a
Gas (per Mcf)	$	14.10	$	7.06	$	5.55

(1)The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value (using an annual discount rate of 10%) of estimated future net cash flows from the production of proved reserves, after giving effect to income taxes. See “Note J - Oil and gas reserves information (unaudited)” in the Notes to the Financial Statements of the Company included elsewhere in this Report for additional information regarding the disclosure of the Standardized Measure information in accordance with the provisions of Statement of Financial Accounting Standards (“FAS”) No. 69 (“FAS No. 69”), “Disclosures about Oil and Gas Producing Activities.”

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The information set forth in this Report relating to our proved reserves, estimated future net cash flows and Present Values is taken from reports prepared by the Dallas office of RPS Scotia, Inc., an independent, petroleum engineering firm, for fiscal years 2008, 2007 and 2006. The estimates of this independent petroleum engineering firm were based upon review of production histories and other geological, economic, ownership and engineering data provided by the Company. Information with respect to approximately 2% of the total proved reserves as of June 30, 2008, was prepared in-house and was not reviewed by an independent engineering firm. No reports on our reserves have been filed with any federal agency. In accordance with guidelines of the SEC, our estimates of proved reserves and the future net revenues from which present values are derived are made using year end oil and gas sales prices held constant throughout the life of the properties (except to the extent a contract specifically provides otherwise). Operating costs, development costs and certain production-related taxes were deducted in arriving at estimated future net cash flows, but such costs do not include debt service or general and administrative expenses.

There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond our control. The reserve data set forth in this Report represents estimates only. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development, exploitation and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. There can be no assurance that these estimates are accurate predictions of our oil and gas reserves or their values. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves.

Costs Incurred

The following table shows certain information regarding the costs incurred by us in our property acquisition, development and exploratory activities during the periods indicated.

	Year Ended June 30,
	2008		2007		2006
Property acquisition costs	$	394,675	$	481,229	$	6,176,766
Exploratory costs	14,030,615		2,759,794		808,678
Development costs	916,613		966,879		1,323,243
Total	$	15,341,903	$	4,207,902	$	8,308,687

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Drilling Results

We drilled or participated in the drilling of wells as set out in the table below for the periods indicated. The table was completed based upon the date drilling commenced. We did not acquire any wells during these periods. You should not consider the results of prior drilling activities as necessarily indicative of future performance, nor should you assume that there is necessarily any correlation between the number of productive wells drilled and the oil and natural gas reserves generated by those wells.

	Year Ended June 30,
	2008		2007		2006
	Gross	Net	Gross	Net	Gross	Net
Development wells:
Productive	—	—	—	—	—	—
Dry	—	—	—	—	—	—
Total development	—	—	—	—	—	—
Exploratory wells:
Productive	12	5.88	3	0.85	2	0.50
Dry	—	—	—	—	—	—
Total exploratory	12	5.88	3	0.85	2	0.50
Total wells:
Productive	12	5.88	3	0.85	2	0.50
Dry	—	—	—	—	—	—
Total wells	12	5.88	3	0.85	2	0.50

NET PRODUCTION, SALES PRICES AND COSTS

The following table presents certain information with respect to production, prices and costs attributable to all oil and gas property interests owned by us for the fiscal years ended June 30, 2008, 2007 and 2006:

	Year Ended June 30,
	2008		2007		2006
Production Volumes:
Oil (Bbl)	1,682		967		1,047
Natural gas liquids (gallons)	44,476		—		—
Natural gas (Mcf)	228,219		70,412		53,516
Total oil, natural gas liquids, and natural gas (Mcfe)	244,665		76,214		59,798
Weighted Average Sales Prices:
Oil (per Bbl)	$	102.17	$	61.68	$	59.90
Natural gas liquids (per gallon)	$	1.66	n/a		n/a
Natural gas (per Mcf)	$	9.01	$	7.44	$	8.34
Selected Expenses per Mcfe:
Production costs	$	3.60	$	4.18	$	5.05
Workover expenses (non-recurring)	$	0.11	$	1.40	$	—
Severance taxes	$	0.29	$	0.39	$	0.39
Other revenue deductions	$	0.75	$	0.35	$	0.22
Total lease operating expenses	$	4.75	$	6.32	$	5.66
General and administrative expenses	$	10.17	$	17.39	$	23.42
Depreciation, depletion and amortization	$	8.79	$	4.76	$	3.00

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PRODUCTIVE WELLS AND ACREAGE

Productive Wells

The following table sets forth our domestic productive wells at June 30, 2008:

Oil		Gas		Total
Gross	Net	Gross	Net	Gross	Net
—	—	32	18.42	32	18.42

Acreage

The following table sets forth our undeveloped and developed gross and net leasehold acreage at June 30, 2008. Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

Undeveloped		Developed		TOTAL
Gross	Net	Gross	Net	Gross	Net
6,272	1,941	8,439	4,210	14,711	6,151

As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights.

OPERATIONS

Oil and gas properties are customarily operated under the terms of a joint operating agreement, which provides for reimbursement of the operator’s direct expenses and monthly per well supervision fees. Per well supervision fees vary widely depending on the geographic location and producing formation of the well, whether the well produces oil or gas and other factors. We are not the operator of our wells, but, in all cases, except for three wells in Northwest Louisiana in which we have minor working interests, and which are operated by Chesapeake Energy Corp., Fossil Operating, Inc. (“Fossil”), an entity wholly owned by Mr. Wallen, is the operator. Fossil charges the Company, without mark-up, for the Company’s working interest portion of the direct operating costs and overhead costs (which are comprised of administrative, supervision, office services and warehousing costs) that Fossil incurs with respect to our wells.

We have contract relationships with petroleum engineers, geologists and other operations and production specialists who we believe will be able to improve production rates, increase reserves and/or lower the cost of operating our oil and gas properties.

EMPLOYEES

At September 1, 2008, the Company had 10 employees, four (4) full-time and six (6) part-time. We regularly use independent consultants and contractors to perform various professional services, including well-site supervision, design, construction, permitting and environmental assessment. We use independent contractors to perform field and on-site production operation services.

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FACILITIES

The Company’s principal executive and administrative offices are located at 9870 Plano Road, Dallas, Texas. The offices are subleased on a month-to-month basis from an affiliate controlled by Mr. Wallen and the offices are owned by this affiliate. The average monthly amount charged to the Company during the year ended June 30, 2008, was $2,229. The Company believes that there is other appropriate space available in the event the Company should terminate its current leasing arrangement.

COMPETITION

We compete with major integrated oil and natural gas companies and independent oil and natural gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Further, our competitors may have technological advantages and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

Recent increased oil and natural gas drilling activity in East Texas and Northwest Louisiana has resulted in increased demand for drilling rigs and other oilfield equipment and services. At various times, we have and may continue to experienced temporary or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and gas drilling and completing. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry, many of which are used in this Report.

“Bbl” means a barrel of 42 U.S. gallons, used herein in reference to oil or other liquid hydrocarbons.

“Bcf” means billion cubic feet.

“Bcfe” means Bcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

“Btu” means British thermal unit, which means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Casing” means a type of pipe that is used for encasing a smaller diameter carrier pipe for installation in a well.  Casing is used to send off fluids from the hole or keep a hole from caving in.

“Coiled Tubing” means a continuous, jointless hollow steel cylinder that is stored on a reel and can be uncoiled or coiled repeatedly as required; coiled tubing is increasingly being used in well completion and servicing instead of traditional tubing, which is made up of joined sections of pipe.

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“Completion” means the installation of permanent equipment for the production of oil or gas.

“Compressor Station” means a facility in which the pressure of natural gas is raised to facilitate its transmission through pipelines.

“Condensate” means hydrocarbons naturally occurring in the gaseous phase in a reservoir that condense to become a liquid at the surface due to the change in pressure and temperature.

“Cubic Foot” means the volume of gas that fills one cubic foot of space under standard temperature and pressure conditions.  Standard pressure is 14.73 psi and standard temperature is 60 degrees Fahrenheit.

“Developed Acreage” means the number of acres that are allocated or assignable to producing wells or wells capable of production.

“Development Drilling” or “Development Well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry Hole” or “Dry Well” means a well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil and gas well.

“Estimated Future Net Cash Flows” means estimated future gross cash flows to be generated from the production of proved reserves, net of estimated production, future development costs, and future abandonment costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to deprecation, depletion and amortization.

“Exploration” is the act of searching for potential sub-surface reservoirs of gas or oil.  Methods include the use of magnetometers, gravity meters, seismic exploration, surface mapping, and the drilling of exploratory test wells (known as “wildcats”).

“Exploratory Drilling” or “Exploratory Well” means a well drilled to find and produce oil or gas reserves not classified as proved, to find a new production reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

“Farm-In” or “Farm-Out” means an agreement pursuant to which the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” and the assignor issues a “farm-out.”

 “Gas” means natural gas.

“Gathering System” means a system of pipelines, compressor stations and any other related facilities that gathers natural gas from a supply region and transports it to the major transmission systems.

“Gross” when used with respect to acres or wells, means the total acres or wells in which we have a working interest.

“Horizontal Drilling” means drilling a well that deviates from the vertical and travels horizontally through a prospective reservoir.

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“Hydrocarbons” means an organic chemical compound of hydrogen and carbon.  Hydrocarbons are a large class of liquid, solid or gaseous organic compounds, which are the basis of almost all petroleum products.

“Infill Drilling” means drilling of an additional well or wells provided for by an existing spacing order to more adequately drain a reservoir.

“Landman” means an employee or agent of an oil and gas company whose primary duties are formulating and carrying out exploration strategies and managing an oil and gas company’s relations with its landowners and partners, including securing and administering oil and gas leases and other agreements.

“Lease” means a formal agreement between two or more parties where the owner of the land grants another party the right to drill and produce hydrocarbons in exchange for payment.

“Log” or “Logging” means a record of information about the performance of some thing or some process.  In the oil field, a variety of logs are used in the drilling and completion of oil and gas wells.

“Mcf” means thousand cubic feet.

“Mcfe” means Mcf of natural gas equivalent; determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

“Midstream” means activity involving the processing, storage and transportation sectors of the petroleum industry.

“MMBtu” means one million Btus.

“MMcf” means one million cubic feet.

“MMcfe” means MMcf of natural gas equivalent, determined using the ratio of one Bbl of oil or condensate to six Mcf of natural gas.

“Mud” usually means a colloidal suspension of clays in water along with chemical additives that is circulated through the wellbore during rotary drilling.

“Natural Gas Liquids” means liquid hydrocarbons which have been extracted from natural gas (e.g., ethane, propane, butane and natural gasoline).

 “Net” when used with respect to acres or wells, refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company.

“Net Production” means production that is owned by the Company less royalties and production due others.

“Operator” means the individual or company responsible for the exploration, development and production of an oil or gas well or lease.

 “Pipeline” means all parts of a physical facility through which gas is transported, including pipe, valves and other appendages attached to the pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.

 “Present Value” or “PV-10” when used with respect to oil and gas reserves, is the pre-tax present value, discounted at an annual rate of 10%, of the estimated future gross revenues to be generated from the production of proved reserves calculated in accordance with the guidelines of the SEC, net of estimated production and

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future development costs, using prices and costs as of the date of estimation without future escalation (except to the extent a contract specifically provides otherwise), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization.

“Productive Wells” or “Producing Wells” consist of producing wells and wells capable of production, including natural gas wells waiting on pipeline connections.

“Proved Developed Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

“Proved Reserves” means the estimated quantities of crude oil, natural gas and natural gas liquids which upon analysis of geological and engineering data appear with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Reservoirs are considered proved if either actual production or conclusive formation tests support economic producibility. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (b) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil, natural gas and natural gas liquids that may occur in undrilled prospects; and (d) crude oil, natural gas and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such resources.

“Proved Undeveloped Reserves” means reserves that are recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

“Recompletion” means the completion for production of an existing well bore in another formation from that in which the well has been previously completed.

“Reserves” means proved reserves.

“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

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“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

“Sandstone” means rock composed mainly of sand-sized particles or fragments of the mineral quartz, which, because these grains are rigid, will withstand tremendous pressures without being compacted.

“Set Casing” means the installation of steel pipe or casing in a wellbore.  An accompanying operation is the cementing of the casing in place by surrounding it with a wall of cement extending for all or a portion of the depth of the well.

“Shale” means a type of rock composed of common clay or mud.  When clay is compacted under great pressure and temperature deep in the earth, water contained in the clay is expelled, and clay turns into shale.

 “SPE” means Society of Petroleum Engineers.

“Spud” means the first or initial act of boring of the hole in drilling of an oil or gas well.

“Surface Casing” means the first string of casing put into a well.  Surface casing is cemented into bedrock and serves to shut out shallow water formations and as a foundation for well control during drilling operations.

“2-D Seismic” means an advanced technology method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.

“3-D Seismic” means an advanced technology method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.

“Tcf” means trillion cubic feet.

“Tubing” is small diameter pipe, threaded at both ends, that is lowered into a completed well.  Oil and gas are produced through a string of tubing (which can be periodically removed for maintenance).

“Upstream” means the sector of the petroleum industry involving exploration and production.

“Undeveloped Acreage” means lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Working Interest” means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.

“Workover” means operations on a producing well to restore or increase production.

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Item 1A. Risk Factors.

You should carefully consider the following risk factors, in addition to the other information set forth in this Report, before investing in shares of our common stock. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock. Some information in this Report may contain “forward-looking” statements that discuss future expectations of our financial condition and results of operation. The risk factors noted in this section and other factors could cause our actual results to differ materially from those contained in any forward-looking statements.

We face significant competition, and many of our competitors have resources in excess of our available resources.

The oil and gas industry is highly competitive. We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and sale of crude oil, natural gas and natural gas liquids. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies with substantially larger operating staffs and greater capital resources than us. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We face increased competition for available drilling rigs and other oilfield equipment and services, which could increase our costs, cause our drilling program to be delayed or cause our leases to lapse.

Recent increased oil and natural gas drilling activity in East Texas and Northwest Louisiana has resulted in increased demand for drilling rigs and other oilfield equipment and services. At various times, we have and may continue to experience temporary or prolonged shortages or unavailability of drilling rigs, drill pipe and other material used in oil and gas drilling and completing. Such unavailability could result in increased costs, delays in timing of anticipated development or cause interests in undeveloped oil and natural gas leases to lapse.

Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.

Drilling activities are subject to many risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, many of which are beyond our control, including economic conditions, mechanical problems, pressure or irregularities in formations, title problems, weather conditions, compliance with governmental requirements and shortages in or delays in the delivery of equipment and services. Such equipment shortages and delays sometimes involve drilling rigs where inclement weather prohibits the movement of land rigs causing a high demand for rigs by a large number of companies during a relatively short period of time. Our future drilling activities may not be successful. Lack of drilling success could have a material adverse effect on our financial condition and results of operations.

Our operations are also subject to all the hazards and risks normally incident to the development, exploitation, production and transportation of, and the exploration for, oil and gas, including unusual or unexpected geologic

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formations, pressures, down hole fires, mechanical failures, blowouts, explosions, uncontrollable flows of oil, gas or well fluids and pollution and other environmental risks. These hazards could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. We participate in insurance coverage maintained by the operator of our wells, although there can be no assurances that such coverage will be sufficient to prevent a material adverse effect to us if any of the foregoing events occur.

We are in a capital-intensive business and we will need additional funds.

Our business is highly capital-intensive requiring continuous development and acquisition of oil and gas reserves. In addition, capital is required to operate and expand our oil and gas field operations, purchase equipment and to fund our drilling program.

At June 30, 2008, we had working capital of $1,746,741. On March 5, 2007, Cubic entered into the aforementioned Credit Agreement with Wells Fargo providing for the $20,000,000 Revolving Note and the Term Loan of $5,000,000 in order to fund the drilling of new wells. On May 6, 2008, the Company issued the aforementioned $2,000,000 Subordinated Note to Diversified Dynamics Corporation. Subsequent to the end of fiscal 2008, on August 20, 2008, the Company increased its borrowings under the Revolving Note from $16,827,800 at June 30, 2008 to the full amount of the borrowing base of $20,000,000. As a result, the Company has no additional availability under the aforementioned Credit Facility.  In addition, the entire principal amount of the Subordinated Note was funded at the time of its issuance, and no additional borrowings are provided thereunder. Therefore, the Company’s capital requirements must be satisfied through operations, additional borrowings under new or renegotiated credit arrangements, or the issuance of equity securities.  There can be no assurance that any of these sources of capital will be available or sufficient to satisfy the Company’s capital requirements.

We have experienced and will continue to experience significant capital expenditures and working capital requirements, principally as a result of our drilling program. We expect that we will require additional financing, in addition to cash generated from operations, to fund our expected growth. There can be no assurance, however, that additional financing will be available on acceptable terms or at all. In the event that additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Additionally, failure to drill on certain of our leasehold interests could result in the forfeiture of our interest.

Any future issuances of equity securities would likely result in dilution to our then existing shareholders while incurring additional indebtedness would result in increased interest expense and debt service charges. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We have a history of operating losses and may not be profitable in the future.

We incurred losses before income tax provisions of $(5,128,453) and $(5,800,774) for the fiscal years ended June 30, 2008 and 2007, respectively. Our accumulated deficit as of June 30, 2008 was $(24,451,145). Historically, we have funded our operating losses, acquisitions and drilling costs primarily through a combination of private offerings of convertible debt, senior secured debt, and equity securities; however, on March 5, 2007 we established a $20,000,000 bank line of credit with Wells Fargo under the terms of the Credit Facility described elsewhere herein, the primary purpose of which is to fund drilling costs. The line of credit with Wells Fargo was fully drawn upon, subsequent to the end of fiscal 2008, on August 20, 2008. Our success in obtaining the necessary capital resources to fund future costs associated with our operations and drilling plans is dependent upon our ability to: (i) increase revenues through acquisitions and recovery of our proved producing and proved developed non-producing oil and gas reserves; (ii) maintain effective cost controls at the corporate administrative office and in field operations; and (iii) obtain additional financing, including through the exercise of outstanding warrants. However, even if we achieve some success with our plans, there can be no

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assurance that we will be able to generate sufficient revenues to achieve significant profitable operations or to fund our drilling plans. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

We have substantial capital requirements necessary for undeveloped properties for which we may not be able to obtain adequate financing.

The majority of our oil and gas reserves are undeveloped. At June 30, 2008, we had proved undeveloped reserves of 5,462,271 Mcfe, which represent approximately 82% of our total proved reserves of 6,623,417 Mcfe. Recovery of the Company’s future undeveloped reserves will require significant capital expenditures to further develop these reserves during fiscal year 2009. No assurance can be given that our financing sources will be sufficient to fully fund our planned development activities or that development activities will be either successful or in accordance with our schedule. Additionally, any significant decrease in oil and gas prices or any significant increase in the cost of development could result in a significant reduction in the number of wells drilled and/or reworked. No assurance can be given that any wells will produce oil or gas in commercially profitable quantities.

Development of our properties will require additional capital resources. Subsequent to the end of fiscal 2008, we have fully drawn upon the aforementioned $20,000,000 revolving credit facility with Wells Fargo Energy Capital, and the aforementioned $2,000,000 Subordinated Note was fully funded at the time of its issuance in May 2008. We have no commitments to obtain any additional debt or equity financing and there can be no assurance that additional financing will be available, when required, on favorable terms to us. The inability to borrow under the revolving credit facility or obtain additional financing could have a material adverse effect on us, including requiring us to curtail significantly our oil and gas development plans or farm-out development of our properties. Any additional financing may involve substantial dilution to the interests of our shareholders at that time. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Servicing our debt requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial debt.

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be required to adopt one or more alternatives, such as selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at such time, as well as the value of our properties. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on the market price of our equity securities.

Oil and natural gas prices fluctuate widely and low prices could have a material adverse impact on our business and financial results.

Our revenues, profitability and the carrying value of our oil and gas properties are substantially dependent upon prevailing prices of, and demand for, oil and gas and the costs of acquiring, finding, developing and producing reserves. Our ability to obtain borrowing capacity, to repay future indebtedness, and to obtain additional capital on favorable terms is also substantially dependent upon oil and gas prices. Historically, the markets for oil and gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuations in response to: (i) relatively minor changes in the supply of, and demand for, oil and gas; (ii) market uncertainty; and (iii) a variety of additional factors, all of which are beyond our control. These factors include domestic and foreign political conditions, the price and availability of domestic and imported oil and

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gas, the level of consumer and industrial demand, weather, domestic and foreign government relations, the price and availability of alternative fuels and overall economic conditions. Furthermore, the marketability of our production depends in part upon the availability, proximity and capacity of gathering systems, pipelines and processing facilities. Volatility in oil and gas prices could affect our ability to market our production through such systems, pipelines or facilities. Substantially all of our natural gas production is currently sold to two gas marketing firms on a month-to-month basis at prevailing spot market prices. Oil prices remained subject to unpredictable political and economic forces during fiscal years 2008, 2007 and 2006, and experienced fluctuations similar to those seen in natural gas prices for the year. We believe that oil and gas prices will continue to fluctuate in response to changes in the policies of the Organization of Petroleum Exporting Countries (“OPEC”), changes in demand from many Asian countries and other emerging economies, current events in the Middle East, security threats to the United States, and other factors associated with the world political and economic environment. As a result of the many uncertainties associated with levels of production maintained by OPEC and other oil producing countries, the availabilities of worldwide energy supplies and competitive relationships and consumer perceptions of various energy sources, we are unable to predict what changes will occur in crude oil, natural gas and natural gas liquids prices.

We are subject to uncertainties in reserve estimates and future net cash flows.

This report contains estimates of our oil and gas reserves and the future net cash flows from those reserves, which have been prepared by certain independent petroleum consultants. There are numerous uncertainties inherent in estimating quantities of reserves of oil and gas and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve estimates in this report are based on various assumptions, including, for example, constant oil and gas prices, operating expenses, capital expenditures and the availability of funds, and, therefore, are inherently imprecise indications of future net cash flows. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves set forth in this report. Additionally, our reserves may be subject to downward or upward revision based upon actual production performance, results of future development and exploration, prevailing oil and gas prices and other factors, many of which are beyond our control.

The present value of future net reserves discounted at 10% (the “PV-10”) of proved reserves referred to in this report should not be construed as the current market value of the estimated proved reserves of oil and gas attributable to our properties. In accordance with applicable requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by: (i) the timing of both production and related expenses; (ii) changes in consumption levels; and (iii) governmental regulations or taxation. In addition, the calculation of the present value of the future net cash flows using a 10% discount as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and gas industry in general. Furthermore, our reserves may be subject to downward or upward revision based upon actual production, results of future development, supply and demand for oil and gas, prevailing oil and gas prices and other factors. See “Description of Business and Properties – Oil and Gas Reserves.”

We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.

Our oil and gas business involves a variety of operating risks, including, but not limited to, unexpected formations or pressures, uncontrollable flows of oil, gas, brine or well fluids into the environment (including groundwater contamination), blowouts, fires, explosions, pollution and other risks, any of which could result in personal injuries, loss of life, damage to properties and substantial losses. Although we carry insurance at levels that we believe are reasonable, we are not fully insured against all risks. We do not carry business interruption

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insurance. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on our financial condition and operations.

From time to time, due primarily to contract terms, pipeline interruptions or weather conditions, the producing wells in which we own an interest have been subject to production curtailments. The curtailments range from production being partially restricted to wells being completely shut-in. The duration of curtailments varies from a few days to several months. In most cases, we are provided only limited notice as to when production will be curtailed and the duration of such curtailments. We are not currently experiencing any material curtailment of our production.

We intend to continue our development and exploration activities.  Exploratory drilling and, to a lesser extent, development drilling of oil and gas reserves involve a high degree of risk that no commercial production will be obtained and/or that production will be insufficient to recover drilling and completion costs. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not assure a profit on the investment or a recovery of drilling, completion and operating costs.

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of Calvin A. Wallen, III, our President, Chairman of the Board, and Chief Executive Officer. The loss of the services of Mr. Wallen would have a material adverse effect on our operations. We have not obtained key personnel life insurance on Mr. Wallen.

Certain of our affiliates control a majority of our outstanding common stock, which may affect other shareholders’ ability to influence matters submitted to a vote of shareholders.

As of September 1, 2008, our executive officers, directors and their affiliates and certain 5% shareholders hold approximately 59% of our outstanding shares of common stock. As a result, officers, directors and their affiliates and such shareholders have the ability to exert significant influence or control over our business affairs, including the ability to control the election of directors and results of voting on all matters requiring shareholder approval. This concentration of voting power may delay or prevent a potential change in control.

Certain of our affiliates have engaged in business transactions with the Company, which may result in conflicts of interest.

Certain officers, directors and related parties, including entities controlled by Mr. Wallen, the President and Chief Executive Officer, have engaged in business transactions with the Company which were not the result of arm’s length negotiations between independent parties. Our management believes that the terms of these transactions were as favorable to us as those that could have been obtained from unaffiliated parties under similar circumstances. All future transactions between us and our affiliates will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.

The liquidity, market price and volume of our stock are volatile, and our stock is subject to certain penny stock rules.

Our common stock is traded on the American Stock Exchange (the “AMEX”). The liquidity of our common stock may be adversely affected, and purchasers of our common stock may have difficulty selling our common stock, if our common stock does not continue to trade in that or another suitable trading market.

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There is presently only a limited public market for our common stock, and there is no assurance that a ready public market for our securities will develop. It is likely that any market that develops for our common stock will be highly volatile and that the trading volume in such market will be limited. As of September 1, 2008, the trading price of our common stock was below $5.00 per share. The trading price of our common stock could be subject to wide fluctuations in response to quarter-to-quarter variations in our operating results, announcements of our drilling results and other events or factors. In addition, the U.S. stock market has from time to time experienced extreme price and volume fluctuations that have affected the market price for many companies and which often have been unrelated to the operating performance of these companies. These broad market fluctuations may adversely affect the market price of our securities.

We may experience adverse consequences because of required indemnification of officers and directors.

Provisions of our Articles of Incorporation and Bylaws provide that we will indemnify any director and officer as to liabilities incurred in their capacity as a director or officer and on those terms and conditions set forth therein to the fullest extent of Texas law. Further, we may purchase and maintain insurance on behalf of any such persons whether or not we would have the power to indemnify such person against the liability insured against. The foregoing could result in substantial expenditures by us and prevent any recovery from our officers, directors, agents and employees for losses incurred by us as a result of their actions.

Certain anti-takeover provisions may discourage a change in control.

Provisions of Texas law and our Articles of Incorporation and Bylaws may have the effect of delaying or preventing a change in control or acquisition of our Company. Our Articles of Incorporation and Bylaws include provisions for a classified Board of Directors (although we do not currently have a classified board), “blank check” preferred stock (the terms of which may be fixed by our Board of Directors without shareholder approval), purported limits on shareholder action by written consent in lieu of a meeting, and certain procedural requirements governing shareholder meetings. These provisions could have the effect of delaying or preventing a change in control of our Company.

We do not intend to declare dividends in the foreseeable future.

Our Board of Directors presently intends to retain all of our earnings for the expansion of our business. We therefore do not anticipate the distribution of cash dividends in the foreseeable future. Any future decision of our Board of Directors to pay cash dividends will depend, among other factors, upon our earnings, financial position and cash requirements.

Our internal controls over financial reporting may not be effective, which could have a significant and adverse effect on our business.

Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the Securities and Exchange Commission, which we collectively refer to as Section 404, require us to evaluate our internal controls over financial reporting to allow management to report on those internal controls as of the end of each year beginning in fiscal 2008. Section 404 will also require our independent registered public accounting firm to attest to the effectiveness of our internal controls over financial reporting in future periods. Effective internal controls are necessary for us to produce reliable financial reports and are important in our effort to prevent financial fraud. In the course of our Section 404 evaluations, we may identify conditions that may result in significant deficiencies or material weaknesses and we may conclude that enhancements, modifications or changes to our internal controls are necessary or desirable. Implementing any such matters would divert the attention of our management, could involve significant costs, and may negatively impact our results of operations.

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We note that there are inherent limitations on the effectiveness of internal controls, as they cannot prevent collusion, management override or failure of human judgment. If we fail to maintain an effective system of internal controls or if management or our independent registered public accounting firm were to discover material weaknesses in our internal controls, we may be unable to produce reliable financial reports or prevent fraud, and it could harm our financial condition and results of operations, result in a loss of investor confidence and negatively impact our share price.

We may not have satisfactory title to our properties.

Our contract land professionals have reviewed title records or other title review materials relating to substantially all of our producing properties. The title investigation performed by us prior to acquiring undeveloped properties is thorough, but less rigorous than that conducted prior to drilling, consistent with industry standards. A title opinion obtained on the drill site prior to drilling does not necessarily ensure satisfactory title. We believe we have satisfactory title to all our producing properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. At June 30, 2008, our leaseholds for some of our net acreage were being kept in force by virtue of production on that acreage in paying quantities. The remaining net acreage was held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination. In the normal course of our business, title defects of varying degrees will arise, and, if practicable, reasonable efforts will be made to cure any such defects.

The Company may make acquisitions of oil and gas properties from time to time subject to available resources. In making an acquisition, we generally focus most of our title and valuation efforts on the more significant properties. It is generally not feasible for us to perform an in-depth review of every property we purchase and all records with respect to such properties. However, even an in-depth review of properties and records may not necessarily reveal existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their deficiencies and capabilities. To the extent the seller does not operate the properties, obtaining access to properties and records may be more difficult. Even when problems are identified, the seller may not be willing or financially able to give contractual protection against such problems, and we may decide to assume environmental and other liabilities in connection with acquired properties.

We are subject to various governmental regulations which may cause us to incur substantial costs.

Our operations are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and gas production and related operations are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.

Sales of natural gas by us are not regulated and are generally made at market prices. However, the Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by us, as well as the revenues received by us for sales of such production. Sales of our natural gas currently are made at uncontrolled market prices, subject to applicable contract provisions and price fluctuations that normally attend sales of commodity products.

Since the mid-1980’s, the FERC has issued a series of orders, culminating in Order Nos. 636, 636-A, 636-B and 636-C (“Order 636”), that have significantly altered the marketing and transportation of natural gas. Order 636

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mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of the FERC’s purposes in issuing the orders was to increase competition within all phases of the natural gas industry. Order 636 and subsequent FERC orders issued in individual pipeline restructuring proceedings have been the subject of appeals, and the courts have largely upheld Order 636. Because further review of certain of these orders is still possible, and other appeals may be pending, it is difficult to predict the ultimate impact of the orders on us and our natural gas marketing efforts. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets.

While significant regulatory uncertainty remains, Order 636 may ultimately enhance our ability to market and transport our natural gas, although it may also subject us to greater competition, more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

The FERC has announced several important transportation-related policy statements and proposed rule changes, including the appropriate manner in which interstate pipelines release capacity under Order 636 and, more recently, the price which shippers can charge for their released capacity. In addition, in 1995, the FERC issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. In January 1997, the FERC issued a policy statement and a request for comments concerning alternatives to its traditional cost-of-service rate making methodology. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. While any additional FERC action on these matters would affect us only indirectly, these policy statements and proposed rule changes are intended to further enhance competition in natural gas markets. We cannot predict what action the FERC will take on these matters, nor can we predict whether the FERC’s actions will achieve its stated goal of increasing competition in natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers and marketers with which we compete.

The price we receive from the sale of oil is affected by the cost of transporting such products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil by interstate pipelines, although the most recent adjustment generally decreased rates. These regulations have generally been approved on judicial review. We are not able to predict with certainty the effect, if any, of these regulations on our operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil.

The ultimate impact of the complex rules and regulations issued by the FERC since the mid-1980’s cannot be predicted. We cannot predict what further action the FERC will take on these matters. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.

Additional proposals and proceedings that might affect the natural gas industry are frequently made before Congress, the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Our sales of crude oil and condensate are currently not regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. However, we do not believe that these regulations affect us any differently than other crude oil producers.

The States of Texas and Louisiana and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration for and production

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of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of certain states limit the rate at which oil and gas can be produced from our properties. However, we do not believe we will be affected materially differently by these statutes and regulations than any other similarly situated oil and gas company.

We are subject to various environmental risks which may cause us to incur substantial costs.

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and gas and the discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, penalties or injunctions. In the opinion of management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us. The impact of such changes, however, would not likely be any more burdensome to us than to any other similarly situated oil and gas company.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Furthermore, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We generate typical oil and gas field wastes, including hazardous wastes that are subject to the federal Resources Conservation and Recovery Act and comparable state statutes. The United States Environmental Protection Agency and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our oil and gas operations that are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes,” and therefore be subject to more rigorous and costly operating and disposal requirements.

The Oil Pollution Act (“OPA”) imposes a variety of requirements on responsible parties for onshore and offshore oil and gas facilities and vessels related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The “responsible party” includes the owner or operator of an onshore facility or vessel or the lessee or permittee of, or the holder of a right of use and easement for, the area where an onshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes financial responsibility requirements. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions.

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We own or lease properties that for many years have produced oil and gas. We also own natural gas gathering systems. It is not uncommon for such properties to be contaminated with hydrocarbons. Although we or previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties or on or under other locations where such wastes have been taken for disposal. These properties may be subject to federal or state requirements that could require us to remove any such wastes or to remediate the resulting contamination. All of our properties are operated by third parties over whom we have limited control. Notwithstanding our lack of control over properties operated by others, the failure of the previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact us.

We may be responsible for additional costs in connection with abandonment of properties.

We are responsible for payment of plugging and abandonment costs on our oil and gas properties pro rata to our working interest. Based on our experience, we anticipate that the ultimate aggregate salvage value of lease and well equipment located on our properties will exceed the costs of abandoning such properties. There can be no assurance, however, that we will be successful in avoiding additional expenses in connection with the abandonment of any of our properties. In addition, abandonment costs and their timing may change due to many factors, including actual production results, inflation rates and changes in environmental laws and regulations.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

A description of our properties is included in “Part I. Item 1. Business” and is incorporated herein by reference.

Item 3. Legal Proceedings.

There are no material legal proceedings to which the Company is a party or to which its properties are subject.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Common Stock and Market

The common stock of the Company is traded on the American Stock Exchange (the “AMEX”) under the trading symbol “QBC”. Prior to August 4, 2008, the common stock of the Company was traded on the Over-The-Counter Bulletin Board (the “OTCBB”) under the trading symbol “QBIK”.

At September 1, 2008, there were 60,335,564 shares of common stock outstanding held by approximately 805 shareholders of record.

Under its Articles of Incorporation, as amended, the Company is authorized to issue one class of up to 100,000,000 common shares, par value $0.05 per share, and one class of up to 10,000,000 preferred shares, par value $0.01 per share. As of September 1, 2008, there were no preferred shares of the Company outstanding.

Common Stock Price Range

The following table shows, for the periods indicated, the range of high and low closing price information for our common stock as reported by the OTCBB. Any market for our common stock should be considered sporadic, illiquid and highly volatile. Prices reflect inter-dealer quotations, without adjustment for retail markup, markdowns or commissions, and may not represent actual transactions. Our common stock’s trading range during the periods indicated is as follows:

Fiscal Year 2007	High		Low
1st Quarter	$	0.90	$	0.51
2nd Quarter	$	0.90	$	0.46
3rd Quarter	$	0.90	$	0.65
4th Quarter	$	1.46	$	0.51

Fiscal Year 2008	High		Low
1st Quarter	$	1.35	$	0.91
2nd Quarter	$	1.59	$	1.00
3rd Quarter	$	3.04	$	1.50
4th Quarter	$	4.19	$	2.35

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Through the following exercises of warrants, we issued an aggregate of 1,173,693 shares of common stock, which were not registered under the Securities Act of 1933, as amended, during the fourth quarter of fiscal 2008:

On April 1, 2008, 300,000 warrants were exercised by a warrant holder of the Company and 203,704 shares of Company common stock were issued utilizing a cashless exercise price of $3.04 per share, the closing price of the Company’s common stock on the prior trading day.

On April 1, 2008, a warrant holder of the Company exercised warrants for 100,000 shares of Company common stock, through the payment of $70,000 to the Company.

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On April 2, 2008, 100,000 warrants were exercised by a warrant holder of the Company and 65,150 shares of Company common stock were issued utilizing a cashless exercise price of $2.80 per share, the closing price of the Company’s common stock on the trading day prior to the date of the warrant holder’s subscription notice, which date was March 31, 2008.

On April 2, 2008, 50,000 warrants were exercised by a warrant holder of the Company and 33,291 shares of Company common stock were issued utilizing a cashless exercise price of $2.92 per share, the closing price of the Company’s common stock on the prior trading day.

On April 8, 2008, 5,000 warrants were exercised by a warrant holder of the Company and 3,017 shares of Company common stock were issued utilizing a cashless exercise price of $2.46 per share, the closing price of the Company’s common stock on the prior trading day.

On April 10, 2008, 5,000 warrants were exercised by a warrant holder of the Company and 3,193 shares of Company common stock were issued utilizing a cashless exercise price of $2.70 per share, the closing price of the Company’s common stock on the prior trading day.

On April 16, 2008, 5,000 warrants were exercised by a warrant holder of the Company and 3,374 shares of Company common stock were issued utilizing a cashless exercise price of $3.00 per share, the closing price of the Company’s common stock on the prior trading day.

On April 18, 2008, a warrant holder of the Company exercised warrants for 325,000 shares of Company common stock, through the payment of $317,135 to the Company.

On April 21, 2008, a warrant holder of the Company exercised warrants for 75,000 shares of Company common stock, through the payment of $73,185 to the Company.

On May 14, 2008, a warrant holder of the Company exercised warrants for 100,000 shares of Company common stock, through the payment of $97,580 to the Company.

On June 18, 2008, 250,000 warrants were exercised by a warrant holder of the Company and 186,964 shares of Company common stock were issued utilizing a cashless exercise price of $3.87 per share, the closing price of the Company’s common stock on the prior trading day.

On May 19, 2008, a warrant holder of the Company exercised warrants for 25,000 shares of Company common stock, through the payment of $24,395 to the Company.

On May 26, 2008, a warrant holder of the Company exercised warrants for 50,000 shares of Company common stock, through the payment of $25,000 to the Company.

Aggregate proceeds to the Company of the aforementioned warrant exercises were $607,295, all of which have been or will be used for working capital purposes.  The aforementioned issuances were made in reliance upon an exemption from registration set forth in Section 4(2) of the Securities Act of 1993, as amended, which exempts transactions by an issuer not involving a public offering.

We did not purchase any of our equity securities during the fourth quarter of fiscal 2008.

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Shareholder Return Performance Graph

The following graph compares the cumulative total shareholder returns of our common stock during the five years ended June 30, 2008 with the cumulative total shareholder returns of the AMEX Oil Index and a peer group of 16 oil and gas exploration and production companies comprised of Abraxas Petroleum Corp., The Meridian Resources Corp., GMX Resources Inc., Petrohawk Energy Corp., Chesapeake Energy Corp., Goodrich Petroleum Corp., Northern Oil & Gas Inc., Comstock Resources Inc., EXCO Resources Inc., Penn Virginia Corp., XTO Energy Inc., Quicksilver Resources Inc., Range Resources Corp., Encore Acquisition Co., Plains Exploration & Production Co., St. Mary Land and Exploration Co. (collectively referred to as the “Peer Group Index”). The comparison assumes an investment of $100 on June 30, 2003 in each of our common stock, the AMEX Oil Index and the Peer Group Index.

	6/30/2003		6/30/2004		6/30/2005		6/30/2006		6/30/2007		6/30/2008
Cubic Energy, Inc.	$	100.00	$	171.43	$	288.57	$	228.57	$	380.00	$	1,197.14
AMEX Oil Index	$	100.00	$	134.58	$	187.65	$	243.51	$	297.67	$	324.16
Peer Group Index	$	100.00	$	176.08	$	274.54	$	346.09	$	380.94	$	731.81

Dividend Policy

We have neither declared nor paid any dividends on our common stock since our inception. Presently, we intend to retain our earnings, if any, to provide funds for expansion of our business. Therefore, we do not anticipate declaring or paying cash dividends on our common stock in the foreseeable future. Any future dividends will be subject to the discretion of our Board of Directors and will depend upon, among other things, future earnings, our operating and financial condition, our capital requirements, debt obligation agreements, general business conditions and other pertinent facts. Moreover, the terms of the Credit Facility prohibit the payment of dividends.

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Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of June 30, 2008 with respect to compensation plans (including individual compensation arrangements) under which equity securities of the registrant are authorized for issuance:

	Number of	Weighted
	securities to be	average		Number of shares
	issued upon	exercise price		of common stock
	exercise of	of outstanding		remaining available
	outstanding	options,		for future issuance
	options, warrants	warrants and		under equity
	and rights	rights		compensation plans
2005 Stock Option Plan approved by shareholders	—	$	—	1,341,500
Equity compensation plans not approved by shareholders	—	$	—	—
Total	—			1,341,500

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Item 6. Selected Financial Data.

The following table presents a summary of our financial information for the periods indicated. It should be read in conjunction with our Financial Statements and related notes (beginning on page F-1 at the end of this report) and other financial information included herein.

	Year ended June 30,
(In thousands, except per share data)	2008			2007			2006			2005			2004
Statements of Operations Data:
Total oil and gas sales revenues	$	2,302		$	583		$	509		$	469		$	415
Costs and expenses:
Oil and gas production, operating and development costs	1,163			481			338			273			186
General and administrative expenses	2,488			1,325			1,401			395			240
Depreciation, depletion and amortization	2,152			362			179			364			105
Impairment loss on oil and gas properties	—			1,791			—			—			—
Total costs and expenses	5,803			3,959			1,918			1,032			531
Operating income (loss)	(3,501		)	(3,376		)	(1,409		)	(563		)	(116		)
Non-operating income (expense):
Other income, net	46			38			6			—			2
Interest expense, net	(1,580		)	(1,279		)	(639		)	(193		)	(0		)
Amortization of loan costs	(94		)	(101		)	(67		)	(28		)	—
Total non-operating income (expense)	(1,628		)	(1,342		)	(700		)	(221		)	2
Loss on extinguishment of debt, net	—			(1,083		)	(660		)	—			—
Loss from operations before income taxes	(5,129		)	(5,801		)	(2,769		)	(784		)	(114		)
Income tax expense (benefit)	—			—			—			—			—
Net income (loss)	$	(5,129	)	$	(5,801	)	$	(2,769	)	$	(784	)	$	(114	)
Net loss per common share - basic and diluted	$	(0.09	)	$	(0.12	)	$	(0.07	)	$	(0.02	)	$	(0.00	)
Weighted average common shares outstanding	56,974			50,338			38,477			33,113			31,317
Statements of Cash Flow Data:
Cash provided by (used in) operating activities	$	(1,234	)	$	(1,802	)	$	(964	)	$	(185	)	$	76
Cash provided by (used in) investing activities	$	(15,513	)	$	(4,052	)	$	(4,800	)	$	(2,122	)	$	—
Cash provided by (used in) financing activities	$	15,768		$	8,717		$	5,765		$	2,371		$	—
Balance Sheet Data (at end of period):
Working capital (deficit)	$	1,747		$	2,607		$	(1,357	)	$	576		$	143
Oil and gas properties, and equipment, net	$	26,858		$	13,666		$	11,820		$	3,687		$	434
Total assets	$	29,491		$	18,108		$	13,373		$	4,415		$	707
Long-term liabilities, net of discounts	$	22,971		$	7,627		$	5,155		$	1,612		$	—
Total liabilities	$	23,632		$	9,313		$	7,320		$	1,631		$	130
Shareholders’ equity	$	5,858		$	8,795		$	6,053		$	2,784		$	577
Other Financial Data:
Non-cash stock-based compensation	$	1,255		$	490		$	727		$	79		$	93

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

The following discussion is intended to assist in an understanding of the Company’s historical financial position and results of operations for each year in the three-year period ended June 30, 2008. The Company’s Financial Statements and notes thereto included elsewhere in this Report contain detailed information that should be referred to in conjunction with the following discussion.

General

The Company’s future results of operations and growth are substantially dependent upon (i) its ability to acquire or find and successfully develop additional oil and gas reserves and (ii) the prevailing prices for oil and gas. We have an inventory of drilling locations to pursue after the fiscal year ended June 30, 2008. If we are unable to economically acquire or find significant new reserves for development and exploitation, the Company’s oil and gas production, and thus its revenues, would likely decline gradually as its reserves are produced. In addition, oil and gas prices are dependent upon numerous factors beyond the Company’s control, such as economic, political and regulatory developments and competition from other sources of energy. The oil and gas markets have historically been very volatile, and any significant and extended decline in the price of oil or gas would have a material adverse effect on the Company’s financial condition and results of operations, and could result in a reduction in the carrying value of the Company’s proved reserves and adversely affect its access to capital.

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Summary Operating, Reserve and Other Data

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

	Year ended June 30,
	2008		2007		2006		2005		2004
Operating Data:
Proved Reserves (Bcfe)	6.6		4.3		2.9		0.5		0.3
Production (Mcfe)	244,665		76,214		59,798		70,780		75,176
Producing wells at end of period, gross	32		22		17		17		14
Producing wells at end of period, net	18.42		14.42		13.07		13.65		12.90
Acreage, gross	14,711		17,542		16,913		6,050		930
Acreage, net	6,151		7,364		7,073		2,171		891
Production:
Oil (Bbl)	1,682		967		1,047		506		563
Natural gas (Mcf)	228,219		70,412		53,516		67,744		71,804
Natural gas liquids (gallons)	44,476		—		—		—		—
Total oil, gas and liquids (Mcfe)	244,665		76,214		59,798		70,780		75,182
Average daily (Mcfe)	668		209		164		194		205
Weighted Average Sales Prices:
Oil (per Bbl)	$	102.15	$	61.68	$	59.90	$	43.32	$	32.16
Natural gas (per Mcf)	$	9.01	$	7.44	$	8.34	$	6.61	$	5.55
Natural gas liquids (per gallon)	$	1.66	n/a		n/a		n/a		n/a
Natural gas equivalent (per Mcfe)	$	9.41	$	7.65	$	8.51	$	6.63	$	5.52
Selected Expenses per Mcfe:
Production costs	$	3.60	$	4.18	$	5.05	$	3.33	$	1.92
Workover expenses (non-recurring)	$	0.11	$	1.40	$	—	$	0.08	$	—
Severance taxes	$	0.29	$	0.39	$	0.39	$	0.34	$	0.32
Other revenue deductions	$	0.75	$	0.35	$	0.22	$	0.11	$	0.24
Total lease operating expenses	$	4.75	$	6.32	$	5.66	$	3.86	$	2.48
General and administrative expenses:
Non-cash stock-based compensation	$	5.13	$	6.43	$	12.15	$	1.12	$	1.24
Other general and administrative	$	5.04	$	10.96	$	11.27	4.46		1.95
Total general and administrative	$	10.17	$	17.39	$	23.42	$	5.58	$	3.19
Depreciation, depletion and amortization	$	8.80	$	4.76	$	3.00	$	5.15	$	1.39

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RESULTS OF OPERATIONS

Comparison of Fiscal 2008 to Fiscal 2007

Revenues

OIL AND GAS SALES increased 295% to $2,302,310 for fiscal 2008 from $583,416 for fiscal 2007 primarily due to higher gas volumes resulting from an average of approximately 13 (gross) wells being on-line in Louisiana in fiscal 2008 versus approximately three and one-half wells in fiscal 2007, and a 21% increase in the weighted average sales price for gas (per Mcf).

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as “LEASE OPERATING EXPENSES” elsewhere herein) increased 142% to $1,162,489 (50% of oil and gas sales) for fiscal 2008 from $481,145 (82% of oil and gas sales) for fiscal 2007 primarily due to more wells being on-line in Louisiana, which resulted in: a $307,551 increase in salt water hauling and disposal costs; $126,992 in common facility expenses for production from the Company’s Johnson Branch wells, which did not occur in the prior year period; a $46,470 increase in contract labor costs; a $41,998 increase in state taxes on production (also referred to as “severance taxes” elsewhere herein); and a $156,998 increase in 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. These increases were somewhat offset by a $79,867 drop in non-recurring workover expenses.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) increased 88% to $2,488,133 for fiscal 2008 from $1,325,192 in fiscal 2007 as a result of: a $765,537 increase in non-cash stock compensation expense related primarily to appreciation of the Company’s common stock price, a 29% increase in the number of shares of common stock granted versus the prior year period, and full recognition in fiscal 2008 of stock compensation issued during that year, which vested immediately with no forfeiture provisions, rather than amortization over the four quarters of the service period; a $141,689 increase in cash compensation expense resulting from an increase in the number of employees; a $39,583 increase in reserve report expenses; a $15,428 increase in fees paid to our outside directors; and the following expenses, which occurred in fiscal 2008 but did not occur in the prior year period: $60,000 in contracted professional services fees related to management’s assessment of the Company’s internal controls over financial reporting required by Section 404(a) of the Sarbanes-Oxley Act of 2002; $76,507 in marketing expenses; $51,030 in expense for directors’ and officers’ insurance; and, $23,082 in corporate fees related to the Company’s annual shareholders’ meeting. These increases were partially offset by a $36,279 decrease in legal fees due to non-recurrence of: the preparation of documents and filings related to a private placement of shares of the Company’s common stock in December 2006 and the transacting of the March 2007 debt issue.

DEPRECIATION, DEPLETION AND AMORTIZATION (“DD&A”) increased 494% to $2,152,096 in fiscal 2008 from $362,434 in fiscal 2007 primarily due to an $11,281,505, or 278%, increase in capital expenditures in fiscal 2008 related to the acquisition and development of oil and gas properties.

IMPAIRMENT OF OIL AND GAS PROPERTIES decreased to $0 in fiscal 2008 from $1,790,882 in fiscal 2007. The fiscal 2007 impairment resulted from a downward revision of our reserve estimates, which was effected by the following events: (i) we experienced delays related to third party providers in our Bethany Longstreet acreage, including not receiving contracted-for compression services, which temporarily delayed our ability to produce from these wells; (ii) we did not effectuate final completion of certain wells due to a shift in our focus to the development of our Johnson Branch acreage in Caddo Parish, Louisiana; and, (iii) the lack of

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production history in wells recently brought online lead to a sharper decline curve being utilized by RPS Scotia, Inc. in formulating the reserve estimates.

INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 24% to $1,579,452 in fiscal 2008 from $1,278,721 in fiscal 2007 primarily due to an increase in debt (before discounts) to $23,827,800 at June 30, 2008 from $9,000,000 at June 30, 2007. This increase resulted from the repayment of a $1,300,000 note held by Tauren on February 2, 2007 from the proceeds of a December 2006 equity offering, and the retirement of $5,500,000 of indebtedness held by Petro Capital V. L.P. on March 5, 2007 via the borrowing of $5,000,000 pursuant to the aforementioned Wells Fargo Credit Facility’s senior convertible term loan, subsequent draws of approximately $16,827,800 on a related revolving line of credit, and the borrowing of $2,000,000 under the terms of the May 6, 2008 Subordinated Note. The weighted average debt balance (before discounts) for fiscal 2008 was $16,494,613 as compared to $6,467,579 in fiscal 2007. The Credit Facility with Wells Fargo also resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense with $516,030 being recorded in fiscal 2008 as compared to $164,961 in fiscal 2007. Such increases were somewhat offset by the capitalization of interest expense to the full cost pool for oil and gas properties of $330,608 in fiscal 2008 as compared to zero in fiscal 2007.

LOSS ON EXTINGUISHMENT OF DEBT was $0 in fiscal 2008 as compared to $1,082,887 in fiscal 2007 due to there being no retirement of debt in fiscal 2008. On March 5, 2007, the senior debt held by Petro Capital was retired with proceeds from the Credit Facility with Wells Fargo. In connection with this retirement, the Company recorded a loss on extinguishment of debt in the amount of $(1,082,887) in fiscal 2007. Such amount included the write-off of deferred loan costs ($235,898), and the write-off of the remaining loan discount ($846,989).

Comparison of Fiscal 2007 to Fiscal 2006

Revenues

OIL AND GAS SALES increased 15% to $583,416 in fiscal 2007 from $508,925 in fiscal 2006, due primarily to a 27% increase in oil and gas production, which was partially offset by an 11% decrease in the weighted average sales prices for gas (per Mcf).

Costs and Expenses

OIL AND GAS PRODUCTION, OPERATING AND DEVELOPMENT COSTS (also referred to as “LEASE OPERATING EXPENSES” elsewhere herein) increased 42% to $481,145 in fiscal 2007 from $338,239 in fiscal 2006 due primarily to greater activity resulting from more wells being brought on-line in Louisiana.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”) decreased 5% to $1,325,192 in fiscal 2007 from $1,400,482 in fiscal 2006 primarily as a result of a $266,700 decrease in non-cash compensation expense related to stock grants to officers and directors.  Such decrease was partially offset by a $128,736 increase in compensation expenses resulting from an increase in the number of employees.

DEPRECIATION, DEPLETION AND AMORTIZATION (“DD&A”) increased 102% to $362,434 in fiscal 2007 from $179,237 in fiscal 2006. The increase was primarily due to a $2,595,469, or 143%, increase in capital expenditures in fiscal 2006 related to the acquisition and development of oil and gas properties.

IMPAIRMENT OF OIL AND GAS PROPERTIES increased to $1,790,882 in fiscal 2007 from $0 in fiscal 2006. The impairment resulted from a downward revision of our reserve estimates, which was effected by the following events: (i) we experienced delays related to third party providers in our Bethany Longstreet acreage, including not receiving contracted-for compression services, which temporarily delayed our ability to produce

34

from these wells; (ii) we did not effectuate final completion of certain wells due to a short-term shift in our focus to the development of our Johnson Branch acreage in Caddo Parish, Louisiana; and, (iii) the lack of production history in wells recently brought online lead to a sharper decline curve being utilized by The Scotia Group, Inc. in formulating the reserve estimates.

INTEREST EXPENSE, INCLUDING AMORTIZATION OF LOAN DISCOUNT increased 100% to $1,278,721 in fiscal 2007 from $638,800 in fiscal 2006 due to the increase in debt as a result of the $5,500,000 of Petro Capital debt being in place for eight months in fiscal 2007 as compared to four months in fiscal 2006; and, the borrowing of $5,000,000 pursuant to a new senior convertible term loan on March 5, 2007, and subsequent draws of approximately $4,000,000 on a related revolving line of credit, with Wells Fargo. The Credit Facility with Wells Fargo also resulted in a loan discount being recorded. The weighted average debt balance (before discounts) for fiscal 2007 was $6,467,579 as compared to $3,786,247 in fiscal 2006. The discount is being amortized over the original three-year term of the debt as additional interest expense with $164,961 being recorded in fiscal 2007.

LOSS ON EXTINGUISHMENT OF DEBT increased 64% to $1,082,887 from $660,330 in fiscal 2007. On March 5, 2007, the senior debt held by Petro Capital was retired with proceeds from the Credit Facility with Wells Fargo.  In connection with this retirement, the Company recorded a loss on extinguishment of debt in the amount of $(1,082,887) in fiscal 2007.  Such amount includes the write-off of deferred loan costs ($235,898), and the write-off of the remaining loan discount ($846,989).  In fiscal 2006, the remaining Debentures were retired with proceeds from the then-new senior debt issue held by Petro Capital.  In connection with this retirement, the Company recorded a loss on extinguishment of debt in the amount of $(660,330) in fiscal 2006.  Such amount included the write-off of deferred loan costs ($99,204), the write-off of the remaining loan discount ($237,931), and a prepayment penalty and associated legal fees ($323,195).

Liquidity and Capital Resources

Overview

The Company’s primary resource is its oil and gas reserves. The Company has entered into a senior credit facility, but such facility is not expected to supplement the Company’s internally generated cash flow as a source of financing for its general working capital purposes. Product prices, over which we have no control, have a significant impact on revenues from production and the value of such reserves and thereby on the Company’s borrowing capacity in the event the Company determines to borrow additional funds. Within the confines of product pricing, the Company must be able to find and develop or acquire oil and gas reserves in a cost effective manner in order to generate sufficient financial resources through internal means to complete the financing of its capital expenditure program.

At June 30, 2008, the Company had working capital of $1,746,741. On July 28 and December 15, 2006, we raised $2,100,000 and $3,940,000, respectively, through the private placement of common stock. On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo providing for the Credit Facility, which consists of a convertible term loan of $5,000,000 and a revolving credit facility of $20,000,000 in order to fund the drilling and completion of new wells. On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 to Diversified Dynamics Corporation (see “Notes to Financial Statements – Note E – Long-term debt” elsewhere herein).

During the twelve months ended June 30, 2008, the Company used cash flows from operating activities of $1,233,829 as compared to $1,802,068 in fiscal 2007. Cash flow from operations is dependent on our ability to increase production through our development and exploratory activities and the price received for oil and natural gas.

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Working Capital and Cash Flow

The Company’s working capital decreased to $1,746,741 at June 30, 2008 from $2,606,796 at June 30, 2007, primarily due to capital expenditures of $15,341,903 related to the drilling and completion of new wells and the aforementioned $1,233,829 use of cash from operating activities in fiscal 2008. These uses of cash were somewhat offset by the borrowing of $12,827,800 on the aforementioned revolving line of credit with Wells Fargo, the borrowing of $2,000,000 under the aforementioned subordinated promissory note issued to Diversified  Dynamics Corporation and $1,110,295 in proceeds from the issuance of stock, resulting from the exercise of warrants, during fiscal 2008.

The Company’s working capital increased to $2,606,796 at June 30, 2007 from a deficit of $(1,357,230) at June 30, 2006, primarily due to an increase in cash and cash equivalents resulting from the borrowing of approximately $9,000,000 on the aforementioned Credit Facility with Wells Fargo, which was somewhat offset by capital expenditures of $4,060,398 related to the drilling and completion of new wells and a cash flow deficit from operating activities of $(1,802,068) during fiscal 2007.

Capital Expenditures

The majority of our oil and gas reserves are undeveloped. As such, recovery of the Company’s future undeveloped proved reserves will require significant capital expenditures. Our management estimates that aggregate capital expenditures ranging from a minimum of approximately $6,000,000 (from currently available funds and projected cash from operating activities) to a maximum of approximately $36,000,000 (subject to the availability of additional financing) will be made to further develop these reserves during fiscal 2009. Moreover, additional capital expenditures may be required for exploratory drilling on our undeveloped acreage. The Company may increase its planned activities for fiscal 2009 if product prices improve and if we are able to obtain the additional capital resources necessary to finance such activities. However, to the extent that: i) we are not able to raise additional capital; or ii) drilling rigs, drill pipe and other material used in oil and gas drilling and completing are unavailable, our capital expenditures will be restricted.

Capital Resources

The Company plans to fund its development and exploratory activities through cash on hand (which was approximately $5 million as of the date of this filing), cash provided from operations; the potential exercises of warrants for cash; and one of, or a combination of, the following potential transactions: a private placement of common stock; a public offering of common stock; a joint venture with a more well-financed industry partner in which we would farm-out a to-be-determined percentage of our working interests in certain properties; or a disposition of assets.

While we expect production from the wells drilled and completed in fiscal 2006, 2007, 2008 and subsequent to the end of fiscal 2008 to provide cash flow to support additional drilling in fiscal 2009, the Company cannot be certain that adequate funds will be available from cash on hand, operating cash flow, the exercise of warrants, and the aforementioned potential transactions to fully fund the projected capital expenditures for fiscal 2009. Additionally, because future cash flows, the availability of borrowings, and the ability to consummate 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.

Although the Company believes it will be able to obtain funds pursuant to the above-mentioned alternatives, management cannot be assured that such capital resources will be available to the Company. If we are unable to

36

obtain such capital resources on a timely basis, the Company may curtail its planned development and exploratory activities.

Subsequent Events

Subsequent to the end of fiscal 2008, during July and August, 2008, the Company completed for production four wells in its Johnson Branch acreage, two of which were completed in the Bossier/Haynesville shales, bringing the Company’s number of producing wells in Louisiana to 20. Also, since the end of fiscal 2008, Cubic has drilled two wells, the Estes 7-1 and the Red Oak Timber 5-1 (our fourth and fifth wells to be drilled into the Bossier/Haynesville shales), to total depth of approximately 11,950 feet into the Bossier/Haynesville shales in its Bethany Longstreet acreage. Cubic has a 35% working interest in both wells. The Estes 7-1 was drilled using a casing program with 7 5/8” pipe for the intermediate string, which will allow the Company to drill horizontally into the Bossier/Haynesville shales at a later date, after being vertically completed initially in the Cotton Valley formation.

As of September 1, 2008, the Company had successfully drilled 22 wells in northwest Louisiana with 20 having been completed as producers of hydrocarbons; the two other wells are awaiting completion. As of such date, 10 Johnson Branch wells have been completed as hydrocarbon producers in the Cotton Valley sandstones and two into the Bossier/Haynesville shales. Cubic has a 49% working interest in its Johnson Branch acreage. Seven miles to the South, in its Bethany Longstreet acreage, Cubic has eight wells producing from the Cotton Valley and Hosston formations. Cubic has a 25% working interest in seven of these producing wells, and a 35% working interest in the Estes 8-1 well. Work is ongoing at the Bethany Longstreet and Johnson Branch wells to increase the average daily production from these areas. We also anticipate that we will complete and fracture stimulate additional zones of certain Johnson Branch wells.

Given the forgoing subsequent events, the Company does not believe that the downward revisions in estimates taken in the fiscal 2008 and 2007 reserve reports (please also see Item 1. Business – “DESCRIPTION OF BUSINESS” and Item 1. Business – “OIL AND GAS RESERVES”, and Notes to Financial Statements, “Note J - Oil and gas reserves information (unaudited)”) will have a material impact on the Company’s future prospects.

All of the Company’s Louisiana acreage lies atop the center of what is known in our industry as the “Haynesville Shale Play” (which we refer to as the “Bossier/Haynesville shales” elsewhere herein), which is believed in our industry to be one of the most prolific field discoveries in the United States. The discovery of the existence of the Bossier/Haynesville shale formations in the Company’s acreage mandated that we redirect capital in fiscal 2008 to protect our rights to this formation, which took spending away from the maximization of development of the Cotton Valley formation in our Bethany Longstreet and Johnson Branch fields.

Our first round of drilling was undertaken to maximize retention of our lease rights to develop our Johnson Branch and Bethany Longstreet acreage. Infrastructure costs have required greater capital outlay than anticipated. This variance, coupled with increases in overall drilling and completion costs, had an effect on the completion techniques that we utilized in fiscal 2008. While it is in the Company’s future development plans to re-complete this first round of producing wells at a later date, the Company’s focus has changed from maximizing production and reserves in the first round of drilling to holding acreage and preserving capital for potentially much greater production and reserves from the emerging Haynesville Shale Play.

The majority of the Company’s unproven acreage lies in our Johnson Branch field. Reservoir analysis produced by a third-party engineer for the Johnson Branch acreage indicates a prolific and economic Bossier/Haynesville shale formation and a productive and economic Cotton Valley formation. Wells drilled by the Company subsequent to the end of fiscal 2008 into the Bossier/Haynesville shale formation in our Bethany Longstreet field seem to indicate the same productive formation characteristics as compared to the wells drilled into the Bossier/Haynesville shales in our Johnson Branch acreage. Moreover, horizontal Cotton Valley formation wells drilled by our competitors in the Bethany Longstreet field have demonstrated productive characteristics.

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Accordingly, while work undertaken by the Company subsequent to the end of fiscal 2008 has allowed us to improve our completion techniques for vertical Cotton Valley wells in our Bethany Longstreet and Johnson Branch fields, going forward, the Company contemplates horizontal drilling of all its Cotton Valley and Bossier/Haynesville wells.

The redirection of the Company’s focus outlined above impacted the Company’s proved reserves amounts for the fiscal year ended June 30, 2008 as follows: (i) only horizontal wells for the Cotton Valley sandstone and Bossier/Haynesville shale formations are now contemplated, which resulted in the loss of Proved Undeveloped (“PUD”) reserves for certain Cotton Valley wells that had previously been allowed with a vertical drilling program; and (ii) the lack of production history information as of June 30, 2008 for horizontal Cotton Valley and horizontal Bossier/Haynesville shale wells adversely impacted assumptions regarding both initial production rates and production decline curves used in calculating the Company’s reserve estimates. The Company believes that proceeding at a more measured drilling pace for fiscal 2009 will allow the Company to take advantage of improved completion techniques, and, pursuant to the data filed subsequent to the end of fiscal 2008 by our competitors with respect to productive wells in the Haynesville Shale Play, that the two wells drilled and the four wells completed subsequent to the end of fiscal 2008 (see Item 1. Business – “RECENT DEVELOPMENTS” elsewhere herein) will result in a significant increase in reserves for fiscal 2009.

Critical Accounting Policies

The preparation of the financial statements requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of our accounting estimates and judgments which management believes are most significant in its application of generally accepted accounting principles used in the preparation of the financial statements.

Impairment of long-lived assets and long-lived assets to be disposed of

The Company has adopted the provisions of the Financial Accounting Standards Board’s (the “FASB”) Statement of Financial Accounting Standards (“FAS”) No. 144 (“FAS No. 144”), Accounting for the Impairment or Disposal of Long-Lived Assets effective for periods beginning July 1, 2002, and thereafter. FAS No. 144 replaces FAS No. 121, and, among other matters, addresses financial accounting and reporting for the impairment or disposal of long-lived assets. FAS No. 144 retains the basic provisions of FAS No. 121, but broadens its scope and establishes a single model for long-lived assets to be disposed of by sale. In addition, the Company is subject to the rules of the Securities and Exchange Commission with respect to impairment of oil and gas properties accounted for under the full cost method of accounting, as described below.

Full cost method of accounting for oil and gas properties

The Company has adopted the full cost method of accounting for oil and gas properties. Management believes adoption of the full cost method more accurately reflects management’s exploration objectives and results by including all costs incurred as integral for the acquisition, discovery and development of whatever reserves ultimately result from its efforts as a whole. Under the full cost method of accounting, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs related to exploratory and development activities, and directly related overhead costs, are capitalized into the full cost pool.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects

38

can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

In addition, the capitalized costs are subject to a “full cost ceiling test,” which generally limits such costs to the aggregate of the “estimated present value” (discounted at a 10 percent (10%) interest rate) of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.

Oil and gas revenues

The Company recognizes oil and gas revenues when oil and gas production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. Differences between sales and production volumes during the years ended June 30, 2008, 2007 and 2006 were not significant.

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Certain significant estimates

Management’s estimates of oil and gas reserves are based on various assumptions, including constant oil and gas prices. It is reasonably possible that a future event in the near term could cause the estimates to change and such changes could have a severe impact. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimates. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. While it is at least reasonably possible that the estimates above will change materially in the near term, no estimate can be made of the range of possible changes that might occur.

Stock-based compensation

The Company accounts for its stock-based employee compensation plans pursuant to FAS No. 123R, Share-Based Payment, which is a revision of FAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). This FAS requires the Company to recognize compensation costs related to stock-based payment

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transactions (i.e., the granting of stock options and warrants, and awards of unregistered shares of common stock) in the financial statements. With limited exceptions, the amount of compensation is measured based on the grant-date fair value of the equity issued. Compensation cost is recognized over the period that an employee provides services in exchange for the award. This new standard became effective for awards that are granted, modified or settled in cash in interim and annual financial periods beginning after June 30, 2006.

Other Accounting Policies and Recent Accounting Pronouncements

Please see “Notes to Financial Statements – Note B – Significant accounting policies” elsewhere herein.

Inflation

Although the level of inflation affects certain of the Company’s costs and expenses, inflation did not have a significant effect on the Company’s results of operations during fiscal 2008.

Related Party Transactions

A description of our related party transactions is included in “Note F – Related party transactions” in the Notes to the Financial Statements of the Company included elsewhere in this Report, and is incorporated herein by reference.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance our liquidity and capital resource positions, or for any other purpose.

Forward-Looking Statements and Safe Harbor Provisions

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Such forward-looking statements are based on current expectations that involve a number of risks and uncertainties that could cause actual results to differ materially from the results discussed in the forward-looking statements. Generally, forward-looking statements include words or phrases such as “management anticipates,” “the Company believes,” “the Company anticipates,” and words and phrases of similar impact. The forward-looking statements are made pursuant to safe harbor provisions of the Private Securities Litigation’s Reform Act of 1995.

The factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: (i) industry conditions and competition, (ii) the cyclical nature of the industry, (iii) domestic and worldwide supplies and demand for oil and gas, (iv) operational risks and insurance, (v) environmental liabilities which may arise in the future which are not covered by insurance or indemnity, (vi) the impact of current and future laws and government regulations, as well as repeal or modification of same, affecting the oil and gas industry and the Company’s operations in particular, (vii) production levels and other activities of OPEC and other oil and gas producers, and the impact that the above factors and other events have on the current and expected future pricing of oil and natural gas, and (viii) the risks described from time to time in the Company’s reports filed with the Securities and Exchange Commission.

The forward-looking statements in this report are subject to all the risks and uncertainties which are described in this document. We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and are not taken into consideration in the forward-looking statements.

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For all of these reasons, actual results may vary materially from the forward-looking statements and we cannot assure you that the assumptions used are necessarily the most likely. We will not necessarily update any forward looking statements to reflect events or circumstances occurring after the date the statement is made except as may be required by federal securities laws.

There are a number of risks that may affect our future operating results and financial condition. See “Item 1A. Risk Factors.”

Item 7A. 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. To date, we have not entered into futures contracts or other hedging agreements to manage the commodity price risk for a portion of our production.

Interest Rate Risk

As of June 30, 2008, we had $23,827,800 of long-term debt outstanding under our Credit Facility and the Subordinated Note, each of which matures in fiscal 2010 and bears interest at the prime rate plus 2.0%. As a result, our interest costs fluctuate based on short-term interest rates. Based on the aforementioned borrowings outstanding at June 30, 2008, a 100 basis point change in interest rates would change our annual interest expense by approximately $238,828. We had no interest rate derivatives during fiscal 2008.

Item 8.    Financial Statements and Supplementary Data.

The Report of Independent Accountants, Financial Statements and any supplementary financial data required by this Item are set forth on pages F-1 through F-37 of this Report and are incorporated herein by reference.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

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Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13(a)-15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an assessment, including testing, of the effectiveness of our internal control over financial reporting as of June 30, 2008 based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Based on our evaluation under the criteria set forth in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of June 30, 2008. This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. We were not required to have, nor have we engaged our independent registered public accounting firm to perform, an audit on our internal control over financial reporting pursuant to the rules of the Securities and Exchange Commission that permit us to provide only management’s report in this Annual Report.

Changes in Internal Control Over Financial Reporting

Subsequent to our evaluation, there were no changes in internal controls or other factors that could materially affect, or are reasonably likely to materially affect, these internal controls. We maintain a system of internal control over financial reporting. There were no changes in our internal control over financial reporting during the fourth quarter of fiscal 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Inherent Limitations on Internal Control

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple errors. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

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Certifications

Our chief executive officer and chief financial officer have completed the certifications required to be filed as an Exhibit to this Report (see Exhibits 31.1 and 31.2) relating to the design of our disclosure controls and procedures and the design of our internal control over financial reporting.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Directors and Executive Officers

The following table provides information concerning each of our executive officers and directors as of September 1, 2008:

Name	Age	Position(s) Held with Cubic	Director Since
Calvin A. Wallen, III	53	Chairman of the Board, President and Chief Executive Officer	1997
Scott D. Guffey	44	Chief Financial Officer	n/a
Jon S. Ross	44	Corporate Secretary and Director	1998
Gene C. Howard	81	Director	1991
Herbert A. Bayer	59	Director	2003
Bob L. Clements	65	Director	2004

CALVIN A. WALLEN, III has served as the President and Chief Executive Officer of the Company since December 1997, and as Chairman of the Board of Directors since June 1999. Mr. Wallen has over 20 years of experience in the oil and gas industry working as a drilling and petroleum engineer. Prior to joining Cubic, Mr. Wallen was employed by Superior Oil and various other drilling contractors including Resource, Tom Brown and Rowan International. Mr. Wallen assisted in the design and construction of several land rigs with advanced drilling systems and has domestic and international experience in drilling engineering. While employed by Rowan International, Mr. Wallen gained experience in drilling high angle directional wells at Prudhoe Bay on contract to Arco. In 1982, Mr. Wallen began acquiring and developing oil and gas properties, forming a production company that has evolved into Tauren Exploration, Inc. Mr. Wallen attended Texas A&M University at College Station, Texas.

SCOTT D. GUFFEY joined the Company in August 2007 as Chief Financial Officer and brings more than 20 years of corporate finance-related experience to the Company. Prior to joining Cubic, Mr. Guffey served from 2000 through 2006 as Vice President of Corporate Finance for venture capital-backed BenefitMall Inc., a leading broker services provider that was acquired by Allied Capital in late 2006. Prior to joining BenefitMall, Mr. Guffey served as Vice President of Finance, Mergers & Acquisitions (“M&A”) and Investor Relations for publicly-traded Aegis Communications Group, Inc. from 1997 through 2000. Before joining Aegis, he was Vice President of Investment Banking with Principal Financial Securities, Inc. for three years, and has seven years of Financial Planning & Analysis and M&A experience with Electronic Data Systems Corporation. Mr. Guffey holds an M.B.A from Southern Methodist University’s Cox School of Business and a B.A. in Economics from the University of Virginia.

JON S. ROSS has served as a director of the Company since April 1998 and as Secretary since November 1998. Since 1989, Mr. Ross has been a practicing attorney in Dallas, Texas representing over 80 business entities. He has served on several community and not-for-profit committees and boards and has been asked to speak to corporate and civic leaders on a variety of corporate law topics. Mr. Ross graduated from St. Mark’s School of Texas with honors in 1982 and graduated from the University of Texas at Austin in 1986 with a B.B.A. in Accounting. He then graduated from the University of Texas School of Law in 1989 attaining a Juris Doctorate degree.

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GENE C. HOWARD is the Senior Partner of the law firm of Howard, Widdows, and Bufogle, P.C. of Tulsa, Oklahoma and has been engaged primarily in the private practice of law over the past thirty-five years. Mr. Howard served in the Oklahoma State Senate from 1964 through 1982 and was President Pro Tem from 1975 through 1981. In addition, he served as the Chairman of the Board of Farmers and Exchange Bank from 1972 through 1991 and on the Board of Directors of Local Federal Bank of Oklahoma. Mr. Howard is a Director of the Oklahoma State Education and Employment Group Insurance Board and presently acts as Chairman. Mr. Howard served as Director of EntreCap Financial Corporation and Hinderliter Construction, Inc. from 1991 to August of 1992. He is also Chairman of the Board of Philadelphia Mortgage Trust.

HERBERT A. BAYER has served as a director of Cubic Energy, Inc. since May 2003. From 2006 to 2008, Mr. Bayer served as Global Director of Wi-Fi and Municipal Markets for SmartSynch, Inc., which provides GPRS and Wi-Fi Smart Metering Technology for Smart Grid Deployments for the electric utility industry. Prior to joining SmartSynch, Mr. Bayer served as Director of Client Services for CH2M HILL, an engineering, construction and operations company, from 2005 to 2006, and National Director of Sales for Hexagram Inc. from 2003 to 2005. During his career, Mr. Bayer has worked with investor-owned utilities, government-run municipalities and electric cooperatives. His work experience includes work in Electronic Meter Reading, Automatic Meter Reading, Load Research, Internet Applications, and Wi-Fi Network Systems. Mr. Bayer’s major course of study at Indiana State University was Business Management.

BOB L. CLEMENTS joined the Company’s board of directors in February 2004. Mr. Clements has a degree in the OPM Program from the Harvard Business School. Mr. Clements has been in the wholesale food and restaurant business for over thirty years, currently controlling the largest independent producer of stuffed jalapenos and corn dogs as well as two successful restaurants in the Rockwall, Texas area. Mr. Clements has served and currently serves on a variety of profit and charitable committees and boards.

There are no family relationships among any of the directors or executive officers of the Company. See “Certain Relationships and Related Transactions” for a description of transactions between the Company and its directors, executive officers or their affiliates.

Audit Committee; Financial Expert

The Audit Committee is comprised of Messrs. Howard (Chairman), Clements and Bayer. All of the members of the Audit Committee are “independent” under the rules of the SEC. The Board of Directors, after reviewing all of the relevant facts, circumstances and attributes, has determined that Mr. Howard is the sole “audit committee financial expert” on the Audit Committee.

Compliance with Section 16(a) of the Exchange Act

Section 16(a) of the Exchange Act requires the Company’s directors, executive officers, and holders of more than 10% of the common stock to file with the SEC reports of ownership and changes in ownership of common stock. SEC regulations require those directors, executive officers, and greater than 10% shareholders to furnish the Company with copies of all Section 16(a) forms they file. Based on the Company’s review of reports, the Company believes that the directors, executive officers, and greater than 10% shareholders complied with all applicable Section 16(a) filing requirements during fiscal 2008.

Code of Ethics

The Company has adopted a Code of Ethics that applies to its directors, officers and employees. The Company will provide a copy of its Code of Ethics, without charge, to any stockholder who makes such request in writing to the Company, attention:  Secretary.

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Item 11. Executive Compensation.

Compensation Discussion and Analysis

General. Our Board of Directors has established a Compensation Committee, comprised entirely of independent non-employee directors, with authority to set all forms of compensation of our executive officers. Messrs. Bayer, Clements and Howard comprised the Compensation Committee in fiscal 2008, with Mr. Howard serving as its Chairman. The Compensation Committee has overall responsibility for our executive compensation policies as provided in a written charter adopted by the Board of Directors. The Compensation Committee is empowered to review and approve the annual compensation and compensation procedures for our executives: the President and Chief Executive Officer, the Chief Financial Officer, and the Secretary. The Compensation Committee does not delegate any of its functions to others in setting compensation.

When establishing base salaries, cash bonuses and equity grants for each of the executives, the Compensation Committee considers the recommendations of the President and Chief Executive Officer and the Secretary, the executive’s role and contribution to the management team, responsibilities and performance during the past year and future anticipated contributions, corporate performance, and the amount of total compensation paid to executives in similar positions, and performing similar functions, at other companies for which data was available, as provided by third party compensation studies. One such study, published in April 2007 by Salary.com was a blind survey of over 1,000 companies located in the Dallas metropolitan area in the “Energy & Utilities” industry with less than 100 full-time equivalent employees. Another study, published in December 2004, included data from a survey of the following comparable companies: Arena Resources, Inc., ATP Oil & Gas, Berry Petroleum Company, Canadian Superior Energy, Edge Petroleum, Goodrich Petroleum, Infinity Inc., Petroleum Development Corp., The Meridian Resources Corp., and The Exploration Company.

The Compensation Committee relies upon its judgment in making compensation decisions, after reviewing the Company’s performance and evaluating each executive’s performance during the year. The Committee generally does not adhere to formulas or necessarily react to short-term changes in business performance in determining the amount and mix of compensation elements. We incorporate flexibility into our compensation programs and in the assessment process to respond to and adjust for the evolving business environment.

Compensation Philosophy. The Compensation Committee’s compensation philosophy is to reward executive officers for the achievement of short and long-term corporate objectives and for individual performance. The objective of this philosophy is to provide a balance between short-term goals and long-term priorities to achieve immediate objectives while also focusing on increasing shareholder value over the long term. Also, to ensure that we are strategically and competitively positioned for the future, the Compensation Committee has the discretion to attribute significant weight to other factors in determining executive compensation, such as maintaining competitiveness, pursuing growth opportunities and achieving other long-range business and operating objectives. The level of compensation should also allow us to attract, motivate, and retain talented executive officers that contribute to our long-term success. The compensation of our President and Chief Executive Officer and other executive officers is comprised of cash compensation and long-term incentive compensation in the form of base salary, discretionary bonuses and unregistered stock awards.

Elements of Our Compensation Program and Why We Pay Each Element. For fiscal 2008, our total compensation for executive officers consisted of base salary, bonuses and long-term incentives in the form of common stock awards. In setting fiscal 2008 compensation, the Compensation Committee considered the specific factors discussed below:

Base Salary. In setting the executive officers’ base salaries, the Compensation Committee considers the achievement of corporate objectives as well as individual performance. Because the Compensation Committee believes that executive compensation should be viewed in terms of a balanced combination of cash compensation (i.e., base salaries and bonuses) and long-term incentive (i.e., grants of unregistered stock), base

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salaries are targeted to approximate the low end of the range of base salaries paid to executives of similar companies for each position. To ensure that each executive is paid appropriately, the Compensation Committee considers the executive’s level of responsibility, prior experience, overall knowledge, contribution to business results, existing equity holdings, executive pay for similar positions in other companies, and executive pay within our company.

Base salaries and base salary increases for our named executive officers in fiscal 2008 were as follows:

Name	Amount of Base Salary Increase for Fiscal 2008			Base Salary for Fiscal 2008
Calvin A. Wallen, III	$	50,000		$	200,000
Scott D. Guffey	$	—		$	135,000
Jon S. Ross	$	90,000	(1)	$	150,000

(1)Effective July 1, 2007, Mr. Ross transitioned from a part-time employee, being paid an annual base salary of $60,000, to a full-time employee of the Company with a base salary of $100,000. His base salary was subsequently increased to $150,000 on February 1, 2008.

Discretionary Bonuses. Executive bonuses are intended to link executive compensation with the attainment of Company goals. The actual payment of bonuses is primarily dependent upon the extent to which these Company-wide objectives are achieved. Determination of executive bonus amounts is not made in accordance with a strict formula, but rather is based on objective data combined with competitive ranges and internal policies and practices, including an overall review of both individual and corporate performance. For fiscal year 2008, bonuses to executives were primarily based upon the achievement of certain business objectives including progress in meeting our expected drilling and completion schedule, and the obtainment of additional financing. The President and Chief Executive Officer has the discretion to recommend to the Compensation Committee to increase or decrease bonuses for all other executive officers, but any bonus amounts must be approved by the Compensation Committee.

Long-Term Incentives. On December 29, 2005, the shareholders of the Company approved the 2005 Stock Option Plan (the “Plan”) under which our executive officers may be, among other forms of compensation, compensated through grants of unregistered shares of our common stock and/or grants of options to purchase shares of common stock. The Compensation Committee approves Plan grants that provide additional incentives and align the executives’ long-term interests with those of the shareholders of the Company by tying executive compensation to the long-term performance of the Company’s stock price. Annual equity grants for our executives are typically approved in January.

The Compensation Committee recommends equity to be granted to an executive with respect to shares of common stock based on the following principal elements including, but not limited to:

·President and Chief Executive Officer’s and Secretary’s recommendations;

·Management role and contribution to the management team;

·Job responsibilities and past performance;

·Future anticipated contributions;

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·Corporate performance; and

·Existing equity holdings.

Determination of equity grant amounts is not made in accordance with a formula, but rather is based on objective data combined with competitive ranges, past internal policies and practices and an overall review of both individual and corporate performance. Equity grants may also be made to new executives upon commencement of employment and, on occasion, to executives in connection with a significant change in job responsibility. The Compensation Committee believes annual equity grants more closely align the long-term interests of executives with those of shareholders and assist in the retention of key executives. As such, these grants comprise the Company’s principal long-term incentive to executives.

Other Compensation Policies Affecting the Executive Officers

Compliance with Section 162(m) of the Internal Revenue Code. Section 162(m) disallows a federal income tax deduction to publicly held companies for certain compensation paid to our Named Executive Officers to the extent that compensation exceeds $1 million per executive officer covered by Section 162(m) in any fiscal year. The limitation applies only to compensation that is not considered “performance based” as defined in the Section 162(m) rules. In designing our compensation programs, the Compensation Committee considers the effect of Section 162(m) together with other factors relevant to our business needs. We have historically taken, and intend to continue taking, appropriate actions, to the extent we believe desirable, to preserve the deductibility of annual incentive and long-term performance awards. However, the Compensation Committee has not adopted a policy that all compensation paid must be tax-deductible and qualified under Section 162(m). We believe that the fiscal 2008 base salary, annual bonus and stock grants paid to the individual executive officers covered by Section 162(m) will not exceed the Section 162(m) limit and will be fully deductible under Section 162(m).

Stock Ownership Requirements. The Compensation Committee does not maintain a policy relating to stock ownership guidelines or requirements for our executive officers because the Compensation Committee does not feel that it is necessary to impose such a policy on our executive officers. If circumstances change, the Compensation Committee will review whether such a policy is appropriate for executive officers.

Employment Agreements. On February 29, 2008, the Company entered into employment agreements with its President and Chief Executive Officer, Calvin A. Wallen, III, and Secretary, Jon S. Ross. The agreement with Mr. Wallen provides for a base salary of $200,000 per year, while the agreement with Mr. Ross provides for a base salary of $150,000 per year. The other terms and conditions of the agreements are substantially consistent.

Both agreements provide for a term of employment of 36 months from the effective date of February 1, 2008, which term shall be automatically extended by one additional month upon the expiration of each month during the term; provided, that the Company may terminate subsequent one-month extensions at any time. Each agreement is subject to early termination by the Company in the event that the employee dies, becomes totally disabled or commits an act constituting “Just Cause” under the agreement. The agreements provide that Just Cause includes, among other things, the conviction of certain crimes, habitual neglect of his duties to the Company or other material breaches by the employee of the agreement. Each agreement also provides that the employee shall be permitted to terminate his employment upon the occurrence of “Good Reason,” as defined in the agreement. The agreements provide that Good Reason includes, among other things, a material diminution in the employee’s authority, duties, responsibilities or salary, or the relocation of the Company’s principal offices by more than 50 miles. If the employee’s employment is terminated by (a) the Company other than due to the employee’s death, disability or Just Cause, or (b) the employee for Good Reason, then the Company is required to pay all remaining salary through the end of the then-current term. The foregoing severance payment is subject to reduction under certain conditions.

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The following table sets forth the estimated amounts that would be payable to each of the named executives upon a termination under the scenarios outlined above, excluding termination for Just Cause or on account of death or disability, assuming that such termination occurred on June 30, 2008. There can be no assurance that these scenarios would produce the same or similar results as those disclosed if a termination occurs in the future.

Without Just Cause/For Good Reason	Severance Payment (1)		Total
Calvin A. Wallen, III	$	600,000	$	600,000
Jon S. Ross	$	450,000	$	450,000

(1)Represents 36 months of base salary.

Chief Executive Officer Compensation

Mr. Wallen received $170,833 in base salary for fiscal 2008. His annual base salary was increased from $150,000 at the beginning of the fiscal year to $200,000, effective February 1, 2008. Mr. Wallen received a common stock award of 150,000 unregistered shares granted on January 31, 2008, which vested immediately. Rule 144 promulgated under the Securities Act, which permits certain re-sales of unregistered securities, currently requires that such securities be paid for and held for a minimum of six months before they may be resold.

Chief Financial Officer Compensation

Mr. Guffey’s annual base salary for fiscal 2008 was $135,000, of which he received $116,492 because he was appointed Chief Financial Officer subsequent to the beginning of the fiscal year, on August 20, 2007. He received a common stock award of 90,000 unregistered shares granted on August 20, 2007, which vested on a quarterly schedule with 18,750 shares vesting on each of November 20, 2007, February 20, 2008 and May 20, 2008; and the remaining 33,750 shares vesting, subsequent to the end of fiscal 2008, on August 20, 2008.

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Summary Compensation Table

The following table shows information regarding the compensation earned during the fiscal year ended June 30, 2008 by our Chief Executive Officer, our current Chief Financial Officer, our former Chief Financial Officer and our other most highly compensated executive officer who was employed by us as of June 30, 2008 and whose total compensation exceeded $100,000 during that fiscal year (the “Named Executive Officers”):

Name and Principal Position		Fiscal Year	Salary		Bonus		Stock Awards (1)		All Other Compensation (2)		Total
Calvin A. Wallen, III		2008	$	170,833	$	—	$	241,500	$	3,600	$	415,933
Chairman of the Board,		2007	$	150,000	$	—	$	120,000	$	3,600	$	273,600
President and Chief
Executive Officer
James L. Busby	(3)	2008	$	—	$	—	$	—	$	—	$	—
Former Chief Financial		2007	$	80,601	$	2,100	$	60,000	$	3,300	$	146,001
Officer
Scott D. Guffey	(4)	2008	$	116,492	$	1,000	$	103,500	$	3,300	$	224,292
Chief Financial Officer		2007	$	—	$	—	$	—	$	—	$	—
Jon S. Ross		2008	$	120,833	$	2,000	$	161,000	$	3,600	$	287,433
Secretary and Director	(5)	2007	$	60,000	$	23,000	$	38,000	$	3,600	$	124,600

(1)On January 31, 2008 we granted our Named Executive Officers a total of 250,000 unregistered shares of common stock as follows: Mr. Wallen, 150,000 shares; and Mr. Ross, 100,000 shares. These shares vested immediately on the grant date. On August 20, 2007, Mr. Guffey was granted 90,000 unregistered shares of common stock, which vested on a quarterly schedule. On January 10, 2007 we granted our Named Executive Officers a total of 272,500 unregistered shares of common stock as follows: Mr. Wallen, 150,000 shares; Mr. Busby, 75,000 shares; and Mr. Ross, 47,500 shares. These shares vested immediately on the grant date.

(2)All Other Compensation consists solely of a $300 per month reimbursement towards each officer’s medical insurance premiums. The Company does not provide group health insurance coverage to its employees.

(3)Mr. Busby resigned as Cubic’s Chief Financial Officer effective May 18, 2007.

(4)Mr. Guffey was appointed Cubic’s Chief Financial Officer on August 20, 2007.

(5)Effective July 1, 2007, Mr. Ross transitioned from a part-time employee being paid an annual base salary of $60,000 to a full-time employee of the Company with an annual base salary of $100,000. His annual base salary was subsequently increased to $150,000 on February 1, 2008.

Fiscal 2008 Grants of Plan-Based Awards

The following table provides details regarding equity grants in fiscal 2008 to the Named Executive Officers. No stock options were granted to executive officers last year and thus any reference to options in the table below has been omitted.

Name	Grant Date	All Other Stock Awards: Number of Shares	Grant Date Fair Value of Stock Award
Calvin A. Wallen, III	January 31, 2008	150,000	$	241,500
Scott D. Guffey	August 20, 2007	90,000	$	103,500
Jon S. Ross	January 31, 2008	100,000	$	161,000

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Stock Grants

On January 10 and January 18, 2007, the Company issued 489,500 and 52,500 unregistered shares, respectively, to the officers and directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $391,600 and $42,000, respectively, based on the last sale price on the OTC Bulletin Board of the Company’s common stock. Such amounts were amortized to compensation expense on a quarterly basis during calendar year 2007. An additional $30,000 was recorded when our former Chief Financial Officer resigned during fiscal 2007. Accordingly, $186,800 and $246,800 was recorded as compensation expense and included in general and administrative expense for the fiscal years ended June 30, 2008 and 2007, respectively. The Named Executive Officers received the following grants: (i) 150,000 unregistered shares to Calvin A. Wallen, III, (ii) 75,000 unregistered shares to James L. Busby, and (iii) 47,500 unregistered shares to Jon S. Ross.

On August 20, 2007, the Company issued 90,000 unregistered shares to the current Chief Financial Officer of the Company pursuant to the Plan, with such grant subject to vesting in quarterly installments over the following four quarters. As of such date, the aggregate market value of the common stock granted was $103,500 based on the then market price on the OTCBB of the Company’s common stock. Such amount is being amortized to compensation expense on a quarterly basis during fiscal years 2008 and 2009. Accordingly, $90,563 was recorded as compensation expense and included in general and administrative expenses for fiscal 2008. The remaining $12,937 will be amortized to compensation expense in the first quarter of fiscal 2009, which ends September 30, 2008.

On January 31 and February 4, 2008, the Company issued 555,000 and 52,500 unregistered shares, respectively, to the officers and directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $893,550 and $84,525 (a total of $978,075), respectively, based on the then-market price on the OTCBB of the Company’s common stock. Recent SEC guidance requires that immediately-vesting common stock grants with no forfeiture provisions be expensed at the time of grant rather than amortized over the four quarters of the service period. Accordingly, the full $978,075 was recorded as compensation expense and included in general and administrative expenses for the fiscal year ended June 30, 2008. The Named Executive Officers received the following grants: (i) 150,000 unregistered shares to Calvin A. Wallen, III, (ii) zero unregistered shares to Scott D. Guffey, and (iii) 100,000 unregistered shares to Jon S. Ross.

Outstanding Equity Awards at Fiscal Year-End

The Company had no outstanding stock options at June 30, 2008, thus any reference to options in the table below has been omitted. The Company had the following unvested stock awards at the end of fiscal 2008:

Name	Number of Shares of Stock That Have Not Vested	Market Value of Shares of Stock That Have Not Vested
Scott D. Guffey	33,750	$	141,413

51

Option Exercises and Stock Vesting

The following table sets forth dollar amounts realized pursuant to the vesting or exercise of equity-based award during the latest fiscal year. No stock options were granted to executive officers last year and thus any reference to options in the table below has been omitted.

Name	Number of Shares Acquired on Vesting (1)	Value Realized on Vesting
Calvin A. Wallen, III	150,000	$	241,500
Scott D. Guffey	56,250	$	100,313
Jon S. Ross	100,000	$	161,000

(1)Messrs. Wallen and Ross’s stock grants vested immediately. Mr. Guffey received a common stock award of 90,000 unregistered shares granted on August 20, 2007, vesting on a quarterly schedule with 18,750 shares vesting on each of November 20, 2007, February 20, 2008 and May 20, 2008, with the remaining 33,750 shares of Mr. Guffey’s grant vesting subsequent to the end of fiscal 2008, on August 20, 2008.

Information Related to Stock-Based Compensation

The Company accounts for its stock-based employee compensation plans pursuant to FAS No. 123R, Share-Based Payment, which is a revision of FAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). This Statement requires the Company to recognize compensation costs related to stock-based payment transactions (i.e., the granting of stock options and warrants, and awards of unregistered shares of common stock) in the financial statements. With limited exceptions, the amount of compensation cost is measured based on the grant-date fair value of the equity issued. Compensation cost is recognized over the period that an employee provides services in exchange for the award. This new standard became effective for awards that are granted, modified or settled in cash in interim and annual financial periods beginning after June 30, 2006. See “Stock Grants”.

Non-Employee Director Compensation for Fiscal 2008

Name	Fees Earned or Paid in Cash (1)		Stock Awards (2)		All Other Compensation		Total
Gene C. Howard	$	7,000	$	136,850	$	—	$	143,850
Herbert A. Bayer	$	7,000	$	120,750	$	—	$	127,750
Bob L. Clements	$	7,000	$	120,750	$	—	$	127,750

(1)Represents the amount of cash compensation earned in fiscal 2008 for Board and Committee service. Each non-employee director was paid a stipend of $1,000 for each Board of Directors or Committee meeting attended (whether in person or via teleconference) beginning with the January 29, 2008 Board meeting, with various meetings occurring on the same date being provided one stipend.

(2)Each non-employee director received: 40,000 shares of common stock for service on the Board of Directors; 20,000 shares of common stock for service on the Audit Committee; and, 15,000 shares of common stock for service on the Compensation Committee. Mr. Howard received an additional 10,000 shares of common stock for serving as the financial expert and Chairman of the Audit Committee.

52

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth the number of shares of the Company’s common stock beneficially owned, as of September 1, 2008 by (i) each person known to the Company to beneficially own more than 5% of the common stock of the Company (the only class of voting securities now outstanding), (ii) each director and executive officer, and (iii) all directors and executive officers as a group. Unless otherwise indicated, we consider all shares of common stock that can be issued under convertible securities or warrants currently or within 60 days of September 1, 2008 to be outstanding for the purpose of computing the percentage ownership of the person holding those securities, but do not consider those securities to be outstanding for computing the percentage ownership of any other person. Each owner’s percentage is calculated by dividing the number of shares beneficially held by that owner by the sum of 60,335,564 and the number of shares that owner has the right to acquire within 60 days.

Name and Address	Number of Shares		Approximate Percent of Class (1)
5% Stockholders
William Bruggeman 20 Anemone Circle, North Oaks, MN 55127	17,498,897	(2)	28.0	%
Wells Fargo Energy Capital, Inc. 1000 Louisiana 9th Floor, Houston, TX 77002	7,500,000	(3)	11.1	%
Steven S. Bruggeman 5609 St. Albans Circle, Shoreview, MN 55126	4,189,955	(4)	6.8	%
George Karfunkel 9870 Plano Road, Dallas, TX 75238	3,375,000	(5)	5.6	%
Named Executive Officers and Directors
Calvin A. Wallen, III 9870 Plano Road, Dallas, TX 75238	11,615,972	(6)	19.2	%
Bob L. Clements 9870 Plano Road, Dallas, TX 75238	807,527	(7)	1.3	%
Gene C. Howard 2402 East 29th St., Tulsa, OK 74114	630,180	(8)	1.0	%
Jon S. Ross 9870 Plano Road, Dallas, TX 75238	468,000	(9)	*
Herbert A. Bayer 9870 Plano Road, Dallas, TX 75238	390,287	(10)	*
Scott D. Guffey 9870 Plano Road, Dallas, TX 75238	90,000		*
All officers and directors as a group (6 persons)	14,001,966		23.2	%

* Denotes less than one percent

(1)	Based on a total of 60,335,564 shares of Common Stock issued and outstanding on September 1, 2008.
(2)	Includes 2,034,000 shares and warrants to purchase 600,000 shares held by Diversified Dynamics Corporation, a company controlled by William Bruggeman; 120,000 shares owned by Consumer Products Corp., in which Mr.

53

	Bruggeman’s spouse, Ruth, is a joint owner; and, 13,160,897 shares and warrants to purchase 1,544,000 shares held jointly by William Bruggeman & Ruth Bruggeman as joint tenants with rights of survivorship.
(3)	Includes warrants to purchase 2,500,000 shares and a promissory note convertible into 5,000,000 shares.
(4)	Includes 901,955 shares held jointly by Steven S. Bruggeman and Jacqueline Bruggeman as joint tenants with rights of survivorship; 48,000 shares and warrants to purchase 24,000 shares held by Jacqueline Bruggeman, of which Steven S. Bruggeman disclaims beneficial ownership; 96,000 shares and warrants to purchase 48,000 shares held by minor children; and, warrants to purchase 1,024,000 shares held by Steven S. Bruggeman.
(5)	Includes warrants to purchase 1,125,000 shares.
(6)	Includes 1,414,000 shares and warrants to purchase 50,000 shares held by Tauren Exploration, Inc., an entity controlled by Mr. Wallen; 500,000 shares held by spouse; and, 386,000 shares held by minor children.
(7)	Includes 109,527 shares held with spouse as joint tenants with rights of survivorship; and, warrants to purchase 50,000 shares.
(8)	Includes 322,245 shares are held by Mr. Howard’s spouse, Belva, of which Mr. Howard disclaims beneficial ownership.
(9)	Includes 6,000 shares held by minor children.
(10)	Includes 390,287 shares held with spouse as joint tenants with rights of survivorship.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Certain Relationships and Related Transactions

On February 6, 2006 the Company entered into a Purchase Agreement with Tauren Exploration, Inc., an entity wholly owned by Calvin A. Wallen III, the Company’s Chairman of the Board and Chief Executive Officer, with respect to the purchase by the Company of certain Cotton Valley leasehold interests (approximately 11,000 gross acres; 5,000 net acres) held by Tauren. Pursuant to the Purchase Agreement, the Company acquired from Tauren a 35% working interest in approximately 2,400 acres and a 49% working interest in approximately 8,500 acres located in DeSoto and Caddo Parishes, Louisiana, along with an associated Area of Mutual Interest (“AMI”) and the right to acquire at “cost” (as defined in the Purchase Agreement) a working interest in all additional mineral leases obtained by Tauren in the AMI, in exchange for (a) $3,500,000 in cash, (b) 2,500,000 unregistered shares of Company common stock, (c) an unsecured 12.5% short-term promissory note in the amount of $1,300,000, which note was convertible into Company common stock at a conversion price of $0.80 per share, and (d) a drilling credit of $2,100,000. The consideration described above was determined based upon negotiations between Tauren and a Special Committee of the Company’s directors, excluding Mr. Wallen. The Special Committee obtained an opinion from its independent financial advisor with respect to the fairness, from a financial point of view, to the public stockholders of the Company, of such transactions.

On November 10, 2006, the maturity of the Tauren Note was extended to October 5, 2007. In connection with the extension of the Tauren Note, the Company issued to Tauren warrants, with three-year expirations, for the purchase of up to 50,000 shares of Company common stock at an exercise price of $0.70 per share.

On December 15, 2006, the Company entered into Subscription and Registration Rights Agreements with certain investors. One of the investors, William Bruggeman (and entities affiliated with him) was the beneficial owner, prior to this transaction, of approximately 23.0% of the common stock of the Company. In this transaction, Mr. Bruggeman (and entities affiliated with him) purchased an aggregate of 4,288,000 shares of common stock at a purchase price of $0.50 per share, or an aggregate of $2,144,000. Mr. Bruggeman (and entities affiliated with him) received warrants to purchase 2,144,000 shares of common stock with an exercise price of $0.70 per share. Another investor, Bob Clements, a director of the Company, purchased 100,000 shares of common stock at a purchase price of $0.50 per share, or an aggregate of $50,000. Mr. Clements received warrants to purchase 50,000 shares of common stock with an exercise price of $0.70 per share. The consideration described above was determined based upon negotiations between the Company and various potential investors.

54

On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 to Diversified Dynamics Corporation, an entity controlled by William Bruggeman who, at the time of such transaction, was the beneficial owner of approximately 28.9% of the common stock of the Company. The Subordinated Note bears interest at a fluctuating rate equal to the sum of the prime rate plus two percent (2%) per annum, and matures on April 30, 2010. The Company is paying interest on the note on a monthly basis.

In addition, all but three wells in which the Company owns a working interest are operated by an affiliated company, Fossil Operating, Inc. (“Fossil”), an entity wholly-owned by the Company’s President and Chief Executive Officer, Calvin A. Wallen III. In consideration for Fossil serving as operator and to satisfy the Company’s working interest obligations related to drilling costs and lease operating expenses, Cubic paid to Fossil an aggregate of $14,288,122, $4,120,012 and $1,077,354 during fiscal 2008, 2007 and 2006, respectively; and Fossil paid Cubic an aggregate of $310,407, $384,659 and $460,323 during fiscal 2008, 2007 and 2006, respectively for oil and gas sales. As of June 30, 2008, 2007 and 2006, the Company owed Fossil $862,895, $1,659,786 and $1,196,203, respectively, for drilling costs and lease operating expenses, and was owed by Fossil $450,669, $28,446 and $88,477, respectively, for oil and gas sales. The Company and Fossil have operating agreements with respect to all wells for which Fossil serves as operator.

It is the Company’s policy that any transactions between us and related parties will be on terms no less favorable than could be obtained from unaffiliated third parties and will be approved by a majority of the disinterested members of our Board of Directors.

Director Independence

Messrs. Howard, Clements and Bayer meet the independence standards for independent directors under the rules of the SEC and the rules of the American Stock Exchange as published in the American Stock Exchange’s Company Guide — Corporate Governance Requirements.

Item 14. Principal Accountant Fees and Services.

	July 1, 2007 - June 30, 2008		July 1, 2006 - June 30, 2007
Audit fees	$	27,000	$	21,000
Audit-related fees	10,100		8,500
Tax fees	4,180		4,585
All other fees	3,400		8,500
Total	$	44,680	$	42,585

Audit Fees

Aggregate audit fees billed for professional services rendered by Philip Vogel & Co., PC were $27,000 for the year ended June 30, 2008 and $21,000 for the year ended June 30, 2007. Such fees were primarily for professional services rendered for the audits of our consolidated financial statements during the fiscal years ended June 30, 2008 and 2007.

Audit-Related Fees

Aggregate audit-related fees billed for professional services rendered by Philip Vogel & Co., PC were $10,100 for the year ended June 30, 2008 and $8,500 for the year ended June 30, 2007. Such fees were for limited reviews of our unaudited condensed consolidated interim financial statements.

55

Tax Fees

Aggregate income tax compliance and related services fees billed for professional services rendered by Philip Vogel & Co., PC were $4,180 for the year ended June 30, 2008 and $4,585 for the year ended June 30, 2007.

All Other Fees

In addition to the fees described above, aggregate fees of: $3,400 were billed by Philip Vogel & Co., PC during the year ended June 30, 2008, primarily for review of our Form SB-2 registration statements and related amendments, attendance at our annual shareholders’ meeting, and for research regarding our compliance with Section 404 of the Sarbanes-Oxley Act of 2002; and $8,500 were billed by Philip Vogel & Co., PC during the year ended June 30, 2007, primarily for review of our Form SB-2 registration statements and related amendments, and for research regarding our use of shares of common stock as compensation.

Audit Committee Pre-Approval Policies and Procedures

In accordance with Company policy, any additional audit or non-audit services must be approved in advance. All of the foregoing professional services provided by Philip Vogel & Co., PC during the years ended June 30, 2008 and June 30, 2007 were pre-approved in accordance with the policies of our Audit Committee.

56

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) (1) and (2) Financial Statements and Financial Statement Schedules

 See “Index to Financial Statements” on page F-1.

(a) (3) Exhibits

See the Exhibit Index immediately preceding the Exhibits filed with this report.

57

SIGNATURES

Pursuant to requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on September 29, 2008.

CUBIC ENERGY, INC.
By:	/s/ Calvin A. Wallen, III
	Calvin A. Wallen, III
	President and Chief
	Executive Officer
By:	/s/ Scott D. Guffey
	Scott D. Guffey
	Chief Financial Officer

Pursuant to requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Calvin A. Wallen, III	President, Chief Executive	September 29,
Calvin A. Wallen, III	Officer and Director	2008
/s/ Scott D. Guffey	Chief Financial Officer	September 29,
Scott D. Guffey	(principal accounting	2008
	officer)
/s/ Jon Stuart Ross	Secretary and Director	September 29,
Jon Stuart Ross		2008
/s/ Gene Howard	Director	September 29,
Gene Howard		2008
/s/ Herbert A. Bayer	Director	September 29,
Herbert A. Bayer		2008
/s/ Bob Clements	Director	September 29,
Bob Clements		2008

CUBIC ENERGY, INC.

INDEX TO FINANCIAL STATEMENTS

JUNE 30, 2008

	Page
Independent Auditors’ Report	F-2
Management’s Annual Report on Internal Control over Financial Reporting	F-3
Financial Statements:
Balance Sheets	F-4
Statements of Operations	F-5
Statements of Changes in Stockholders’ Equity	F-6
Statements of Cash Flows	F-7
Notes to Financial Statements	F-8
Note A – Background and general	F-8
Note B – Significant accounting policies	F-8
Note C – Stockholders’ equity	F-19
Note D – Loss per common share	F-22
Note E – Long-term debt	F-23
Note F – Related party transactions	F-25
Note G – Income taxes	F-27
Note H – Commitments and contingencies	F-29
Note I – Cost of oil and gas properties	F-30
Note J – Oil and gas reserves information (unaudited)	F-31
Note K – Selected quarterly financial data (unaudited)	F-36
Note L – Subsequent events	F-37

F-1

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholders of Cubic Energy, Inc.,

We have audited the balance sheets of Cubic Energy, Inc., a Texas corporation, as of June 30, 2008 and 2007, and the related statements of operations, of changes in stockholders’ equity and of cash flows for each of the three years in the period ended June 30, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cubic Energy, Inc. as of June 30, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended June 30, 2008, in conformity with accounting principles generally accepted in the United States of America.

	PHILIP VOGEL & CO. PC
	Certified Public Accountants
Dallas, Texas
September 24, 2008

F-2

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13(a)-15(f) of the Securities Exchange Act of 1934, as amended. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an assessment, including testing, of the effectiveness of our internal control over financial reporting as of June 30, 2008 based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Based on our evaluation under the criteria set forth in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of June 30, 2008. This Annual Report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. We were not required to have, nor have we engaged our independent registered public accounting firm to perform, an audit on our internal control over financial reporting pursuant to the rules of the Securities and Exchange Commission that permit us to provide only management’s report in this Annual Report.

Subsequent to our evaluation, there were no changes in internal controls or other factors that could materially affect, or are reasonably likely to materially affect, these internal controls. We maintain a system of internal control over financial reporting. There were no changes in our internal control over financial reporting during the fourth quarter of fiscal 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, and that breakdowns can occur because of simple errors. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Our chief executive officer and chief financial officer have completed the certifications required to be filed as an Exhibit to this Report (see Exhibits 31.1 and 31.2) relating to the design of our disclosure controls and procedures and the design of our internal control over financial reporting.

F-3

CUBIC ENERGY, INC.

BALANCE SHEETS

JUNE 30, 2008 AND 2007

	2008			2007
Assets
Current assets:
Cash and cash equivalents	$	2,144,002		$	3,122,273
Accounts receivable - trade	165,910			218,874
Prepaid drilling costs	33,399			721,136
Other prepaid expenses	65,344			231,232
Total current assets	2,408,655			4,293,515
Property and equipment (at cost):
Oil and gas properties, full cost method:
Proved properties (including wells and related equipment and facilities)	27,751,133			8,836,790
Unproven properties	3,254,901			6,827,341
Office and other equipment	14,672			12,886
Oil and gas properties, and equipment, at cost	31,020,706			15,677,017
Less accumulated depreciation, depletion and amortization	4,163,112			2,011,015
Oil and gas properties, and equipment, net	26,857,594			13,666,002
Other assets:
Deferred loan costs - net	224,434			148,724
Total other assets	224,434			148,724
	$	29,490,683		$	18,108,241
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued expenses	$	250,630		$	51,664
Due to affiliates	411,284			1,635,055
Total current liabilities	661,914			1,686,719
Long-term liabilities:
Long-term debt, net of discounts	22,970,570			7,626,739
Total long-term liabilities	22,970,570			7,626,739
Commitments and contingencies (Note H)	—			—
Stockholders’ equity:
Preferred stock - $.01 par value, authorized 10,000,000 shares, issued none	—			—
Common stock - $.05 par value, authorized 100,000,000 shares, issued 58,853,064 in 2008 and 55,840,896 shares in 2007	2,942,654			2,792,046
Additional paid-in capital	27,366,690			25,325,429
Accumulated deficit	(24,451,145		)	(19,322,692		)
Stockholders’ equity	5,858,199			8,794,783
	$	29,490,683		$	18,108,241

The accompanying notes are an integral part of these statements.

F-4

CUBIC ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED JUNE 30, 2008, 2007, AND 2006

	2008			2007			2006
Revenues:
Oil and gas sales	$	2,302,310		$	583,416		$	508,925
Total revenues	$	2,302,310		$	583,416		$	508,925
Operating costs and expenses:
Oil and gas production, operating and development costs	1,162,489			481,145			338,329
General and administrative expenses	2,488,133			1,325,192			1,400,482
Depreciation, depletion and non-loan-related amortization	2,152,096			362,434			179,237
Impairment loss on oil and gas properties	—			1,790,882			—
Total operating costs and expenses	5,802,718			3,959,653			1,918,048
Operating income (loss)	(3,500,408		)	(3,376,237		)	(1,409,123		)
Non-operating income (expense):
Other income	45,697			38,037			6,402
Interest expense, including amortization of loan discount	(1,579,452		)	(1,278,721		)	(638,800		)
Amortization of loan costs	(94,290		)	(100,966		)	(67,199		)
Total non-operating income (expense)	(1,628,045		)	(1,341,650		)	(699,597		)
Loss on debt extinguishment	—			(1,082,887		)	(660,330		)
Loss before income taxes	(5,128,453		)	(5,800,774		)	(2,769,050		)
Provision for income taxes	—			—			—
Net loss	$	(5,128,453	)	$	(5,800,774	)	$	(2,769,050	)
Net loss per common share - basic and diluted	$	(0.09	)	$	(0.12	)	$	(0.07	)
Weighted average common shares outstanding	56,974,407			50,338,450			38,477,353

The accompanying notes are an integral part of these statements.

F-5

CUBIC ENERGY, INC.

STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED JUNE 30, 2008, 2007, AND 2006

	Common Stock			Additional						Total
	Shares	Par		paid-in			Accumulated			stockholders’
	outstanding	value		capital			deficit			equity
Balance at June 30, 2005	35,161,963	$	1,758,100	$	11,778,915		$	(10,752,868	)	$	2,784,147
Stock issued for acquisition of property interests	2,500,000	125,000		1,175,000			—			1,300,000
Stock issued under compensation plan	1,169,000	58,450		911,320			—			969,770
Stock issued for working capital	2,679,000	133,950		1,786,836			—			1,920,786
Stock issued under convertible debenture agreements	900,000	45,000		354,626			—			399,626
Warrants issued for debt costs	—	—		208,333			—			208,333
Debt proceeds allocated to warrants	—	—		1,203,752			—			1,203,752
Stock issued in payment of interest obligations	40,805	2,040		34,002			—			36,042
Net loss, year ended June 30, 2006	—	—		—			(2,769,050		)	(2,769,050		)
Balance at June 30, 2006	42,450,768	$	2,122,540	$	17,452,784		$	(13,521,918	)	$	6,053,406
Stock issued under compensation plan	542,000	27,100		406,500			—			433,600
Stock issued for working capital	10,880,000	544,000		5,496,000			—			6,040,000
Stock issued for placement fee	150,000	7,500		(7,500		)	—			—
Stock issued for warrant exercises	1,818,128	90,906		726,594			—			817,500
Debt proceeds allocated to warrants	—	—		1,251,051			—			1,251,051
Net loss, year ended June 30, 2007	—	—		—			(5,800,774		)	(5,800,774		)
Balance at June 30, 2007	55,840,896	$	2,792,046	$	25,325,429		$	(19,322,692	)	$	8,794,783
Stock issued under compensation plan	697,500	34,875		1,046,700			—			1,081,575
Stock issued for warrant exercises	2,314,665	115,733		994,561			—			1,110,294
Other	3	—		—			—			—
Net loss, year ended June 30, 2008	—	—		—			(5,128,453		)	(5,128,453		)
Balance at June 30, 2008	58,853,064	$	2,942,654	$	27,366,690		$	(24,451,145	)	$	5,858,199

The accompanying notes are an integral part of these statements.

F-6

CUBIC ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED JUNE 30, 2008, 2007, AND 2006

	2008			2007			2006
Cash flows from operating activities:
Net (loss)	$	(5,128,453	)	$	(5,800,774	)	$	(2,769,050	)
Adjustments to reconcile net (loss) to cash provided (used) by operating activities:
Depreciation, depletion and amortization	2,762,417			545,261			465,519
Impairment loss	—			1,790,882			—
Stock issued for interest	—			—			36,042
Stock issued for compensation	1,255,437			489,900			726,670
Write-off deferred loan costs	—			318,999			99,203
Write-off note payable discount	—			1,145,359			237,931
Change in assets and liabilities:
(Increase) decrease in accounts receivable - trade	52,964			(177,194		)	(7,326		)
(Increase) decrease in other prepaid expenses	(7,974		)	(44,432		)	—
Increase (decrease) in accounts payable and accrued liabilities	198,966			(113,964		)	154,367
Increase (decrease) in due to affiliates	(367,186		)	43,895			92,771
Net cash provided (used) by operating activities	(1,233,829		)	(1,802,068		)	(963,873		)
Cash flows from investing activities:
Acquisition and development of oil and gas properties	(15,341,903		)	(4,060,398		)	(4,502,186		)
Increase (decrease) in capital portion of due to affiliates	(856,585		)	43,895			92,771
Purchase of office equipment	(1,786		)	(5,010		)	(3,003		)
(Increase) decrease in advances on development costs	687,737			(456,913		)	39,443
(Increase) decrease in cash restricted by debt	—			401,723			(401,723		)
(Increase) decrease in other assets	—			25,000			(25,000		)
Net cash provided (used) by investing activities	(15,512,537		)	(4,051,703		)	(4,799,698		)
Cash flows from financing activities:
Issuance of common stock, net	1,110,295			6,857,500			2,020,786
Proceeds from credit facility	12,827,800			—			—
Issuance of subordinated debt	2,000,000			—			—
Issuance of convertible debt and warrants	—			9,000,000			5,500,000
Repayment of debt	—			(5,500,000		)	(1,480,000		)
Payment of note payable to affiliate	—			(1,300,000		)	—
Loan costs incurred and other	(170,000		)	(240,613		)	(275,311		)
Repayment of advances	—			(100,000		)	—
Net cash provided (used) by financing activities	15,768,095			8,716,887			5,765,475
Net increase (decrease) in cash and cash equivalents	$	(978,271	)	$	2,863,116		$	1,904
Cash and cash equivalents:
Beginning of year	3,122,273			259,157			257,253
End of year	$	2,144,002		$	3,122,273		$	259,157
Other information:
Cash interest paid on debt	$	1,394,009		$	815,286		$	419,485
Non-cash investing and financing activities:
Acquisition of property with stock issue	$	—		$	—		$	1,300,000
Acquisition of property with debt issue	$	—		$	—		$	2,599,274

The accompanying notes are an integral part of these statements.

F-7

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note A - Background and general:

Cubic Energy, Inc. (“Company”) is engaged in domestic crude oil, natural gas and natural gas liquids exploration, development and production, with primary emphasis on the production of oil and gas reserves through the acquisition and development of proved, producing oil and gas properties in the states of Texas and Louisiana.

Note B - - Significant accounting policies:

Cash equivalents

For purposes of the statements of cash flows, the Company considers all certificates of deposit and other financial instruments with original maturity dates of three months or less to be cash equivalents.

Office and other equipment

Office and other equipment are stated at cost and depreciated by the straight-line method over estimated useful lives ranging from five to seven years. Depreciation and amortization of office and other equipment amounted to $2,526, $1,524 and $1,173 for the years ended June 30, 2008, 2007 and 2006, respectively.

Impairment of long-lived assets and long-lived assets to be disposed of

The Company has adopted the provisions of the Financial Accounting Standards Board’s (the “FASB”) Statement of Financial Accounting Standards (“FAS”) No. 144 (“FAS No. 144”), Accounting for the Impairment or Disposal of Long-Lived Assets effective for periods beginning July 1, 2002, and thereafter. FAS No. 144 replaces FAS No. 121, and, among other matters, addresses financial accounting and reporting for the impairment or disposal of long-lived assets. FAS No. 144 retains the basic provisions of FAS No. 121, but broadens its scope and establishes a single model for long-lived assets to be disposed of by sale. In addition, the Company is subject to the rules of the Securities and Exchange Commission with respect to impairment of oil and gas properties accounted for under the full cost method of accounting, as described below.

Full cost method of accounting for oil and gas properties

The Company has adopted the full cost method of accounting for oil and gas properties. Management believes adoption of the full cost method more accurately reflects management’s exploration objectives and results by including all costs incurred as integral for the acquisition, discovery and development of whatever reserves ultimately result from its efforts as a whole. Under the full cost method of accounting, all costs associated with acquisition, exploration and development of oil and gas reserves, including such costs as leasehold acquisition costs, interest costs related to exploratory and development activities, and directly related overhead costs, are capitalized into the full cost pool.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

F-8

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

In addition, the capitalized costs are subject to a “full cost ceiling test,” which generally limits such costs to the aggregate of the “estimated present value” (discounted at a 10 percent (10%) interest rate) of future net revenues from proved reserves, based on current economic and operating conditions, plus the lower of cost or fair market value of unproved properties. Accordingly, no impairment of oil and gas properties charge was recorded in fiscal 2008, and $1,790,882 was recorded for fiscal 2007; however, an excess of the capitalized costs over the full cost ceiling test limitation at June 30, 2006 was not charged against earnings for fiscal 2006 because of an increase in oil and gas prices subsequent to year end.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.

Depletion of producing oil and gas properties amounted to $2,149,570, $360,910 and $178,064 for the years ended June 30, 2008, 2007 and 2006, respectively.

Income taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates that will apply in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

In September 2005, the Emerging Issues Task Force (“EITF”) reached a consensus on Issue No. 05-08, Income Tax Consequences of Issuing Convertible Debt with a Beneficial Conversion Feature (“EITF 05-08”). Under EITF 05-08, the issuance of convertible debt with a beneficial conversion feature results in a temporary difference for purposes of applying FAS No. 109, Accounting for Income Taxes. The deferred taxes recognized for the temporary difference should be recorded as an adjustment to paid-in capital. EITF 98-05, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios, and EITF 00-27, Application of Issue No. 98-05 to Certain Convertible Instruments, require that the non-detachable conversion feature of a convertible debt security be accounted for separately if it is a beneficial conversion feature. A beneficial conversion feature is recognized and measured by allocating to additional paid-in capital a portion of the proceeds equal to the conversion feature’s intrinsic value. A discount on the convertible debt is recognized for the amount that is allocated to additional paid-in capital. The debt discount is accreted from the date of issuance to the stated redemption date of the convertible instrument or through the earliest conversion date if the instrument does not have a stated redemption date. The U.S. Federal Income Tax Code includes the entire amount of proceeds received at issuance as the tax basis of the convertible debt security. The adoption of EITF 05-08 has had no impact on the Company’s financial statements because none of the conversion features embedded in the Company’s notes payable is considered beneficial.

In July 2006, the FASB issued Interpretation No. 48 (“FIN No. 48”), Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, which clarifies the accounting for uncertainty in tax positions. FIN No. 48 requires that the Company recognize in the financial statements the impact of a tax position if that position is more likely than not of being sustained upon audit, based on the technical merits of the position. FIN No. 48 became effective for fiscal years beginning after December 15, 2006. The adoption of FIN No. 48 has had no impact on the Company’s financial statements.

F-9

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Oil and gas revenues

The Company recognizes oil and gas revenues when oil and gas production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a purchaser’s pipeline or truck. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results include estimates of production and revenues for the related time period. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. Differences between sales and production volumes during the years ended June 30, 2008, 2007 and 2006 were not significant.

Earnings (loss) per common share

The Company has adopted the provisions of FAS No. 128, Earnings per Share. FAS No. 128 requires the presentation of basic earnings (loss) per share (EPS) and diluted EPS. Basic EPS is calculated by dividing net income or loss (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, such as stock options, warrants, convertible preferred stock and convertible debentures, were exercised or converted into common stock.

As discussed in Note E, there were no dilutive securities outstanding during the years ended June 30, 2008, 2007 and 2006. The weighted average number of common and common equivalent shares outstanding was 56,974,407, 50,338,450 and 38,477,353 for the years ended June 30, 2008, 2007 and 2006, respectively.

Concentration of credit risk

Financial instruments which potentially subject the Company to a concentration of credit risk consists primarily of trade accounts receivable with a variety of local, national, and international oil and natural gas companies. Such credit risks are considered by management to be limited due to the financial resources of the oil and natural gas companies.

The Company had cash balances of approximately $2,150,437, at June 30, 2008, in one banking institution; such amount is in excess of the federally insured amount of $100,000 for each institution. This balance is before considering outstanding items.

F-10

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Reporting comprehensive income (loss) and operating segments

The Company has adopted the provisions of FAS No. 130, Reporting Comprehensive Income, and FAS No. 131, Disclosure about Segments of an Enterprise and Related Information. FAS No. 130 requires that an enterprise report, by major components and as a single total, the change in its net assets during the period from non-owner sources. FAS No. 131 establishes annual and interim reporting standards for an enterprise’s operating segments and related disclosures about its products, services, geographic areas and major customers. Adoption of FAS No. 130 and FAS No. 131 has had no impact on the Company’s financial position, results of operations, cash flows, or related disclosures because the Company’s operations are considered to be a single segment.

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Certain significant estimates

Management’s estimates of oil and gas reserves are based on various assumptions, including constant oil and gas prices. It is reasonably possible that a future event in the near term could cause the estimates to change and such changes could have a severe impact. Actual future production, cash flows, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves may vary substantially from those assumed in the estimate. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. While it is at least reasonably possible that the estimates above will change materially in the near term, no estimate can be made of the range of possible changes that might occur.

Fair value of financial instruments

The Company defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties. Financial instruments included in the Company’s financial statements include cash and cash equivalents, short-term investments, accounts receivable, other receivables, other assets, accounts payable, notes payable and due to affiliates. Unless otherwise disclosed in the notes to the financial statements, the carrying value of financial instruments is considered to approximate fair value due to the short maturity and characteristics of those instruments. The carrying value of debt approximates fair value as terms approximate those currently available for similar debt instruments.

F-11

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Asset retirement obligations

The Company has adopted the provisions of FAS No. 143, Accounting for Asset Retirement Obligations, effective July 1, 2002. FAS No. 143 amended FAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and, among other matters, addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. FAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the related asset and allocated to expense over the asset’s useful life.

This is a change from the approach taken under FAS No. 19, whereby an amount for an asset retirement obligation was recognized using a cost-accumulation measurement approach. Under that approach, the obligation was reported as a contra-asset recognized as part of depletion and depreciation over the life of the asset without discounting. Management has determined that adopting FAS No. 143 has had no significant effect on the Company’s financial statements since abandonment costs for which it is responsible are not material.

In March 2005, the FASB issued FASB Interpretation No. 47 (“FIN No. 47”), Accounting for Conditional Asset Retirement Obligations. FIN No. 47 clarifies that a conditional asset retirement obligation, as used in FAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing or method of the settlement are conditional on a future event that may or may not be within the control of the entity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated. FIN No. 47 is effective no later than fiscal years ending after December 15, 2005. The adoption of FIN No. 47 has had no impact on the financial statements of the Company.

Stock-based compensation

The Company accounts for its stock-based employee compensation plans pursuant to FAS No. 123R, Share-Based Payment, which is a revision of FAS No. 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees (“APB No. 25”). This FAS requires the Company to recognize compensation costs related to stock-based payment transactions (i.e., the granting of stock options and warrants, and awards of unregistered shares of common stock) in the financial statements. With limited exceptions, the amount of compensation is measured based on the grant-date fair value of the equity issued. Compensation cost is recognized over the period that an employee provides services in exchange for the award. This new standard became effective for awards that are granted, modified or settled in cash in interim and annual financial periods beginning after June 30, 2006.

Prior to adopting FAS No. 123R, the Company applied APB No. 25 and related interpretations, which required that compensation expense be recorded on the date of the grant of stock options and warrants only if the current market price of the underlying stock exceeded the exercise price. Alternatively, FAS No. 123R permits entities to recognize, as expense over the vesting period, the fair value of all stock-based awards on the date of grant. No retroactive or cumulative effect adjustments were required upon the Company’s adoption of SFAS No. 123R.

F-12

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

In December 2002, the FASB issued FAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure, which amends FAS No. 123. FAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based compensation. In addition, FAS No. 148 amends the disclosure requirements of FAS No. 123 to require more prominent and more frequent disclosures in financial statements about the effects of stock-based compensation. The transition guidance and annual disclosure provisions are effective for years ending after December 15, 2002. The interim disclosure provisions became effective for financial reports containing financial statements for interim periods beginning after December 15, 2002. The other requirements of this standard have been adopted by the Company for periods beginning January 1, 2003.

Additionally, in August 2005, the FASB issued FASB Staff Position (“FSP”) No. 123R-1 (“FSP1”), Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R). In FSP1, the FASB decided to defer the requirements in FAS No. 123 that make a freestanding financial instrument subject to the recognition and measurement requirements of other GAAP when the rights conveyed by the instrument are no longer dependent on the holder being an employee. In October 2005, the FASB issued FSP No. 123R-2 (“FSP2”), Practical Accommodation to the Application of Grant Date as Defined in FASB Statement No. 123(R). In FSP2, the FASB is providing companies with a “practical accommodation” when determining the grant date of an award that is subject to the accounting provisions in FAS No. 123R. In November 2005, the FASB issued FSP No. 123R-3 (“FSP3”), Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards. FSP3 provides an elective alternative method that establishes a computational component to arrive at the beginning balance of the accumulated paid-in capital pool related to employee compensation and a simplified method to determine the subsequent impact on the accumulated paid-in capital pool of employee awards that are fully vested and outstanding upon the adoption of FAS No. 123R.

In February 2006, the FASB issued FSP No. 123R-4 (“FSP4”), Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event, which concludes that a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not become a liability until it becomes probable that the event will occur. An option or similar instrument that is classified as equity, but subsequently becomes a liability because the contingent cash settlement event is probable of occurring, shall be accounted for similar to modification from an equity to liability award. To the extent that the liability exceeds the amount previously recognized in equity, the excess is recognized as compensation cost. The total recognized compensation cost for an award with a contingent cash settlement feature shall at least equal the fair value of the award at the grant date. FSP4 is applicable only for options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP1, FSP2, FSP3 and FSP4 has been applied concurrent with our adoption of FAS No. 123R.

F-13

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

In March 2005, the SEC published Staff Accounting Bulletin No. 107 (“SAB No. 107”). The interpretations in this staff accounting bulletin express the views of the staff regarding the interaction between FAS No. 123R and certain SEC rules and regulations and provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. In particular, SAB No. 107 provides guidance related to share-based payment transactions with non-employees, the transition from non-public to public entity status, valuation methods (including assumptions such as expected volatility and expected term), the accounting for certain redeemable financial instruments issued under share-based payment arrangements, the classification of compensation expense, non-GAAP financial measures, first-time adoption of FAS No. 123R in an interim period, capitalization of compensation cost related to share-based payment arrangements, the accounting for income tax effects of share-based payment arrangements upon adoption of FAS No. 123R, the modification of employee share options prior to adoption of FAS No. 123R and disclosures in Management’s Discussion and Analysis subsequent to adoption of FAS No. 123R. The provisions of SAB No. 107 became effective with our adoption of FAS No. 123R.

In periods prior to fiscal 2007, the Company applied APB No. 25 in accounting for its stock warrants issued to employees and directors, and, accordingly, has recognized no compensation expense for stock warrants and options granted at exercise prices at least equal to the market value of the Company’s common stock. Had the Company determined compensation cost based on the fair value at the grant date for its stock options under FAS No. 123R, the Company’s net loss and loss per share would not have been different from the amounts reported for the fiscal year ended June 30, 2006.

Exit or disposal activities

In July 2002, the FASB issued FAS No. 146, Accounting for Cost Associated with Exit or Disposal Activities. FAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. Examples of costs covered by the standard include lease termination costs and certain employee severance costs that are associated with a restructuring, discontinued operations, or other exit or disposal activities. FAS No. 146 is effective prospectively for exit or disposal activities initiated after December 31, 2002, with earlier adoption encouraged. No exit or disposal activities have been entered into by management.

Financial instruments with characteristics of both liabilities and equity

In May 2003, the FASB issued FAS No. 150 (“FAS No. 150”), Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. FAS No. 150 established standards for how a company classifies and measures certain financial instruments with characteristics of both liabilities and equity. The statement requires that a company classify a financial instrument that is within its scope as a liability (or an asset in some circumstances) if certain criteria are met. Freestanding financial instruments that obligate the issuer to redeem the holder’s shares, or are indexed to such an obligation, and are settled in cash or settled with shares meeting certain conditions would be treated as liabilities. Many of those instruments were previously classified as equity.

F-14

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

In June 2005, the FASB issued FSP FAS No. 150-5 (“FAS No. 150-5”), Issuers Accounting under FASB Statement No. 150 for Freestanding Warrants and Other Similar Instruments on Shares that are Redeemable. FAS No. 150-5 clarifies that freestanding warrants and similar instruments on shares that are redeemable should be accounted for as liabilities under FAS No. 150 regardless of the timing of the redemption feature or price, even though the underlying shares may be classified as equity. FAS No. 150-5 is effective for the first reporting period beginning after June 30, 2006. Although the Company had outstanding warrants as of June 30, 2008, the shares issued upon exercise of the warrants are not redeemable; consequently, adoption of FAS No. 150-5 has not had an impact on the Company’s financial position, results of operations or cash flows.

Guarantee of debt

In November 2002, the FASB issued Interpretation No. 45 (“FIN No. 45”), Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, an Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34. FIN No. 45 clarifies the requirements of FAS No. 5, relating to the guarantor’s accounting for, and disclosure of, the issuance of certain types of guarantees. This Interpretation clarifies that a guarantor is required to recognize, at the inception of certain types of guarantees, a liability for the fair value of the obligation undertaken in issuing the guarantee, and requires additional disclosures on existing guarantees even if the likelihood of future liability under the guarantees is deemed remote. The Company has not issued any guarantees and, therefore, the adoption of FIN No. 45 does not have a significant impact on the Company’s financial statements.

Variable interest entities

In January 2003, the FASB issued Interpretation No. 46 (“FIN No. 46”), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. FIN No. 46 states that if a business enterprise has a controlling financial interest in a variable interest entity as the primary beneficiary, the assets, liabilities and results of the activities of the variable interest entity should be included in the consolidated financial statements of the business enterprise. This Interpretation explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. The primary beneficiary of a variable interest entity would be required to consolidate if the other equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN No. 46 applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. The Company has no current contractual relationships or other business relationships with variable interest entities.

F-15

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Accounting changes and error corrections

In May 2005, the FASB issued FAS No. 154 (“FAS No. 154”), Accounting Changes and Error Corrections — A Replacement of APB Opinion No. 20 and FASB Statement No. 3. FAS No. 154 replaces APB Opinion No. 20 (“APB No. 20”), Accounting Changes, and FAS No. 3 (“FAS No. 3”), Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for, and reporting of, a change in accounting principles. FAS No. 154 applies to all voluntary changes in accounting principles and changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. Under previous guidance, changes in accounting principle were recognized as a cumulative effect in the net income of the period of the change. FAS No. 154 requires retrospective application of changes in accounting principle, limited to the direct effects of the change, to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change in accounting principle.

Additionally, FAS No. 154 requires that a change in depreciation, amortization or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle and that correction of errors in previously issued financial statements should be termed a “restatement.” The provisions in FAS No. 154 became effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of FAS No. 154 did not have a material impact on the Company’s financial position, results of operations or cash flows.

Debt modifications

In September 2005, the EITF reached a consensus on Issue No. 05-07 (“EITF No. 05-07”), Accounting for Modifications to Conversion Options Embedded in Debt Instruments and Related Issues. EITF No. 05-07 requires that a change in the fair value of a conversion option brought about by modifying the debt agreement be included in analyzing in accordance with EITF consensus on Issue No. 96-19 (“EITF No. 96-19”), Debtor’s Accounting for a Modification or Exchange of Debt Instruments, whether a debt instrument is considered extinguished. Under EITF No. 96-19’s requirements, an issuer who modifies a debt instrument must compare the present value of the original debt instrument’s cash flows to the present value of the cash flows of the modified debt. If the present value of those cash flows varies by more than 10 percent (10%), the modification is considered significant and extinguishments accounting is applied to the original debt. If the change in the present value of the cash flows is less than 10 percent (10%), the debt is considered to be modified and is subject to EITF No. 96-19’s modification accounting. EITF No. 05-07 requires that in applying the 10 percent (10%) test the change in the fair value of the conversion option be treated in the same manner as a current period cash flow. EITF No. 05-07 also requires that, if a modification does not result in an extinguishment, the change in fair value of the conversion option be accounted for as an adjustment to interest expense over the remaining term of the debt. The issuer should not recognize a beneficial conversion feature or reassess an existing beneficial conversion feature upon modification of the conversion option of a debt instrument that does not result in an extinguishment. EITF No. 05-07 became effective for modifications of debt instruments beginning in the first interim or annual reporting period beginning after December 15, 2005. The adoption of EITF No. 05-07 did not have a material impact on the Company’s financial position, results of operations or cash flows.

F-16

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Certain hybrid financial instruments

In February 2006, the FASB issued FAS No. 155 (“FAS No. 155”), Accounting for Certain Hybrid Financial Instruments, which amends FAS No. 133 (“FAS No. 133”), Accounting for Derivative Instruments and Hedging Activities and FAS No. 140 (“FAS No. 140”), Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and improves the financial reporting of certain hybrid financial instruments by requiring more consistent accounting that eliminates exemptions and provides a means to simplify the accounting for these instruments. Specifically, FAS No. 155 allows financial instruments that have embedded derivatives to be accounted for as a whole (eliminating the need to bifurcate the derivative from its host) if the holder elects to account for the whole instrument on a fair value basis. FAS No. 155 is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The adoption of FAS No. 155 did not have a material impact on the Company’s financial position, results of operations or cash flows.

Reporting taxes collected

In March 2006, the EITF reached a tentative consensus on Issue No. 06-03 (“EITF No. 06-03”), How Sales Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation). EITF No. 06-03 addresses income statement classification and disclosure requirements of externally-imposed taxes on revenue-producing transactions. EITF No. 06-03 is effective for periods beginning after December 15, 2006. The adoption of EITF No. 06-03 did not have a material impact on the Company’s financial position, results of operations or cash flows.

Other recent accounting pronouncements

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB No. 108”), Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 was issued to address diversity in practice in quantifying financial statement misstatements. Current practice allows for the evaluation of materiality on the basis of either (1) the error quantified as the amount by which the current year income statement was misstated (“rollover method”) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (“iron curtain method”). The guidance provided in SAB No. 108 requires both methods to be used in evaluating materiality (“dual approach”). SAB No. 108 permits companies to initially apply its provisions either by (1) restating prior financial statements as if the dual approach had always been used or (2) recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained earnings. The adoption of SAB No. 108 did not have a material impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued FAS No. 157 (“FAS No. 157”), Fair Value Measurements. FAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. FAS No. 157 does not require any new fair value measurements in financial statements, but standardizes its definition and guidance in GAAP. Thus, for some entities, the application of this statement may change current practice. FAS No. 157 was effective for us beginning on January 1, 2008. The adoption of FAS No. 157 did not have a material impact on the Company’s financial position, results of operations or cash flows.

F-17

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

In February 2007, the FASB issued Statement of FAS No. 159 (“FAS No. 159”), The Fair Value Option for Financial Assets and Financial Liabilities. FAS No. 159 allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. FAS No. 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. FAS No. 159 is effective for fiscal years beginning after November 15, 2007. Early adoption is permitted subject to specific requirements outlined in the Statement. Management is currently evaluating the effect of this pronouncement on its financial statements.

In December 2007, the FASB issued FAS No. 141 (revised 2007) (“FAS No. 141(R)”), Business Combinations. FAS No. 141(R) provides companies with principles and requirements on how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, liabilities assumed, and any non-controlling interest in the acquiree as well as the recognition and measurement of goodwill acquired or a gain from a bargain purchase in a business combination. FAS No. 141(R) also requires certain disclosures to enable users of the financial statements to evaluate the nature and financial effects of the business combination. Acquisition costs associated with the business combination will generally be expensed as incurred. In addition, changes in an acquired entity’s valuation allowance for deferred tax assets and uncertain tax positions after the measurement period will impact income tax expense. FAS No. 141(R) is effective for business combinations occurring in fiscal years beginning after December 15, 2008. Early adoption of FAS No. 141(R) is not permitted. We have not yet assessed the impact FAS No. 141(R) will have if we engage in future business combinations.

In December 2007, the FASB issued FAS No. 160 (“FAS No. 160), Non-controlling Interests in Consolidated Financial Statements, an amendment of ARB No. 51, which mandates that a non-controlling (minority) interest shall be reported in the consolidated statement of financial position within equity, separately from the parent company’s equity. This statement amends ARB No. 51 and clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity. FAS No. 160 also requires consolidated net income to include amounts to both parent and non-controlling interest and requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest. FAS No. 160 is effective for fiscal years and interim periods beginning after December 15, 2008. We have not yet assessed the impact on our consolidated financial statements of adopting FAS No. 160 effective January 1, 2009, but we do not expect it to be material as we currently do not have any minority interests that would be subject to FAS No. 160.

F-18

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note C – Stockholders’ equity:

The Company’s authorized capital is 100,000,000 shares of $0.05 par value common stock and 10,000,000 shares of $0.01 par value preferred stock. No shares of preferred stock were issued or outstanding at June 30, 2008 and 2007.

Stock and warrants

On or about October 1, 2004, the Company closed a Securities Purchase Agreement and issued $2,635,000 in principal amount of 7% Senior Secured Convertible Debentures due September 30, 2009 (the “Debentures”), to a group of institutional and high net worth investors. The Company had the option to pay the interest on the Debentures in common stock. The investors also received warrants to purchase an additional 2,635,000 shares of common stock with an exercise price of $1.00 per share. All of the above-referenced warrants had been exercised at June 30, 2008.

The Company allocated the proceeds from the issuance of the Debentures to the warrants and the Debentures based on their relative fair market values at the date of issuance. The value assigned to the warrants of $510,961 was recorded as an increase in additional paid-in capital for the year ended June 30, 2006.

On or about January 11, 2005, the Company issued 1,531,661 shares of common stock to Caravel Resources Energy Fund 2003-II, L.P. (the “Partnership”) in exchange for a 0.1914575033 working interest in the Kraemer 24-1 Well, DeSoto Parish, Township 14 N, Range 15 W, Section 24 (the “Well”). The Company also issued 468,339 shares of common stock to Mr. Wallen in exchange for a 0.0585424967 working interest in the Well. The common stock closed at a price of $0.90 on January 10, 2005.

On December 16, 2005, the Company entered into a Securities Purchase Agreement and issued 2,500,000 common shares at a price of $0.80 per share and issued warrants, with five year expirations, for the purchase of up to 1,000,000 shares of Company common stock at an exercise price of $1.00 per share. The proceeds of the offering were used for exploratory drilling and working capital. 640,000 of the above-referenced warrants had been exercised and 360,000 remained outstanding at June 30, 2008.

On February 6, 2006, Cubic entered into a Credit Agreement with Petro Capital V, L.P. (“Petro Capital”) pursuant to which Petro Capital advanced to the Company $5,500,000. In connection with the funding under the Credit Agreement, the Company issued to Petro Capital and Petro Capital Securities, LLC, warrants, with five-year expirations, for the purchase of up to 1,833,334 and 250,000 shares, respectively, of Company common stock at an exercise price of $1.00 per share. Pursuant to the anti-dilution adjustment provisions applicable to such warrants, the exercise price applicable to all such warrants still outstanding is currently $0.9842 per share. 1,550,000 of the above-referenced warrants issued to Petro Capital had been exercised and 283,334 remained outstanding at June 30, 2008. None of the 250,000 warrants issued to Petro Capital Securities, LLC had been exercised and all remained outstanding at June 30, 2008. The Company allocated the proceeds from the issuance of the senior debt to the warrants and the senior debt based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,203,752 was recorded as an increase in additional paid-in capital.

F-19

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

On July 28, 2006, Cubic entered into and consummated transactions pursuant to Subscription and Registration Rights Agreements (the “July 2006 Subscription Agreements”) with certain investors that are unaffiliated with the Company (the “Investors”). Pursuant to the Subscription Agreements, the Investors paid aggregate consideration of $2,100,000 to the Company for 3,000,000 shares of the Company’s common stock and warrants exercisable, through July 31, 2011, into 1,500,000 shares of common stock at $0.70 per share. Pursuant to the anti-dilution adjustment provisions applicable to such warrants, the exercise price applicable to all such warrants is currently $0.6885 per share. None of the above-referenced warrants had been exercised and all remained outstanding at June 30, 2008.

On November 10, 2006, in connection with the extension of a promissory note, the Company issued to Tauren warrants, with three-year expirations, for the purchase of up to 50,000 shares of Company common stock at an exercise price of $0.70 per share.

On December 15, 2006, the Company entered into Subscription and Registration Rights Agreements (the “December 2006 Subscription Agreements”) with certain investors. One of the investors, William Bruggeman (and entities affiliated with him) was the beneficial owner, prior to this transaction, of approximately 23.0% of the common stock of the Company. In this transaction, Mr. Bruggeman (and entities affiliated with him) purchased an aggregate of 4,288,000 shares of common stock at a purchase price of $0.50 per share, or an aggregate of $2,144,000. Mr. Bruggeman (and entities affiliated with him) received warrants to purchase 2,144,000 shares of common stock with an exercise price of $0.70 per share. Another investor, Bob Clements, a director of the Company, purchased 100,000 shares of common stock at a purchase price of $0.50 per share, or an aggregate of $50,000. Mr. Clements received warrants to purchase 50,000 shares of common stock with an exercise price of $0.70 per share. Pursuant to the December 2006 Subscription Agreements, the investors paid aggregate consideration of $3,940,000 to the Company for 7,880,000 shares of the Company’s common stock and warrants exercisable into 3,940,000 shares of common stock. The warrants are exercisable through November 30, 2011, at $0.70 per share. 140,000 of the above-referenced warrants had been exercised and 3,800,000 remained outstanding at June 30, 2008.

On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital (“Wells Fargo”) providing for a revolving credit facility of $20,000,000 and a convertible term loan of $5,000,000 (the “Credit Facility”). In connection with entering into the Credit Facility, the Company issued to Wells Fargo warrants, with five-year expirations, for the purchase of up to 2,500,000 shares of Company common stock at an exercise price of $1.00 per share. The term loan is also convertible into 5,000,000 shares of Company common stock at a conversion price of $1.00 per share. None of the above-referenced warrants had been exercised and all remained outstanding at June 30, 2008. The Company allocated the proceeds from the issuance of the debt to the warrants, the debt and net profits interest (see “Note E – Long-term debt”) based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,314,289 was recorded as an increase in additional paid-in capital and the value assigned to the net profits interest of $213,148 was recorded as a credit to the full cost pool for oil and gas properties.

During the fiscal year ended June 30, 2008, the Company received an aggregate total of $1,110,295 relating to the exercise of 2,730,000 warrants representing 2,314,665 shares of common stock.

F-20

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Stock-based compensation

On December 29, 2005, the shareholders of the Company approved the 2005 Stock Option Plan (the “Plan”) and 3,750,000 shares of common stock were reserved, of which 2,408,500 shares had been issued through June 30, 2008, as set forth below.

On December 29, 2005, stock grants aggregating 597,000 unregistered shares were approved for issuance to the officers and directors of the Company. As of such date, the aggregate market value of the common stock granted was $483,570 based on the last sale price on the OTC Bulletin Board (“OTCBB”) of the Company’s common stock. Such amount was recorded as compensation expense and included in general and administrative expenses for the fiscal year ended June 30, 2006.

On January 5, 2006, the Company issued 572,000 unregistered shares to the officers and directors of the Company pursuant to the Plan. As of such date, the aggregate market value of the common stock granted was $486,200 based on the last sale price on the OTCBB of the Company’s common stock. Such amount was amortized to compensation expense on a quarterly basis during calendar year 2006. Accordingly, $243,100 was recorded as compensation expense and included in general and administrative expenses for each of the fiscal years ended June 30, 2007 and 2006.

On January 10 and January 18, 2007, the Company issued 489,500 and 52,500 unregistered shares, respectively, to the officers, directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $391,600 and $42,000, respectively, based on the last sale price on the OTCBB of the Company’s common stock. Such amounts were amortized to compensation expense on a quarterly basis during calendar year 2007. An additional $30,000 was recorded when our former Chief Financial Officer resigned during fiscal 2007. Accordingly, $186,800 and $246,800 was recorded as compensation expense and included in general and administrative expense for the fiscal years ended June 30, 2008 and 2007, respectively. The Named Executive Officers received the following grants: (i) 150,000 unregistered shares to Calvin A. Wallen, III, (ii) 75,000 unregistered shares to James L. Busby, and (iii) 47,500 unregistered shares to Jon S. Ross.

On August 20, 2007, the Company issued 90,000 unregistered shares to the current Chief Financial Officer of the Company pursuant to the Plan, with such grant subject to vesting in quarterly installments over the following four quarters. As of such date, the aggregate market value of the common stock granted was $103,500 based on the then market price on the OTCBB of the Company’s common stock. Such amount is being amortized to compensation expense on a quarterly basis during fiscal years 2008 and 2009. Accordingly, $90,563 was recorded as compensation expense and included in general and administrative expenses for fiscal 2008. The remaining $12,937 will be amortized to compensation expense in the first quarter of fiscal 2009, which ends September 30, 2008.

On January 31 and February 4, 2008, the Company issued 555,000 and 52,500 unregistered shares, respectively, to the officers and directors, and key employees of the Company pursuant to the Plan. As of such dates, the aggregate market value of the common stock granted was $893,550 and $84,525, respectively (a total of $978,075), based on the then-market price on the OTCBB of the Company’s common stock. Recent SEC guidance requires that immediately-vesting common stock grants with no forfeiture provisions be expensed at the time of grant rather than amortized over four quarters. Accordingly, the full $978,075 was recorded as compensation expense and included in general and administrative expenses for the fiscal year ended June 30, 2008.

F-21

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The following table provides information related to stock-based compensation for the years ended June 30, 2008, 2007 and 2006:

	Fiscal Year Ended June 30,
	2008		2007		2006
Officer and employee restricted stock grants:
Pretax compensation expense	$	818,287	$	368,625	$	524,875
Tax benefit	$	—	$	—	$	—
Restricted stock expense, net of tax	$	818,287	$	368,625	$	524,875
Director restricted stock grants:
Pretax compensation expense	$	437,150	$	121,275	$	201,795
Tax benefit	$	—	$	—	$	—
Director stock grants expense, net of tax	$	437,150	$	121,275	$	201,795
Stock options:
Pretax compensation expense	$	—	$	—	$	—
Tax benefit	$	—	$	—	$	—
Stock option expense, net of tax	$	—	$	—	$	—
Total stock-based compensation:
Pretax compensation expense	$	1,255,437	$	489,900	$	726,670
Tax benefit	$	—	$	—	$	—
Total share based compensation expense, net of tax	$	1,255,437	$	489,900	$	726,670

Note D – Loss per common share:

	2008			2007			2006
Net loss attributable to stockholders	$	(5,128,453	)	$	(5,800,774	)	$	(2,769,050	)
Weighted average number of shares of common stock	56,974,407			50,338,450			38,477,353
Income (loss) per common share	$	(0.09	)	$	(0.12	)	$	(0.07	)

Potential dilutive securities (e.g., stock warrants and convertible debt) have not been considered because the Company reported a net loss and, accordingly, their effects would be anti-dilutive.

F-22

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note E – Long-term debt:

October 2004 debt issue

On or about October 1, 2004, the Company closed a Securities Purchase Agreement and issued $2,635,000 in principal amount of 7% Senior Secured Convertible Debentures due September 30, 2009 (the “Debentures”), to a group of institutional and high net worth investors. The Debentures were secured by the collateral set forth in the Deed of Trust, Security Agreement, Assignment of Production and Fixture Filing attached to a Form 8-K filed October 12, 2004. The Debentures paid an annual interest rate of 7% on a quarterly basis and were convertible into shares of our common stock at a price of $0.50 per share. The Company had the option to pay the interest on the Debentures in common stock. The proceeds of the Debentures were used for the acquisition of interests in oil and gas properties. The investors also received warrants to purchase an additional 2,635,000 shares of common stock with an exercise price of $1.00 per share. During the fiscal year ended June 30, 2006, $705,000 of debt was converted into 1,410,000 shares of common stock, and 145,137 shares of common stock were issued in lieu of cash to pay interest. During the fiscal year ended June 30, 2006, $450,000 of debt was converted into 900,000 shares of common stock, and 40,805 shares of common stock were issued in lieu of cash to pay interest.

The Company allocated the proceeds from the issuance of the Debentures to the warrants and the Debentures based on their relative fair market values at the date of issuance. The value assigned to the warrants of $510,961 was recorded as an increase in additional paid-in capital. The assignment of a value to the warrants resulted in a loan discount being recorded for the same amount. The discount was being amortized over the original five year term of the Debentures as additional interest expense. Amortization of the discount was $44,632 and $67,756, for the years ended June 30, 2006 and 2005, respectively. The Company also incurred loan costs of $264,300 on the issuance of the Debentures and warrants. The amount allocable to the Debentures of $213,049 was capitalized and was being amortized over the term of the Debentures. Amortization of loan costs was $18,612 and $28,258, for the years ended June 30, 2006 and 2005, respectively.

The debentures were retired on February 6, 2006, with proceeds from a new senior debt issue, as set forth below. In connection with this retirement, the Company recorded a loss on extinguishment of debt in the amount of $660,330. Such amount includes the write-off of deferred loan costs ($99,204), the write-off of the remaining loan discount ($237,931), and a prepayment penalty and associated legal fees ($323,195).

February 2006 debt issue

On February 6, 2006, Cubic entered into a Credit Agreement with Petro Capital V, L.P. (“Petro Capital”) pursuant to which Petro Capital advanced to the Company $5,500,000. The indebtedness bore interest at a rate of 12.5% per annum, was scheduled to mature on February 6, 2009, and was secured by substantially all of the assets of the Company. $1,800,000 of the funded amount was used to retire the 7% Senior Secured Convertible Debentures that were due September 30, 2009, described above. In connection with the funding under the Credit Agreement, the Company issued to Petro Capital and Petro Capital Securities, LLC, warrants, with five-year expirations, for the purchase of up to 1,833,334 and 250,000 shares, respectively, of Company common stock at an exercise price of $1.00 per share.

F-23

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The Company allocated the proceeds from the issuance of the senior debt to the warrants and the senior debt based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,203,752 was recorded as an increase in additional paid-in capital. The assignment of a value to the warrants resulted in a loan discount being recorded. The discount was being amortized over the original three-year term of the senior debt as additional interest expense. Amortization for the year ended June 30, 2007 was $298,371 and for the year ended June 30, 2006 was $174,451.

Cubic incurred loan costs of $483,643 on the issuance of the senior debt and warrants. The amount allocable to the senior debt of $367,586 was capitalized and was being amortized over the term of the senior debt. Amortization of loan costs for the senior debt was $83,101 for the year ended June 30, 2007 and was $48,587 for the year ended June 30, 2006.

The senior debt was retired on March 5, 2007, with proceeds from a new senior debt issue, as set forth below. In connection with this retirement, the Company recorded a loss on extinguishment of debt in the amount of $(1,082,887). Such amount includes the write-off of deferred loan costs, ($235,898), and the write-off of the remaining loan discount, ($846,989).

March 2007 debt issue

On March 5, 2007, Cubic entered into a Credit Agreement with Wells Fargo Energy Capital, Inc. (“Wells Fargo”) providing for a revolving credit facility of $20,000,000 and a convertible term loan of $5,000,000 (the “Credit Facility”). The indebtedness bears interest at a fluctuating rate equal to the sum of the Wells Fargo Bank prime rate plus two percent (2%) per annum, matures on March 1, 2010, and is secured by substantially all of the assets of the Company. Approximately $5,000,000 of the funded amount was used, together with cash on hand, to retire the Company’s aforementioned previously outstanding senior debt that was due February 6, 2009.

The revolving credit facility is subject to a borrowing base, initially set at $4,000,000, and is subject to periodic review. The convertible term loan of $5,000,000 is convertible into 5,000,000 shares of Cubic common stock at a conversion price of $1.00 per share.

In connection with entering into the Credit Facility, the Company issued to Wells Fargo warrants, with five-year expirations, for the purchase of up to 2,500,000 shares of Company common stock at an exercise price of $1.00 per share.

The Company allocated the proceeds from the issuance of the debt to the warrants, the debt and net profits interest (see below) based on their relative fair market values at the date of issuance. The value assigned to the warrants of $1,314,289 was recorded as an increase in additional paid-in capital and the value assigned to the net profits interest of $213,148 was recorded as a credit to the full cost pool for oil and gas properties. The assignment of a value to the warrants and net profits interest resulted in a loan discount being recorded. The discount is being amortized over the original three-year term of the debt as additional interest expense. Amortization for the years ended June 30, 2008 and 2007 was $516,030 and $164,961, respectively. Amortization for the fiscal years ending June 30, 2009 and 2010 is expected to be approximately $514,620 and $342,610, respectively.

F-24

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Cubic incurred loan costs of $240,613 on the issuance of the debt and warrants. The amount allocable to the debt of $166,590 has been capitalized and is being amortized over the term of the debt. Amortization for the years ended June 30, 2008 and 2007 was $55,886 and $17,865, respectively. Amortization for the fiscal years ending June 30, 2009 and 2010 is expected to be approximately $55,733 and $37,105, respectively. Cubic incurred commitment fees of $170,000 related to subsequent increases in the Credit Facility’s borrowing base; such amount was capitalized in fiscal 2008 and is being amortized over the remaining term of the loan. Amortization for the year ended June 30, 2008 was $38,404. Amortization for the fiscal years ending June 30, 2009 and 2010 is expected to be approximately $79,001 and $52,595, respectively.

May 2008 subordinated debt issue

On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 (the “Subordinated Note”) to Diversified Dynamics Corporation (the “Lender”), an entity controlled by William Bruggeman, who beneficially owns more than 5% of the common stock of the Company. The Subordinated Note bears interest at a fluctuating rate equal to the sum of the prime rate plus two percent (2%) per annum, and matures on April 30, 2010. As consideration for the loan made by Lender pursuant to the Subordinated Note, the Company agreed to convey to Lender, upon the repayment in full of the indebtedness evidenced by the Subordinated Note and the repayment in full of the senior indebtedness evidenced by the Credit Facility with Wells Fargo, an undivided 0.375% (0.375 of one percent) net profits interest in the future production of hydrocarbons from or attributable to Cubic’s net interest in its Louisiana properties. The proceeds of the Subordinated Note are being used for general corporate and working capital purposes.

Issuing the Subordinated Note required the consent of the holder of the Company’s senior indebtedness, Wells Fargo, which consent it granted on May 5, 2008. Subsequently, on May 8, 2008, the Credit Facility with Wells Fargo was amended by the First Amendment to the Credit Agreement (the “First Amendment”). Material provisions of the First Amendment included the following: (i) the Company may not prepay all or any part of the principal balance outstanding on the Term Loan prior to its maturity on March 1, 2010; and (ii) the amount of the Borrowing Base was increased to $20,000,000, which amount was fully drawn upon, subsequent to the end of fiscal 2008, on August 20, 2008.

Note F – Related party transactions:

Effective January 1, 2002, the Company entered into an agreement with Tauren that provides for the following:

1) As of January 1, 2002, the Company owed Tauren $856,712, primarily comprised of non-interest bearing advances the Company had received over the course of several years. In exchange for the amounts owed to it, Tauren accepted the transfer of 856,712 newly issued and unregistered shares of common stock in the Company that had a market price of $0.70 per share.

2) The Company received the rights to participate in prospective oil and gas projects in which Tauren owns a working interest.

3) The Company shall, as requested, have the future privilege of using the general and administrative services of Tauren based on an agreed pro rata cost.

4) The Company issued three series of warrants to Tauren as described in Note C.

F-25

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

On December 1, 1997, as renewed and revised on January 1, 2002, the Company entered into a contract with Tauren to provide the necessary technical, administrative and management expertise needed to conduct its business. Tauren also paid various organization costs and consulting fees on behalf of the Company. The monthly amount charged to the Company was based on actual costs of materials and labor hours of Tauren that were used pursuant to the terms of the agreement. The agreement was terminated effective January 1, 2006, except as to the office sharing provisions, which were extended to June 30, 2007 and since continue on a month to month basis. The Company now has 10 employees and its offices are subleased from Tauren. During fiscal 2008, the Company’s only expense under the office sharing arrangement was the rent sublease. Charges to the Company under the contracts and subsequent arrangements were $26,748, $26,748 and $29,285 for the years ended June 30, 2008, 2007 and 2006, respectively.

An affiliated company, Tauren Exploration, Inc. (“Tauren”), which is owned 100% by the Company’s President and Chief Executive Officer, Calvin A. Wallen III, owns a working interest in the wells in which the Company owns a working interest. As of June 30, 2008, the Company was owed $942 by Tauren for miscellaneous general and administrative expenses paid by the Company on Tauren’s behalf; as of June 30, 2007, the Company owed Tauren $3,715 for miscellaneous general and administrative expenses paid by Tauren on the Company’s behalf; and, as of June 30, 2006, the Company owed Tauren $100,000, for advances for payments of joint interest leasehold and development costs, and was owed $12,865 by Tauren for miscellaneous general and administrative expenses paid by the Company on Tauren’s behalf.

In addition, all but three wells in which the Company owns a working interest are operated by an affiliated company, Fossil Operating, Inc. (“Fossil”), which is owned 100% by the Company’s President and Chief Executive Officer, Calvin A. Wallen III. As of June 30, 2008, 2007 and 2006, the Company owed Fossil $862,895, $1,659,786 and $1,196,203, respectively, for drilling costs and lease and operating expenses, and was owed by Fossil $450,669, $28,446 and $88,477, respectively, for oil and gas sales.

On or about October 6, 2004, the Company acquired from Tauren and its affiliates, a 25% working interest in eight sections in DeSoto Parish, Louisiana, in exchange for $1,080,000. The eight sections include Sections 24 (excluding the Kraemer 24-1 well), 25 and 26 of Township 14 N, Range 16 W and Sections 18, 19, 20, 29 and 30 of Township 14 N, Range 15 W.

On or about January 11, 2005, the Company issued 1,531,661 shares of common stock to Caravel Resources Energy Fund 2003-II, L.P. (the “Partnership”) in exchange for a 0.1914575033 working interest in the Kraemer 24-1 well, DeSoto Parish, Township 14 N, Range 15 W, Section 24 (the “Well”). The Company also issued 468,339 shares of common stock to Mr. Wallen in exchange for a 0.0585424967 working interest in the Well. The common stock closed at a price of $0.90 on January 10, 2005.

On February 6, 2006, the Company entered into a Purchase Agreement with Tauren with respect to the purchase by the Company of certain Cotton Valley leasehold interests (approximately 11,000 gross acres; 5,000 net acres) held by Tauren. Pursuant to the Purchase Agreement, the Company acquired from Tauren a 35% working interest in approximately 2,400 acres and a 49% working interest in approximately 8,500 acres located in DeSoto and Caddo Parishes, Louisiana, along with an associated Area of Mutual Interest (“AMI”) and the right to acquire at “cost” (as defined in the Purchase Agreement) a seventy percent (70%) working interest in all additional mineral leases obtained by Tauren in the AMI, in exchange for (a) $3,500,000 in cash, (b) 2,500,000 unregistered shares of Company common stock, (c) an unsecured 12.5% promissory note in the amount of $1,300,000, which note was convertible into Company common stock at a conversion price of $0.80 per share (the “Tauren Note”), and (d) a drilling credit of $2,100,000. Total interest paid to Tauren under terms of the Tauren Note was $0 in fiscal 2008, $96,610 in fiscal 2007 and $64,110 in fiscal 2006.

F-26

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The consideration described above was determined based upon negotiations between Tauren and a Special Committee of the Company’s directors, excluding Mr. Wallen. The Special Committee obtained an opinion from its independent financial advisor with respect to the fairness, from a financial point of view, to the public stockholders of the Company, of such transactions.

On November 10, 2006, the maturity of the Tauren Note was extended to October 5, 2007. In connection with the extension of the Tauren Note, the Company issued to Tauren warrants, with three-year expirations, for the purchase of up to 50,000 shares of Company common stock at an exercise price of $0.70 per share.

On February 2, 2007, the Tauren Note was retired pursuant to a provision in the note that required payment from the proceeds of an equity offering. The equity offering that occurred in December 2006 (see “Note C – Stockholders’ Equity”) was sufficient to facilitate such repayment.

On May 6, 2008, the Company issued a subordinated promissory note in the amount of $2,000,000 to Diversified Dynamics Corporation, an entity controlled by William Bruggeman who, at the time of such transaction, was the beneficial owner of approximately 28.9% of the common stock of the Company. See “May 2008 subordinated debt issue” in “Note E – Long-term debt” elsewhere herein.

Note G – Income taxes:

Deferred tax assets and liabilities are computed by applying the effective U.S. federal income tax rate to the gross amounts of temporary differences and other tax attributes. Deferred tax assets and liabilities relating to state income taxes are not material. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. As of June 30, 2008, 2007 and 2006, the Company believed it was more likely than not that future tax benefits from net operating loss carryforwards and other deferred tax assets would not be realizable through generation of future taxable income; therefore, they were fully reserved.

The components of the net deferred federal income tax assets (liabilities) at June 30 were as follows:

	2008			2007			2006
Deferred tax assets:
Net operating loss carryforwards	$	7,914,000		$	4,013,000		$	2,441,800
Depletion basis of assets and related accounts	311,000			93,300			—
	$	8,225,000		$	4,106,300		$	2,441,800
Deferred tax liabilities:
Depletion basis of assets and related accounts	$	—		$	(1,500	)	$	(493,800	)
	$	—		$	(1,500	)	$	(493,800	)
Net deferred tax (liabilities) assets before valuation allowance	$	8,225,000		$	4,104,800		$	1,948,000
Valuation allowance	(8,225,000		)	(4,104,800		)	(1,948,000		)
Net deferred tax (liabilities) assets	$	—		$	—		$	—

F-27

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The following table summarizes the difference between the actual tax provision and the amounts obtained by applying the statutory tax rates to the income or loss before income taxes for the years ended June 30, 2008, 2007 and 2006:

	2008			2007			2006
Tax (benefit) calculated at statutory rate	$	(1,282,000	)	$	(1,450,000	)	$	(692,000	)
Losses not providing tax benefits	1,282,000			1,450,000			692,000
Current federal income tax provision (benefit)	$	—		$	—		$	—
Change in valuation allowance	$	(4,120,200	)	$	(2,156,800	)	$	1,346,200

As of June 30, 2008, the Company had net operating loss carryforwards of approximately $31,656,435, which are available to reduce future taxable income. These carryforwards expire as follows:

	Net operating
Year	losses
2009	$	5,700
2011	431,100
2012	205,100
2013	639,800
2019	845,600
2020	297,100
2021	172,100
2022	15,400
2023	571,900
2024	37,000
2025	1,321,800
2026	5,095,600
2027	6,413,700
2028	15,604,535
	$	31,656,435

F-28

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note H – Commitments and contingencies:

Key personnel

The Company depends to a large extent on the services of Calvin A. Wallen III, the Company’s President, Chairman of the Board, and Chief Executive Officer. The loss of the services of Mr. Wallen would have a material adverse effect on the Company’s operations.

On February 29, 2008, the Company entered into employment agreements with its President and Chief Executive Officer, Calvin A. Wallen, III, and Secretary, Jon S. Ross. The agreement with Mr. Wallen provides for a base salary of $200,000 per year, while the agreement with Mr. Ross provides for a base salary of $150,000 per year. The other terms and conditions of the agreements are substantially consistent.

Both agreements provide for a term of employment of 36 months from the effective date of February 1, 2008, which term shall be automatically extended by one additional month upon the expiration of each month during the term; provided, that the Company may terminate subsequent one-month extensions at any time. Each agreement is subject to early termination by the Company in the event that the employee dies, becomes totally disabled or commits an act constituting “Just Cause” under the agreement. The agreements provide that Just Cause includes, among other things, the conviction of certain crimes, habitual neglect of his duties to the Company or other material breaches by the employee of the agreement. Each agreement also provides that the employee shall be permitted to terminate his employment upon the occurrence of “Good Reason,” as defined in the agreement. The agreements provide that Good Reason includes, among other things, a material diminution in the employee’s authority, duties, responsibilities or salary, or the relocation of the Company’s principal offices by more than 50 miles. If the employee’s employment is terminated by (a) the Company other than due to the employee’s death, disability or Just Cause, or (b) the employee for Good Reason, then the Company is required to pay all remaining salary through the end of the then-current term. The foregoing severance payment is subject to reduction under certain conditions.

Environmental matters

The Company’s operations and properties are subject to extensive and changing federal, state, provincial and local laws and regulations relating to environmental protection, including the generation, storage, handling and transportation of oil and gas and the discharge of materials into the environment. The Company generates typical oil and gas field wastes, including hazardous wastes that are subject to the federal Resources Conservation and Recovery Act and comparable state statutes. Furthermore, certain wastes generated by the Company’s oil and gas operations that are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes” and therefore be subject to more rigorous and costly operating and disposal requirements. All of the Company’s properties are operated by third parties over whom the Company has limited control. In addition to the Company’s lack of control over properties operated by others, the failure of previous owners or operators to comply with applicable environmental regulations may, in certain circumstances, adversely impact the Company.

F-29

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note I - Cost of oil and gas properties:

Costs incurred

Costs (capitalized and expensed) incurred in oil and gas property acquisition, exploration, and development activities for the years ended June 30, 2008, 2007 and 2006 were as follows:

	2008		2007		2006
Property acquisitions	$	394,675	$	481,229	$	6,176,766
Exploration	14,030,615		2,759,794		808,678
Development	916,613		966,879		1,323,243
	$	15,341,903	$	4,207,902	$	8,308,687

Capitalized costs

The aggregate amounts of capitalized costs relating to oil and gas producing activities and the aggregate amounts of the related accumulated depreciation, depletion, and amortization at June 30, 2008, 2007 and 2006 were as follows:

	2008		2007		2006
Proved properties	$	29,542,015	$	10,627,672	$	6,679,730
Unproved properties	3,254,901		6,827,341		6,780,529
	32,796,916		17,455,013		13,460,259
Less: accumulated depreciation, depletion and amortization of oil and gas properties	4,156,650		2,007,080		1,646,170
Total properties	28,640,266		15,447,933		11,814,089
Less: accumulated impairment of oil and gas properties due to full cost ceiling test	1,790,882		1,790,882		—
Net properties	$	26,849,384	$	13,657,051	$	11,814,089

F-30

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Results of operations

The results of operations from oil and gas producing activities for the years ended June 30, 2008, 2007 and 2006 were as follows:

	2008			2007			2006
Revenues:
Revenues	$	2,302,310		$	583,416		$	508,925
Preferred return	—			—			—
	2,302,310			583,416			508,925
Expenses (excluding G&A and interest expense):
Production, operating and development costs	1,162,489			481,145			338,329
Depreciation, depletion and amortization	2,149,570			360,910			178,064
	3,312,059			842,055			516,393
Results before income taxes	(1,009,749		)	(258,639		)	(7,468		)
Provision for income taxes	—			—			—
Results of operations (excluding corporate overhead and interest expense)	$	(1,009,749	)	$	(258,639	)	$	(7,468	)

Note J - Oil and gas reserves information (unaudited):

The estimates of proved oil and gas reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the Securities and Exchange Commission and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations over prices and costs existing at year-end except by contractual arrangements.

The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company’s policy is to amortize capitalized oil and gas costs on the unit of production method, based upon these reserve estimates. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and gas reserves, the remaining estimated lives of the oil and gas properties, or any combination of the above may be increased or reduced in the near term.

If reduced, the carrying amount of capitalized oil and gas properties may be reduced materially in the near term.

F-31

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The following unaudited table sets forth proved oil and gas reserves, all within the United States, at June 30, 2008, 2007 and 2006 together with the changes therein:

	Natural Gas (Mcf)
	2008		2007		2006
Proved developed and undeveloped reserves:
Beginning of year	4,242,051		2,796,900		509,625
Revisions of previous estimates	(1,969,397	)	(1,188,985	)	226,730
Purchases of reserves in place	—		—		—
Extensions and discoveries	4,045,294		2,704,548		2,114,061
Less: Production	(228,219	)	(70,412	)	(53,516	)
Disposals of reserves in place	—		—		—
End of year	6,089,729		4,242,051		2,796,900

	Oil, condensate and natural gas liquids (Bbls)
	2008		2007		2006
Proved developed and undeveloped reserves:
Beginning of year	12,830		8,863		1,048
Revisions of previous estimates	(1,002	)	(2,437	)	1,029
Purchases of reserves in place	—		—		—
Extensions and discoveries	79,861		7,371		7,833
Less: Production	(2,741	)	(967	)	(1,047	)
Disposals of reserves in place	—		—		—
End of year	88,948		12,830		8,863

All of the Company’s Louisiana acreage lies atop the center of what is known in our industry as the “Haynesville Shale Play” (which we refer to as the “Bossier/Haynesville shales” elsewhere herein), which is believed in our industry to be one of the most prolific field discoveries in the United States. The discovery of the existence of the Bossier/Haynesville shale formations in the Company’s acreage mandated that we redirect capital in fiscal 2008 to protect our rights to this formation, which took spending away from the maximization of development of the Cotton Valley formation in our Bethany Longstreet and Johnson Branch fields.

Our first round of drilling was undertaken to maximize retention of our lease rights to develop our Johnson Branch and Bethany Longstreet acreage. Infrastructure costs have required greater capital outlay than anticipated. This variance, coupled with increases in overall drilling and completion costs, had an effect on the completion techniques that we utilized in fiscal 2008. While it is in the Company’s future development plans to re-complete this first round of producing wells at a later date, the Company’s focus has changed from maximizing production and reserves in the first round of drilling to holding acreage and preserving capital for potentially much greater production and reserves from the emerging Haynesville Shale Play.

The majority of the Company’s unproven acreage lies in our Johnson Branch field. Reservoir analysis produced by a third-party engineer for the Johnson Branch acreage indicates a prolific and economic Bossier/Haynesville shale formation and a productive and economic Cotton Valley formation. Wells drilled by the Company subsequent to the end of fiscal 2008 into the Bossier/Haynesville shale formation in our Bethany Longstreet field seem to indicate the same productive formation characteristics as compared to the wells drilled into the Bossier/Haynesville shales in our Johnson Branch acreage. Moreover, horizontal Cotton Valley formation wells drilled by our competitors in the Bethany Longstreet field have demonstrated productive characteristics.

F-32

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Accordingly, while work undertaken by the Company subsequent to the end of fiscal 2008 has allowed us to improve our completion techniques for vertical Cotton Valley wells in our Bethany Longstreet and Johnson Branch fields, going forward, the Company contemplates horizontal drilling of all its Cotton Valley and Bossier/Haynesville wells.

The redirection of the Company’s focus outlined above impacted the Company’s proved reserves amounts for the fiscal year ended June 30, 2008 as follows: (i) only horizontal wells for the Cotton Valley sandstone and Bossier/Haynesville shale formations are now contemplated, which resulted in the loss of Proved Undeveloped (“PUD”) reserves for certain Cotton Valley wells that had previously been allowed with a vertical drilling program; and (ii) the lack of production history information as of June 30, 2008 for horizontal Cotton Valley and horizontal Bossier/Haynesville shale wells adversely impacted assumptions regarding both initial production rates and production decline curves used in calculating the Company’s reserve estimates. The Company believes that proceeding at a more measured drilling pace for fiscal 2009 will allow the Company to take advantage of improved completion techniques, and, pursuant to the data filed subsequent to the end of fiscal 2008 by our competitors with respect to productive wells in the Haynesville Shale Play, that the two wells drilled and the four wells completed subsequent to the end of fiscal 2008 (see Item 1. Business – “RECENT DEVELOPMENTS” elsewhere herein) will result in a significant increase in reserves for fiscal 2009.

The “Revisions of previous estimates” amount of (1,969,397) Mcf in fiscal 2008 was primarily a result of more performance information being available for the fiscal 2008 reserve report. Three wells in our Bethany Longstreet acreage that were re-completed in the Hosston formation in late fiscal 2007 and early fiscal 2008 experienced production rates lower than initially anticipated  (i.e., at the time of the fiscal 2007 reserve report). Based on these updated performance rates, downward revisions of an aggregate of 220,840 were made to the Proved Developed reserves of the Kraemer 24-1, Moseley 25-1 and Moseley 26-1 wells and downward revisions of an aggregate of 851,569 Mcf were made to these wells’ PUD offset locations. In addition, four Bethany Longstreet wells that were completed in the Cotton Valley and Hosston formations in late fiscal 2007 and early fiscal 2008 experienced production rates lower than initially anticipated. As a result, downward revisions of an aggregate of 431,913 Mcf were made to the Proved Developed reserves of the Rushing 18-1, S.E. Johnson 19-1, S.E. Johnson 20-1, and S.E. Johnson 29-1wells and downward revisions of an aggregate of 512,452 Mcf were made to these wells’ PUD offset locations. Also, part of the downward revisions amount was due to a temporary delay in our exploratory drilling schedule. To wit, the Estes 7-1 well, which is an offset location to the Estes 8-1 well, was spudded during fiscal 2008 but was not completed until July 15, 2008, subsequent to the end of fiscal 2008 (see “Recent Developments” elsewhere herein). Because the well was not drilled to total depth as of the end of the fiscal year (June 30, 2008), the entire amount of 441,846 Mcf included in PUD reserves in fiscal 2007 for the Estes 7-1 well was written down to zero in fiscal 2008. Had it been completed during fiscal 2008, the amount would not have been written down. These downward revisions were partially offset by an upward PUD offset location revision of 289,966 Mcf to the Estes 8-1 well resulting from its proximity to a competitor’s productive horizontally-drilled Cotton Valley well.

The “Extensions and discoveries” amount of 4,045,294 Mcf in fiscal 2008 was a result of exploratory and developmental, or “step out”, drilling in our Johnson Branch acreage in fiscal 2008. This drilling, coupled with the proving up of the Rye 34-1, Barlow 11-1 and McDonnell 8-1 wells (which were non-proved as of June 30, 2007) lead to additional PUD offset locations. The reserve estimates attributable to these new PUD locations are listed under “Extensions and discoveries.”

F-33

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

The “Revisions of previous estimates” amount of (1,188,985) Mcf in fiscal 2007 was due to more performance information being available for the fiscal 2007 reserve report and a change in our estimation procedure. In fiscal 2007, reserves were based on analogy to the Taylor Alt-2 well, a comparable well located in Section 22 in T14N-R16W, which is adjacent to the Company’s Bethany Longstreet acreage. The initial rate was based on the ratio of hydrocarbon pore volume calculated from the well logs of Cubic wells awaiting completion and the Taylor Alt-2 well. This ratio was then multiplied by the initial rate of the Taylor Alt-2 well. The Calculated Initial Rate for each Cubic well was capped at the initial rate of the Taylor Alt-2 well. For the fiscal 2007 report, more information was available. Several of the wells or zones that were previously categorized as “behind pipe” were now producing and had initial potential tests giving a better indication of initial production rates. These better defined, and lower, initial production rates were combined with typical declines for each formation (the Cotton Valley and the Hosston) in the field and overall reserves were cut off using volumetric analysis. These initial production rates were lower than initially expected (i.e., at the time of the fiscal 2006 reserve report). Based on these updated performance rates, downward revisions of an aggregate of 369,087 Mcf were made to the Proved Developed reserves of the Moseley 25-1 and Moseley 26-1 wells and downward revisions of an aggregate of 1,079,274 Mcf were made to these wells’ PUD offset locations. These downward revisions were partially offset by upward revisions of an aggregate of 196,010 Mcf to the Kraemer 24-1, S.E. Johnson 20-1 and S.E. Johnson 29-1 wells resulting from completions in the Hosston zone.

The “Extensions and discoveries” amount of 2,704,548 Mcf in fiscal 2007 was a result of developmental, or “step out”, drilling in fiscal 2007. This drilling, coupled with the proving up of the Hosston formation as a result of the drilling and completion of the Company’s S.E. Johnson 20-1 and S.E. Johnson 29-1 wells (which were non-proved as of June 30, 2006) and recompletion of the Kraemer 24-1 well, lead to additional PUD offset locations. The reserve estimates attributable to these new PUD locations are listed under “Extensions and discoveries.”

F-34

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Standardized measure of discounted future net cash flows relating to proved reserves:

The standardized measure of discounted future net cash flows was calculated by applying current year-end prices, considering fixed and determinable price changes only to the extent provided by contractual arrangements or law, to estimated future production, less future expenditures (based on fiscal year-end costs) to be incurred in developing proved undeveloped and proved producing oil and gas reserves, and future income taxes. The resulting future net cash flows were discounted using a rate of 10% per annum (Table 1). The standardized measure of discounted net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of the Company’s oil and gas proved by drilling or production history. There are significant uncertainties inherent in estimating timing and amount of future costs. In addition, the method of valuation utilized, is based on current prices and costs and the use of a 10% discount rate, and is not necessarily appropriate for determining fair value (Table 2).

The following is the estimated standardized measure relating to proved oil and gas reserves at June 30, 2008, 2007 and 2006:

Table 1	2008			2007			2006
Future cash flows	$	95,132,248		$	30,768,518		$	16,139,781
Future production costs	(11,759,214		)	(5,601,924		)	(2,975,063		)
Future development costs	(34,598,145		)	(11,832,100		)	(3,453,350		)
Future severance tax expense	(1,708,116		)	(1,713,562		)	(819,785		)
Future income taxes	—			—			—
Future net cash flows	$	47,066,773		$	11,620,932		$	8,891,583
Ten percent annual discount for estimated timing of net cash flows	(13,956,117		)	(4,791,222		)	(2,444,198		)
Standardized measure of discounted future net cash flows	$	33,110,656		$	6,829,710		$	6,447,385

The following is an analysis of changes in the estimated standardized measure of proved reserves during the years ended June 30, 2008, 2007 and 2006:

Table 2	2008			2007			2006
Changes from:
Sale of oil and gas produced	$	(1,139,821	)	$	(102,271	)	$	(170,596	)
Net changes in prices and production costs	13,650,638			1,474,742			18,591
Extensions and discoveries	23,748,732			4,073,195			4,288,891
Revision of previous quantity estimates	(13,379,733		)	(4,559,850		)	508,762
Accretion of discounts	682,971			644,739			107,110
Net change in income taxes	—			—			—
Purchases of reserves in place	—			—			—
Disposals of reserves in place	—			—			—
Development costs incurred that reduced future development costs	(302,200		)	(339,500		)	(11,300		)
Changes in future development costs	(1,786,129		)	324,717			69,210
Changes in timing of production and other	4,806,488			(1,133,447		)	565,617
Change in standardized measure	$	26,280,946		$	382,325		$	5,376,285

F-35

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note K – Selected quarterly financial data (unaudited):

Summarized unaudited quarterly financial data for fiscal 2008 and 2007 are as follows:

	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter			Total
Fiscal 2008
Revenues	$	447,988		$	375,825		$	778,360		$	700,137		$	2,302,310
Loss before income taxes	$	(841,044	)	$	(946,974	)	$	(1,084,333	)	$	(2,256,102	)	$	(5,128,453	)
Net loss	$	(841,044	)	$	(946,974	)	$	(1,084,333	)	$	(2,256,102	)	$	(5,128,453	)
Net loss per common share - basic and diluted (1)	$	(0.02	)	$	(0.02	)	$	(0.02	)	$	(0.04	)	$	(0.09	)
Weighted average common shares outstanding	55,957,472			56,362,581			57,095,686			58,449,786			56,974,407
Fiscal 2007
Revenues	$	132,106		$	86,263		$	77,601		$	287,446		$	583,416
Loss before income taxes	$	(631,228	)	$	(744,585	)	$	(1,869,218	)	$	(2,555,743	)	$	(5,800,774	)
Net loss	$	(631,228	)	$	(744,585	)	$	(1,869,218	)	$	(2,555,743	)	$	(5,800,774	)
Net loss per common share - basic and diluted (1)	$	(0.01	)	$	(0.02	)	$	(0.03	)	$	(0.05	)	$	(0.12	)
Weighted average common shares outstanding	44,660,007			46,967,725			54,474,168			55,396,790			50,338,450

(1) The sum of the per share amounts per quarter does not equal the total year amount due to changes in the weighted average number of common shares outstanding in each quarter.

F-36

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note L – Subsequent events:

On July 3, 2008, two warrant holders of the Company exercised warrants for an aggregate of 1,127,500 shares of Company common stock, through the payment of $777,002 to the Company.

On July 7, 2008, one warrant holder of the Company exercised warrants for 250,000 shares of Company common stock, through the payment of $243,950 to the Company.

On July 8, 2008, one warrant holder of the Company exercised warrants for 100,000 shares of Company common stock, through the payment of $70,000 to the Company.

On July 17, 2008, one warrant holder of the Company exercised warrants for 5,000 shares of Company common stock, through the payment of $5,000 to the Company.

On August 20, 2008, Cubic drew upon an additional $3,172,200 from Wells Fargo under the revolving line of credit component of the Credit Facility in order to fund the completion of four wells drilled in our Johnson Branch acreage in fiscal 2008 and the drilling of two additional wells located in the Company’s Bethany Longstreet acreage in Caddo and DeSoto parishes. As of the date of this filing, September 29, 2008, the Company has borrowed a total of $20,000,000 under the Credit Facility’s Revolving Note (and an aggregate of $25,000,000 under the Credit Facility).

On August 20, 2008, the remaining 33,750 shares of Mr. Guffey’s August 20, 2007 restricted stock grant vested (see “Item 10. Executive Compensation — Compensation Discussion & Analysis — Options Exercises and Stock Vesting”).

F-37

EXHIBIT INDEX

No.	Description
3.1	Articles of Incorporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 10-QSB for the period ended September 30, 1999).
3.2	Articles of Amendment to the Articles of Incorporation of the Company dated December 30, 2005 (incorporated by reference to Exhibit 3.1 of the Company’s Form 10-QSB for the period ended December 31, 2005).
3.3	Bylaws (incorporated by reference to Exhibit 3.2 of the Company’s Form 10-K for the period ended June 30, 2000).
10.1	Form of Common Stock Purchase Warrant (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed with the SEC on October 12, 2004).
10.2	Registration Rights Agreement, effective as of September 30, 2004, among Cubic Energy, Inc. and the purchasers signatory thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on October 12, 2004).
10.3	Securities Purchase Agreement, dated as of December 12, 2005, among Cubic Energy, Inc. and each purchaser identified on the signature pages thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2005).
10.4	Registration Rights Agreement, dated as of December 12, 2005, among Cubic Energy, Inc. and the purchasers signatory thereto (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2005).
10.5	Form of Common Stock Purchase Warrant (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed with the SEC on December 16, 2005).
10.6	Credit Agreement, dated February 6, 2006, by and among Cubic Energy, Inc. and Petro Capital V, L.P. (filed as exhibit 10.1 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.7	Promissory Note, dated as of February 6, 2006, by Cubic Energy, Inc., payable to Petro Capital V, L.P. in the maximum principal amount of $7,000,000 (filed as exhibit 10.2 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.8	Common Stock Purchase Warrant, dated February 6, 2006, issued to Petro Capital Securities, LLC (filed as exhibit 10.3 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.9	Common Stock Purchase Warrant, dated February 6, 2006, issued to Petro Capital V, L.P. (filed as exhibit 10.4 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.10	Registration Rights Agreement, dated as of February 6, 2006, by and between Cubic Energy, Inc., Petro Capital V, L.P. and Petro Capital Securities, LLC (filed as exhibit 10.5 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).

10.11	Purchase Agreement, dated as of February 6, 2006, by and among Cubic Energy, Inc., Calvin A. Wallen III, and Tauren Exploration, Inc. (filed as exhibit 10.6 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.12	Promissory Note, dated as of February 6, 2006, by Cubic Energy, Inc., payable to Tauren Exploration, Inc. in the principal amount of $1,300,000 (filed as exhibit 10.7 to the Company’s Form 8-K dated February 8, 2006, and incorporated herein by reference).
10.13	Amendment to Promissory Note, dated March 30, 2006, by and between, Cubic Energy, Inc. and Tauren Exploration, Inc. (incorporated by reference to Exhibit 10.8 of the Company’s Form 10-QSB for the quarter ended March 31, 2006).
10.14	Amendment to Purchase Agreement, dated April 3, 2006, by and among Cubic Energy, Inc., Calvin A. Wallen III and Tauren Exploration, Inc. (incorporated by reference to Exhibit 10.9 of the Company’s Form 10-QSB for the quarter ended March 31, 2006).
10.15	Amendment to Purchase Agreement, dated May 5, 2006, by and among Cubic Energy, Inc., Calvin A. Wallen III and Tauren Exploration, Inc. (incorporated by reference to Exhibit 10.10 of the Company’s Form 10-QSB for the quarter ended March 31, 2006).
10.16	Subscription and Registration Rights Agreement with George Karfunkel, dated July 26, 2006 (filed as Exhibit 10.1 to the Company’s Form 8-K dated July 28, 2006).
10.17	Subscription and Registration Rights Agreement with Yehuda Neuberger and Anne Neuberger JTWROS dated July 26, 2006 (filed as Exhibit 10.2 to the Company’s Form 8-K dated July 28, 2006).
10.18	Warrant issued to George Karfunkel (filed as Exhibit 10.3 to the Company’s Form 8-K dated July 28, 2006).
10.19	Warrant issued to Yehuda Neuberger and Anne Neuberger JTWROS (filed as Exhibit 10.4 to the Company’s Form 8-K dated July 28, 2006).
10.20	Third Amendment to Promissory Note, dated November 10, 2006, by and between, Cubic Energy, Inc. and Tauren Exploration, Inc. (filed as Exhibit 10.1 to the Company’s Form 10-QSB for the quarter ended September 30, 2006).
10.21	Warrant issued to Tauren Exploration, Inc. dated November 10, 2006 (filed as Exhibit 10.2 to the Company’s Form 10-QSB for the quarter ended September 30, 2006).
10.22	Form of Subscription and Registration Rights Agreement (filed as Exhibit 10.1 to the Company’s Form 8-K filed December 21, 2006).
10.23	Form of Warrant (filed as Exhibit 10.2 to the Company’s Form 8-K filed December 21, 2006).
10.24	Credit Agreement dated March 5, 2007 by and between Cubic Energy, Inc. and Wells Fargo Capital, Inc. (filed as Exhibit 10.1 to the Company’s Form 8-K filed March 9, 2007).
10.25	Convertible Promissory Note dated as of March 5, 2007 by Cubic Energy, Inc. payable to Wells Fargo Energy Capital, Inc. in the principal amount of $5,000,000 (filed as Exhibit 10.2 to the Company’s Form 8-K filed March 9, 2007).

10.26	Promissory Note dated as of March 5, 2007 by Cubic Energy payable to Wells Fargo Energy Capital, Inc. in the maximum principal amount of $20,000,000 (filed as Exhibit 10.3 to the Company’s Form 8-K on March 9, 2007).
10.27	Warrant to Purchase Shares of Common Stock of Cubic Energy, Inc. dated March 5, 2007, issued to Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.4 to the Company’s Form 8-K on March 9, 2007).
10.28	Registration Rights Agreement dated as of March 5, 2007 by and between Cubic Energy, Inc. and Wells Fargo Energy Capital, Inc. (filed as Exhibit 10.5 to the Company’s Form 8-K on March 9, 2007).
10.29	Form of Assignment of Net Profits Interest (filed as Exhibit 10.6 to the Company’s Form 8-K on March 9, 2007).
10.30	Employment Agreement with Calvin A. Wallen, III, dated February 29, 2008 (filed as Exhibit 10.1 to the Company’s Form 8-K on March 5, 2008).
10.31	Employment Agreement with Jon S. Ross dated February 29, 2008 (filed as Exhibit 10.1 to the Company’s Form 8-K on March 5, 2008).
10.32	Subordinated Promissory Note dated May 6, 2008 (filed as Exhibit 10.1 to the Company’s Form 10-QSB for the quarter ended March 31, 2008).
10.33	First Amendment to Credit Agreement with Wells Fargo Energy Capital dated May 8, 2008 (filed as Exhibit 10.2 to the Company’s Form 10-QSB for the quarter ended March 31, 2008).
23.1*	Consent of Philip Vogel & Co., PC
31.1*	Rule 13a-14(a)/15d-14(a) Certification of Calvin A. Wallen, III
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Scott D. Guffey
32.1*	Section 1350 Certification of Calvin A. Wallen, III
32.2*	Section 1350 Certification of Scott D. Guffey

* Filed herewith.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT AUDITORS

Cubic Energy, Inc.

We hereby consent to the use in the Form 10-K filing of our report dated September 24, 2008, relating to the balance sheet of Cubic Energy, Inc. as of June 30, 2008 and 2007, and the related statements of operations, changes in shareholders’ equity, and cash flows for each of the three years in the period ended June 30, 2008, which are contained in that filing.

PHILIP VOGEL & CO., PC

Dallas, Texas

September 24, 2008

EX-31.1

Exhibit 31.1

CERTIFICATION

Pursuant to Rule 13a-14(a) and 15d-14(a)

I, Calvin A. Wallen, III, certify that:

1. I have reviewed this annual report on Form 10-K of Cubic Energy, Inc.

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report.

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - -15(e) and 15d-15(e)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and,

(c) disclosed in this annual report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the Audit Committee of the registrant’s Board of Directors (or persons performing the equivalent function):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: September 29, 2008

Signature:	/s/ Calvin A. Wallen, III
	Calvin A. Wallen, III, C.E.O.

EX-31.2

Exhibit 31.2

CERTIFICATION

Pursuant to Rule 13a-14(a) and 15d-14(a)

I, Scott D. Guffey, certify that:

1. I have reviewed this annual report on Form 10-K of Cubic Energy, Inc.

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report.

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a - -15(e) and 15d-15(e)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and,

(c) disclosed in this annual report any change in the registrant’s internal control over financial    reporting that occurred during the registrant’s fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the Audit Committee of the registrant’s Board of Directors (or persons performing the equivalent function):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and,

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: September 29, 2008

Signature:	/s/ Scott D. Guffey
	Scott D. Guffey, C.F.O.

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Cubic Energy, Inc. (the “Company”) on Form 10-K for the period ending June 30, 2008 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, as C.E.O., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 29, 2008

Signature:	/s/ Calvin A. Wallen, III
	Calvin A. Wallen, III, C.E.O.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Cubic Energy, Inc. (the “Company”) on Form 10-K for the period ending June 30, 2008 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, as C.F.O., certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: September 29, 2008

Signature:	/s/ Scott D. Guffey
	Scott D. Guffey, C.F.O.