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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-KSB

ANNUAL REPORT

PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED JUNE 30, 2004

COMMISSION FILE NUMBER 0-9355

CUBIC ENERGY, INC.

(Name of Small Business Issuer 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)

TELEPHONE: (972) 686-0369

(Issuer's Telephone Number)

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

COMMON STOCK-PAR VALUE $.05 PER SHARE

Check whether 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, and (2) has been subject to such filing requirements for the past 90

days.

Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405

of Regulation S-B 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-KSB or any amendment to

this Form 10-KSB.

[ ]

As of June 30, 2004, the registrant had outstanding 31,451,826 shares of common

stock, $.05 par value ("Common Stock"), which is registrant's only class of

common stock. The aggregate market value of the Common Stock held by

non-affiliates of the registrant, computed by reference to the average bid and

ask price and shares outstanding, was approximately $5,991,586 as of September

1, 2004. Shares of Common Stock held by each officer and director of the
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registrant and by each person who may be deemed to be an affiliate have been

excluded. This determination of affiliate status is not necessarily a conclusive

determination for other purposes.

<PAGE>

The registrant's revenues for the fiscal year ended June 30, 2004 were $417,181.

Transitional Small Business Disclosure Format: Yes No X

--- ---

2

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CUBIC ENERGY, INC.

TABLE OF CONTENTSDESCRIPTION

PART I

Item Page

---- ----

ITEM 1. Description of Business and Properties 5

GENERAL........................................................................5

DESCRIPTION OF BUSINESS........................................................5
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RESTATEMENT OF FINANCIAL RESULTS...............................................7

PRINCIPAL OIL AND GAS PROPERTIES...............................................7

MARKETING OF PRODUCTION........................................................8

OIL AND GAS RESERVES...........................................................9

NET PRODUCTION, SALES PRICES AND COSTS........................................10

PRODUCTIVE WELLS AND ACREAGE..................................................11

ITEM 4. Submission of Matters to a Vote of Security Holders 28

ITEM 5. Market for Registrant's Common Equity and Related Stockholder

Matters 28

ITEM 6. Management's Discussion and Analysis or Plan of Operations 29

RESULTS OF OPERATIONS 30

COMPARISON OF FISCAL 2004 TO FISCAL 2003 REVENUES.............................30

LIQUIDITY AND CAPITAL RESOURCES...............................................30

ITEM 7. FINANCIAL STATEMENTS 32

ITEM 9. Directors, Executive Officers, Promoters and Control Persons of

the Registrant; Compliance With Section 16(A) of the Exchange Act............ 33

The Company accounts for its stock-based employee compensation plans

under the recognition and measurement principles of APB Opinion

NO. 25, Accounting for Stock Issued to Employees, and related interpretations.

No stock based employee compensation cost is reflected in net income,

as all options granted under those plans had an exercise price at least

equal to the market of the underlying common stock on the date of the grant. 34

COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT.............................35

ITEM 10. Executive Compensation 35

The Company Accounts for its stock-based employee compensation plans

under the recognition and measurement principles of APB Opinion

No. 25, Accounting for Stock Issued to Employees, and related interpretations.

No stock based employee compensation cost is reflected in net income,

as all options granted under those plans had an exercise price at least

equal to the market of the underlying common stock on the date of the grant. 36

ITEM 11. Security Ownership of Certain Beneficial Owners and Management 36

item 13. Exhibits, Financial Statement Schedules and Reports On Form 8-K 39

the following documents are filed as part of this report commencing

on page F-1:..................................................................39

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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. 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
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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.

4

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Cubic Energy, Inc.

PART I

ITEM 1. Description of Business and Properties

GENERAL

Cubic Energy, Inc. is an independent energy company engaged in the development

and production of, and exploration for, crude oil and natural gas. Our oil and

gas assets are concentrated principally in Texas and Louisiana. At June 30,

2004, our total proved reserves were 51,850 BOE.

We were incorporated in October 1978 in the State of Texas and in March 1980, we

were merged into a publicly held Utah corporation with the surviving entity

being Roseland Oil and Gas, Inc., a Utah corporation. In August 1991, Roseland

Oil and Gas, Inc., the Utah Corporation, was merged into an Oklahoma corporation

and we relocated our corporate offices from Houston, Texas to Tulsa, Oklahoma.

In October of 1999, pursuant to approval of the Shareholders, Roseland Oil and

Gas, Inc. was merged into Cubic Energy, Inc., a Texas corporation. References to

Cubic, Roseland or the Company include the Company and our predecessors unless

the context otherwise requires. Our principal executive office is located at

9870 Plano Road, Dallas, Texas 75238, and our telephone number is (972)

686-0369.
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In December 1997, the Company 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 Stock Purchase 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 December 1997 Stock Purchase Agreement, the Company focused

primarily on the acquisition of non-operated working interests and overriding

royalty interests in oil and gas properties. Subsequent to the Stock Purchase

Agreement in December 1997, the Company 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 our own properties 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 are

reviewing plans to acquire and develop properties in our core areas in Texas and

Louisiana, as well as establishing a drilling program for the drilling of

exploratory, development and infill wells, a strategy previously unavailable to

the Company 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.

5

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We also took decisive steps in addressing various accounting issues and, in

accordance with generally accepted accounting principles, took significant

write-downs of our assets prior to our fiscal year end of June 30, 1999, which

directly impacted our net income. The Company recorded a net loss in fiscal 1999

of $515,933 due largely to depletion and lease operating expense. In addition,

our management requested our prior auditor to provide the Company with restated

audited financial statements for the fiscal year ending June 30, 1998 to

accurately reflect the condition of the Company.

In the year ending June 30, 1999, we took a prior year adjustment that affected

the income statement for the year ending June 30, 1997. The adjustment was

necessary to recapture excess depletion to income that should have been adjusted

in 1997. Consequently, the retained deficit for 1999 was adjusted to reflect

$196,491 of prior year excess depletion.

On April 27, 2001, the Company completed an exchange offer pursuant to which it

acquired (i) certain direct working interests in producing oil and/or natural

gas wells (the "Working Interests") and (ii) all of the outstanding membership

units in four privately held limited liability companies and approximately 9.85%
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of the working interest in another privately held limited liability company, all

of which are engaged in oil and/or natural gas exploration and production. The

Working Interests consist of between 15% and 45% working interests in fourteen

(14) wells. The Working Interests are part of projects operated by Tauren

Exploration, Inc. ("Tauren"), an independent energy company, and Fossil

Operating, Inc. ("Fossil") acts as the operator for some of the properties.

Calvin A. Wallen, III, a material shareholder, director and officer of the

Company is the sole shareholder, director and officer of Tauren and Fossil. The

relationship between the Company and each of Tauren and Fossil were approved by

the disinterested directors of the Company. The exchange offer was made to and

was accepted by the various individual holders of the interests acquired. The

Working Interests and the properties held are located in Texas and Louisiana.

The consideration paid to the individuals who accepted the exchange offer was

determined based on the Company's valuation of the reserves underlying the

interests acquired. The value of the Company's common stock for purpose of the

exchange offer was deemed to be $0.50 per share. In connection with the exchange

offer, the Company issued approximately 11,141,256 shares of the Company's

common stock. In addition, as consideration for services rendered with respect

to this exchange offer, C. K. Cooper & Company, and/or its principals and

employees, received 111,413 shares of the Company's common stock.

Effective January 1, 2002, the Company entered into an Agreement with Tauren

Exploration, Inc. whereby (i). Tauren exchanged and traded the accounts

receivable of $856,712 owed by the Company for 856,712 shares of restricted

Company common stock, (ii). The Company attained ground floor opportunities from

Tauren to participate in Tauren's prospect and project inventory, and (iii).

Certain warrants were issued to Tauren from the Company to acquire restricted

Company common stock. A copy of this Agreement was filed with the Company's

March 31, 2002 Form 10-QSB.

In April, 2002, the Company made the strategic decision not to renew the Red

Rock Louisiana leaseholds, which action has had a substantial impact on the June

30, 2002 income statement for the Company. Despite the impact, the Company

believes the decision not to re-new the leases will be to the ultimate benefit

of the Company.

On June 1, 2002, Tauren Exploration, Inc. assigned certain oil and gas

properties to the Company for di minimus consideration. The Company already had

an interest in some of the properties assigned for Tauren.

6

<PAGE>

RESTATEMENT OF FINANCIAL RESULTS

Subsequent to the issuance of our financial statements for the fiscal year ended

June 30, 1999 and prior to the issuance of our financial statements for the

fiscal year ended June 30, 1998, our new Board of Directors determined that the

prior management of the Company (i.e., our management prior to the December 1997

Stock Purchase Agreement) had included assets consisting of oil and gas

properties on our financial statements after the oil and gas properties had

already been sold or transferred by the Company prior to the periods covered by

the 1996 and 1997 financial statements. Upon examination, the Board of Directors

and new management of the Company determined that certain assets were improperly

included on our financial statements for prior periods and were inappropriately
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included in calculations of assets, depletion deductions and net income in our

balance sheets and statements of operations. As a result, the financial

statements as of June 30, 1998 and for the year ended, presented the restated

accumulated deficit at June 30, 1999 of $2,430,936 and a restated net loss for

the year ended June 30, 1999 of $515,933.

In response to the errors discussed above, a number of conditions, which could

represent a material weakness in our prior internal accounting controls, were

identified. These conditions included a deterioration in our internal accounting

controls under prior management, lack of adequate communication between our

prior management and prior auditors, a failure to stress the importance of

controls by prior management, and an apparent lack of clarity and consistent

understanding within the Company by prior management concerning the application

of our accounting policies to transactions involving the sale of properties. We

have implemented steps that have strengthened our internal accounting controls.

These steps included provision of in house accounting services through our

affiliate, updating our policies regarding accounting and reporting for

transactions, changing our corporate accounting and reporting structure and

hiring a new accounting firm.

PRINCIPAL OIL AND GAS PROPERTIES

The following table summarizes certain information with respect to our principal

areas of operation at June 30, 2004.

Percent Present

Oil Gas of Proved Value

Areas (Bbl) (Mcf) Reserves (Disc @ 10%)

----- ----- ----- --------- ------------

Texas 0 311,098 100% $731,913

-----------------------------------------------------------------------

Total 0 311,098 100% $731,913

Our Texas properties are situated in Palo Pinto, Parker, Eastland and Callahan

Counties. At June 30, 2004, the Texas properties contained 100% of our proved

reserves, which represented 100% of our Present Value of total proved reserves.

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.

In June 1998, we agreed to a farm-out agreement with Cummings Company, reserving

an overriding royalty interest. As of June 30, 2000, Cummings had completed its

drilling program on the farmed out interest and completed four wells, the Reagan

11-1, Reagan 11-2, Reagan 11-3 and the Reagan 11-4.

7

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Our net production for the fiscal year ending June 30, 2004 for the Texas wells

averaged approximately 196 Mcf of natural gas per day and 1 barrel of oil per

day.

EXPLORATION ACTIVITIES
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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 at 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, Texas, and New Mexico.

Currently we have development opportunities in and will acquire additional

leasehold interests in Allen, Caddo, Desoto, Evangeline, Sabine, Natchitoches,

Rapides Parishes, Louisiana, in Limestone, Navarro, Red River, Henderson

Counties, Texas and in Chaves County, New Mexico. 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. Additionally over 2,240

miles of aeor-magnetics has been acquisitioned over several large Texas areas

and is under final analysis for basement structural mapping. Prospects have been

developed from 4,000-17,500 feet in depth in the Paluxy, Frio, Wilcox,

Smackover, Bradley, Canyon, Rodessa and James formations.

We also have included an acquisition strategy to our business plan that would

allow us to capitalize on producing oil and gas acquisition targets.

MARKETING OF PRODUCTION

Crude Oil and Natural Gas

Our production consists mainly of natural gas. We market our operated production

of natural gas to one purchaser, Devon Gas Services LP. 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 $399,045 for the fiscal year ended

June 30, 2004 and represented 96% of our total oil and gas revenues for that

fiscal year.

8

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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
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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 year

2004 was $32.16.

Natural gas 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 2004 was $5.55.

OIL AND GAS RESERVES

The following tables set forth the proved developed and undeveloped reserves at

June 30, 2004, the estimated future net revenues from such proved reserves and

the Present Value and Standardized Measure of Discounted Future Net Cash Flows

attributable to our reserves at June 30, 2003, 2002 and 2001:

10%

Category Oil (Bbls) Gas (Mcf) Total (Mcfe) Income Discount

---------- --------- ------------ ------ --------

Proved Producing 0 311,098 311,098 $975,468 $731,913

Proved Undeveloped 0 0 0 $0 $0

AT JUNE 30,

--------------------------------------

2004 2003 2002

Proved reserves:

Oil (Bbl) ....................... 0 0 0

Gas (Mcf) ....................... 311,098 330,409 564,000

BOE .................................. 51,850 55,068 94,045

Estimated future net revenues

(before income tax) ......... $ 975,468 $1,098,147 $1,060,369

Standardized Measure(1) ......... $ 731,913 $ 798,381 $ ,657,668

Proved developed reserves:

Oil (Bbl) ....................... 0 0 0

Gas (Mcf) ....................... 311,098 330,409 564,000

BOE .................................. 51,850 55,068 94,045

Estimated future net revenues

(before income tax) ......... $ 975,468 $1,098,147 $1,060,369

Present Value ........................ $ 731,913 $ 798,381 $ 657,668

Standardized Measure (1) ............. $ 731,913 $ 798,381 $ 657,668

Weighted average sales prices:

Oil (per Bbl) ................... $ 32.16 $ 26.20 $ 24.18

Gas (per Mcf) ................... $ 5.55 $ 4.91 $ 3.09

(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 revenues from the production of

proved reserves, after giving effect to income taxes. See the
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Supplemental Financial Information attached 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 ("SFAS") No. 69, "Disclosures about Oil and Gas

Producing Activities."

All information set forth in this Report relating to our proved reserves,

estimated future net revenues and present values is taken from reports prepared

by Michael S. Turner, P.E., an independent petroleum engineer. The estimates of

this engineer were based upon review of production histories and other

geological, economic, ownership and engineering data provided by the Company. No

reports on our reserves have been filed with any federal agency. In accordance

with guidelines of the Securities and Exchange Commission (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

revenues, 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.

NET PRODUCTION, SALES PRICES AND COSTS

The following table presents certain information with respect to oil and gas

production, prices and costs attributable to all oil and gas property interests

owned by us for the period ended June 30, 2004.
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YEAR ENDED YEAR ENDED

JUNE 30, 2004 JUNE 30, 2003

------------- -------------

PRODUCTION VOLUMES:

Oil (Bbl) ............................. 562 298

Gas (Mcf) ............................. 71,804 71,054

WEIGHTED AVERAGE SALES PRICES:

Oil (per Bbl) ......................... $ 32.16 $ 26.20

Gas (per Mcf) ......................... $ 5.55 $ 4.91

SELECTED EXPENSES PER BOE:

Lease operating ....................... $ 14.88 $ 13.78

Depreciation, depletion and

Amortization .......................... $ 8.36 $ 9.82

General and administrative ............ $ 19.16 $ 14.43

PRODUCTIVE WELLS AND ACREAGE

Productive Wells

The following table sets forth our domestic productive wells at June 30, 2004:

OIL GAS TOTAL

-------------------- ------------------- -------------------

Gross Net Gross Net Gross Net

----- --- ----- --- ----- ---

0 0 14 12.9 14 12.9

Acreage

The following table sets forth our undeveloped and developed gross and net

leasehold acreage at June 30, 2004. 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

----- --- ----- --- ----- ---

0 0 930 891 930 891

All the leases for the undeveloped acreage summarized in the preceding table

will expire at the end of their respective primary terms unless prior to that

date the existing leases are renewed or production has been obtained from the

acreage subject to the lease, in which event the lease will remain in effect

until the cessation of production. As is customary in the industry, we generally

acquire oil and gas acreage without any warranty of title except as to claims
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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. In many instances, title opinions may not be obtained if in

our judgment it would be uneconomical or impractical to do so.

On June 18, 1998, the Company farmed-out 188 acres of the Reagan lease in

Section 11, Palo Pinto County, Texas to the Cummings Company, Inc. retaining a

6.25% overriding royalty interest in any wells drilled under the Farm-out

Agreement.

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In addition, on December 10, 1998, the Company entered into an agreement with

Tauren Exploration Inc. ("Tauren") that provides for Tauren to drill on the

Company's Section 11 in Palo Pinto County, Texas. The agreement grants Tauren

Exploration Inc. a farm-out with Cubic retaining a 7.5% overriding royalty

interest. The agreement also provides for a preferential right in the event that

Tauren, at some later date, decides to dispose of a part or all of their

interest in the drilled wells. Tauren is an affiliate of Calvin A. Wallen, III,

an officer, director and majority shareholder of the Company.

On April 27, 2001, the Company completed an exchange offer pursuant to which it

acquired (i) certain direct working interests in producing oil and/or natural

gas wells (the "Working Interests") and (ii) all of the outstanding membership

units in four privately held limited liability companies and approximately 9.85%

of the working interest in another privately held limited liability company, all

of which are engaged in oil and/or natural gas exploration and production. The

Working Interests consist of between 15% and 45% working interests in fourteen

(14) wells. The Working Interests are part of projects operated by Tauren

Exploration, Inc. ("Tauren"), and independent energy company, and Fossil

Operating, Inc. ("Fossil") acts as the operator for some of the properties.

Calvin A. Wallen, III, a material shareholder, director and officer of the

Company is the sole shareholder, director and officer of Tauren and Fossil. The

relationship between the Company and each of Tauren and Fossil were approved by

the disinterested directors of the Company. The exchange offer was made to and

was accepted by the various individual holders of the interests acquired. The

Working Interests and the properties held are located in Texas. The

consideration paid to the individuals who accepted the exchange offer was

determined based on the Company's valuation of the reserves underlying the

interests acquired. The value of the Company's common stock for purpose of the

exchange offer was deemed to be $0.50 per share. In connection with the exchange

offer, the Company issued approximately 11,141,256 shares of the Company's

common stock. In addition, as consideration for services rendered with respect

to this exchange offer, C. K. Cooper & Company, and/or its principals and

employees, received 111,413 shares of the Company's common stock.

OPERATIONS

Although in the past we have not been the operator of our wells, in the future

we generally intend to seek to be named operator for wells in which we acquire a

significant interest or will appoint an operator on our behalf. As is common in
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the industry, this typically occurs only when we own the major portion of the

working interest in a particular well or field. At June 30, 2004, third parties

operated our wells under specific agreements.

Through the specific agreements providing for third party operations of majority

owned wells, we are able to exercise a great deal of influence over the

development and enhancement of a well and to supervise operation and maintenance

activities. We have not conducted the actual drilling of wells on properties in

which we have acted as operator in the past, but in the future we plan to engage

independent contractors who are supervised by the Company. 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.

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.

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RISK FACTORS

Holders of our Common Stock and future investors in the Company should be aware

of the following factors in evaluating their investment in the Company.

Competition

The oil and gas industry is highly competitive. The Company encounters

competition from other oil and gas companies in all areas of its operations,

including the acquisition of producing properties and sale of crude oil and

natural gas. The Company's competitors include major integrated oil and gas

companies and numerous independent oil and gas companies, individuals and

drilling and income programs. Many of its competitors are large, well

established companies with substantially larger operating staffs and greater

capital resources than the Company. 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

the Company's financial or human resources permit. The Company's ability to

acquire additional properties and to discover reserves in the future will depend

upon its ability to evaluate and select suitable properties and to consummate

transactions in this highly competitive environment.

Drilling and Operating Risks

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 the Company will be productive or that

the Company will recover all or any portion of its 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. The Company's drilling
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operations may be curtailed, delayed or canceled as a result of a variety of

factors, many of which are beyond its 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. The Company's future

drilling activities may not be successful. Lack of drilling success could have a

material adverse effect on the Company's financial condition and results of

operations.

The Company's 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

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

the Company 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. The Company participates in insurance coverage maintained by the

operator of its wells, although there can be no assurances that such coverage

will be sufficient to prevent a material adverse effect on the Company in such

events.

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Limited Operating History; Capital Intensive Business; Need for Additional Funds

From its inception through December 1997, the Company was engaged principally in

non-operating activities. While the Company's new management has extensive

experience in oil and gas exploration and operating activities, the Company has

had very limited experience in these operations. The Company's business is

highly capital-intensive requiring continuous development and acquisition of oil

and gas reserves. In addition, capital is required to operate and expand the

Company's oil and gas field operations and purchase equipment. At June 30, 2004,

the Company had working capital of $143,032. As a result of the Company's

determination to operate in the future, the Company's working capital

requirements may be expected to increase significantly over prior periods. The

Company anticipates that it will be able to meet its cash requirements for the

next 12 months. However, if such plans or assumptions change or prove to be

inaccurate, the Company could be required to seek additional financing sooner

than currently anticipated. The Company has no commitments to obtain any

additional debt or equity financing and there can be no assurance that

additional funds will be available, when required, on terms favorable to the

Company. Any future issuances of equity securities would likely result in

dilution to the Company's then existing shareholders while the incurring of

additional indebtedness would result in increased interest expense and debt

service changes. See "Management's Discussion and Analysis or Plan of

Operations."

History of Losses

The Company incurred losses before income tax provisions of $114,116 and
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$217,121 for the fiscal years ended June 30, 2004 and 2003, respectively. The

Company's accumulated deficit as of June 30, 2004 was $9,968,342. The Company

does not have a bank line of credit. The Company has funded its operating

losses, acquisitions and expansion costs primarily through a combination of

private offerings of convertible debt, exempt transactions, equity securities

and proceeds from the exercise of warrants. The success of the Company in

obtaining the necessary capital resources to fund future costs associated with

its operations and expansion plans is dependent upon the Company's ability to:

(i) increase revenues through acquisitions and recovery of the Company's 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 the exercise of outstanding warrants. However, even

if the Company achieves some success with its plans, there can be no assurance

that it will be able to generate sufficient revenues to achieve significant

profitable operations or fund its expansion plans. See "Management's Discussion

and Analysis or Plan of Operations".

Significant Capital Expenditures Necessary for Undeveloped Properties

The vast majority of the Company's oil and gas reserves are classified as Proved

Reserves. Recovery of the Company's future Proved Undeveloped Reserves will

require significant capital expenditures. Management estimates that aggregate

capital expenditures of approximately $1,000,000 will be required to fully

develop some of these reserves in the next twelve months. No assurance can be

given that the Company's estimates of capital expenditures will prove accurate,

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that its financing sources will be sufficient to fully fund its planned

development activities or that development activities will be either successful

or in accordance with the Company's 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.

No Assurance of Additional Financing

Development of the Company's properties will require additional capital

resources. The Company has 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 the Company. The inability to

obtain additional financing could have a material adverse effect on the Company,

including requiring the Company to curtail significantly its oil and gas

acquisition and development plans or farm-out development of its properties. Any

additional financing may involve substantial dilution to the interests of the

Company's shareholders at that time. See "Management's Discussion and Analysis

or Plan of Operations."

Exploration and Development Risks

The Company intends to increase its development and, to a lesser extent,

exploration activities. Exploration 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
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insufficient to recover drilling and completion costs. The cost of drilling,

completing and operating wells is often uncertain. The Company's 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.

Volatility of Oil and Gas Prices

The Company's revenues, profitability and the carrying value of its 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. The Company's 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 the Company's control. These factors include domestic and foreign

political conditions, the price and availability of domestic and imported oil

and 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 the Company's

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 the Company's ability to market its production through

such systems, pipelines or facilities. Substantially all of the Company's gas

production is currently sold to one gas marketing firm on a month-to-month basis

at prevailing spot market prices. Oil prices remained subject to unpredictable

political and economic forces during fiscal 2002, fiscal 2003 and fiscal 2004,

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and experienced fluctuations similar to those seen in natural gas prices for the

year. We believe that oil 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, 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 and natural gas

prices.

Uncertainty of Estimates of Reserves and Future Net Cash Flows

This Annual Report contains estimates of the Company's 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
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many factors beyond the Company's control. The reserve estimates in this Annual

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 Annual Report. Additionally, the Company's 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 the Company's control.

The present value of future net reserves discounted at 10% (the "PV-10") of

Proved Reserves referred to in this Annual Report should not be construed as the

current market value of the estimated Proved Reserves of oil and gas

attributable to the Company's properties. In accordance with applicable

requirements of the Commission, 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 Commission is not necessarily the most appropriate discount factor based on

interest rates in effect from time to time and risks associated with the

Company's reserves or the oil and gas industry in general. Furthermore, the

Company's 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 "Properties -- Oil and

Gas Reserves."

Operating Hazards and Uninsured Risks; Production Curtailments

The Company's 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

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(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 the Company carries

insurance at levels that it believes are reasonable, it is not fully insured

against all risks. The Company does not carry business interruption insurance.

Losses and liabilities arising from uninsured or under-insured events could have

a material adverse effect on the financial condition and operations of the

Company.

From time to time, due primarily to contract terms, pipeline interruptions or

weather conditions, the producing wells in which the Company owns 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
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cases, the Company is provided only limited notice as to when production will be

curtailed and the duration of such curtailments. The Company is not currently

experiencing any material curtailment of its production.

Dependence on 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. The Company has not entered into any employment contracts

with its executive officer and has not obtained key personnel life insurance on

Mr. Wallen, its President and Chief Executive Officer.

Concentration of Voting Power

The Company's executive officers, directors and their affiliates and certain 5%

shareholders hold approximately 68% of the Company's outstanding shares of

Common Stock. As a result, officers, directors and their affiliates and such

shareholders have the ability to exert significant influence over the business

affairs of the Company, 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.

Conflicts of Interests

Certain officers, directors and related parties, including entities controlled

by Calvin A. Wallen, III, 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. Management believes that

the terms of these transactions were as favorable to the Company as those that

could have been obtained from unaffiliated parties under similar circumstances.

All future transactions between the Company and its 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 the Board of

Directors of the Company.

Public Market and Possible Volatility

Our Common Stock is traded on "over-the-counter" market. 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. The trading price of our Common

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Stock could be subject to wide fluctuations in response to quarter-to-quarter

variations in our operating results, announcements of drilling results by the

Company 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 the Company's securities.
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Additional risks related to the Company's common stock's status as a low price

or "penny" stock

The trading price of our Common Stock is below $5.00 per share. As long as the

trading price of our Common Stock remains below $5.00 per share, trading in our

Common Stock is subject to the requirements of certain rules under the Exchange

Act which require additional disclosure by broker-dealers in connection with any

trades generally involving any non-NASDAQ equity security that has a market

price of less than $5.00 per share, subject to certain exceptions. Such rules

require the delivery, prior to any penny stock transaction, of a disclosure

schedule explaining the penny stock market and the associated risks, and impose

various sales practice requirements on broker-dealers who sell penny stocks to

persons other than established customers and accredited investors. For these

types of transactions, the broker-dealer must make a special suitability

determination for the purchaser and have received the purchaser's written

consent to the transaction prior to sale. The additional burdens imposed upon

broker-dealers by such requirements may discourage broker-dealers from effecting

transactions in our Common Stock, which could severely limit the market

liquidity of our Common Stock.

Possible adverse consequences due to the indemnification of officers and

directors

Provisions of our Certificate of Incorporation and By-Laws provide that we will

indemnify any director and officer as to those liabilities and on those terms

and conditions 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. Further, the SEC takes the position that

indemnification against liability under the Securities Act is against the public

policy as expressed in the Securities Act, and is, therefore, unenforceable.

Texas law and our charter documents contain anti-takeover provisions that may

discourage a change in control

Provisions of Texas law and our Certificate of Incorporation and By-Laws may

have the effect of delaying or preventing a change in control or acquisition of

our Company. Our Certificate of Incorporation and By-Laws 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 stockholder approval), purported limits on

stockholder action by written consent in lieu of a meeting, and certain

procedural requirements governing stockholder meetings. These provisions could

have the effect of delaying or preventing a change in control of our Company.

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No Dividends

The Company's board of directors presently intends to retain all of its earnings

for the expansion of its business. The Company therefore does not anticipate the
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distribution of cash dividends in the foreseeable future. Any future decision of

the Company's board of directors to pay cash dividends will depend, among other

factors, upon the Company's earnings, financial position and cash requirements.

Title to Properties

The Company's contract land professionals have reviewed title records or other

title review materials relating to substantially all of its producing

properties. The title investigation performed by the Company prior to acquiring

undeveloped properties is thorough, but less rigorous than that conducted prior

to drilling, consistent with industry standards. The Company believes it has

satisfactory title to all its producing properties in accordance with standards

generally accepted in the oil and gas industry. The Company's properties are

subject to customary royalty interests, liens incident to operating agreements,

liens for current taxes and other burdens, which the Company believes do not

materially interfere with the use of or affect the value of such properties. At

June 30, 2004, the Company's leaseholds for approximately 100% of its 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.

The Company expects to make acquisitions of oil and gas properties from time to

time subject to available resources. In making an acquisition, the Company

generally focuses most of its title and valuation efforts on the more

significant properties. It is generally not feasible for the Company to review

in-depth every property it purchases 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 the

Company to become familiar enough with the properties to assess fully their

deficiencies and capabilities. Evaluation of future recoverable reserves of oil

and gas, which is an integral part of the property selection process, is a

process that depends upon evaluation of existing geological, engineering and

production data, some or all of which may prove to be unreliable or not

indicative of future performance. 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 the Company may

decide to assume environmental and other liabilities in connection with acquired

properties.

Governmental Regulation

The Company's 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 the Company's cost of doing business and affects its

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profitability. Although the Company believes it is in substantial compliance

with all applicable laws and regulations, because such laws and regulations are

frequently amended or reinterpreted, the Company is unable to predict the future

cost or impact of complying with such laws and regulations.

Sales of natural gas by the Company 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 the Company, as well as

the revenues received by the Company for sales of such production. Sales of the

Company's 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 and 636-B ("Order 636"), that have significantly altered

the marketing and transportation of natural gas. Order 636 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 exactly

predict the ultimate impact of the orders on the Company and its 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 the Company's ability to market and transport its natural gas, although

it may also subject the Company 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 the

Company only indirectly, these policy statements and proposed rule changes are

intended to further enhance competition in natural gas markets. The Company

cannot predict what action the FERC will take on these matters, nor can it

predict whether the FERC's actions will achieve its stated goal of increasing

competition in natural gas markets. However, the Company does not believe that

it will be treated materially differently than other natural gas producers and

marketers with which it competes.

The price the Company receives from the sale of oil is affected by the cost of
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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,

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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. The Company is not able to predict with certainty

the effect, if any, of these regulations on its operations. However, the

regulations may increase transportation costs or reduce wellhead prices for oil.

The State of Texas 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 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 the

Company's properties. However, the Company does not believe it will be affected

materially differently by these statutes and regulations than any other

similarly situated oil and gas company.

Environmental Matters

The Company's 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 the Company's operations.

The permits required for the Company's 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, the Company is in substantial compliance with current applicable

environmental laws and regulations, and the Company has 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 the Company. The

impact of such changes, however, would not likely be any more burdensome to the

Company 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
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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.

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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. 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 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.

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.

The Company owns or leases properties that for many years have produced oil and

gas. The Company also owns natural gas gathering systems. It is not uncommon for

such properties to be contaminated with hydrocarbons. Although the Company 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

the Company to remove any such wastes or to remediate the resulting

contamination. All of the Company's properties are operated by third parties

over whom the Company has limited control. Notwithstanding the Company's 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 the Company.

Abandonment Costs

The Company is responsible for payment of plugging and abandonment costs on its
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oil and gas properties pro rata to its working interest. Based on its

experience, the Company anticipates that the ultimate aggregate salvage value of

lease and well equipment located on its properties will exceed the costs of

abandoning such properties. There can be no assurance, however, that the Company

will be successful in avoiding additional expenses in connection with the

abandonment of any of its 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.

Employees

At June 30, 2004, the Company had no full time employees. In January, 2002, the

Company entered into a new contract with an affiliate controlled by our

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President to provide certain technical administration and management services

needed to conduct its business. The terms of the contract provided for personnel

to be contracted at the affiliates true cost; which is more favorable to the

company than would be available from an unaffiliated third party.

Facilities

The Company's principal executive and administrative offices are located at 9870

Plano Road, Dallas, Texas. The offices are subleased from an affiliate

controlled by our President and Chief Executive Officer and the offices are

owned by this affiliate. The monthly amount charged to the Company is based on

actual costs of materials and man-hours of the affiliates that are used pursuant

to the terms of the agreement. The Company believes that there is other

appropriate space available in the event the Company should terminate its

current leasing arrangement.

Possible adverse consequences due to claims and legal proceedings

The Company had filed suit in the 29th Judicial District Court in Palo Pinto

County, Texas, styled "Roseland Oil and Gas, Inc. v. William Vandever, et al.",

bringing suit against Clifford Kees, William Vandever and various persons,

seeking a judicial determination that all grants of preferential rights in the

Reagan Section 11 and 12 are void. This lawsuit was filed on April 26, 1999. All

section 11 preferential rights were returned to the Company on or about January

2002. However, Clifford Kees was to retain his 1% override interest in these

Reagan Lease Sections.

Clifford Kees then moved to trial against on the claim of attorney fees owed to

him for the prosecution of this lawsuit. The trial was heard on September 25,

2002, with Kees requesting in excess of $200,000.00 in attorney fees and costs.

In June of 2003, The Court re-opened the trial as to attorney fees and costs, to

allow Kees to put on additional evidence, and such trial was re-convened on June

19, 2003.

On July 15, 2003, The Court entered a Judgment in favor of Kees and as against

the Company for approximately $112,000.00. The Company believed the Judgment

should not stand and appealed the Judgment. On or about, September 17, 2004, the
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Eastland Court Of Appeals issued its ruling, modifying the amounts owed by the

Company under the Judgment to $59,000.00. The Company is weighing the options as

to filing for re-Hearing or filing a Writ with the Texas Supreme Court. Should

the Judgment stand, it could have a material adverse effect on the cash position

of the Company.

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Glossary of Oil and Gas Terms

The following are abbreviations and definitions of terms commonly used in the

oil and gas industry that are used in this Report.

"BBL" means a barrel of 42 U.S. gallons.

"BOE" means barrels of oil equivalent; converting volumes of natural gas to

oil equivalent volumes using a ratio of six Mcf of natural gas to one Bbl of

oil.

"COMPLETION" means the installation of permanent equipment for the

production of oil or gas.

"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 such that proceeds from the sale of such

production exceed production expenses and taxes.

"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.
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"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".

"FARM-IN" see "FARM-OUT" above.

"GAS" means natural gas.

"GROSS" when used with respect to acres or wells, refers to the total acres

or wells in which we have a working interest.

"INFILL DRILLING" means drilling of an additional well or wells provided

for by an existing spacing order to more adequately drain a reservoir.

"MCF" means thousand cubic feet.

"BTU" means British Thermal Units. British Thermal Unit means the quantity

of heat required to raise the temperature of one pound of water by one degree

Fahrenheit.

"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.

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"PRESENT VALUE" ("PV") when used with respect to oil and gas reserves,

means 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 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, and

discounted using an annual discount rate of 10%.

"PRODUCTIVE WELLS" or "PRODUCING WELLS" consist of producing wells and

wells capable of production, including 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
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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 and natural

gas 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.

(i) 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.

(ii) 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.

(iii) 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 and natural

gas, the recovery of which is subject to reasonable doubt because of

uncertainty as to geology, reservoir characteristics or economic factors;

(C) crude oil and natural gas that may occur in undrilled prospects; and

(D) crude oil and natural gas that may be recovered from oil shales, coal,

gilsonite and other such resources.

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"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.
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"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.

"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.

"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.

"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 2. Description of Properties.

See "ITEM 1. Description of Business And Properties."

ITEM 3. Legal Proceedings

The Company had filed suit in the 29th Judicial District Court in Palo Pinto

County, Texas, styled "Roseland Oil and Gas, Inc. v. William Vandever, et al.",

bringing suit against Clifford Kees, William Vandever and various persons,

seeking a judicial determination that all grants of preferential rights in the

Reagan Section 11 and 12 are void. This lawsuit was filed on April 26, 1999. All

section 11 preferential rights were returned to the Company on or about January

2002. However, Clifford Kees was to retain his 1% override interest in these
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Reagan Lease Sections.

Clifford Kees then moved to trial against on the claim of attorney fees owed to

him for the prosecution of this lawsuit. The trial was had on September 25,

2002, with Kees requesting in excess of $200,000.00 in attorney fees and costs.

In June of 2003, The Court re-opened the trial as to attorney fees and costs, to

allow Kees to put on additional evidence, and such trial was re-convened on June

19, 2003.

On July 15, 2003, The Court entered a Judgment in favor of Kees and as against

the Company for approximately $112,000.00. The Company believed the Judgment

should not stand and appealed the Judgment. On or about, September 17, 2004, the

Eastland Court Of Appeals issued its ruling, modifying the amounts owed by the

Company under the Judgment to $59,000.00. The Company is weighing the options as

to filing for re-Hearing or filing a Writ with the Texas Supreme Court. Should

the Judgment stand, it could have a material adverse effect on the cash position

of the Company.

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

During the fourth quarter of the fiscal year ended June 30, 2003, proxies were

mailed to shareholders of record as of April, 2003, for the Annual Stockholder

meeting that was held on June 2, 2003 in Minneapolis, Minnesota. Security

holders were asked to ratify the selection of the Company's accounting firm,

Philip Vogel & Co., PC, and to vote on directors of the Company with the

directors elected to serve one year or until their replacement was elected.

On June 2, 2003, a quorum was not obtained for the Shareholder meeting and the

shareholder meeting was adjourned without conducting business. The Directors
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then conducted a Director's meeting immediately following the adjournment. The

Directors, vested with the power to do so, approved the selection of Philip

Vogel & Co., PC, and added Herb Bayer to act as Director for the Company, until

a successor is elected and sworn. It was determined that Gene Howard would act

as chairman of the Audit Committee and act as the "financial expert" for the

Audit Committee; and that Herb Bayer would serve on the Audit Committee.

On a going forward basis, the Company plans to hold its Annual Shareholder

Meetings in November or December of each year.

PART II

ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters

The Company is traded OTC BB, trading symbol "QBIK", with CK Cooper & Company,

18300 Von Karman, Suite 440, Irvine, California 92612, acting as the lead market

maker.

At June 30, 2004, there were 31,451,835 shares of Common Stock outstanding held

by approximately 870 shareholders of record.

In the fall of 1999, Roseland Oil and Gas, Inc. was merged into Cubic Energy,

Inc., a Texas corporation and a wholly owned subsidiary of Roseland Oil and Gas,

Inc. Under its Texas Articles of Incorporation, Cubic is authorized to issue one

class of 50,000,000 common shares, par value $0.05/share and one class of

10,000,000 preferred shares, par value $0.01/share. An exchange of one common

share of Roseland for one common share of Cubic was effectuated in the merger.

At the time of the merger, and as of June 30, 2004, there were no preferred

shares of the Company outstanding.

The following table shows, for the periods indicated, the range of high and low

bid information for our common stock as reported by the Over-the-Counter

Bulletin Board. 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:

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---------------------------- -------------- -----------------

Fiscal Year 2003 High Low

---------------------------- -------------- -----------------

1st quarter $0.52 $0.30

---------------------------- -------------- -----------------

2nd quarter $0.49 $0.18

---------------------------- -------------- -----------------

3rd quarter $0.75 $0.28

---------------------------- -------------- -----------------

4th quarter $0.45 $0.25

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---------------------------- -------------- -----------------

Fiscal Year 2004 High Low

---------------------------- -------------- -----------------

1st quarter $0.45 $0.20

---------------------------- -------------- -----------------

2nd quarter $0.30 $0.11

---------------------------- -------------- -----------------

3rd quarter $1.00 $0.25

---------------------------- -------------- -----------------

4th quarter $0.70 $0.60

---------------------------- -------------- -----------------

The Company does not have a written cash dividend policy, has not paid cash

dividends on its common stock in the past and does not expect to pay cash

dividends in the foreseeable future. It is the present intention of management

to utilize all available funds for the development of the Company's business.

ITEM 6. Management's Discussion and Analysis or Plan 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 two-year period ended June 30, 2004. 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 development drilling locations to pursue after the

fiscal year ending June 30, 2004. 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.

THIS MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION 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. ACTUAL RESULTS COULD DIFFER MATERIALLY FROM THOSE PROJECTED IN THE

FORWARD-LOOKING STATEMENTS AS A RESULT OF CERTAIN FACTORS DESCRIBED HEREIN AND

IN OTHER DOCUMENTS. READERS SHOULD CAREFULLY REVIEW THE RISK FACTORS DESCRIBED

IN THIS ANNUAL REPORT AND THE DOCUMENTS THE COMPANY FILES FROM TIME TO TIME WITH

THE SECURITIES AND EXCHANGE COMMISSION.
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RESULTS OF OPERATIONS

COMPARISON OF FISCAL 2004 TO FISCAL 2003 REVENUES

HISTORICALLY PRESENTED:

OIL AND GAS SALES increased 16% to $414,741 in the fiscal year ended June 30,

2004 ("fiscal 2004") from $356,635 in the fiscal year ended June 30, 2003

("fiscal 2003"), due to higher oil and gas prices.

COSTS AND EXPENSES

HISTORICALLY PRESENTED:

PRODUCTION AND OPERATING EXPENSE increased 11% to $186,465 in the year ended

June 30, 2004 ("fiscal 2004") from $167,303 in the year ended June 30, 2003

("fiscal 2003").

HISTORICALLY PRESENTED:

DEPRECIATION, DEPLETION AND AMORTIZATION decreased 12% to $104,735 in fiscal

2004 from $119,249 in fiscal 2003. The decrease was primarily due to an increase

in estimated reserves.

HISTORICALLY PRESENTED:

SELLING, GENERAL AND ADMINISTRATIVE EXPENSE ("G&A") increased 37% to $240,022 in

the year ended June 30, 2004 ("fiscal 2004") from $175,201 in the year ended

June 30, 2003 ("fiscal 2003") because officer stock grants were expensed.

HISTORICALLY PRESENTED:

INTEREST EXPENSE increased to $75 in the year ended June 30, 2004 ("fiscal

2004") from $4 in the year ended June 30, 2003 ("fiscal 2003").

HISTORICALLY PRESENTED:

GAIN ON SALE OF ASSETS was $0 in the years ended June 30, 2004 ("fiscal 2004")

and ended June 30, 2003 ("fiscal 2003") because no assets were sold in either

year.

NET INCOME

HISTORICALLY PRESENTED:

Net loss decreased to reflect a loss of $114,116 in fiscal 2004 from a loss of

$217,121 in fiscal 2003 as a result of higher oil and gas prices.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

The Company's primary financial resource is its oil and gas reserves. The

Company does not have any credit facilities to supplement its internally

generated cash flow as a source of financing for its capital expenditure

programs. 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

funds. Within the confines of product pricing, the Company must be able to find
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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.

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The Company had net working capital of $143,031 at June 30, 2004.

The following discussion sets forth the Company's current plans for capital

expenditures in fiscal 2005, and the expected capital resources needed to

finance such plans.

CAPITAL EXPENDITURES

HISTORICALLY PRESENTED:

At the present time, the Company anticipates an increase to spending on

exploration and development activities during fiscal 2005 through the

development of strategic alliances that will position the Company to take

advantage of possible acquisition objectives that will fit into the Company's

core activity areas of oil and gas production.

The Company will increase its planned activities for fiscal 2005 if product

prices remain strong and if we are able to obtain the capital resources

necessary to finance such activities. See "BUSINESS - DRILLING, EXPLORATION AND

PRODUCTION ACTIVITIES."

WORKING CAPITAL AND CASH FLOW

HISTORICALLY PRESENTED:

During fiscal 2004, the Company generated cash flow from operating activities of

$75,763.

The Company's working capital increased to $143,031 at June 30, 2004 from

$59,362 at June 30, 2003, due to increased oil and gas sales which were

primarily achieved by higher oil and gas prices.

CAPITAL RESOURCES

The Company cannot be certain that the funds which will be available from the

completed and pending sales of assets, combined with operating cash flow, will

be adequate to fund the projected capital expenditures for fiscal 2005. However,

because future cash flows and the availability of borrowings 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, and the uncertainty with respect to the amount of funds

which may ultimately be required to finance the Company's exploration program,

there can be no assurance that the Company's capital resources will be

sufficient to sustain the Company's exploratory and development activities.

If funds available from asset sales, combined with operating cash flow, are not

sufficient to fund its anticipated levels of capital expenditures, the Company

will be required to seek alternative forms of capital resources, including the

sale of other assets and the issuance of debt or equity securities. Although the

Company believes it will be able to obtain funds pursuant to one or more of
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these alternatives, if needed, management cannot be assured that any such

capital resources will be available to the Company. If additional capital

resources are needed, but we are unable to obtain such capital resources on a

timely basis, the Company may not be able to maintain a level of liquidity

sufficient to meet its obligations as they mature or to implement its capital

expenditures or develop its assets.

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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 2004.

INFORMATION SYSTEMS FOR THE YEAR 2000

The Company completed implementation of a "Year 2000 Plan" in the fiscal year

ended June 30, 2000; and through June 30, 2004, the Company experienced no

effects of its information systems from "Y2K". Though not expected, it is still

possible that "Y2K" issues could have a material effect on the operations,

productivity, and profitability of the Company.

ITEM 7. FINANCIAL STATEMENTS

The Report of Independent Accountants, Financial Statements and any

supplementary financial data required by this Item are set forth on pages F1

through F23 of this Report and are incorporated herein by reference.

PART III

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

FINANCIAL DISCLOSURE.

None.

Item 8A. Controls and Procedures.

Our principal executive and financial officer has concluded, based on his

evaluation as of the end of the period covered by this report, that our

disclosure controls and procedures under Rule 13a-14 of the Securities Exchange

Act of 1934, as amended, are effective to ensure that information we are

required to disclose in the 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 include controls and procedures designed to

ensure that information we are required to disclose in such reports is

accumulated and communicated to management, including our principle executive

and financial officer, as appropriate to allow timely decisions regarding

required disclosure. Subsequent to our evaluation, there were no significant

changes in internal controls or other factors that could significantly affect
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these internal controls.

We maintain a system of internal control over financial reporting. There has

been no change in our internal control over financial reporting that occurred

during our fourth fiscal quarter that has materially affected, or is reasonably

likely to materially affect, our internal control over financial reporting.

Item 8B. Other Information.

None.

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ITEM 9. Directors, Executive Officers, Promoters and Control Persons of the

Registrant; Compliance with Section 16(a) of the Exchange Act.

The following table sets forth the name and age of each director and executive

officer and the period during which each has served as a director of the

Company:

Directors and Executive Officers

The following table provides information concerning each of our

executive officers and directors as of June 30, 2004:

---------------------- -------- -------------------------- ----------------

Name Age Position with Cubic Director Since

---------------------- -------- -------------------------- ----------------

Calvin A. Wallen, III 49 Chairman of the Board,

President, & 1997

Chief Executive Officer

---------------------- -------- -------------------------- ----------------

Jon S. Ross 40 Director, Secretary 1998

---------------------- -------- -------------------------- ----------------

Gene Howard 77 Director 1991

---------------------- -------- -------------------------- ----------------

Herbert Bayer 55 Director 2003

---------------------- -------- -------------------------- ----------------

Bob Clements 62 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. He was employed

by Superior Oil and various other drilling contractors including Resource, Tom

Brown and Rowan International. He 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
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evolved into Tauren Exploration, Inc. Mr. Wallen did his undergraduate studies

at Texas A&M University in College Station, Texas.

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 specializing in the representation of over fifty

corporate entities within the past eight years. 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.

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

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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 and Hinderliter corporations

from 1991 to August of 1992. He is also Chairman of the Board of Philadelphia

Mortgage Trust ("PMT").

HERBERT A. BAYER has served as a director of Cubic Energy since May of

2003. Mr. Bayer is currently the Regional Director of Sales for Itron, which

provides intelligent electronic maps of utility transmission and distribution

systems. He was a Business Management major at Indiana State University.

ROBERT L. CLEMENTS joined the Cubic Energy, Inc. Board Of Directors in

February 0f 2004. Mr. Clements was born and raised in Texas. The culmination of

Mr. Clements' education was degree in the OPM Program at 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 area. Bob has served and currently serves on a variety for profit and

charitable committees and Boards.

Audit Committee Financial Expert

The Board of Directors, after reviewing all of the relevant facts, circumstances

and attributes, has determined that Mr. Howard, the Chairman of the Audit

Committee, is the sole "audit committee financial expert" on the Audit Committee

and that Mr. Howard is "independent" (as defined by SEC rules).

Stock grants:

On September 12, 2003, the Directors of Cubic tentatively approved of a Director
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and Officer compensation plan as follows: (i.) Directors of record as of June 1,

2003 would receive 24,000 restricted Cubic common shares (16,000 shares per

year, multiplied by 1.5 years) for years of prior service, (ii.) the

President/CEO of Cubic would receive 45,000 restricted Cubic common shares

(30,000 share per year, multiplied by 1.5 years) for years of prior service,

(iii.) the Secretary of Cubic would receive 22,500 restricted Cubic common

shares (15,000 shares per year, multiplied by 1.5 years) for prior years of

service, (iv.) going forward, Directors would receive 16,000 restricted Cubic

common shares per year of service, (v.) going forward, the President/CEO would

receive 30,000 restricted Cubic common shares per year of service, (vi.) going

forward, the Secretary would receive 15,000 restricted Cubic common shares per

year of service, (vii.) Audit Committee members would receive 10,000 restricted

Cubic common shares per audit, and, (viii.) any Compensation Committee member,

should one be formed, would receive 3,000 restricted Cubic common shares per

year of service. On February 9, 2004, Cubic issued 155,000 common shares of

stock to its Officers and Directors pursuant to this plan, for service during

the current fiscal year. Based on a then market price of $0.45 per share, Cubic

recorded a compensation expense of $69,750; which expense is recorded in the

above financial statements as a selling, general and administrative expense.

Pro forma information related to stock options:

The Company accounts for its stock-based employee compensation plans under the

recognition and measurement principles of APB Opinion No. 25, Accounting for

Stock Issued to Employees, and related interpretations. No stock based employee

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compensation cost is reflected in net income, as all options granted under those

plans had an exercise price at least equal to the market of the underlying

common stock on the date of the grant.

Directors are reimbursed by the Company for all travel expenses.

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.

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 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, except for (1) Herbert Bayer's

inadvertent late filing of his initial Form 3 due in June 2003 and a Form 4 to

report one transaction in November 2003, (2) Gene Howard's inadvertent late

filing of a Form 4 to report one transaction in November 2003, (3) Calvin Wallen

III's inadvertent late filing of one Forms 4 to report one transaction in

November 2003 and one Form 4 to report three transactions in March 2004 and (4)
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Jon Stuart Ross' inadvertent late filing of a Form 4 to report one transaction

in November 2003.

ITEM 10. Executive Compensation

The total cash compensation for the three fiscal years ended June 30, 2004, for

Calvin A. Wallen, III, the Company's current Chief Executive Officer and Jon S.

Ross, the Company's current Secretary is set forth below in the following

Summary Compensation Table. No other person received cash compensation in excess

of $100,000 during the fiscal year ended June 30, 2004.

SUMMARY COMPENSATION TABLE

Fiscal Annual Other Annual

Name and Principal Position Year Salary Compensation

--------------------------- ---- ------ ------------

Calvin A. Wallen, III, President and CEO 2004 0 0

2003 0 0

2002 0 0

Jon S. Ross, Secretary 2004 0 0

2003 0 0

2002 0 0

Warrants were granted to an affiliate of Calvin A. Wallen, III effective January

1, 2002, as described in that agreement attached as an exhibit to the March 31,

2002, Form 10-QSB.

Stock grants:

On September 12, 2003, the Directors of Cubic tentatively approved of a Director

and Officer compensation plan as follows: (i.) Directors of record as of June 1,

2003 would receive 24,000 restricted Cubic common shares (16,000 shares per

year, multiplied by 1.5 years) for years of prior service, (ii.) the

President/CEO of Cubic would receive 45,000 restricted Cubic common shares

(30,000 share per year, multiplied by 1.5 years) for years of prior service,

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(iii.) the Secretary of Cubic would receive 22,500 restricted Cubic common

shares (15,000 shares per year, multiplied by 1.5 years) for prior years of

service, (iv.) going forward, Directors would receive 16,000 restricted Cubic

common shares per year of service, (v.) going forward, the President/CEO would

receive 30,000 restricted Cubic common shares per year of service, (vi.) going

forward, the Secretary would receive 15,000 restricted Cubic common shares per

year of service, (vii.) Audit Committee members would receive 10,000 restricted

Cubic common shares per audit, and, (viii.) any Compensation Committee member,

should one be formed, would receive 3,000 restricted Cubic common shares per

year of service. On February 9, 2004, Cubic issued 155,000 common shares of

stock to its Officers and Directors pursuant to this plan, for service during

the current fiscal year. Based on a then market price of $0.45 per share, Cubic

recorded a compensation expense of $69,750; which expense is recorded in the

above financial statements as a selling, general and administrative expense.

Pro forma information related to stock options:
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The Company accounts for its stock-based employee compensation plans under the

recognition and measurement principles of APB Opinion No. 25, Accounting for

Stock Issued to Employees, and related interpretations. No stock based employee

compensation cost is reflected in net income, as all options granted under those

plans had an exercise price at least equal to the market of the underlying

common stock on the date of the grant.

ITEM 11. Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the number of shares of the Company's Common

Stock beneficially owned, as of June 30, 2004 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, the number of shares and percentage of ownership of

Common Stock for each of the stockholders set forth below assumes that shares of

Common Stock that the stockholder may acquire within sixty days of June 30, 2004

are outstanding.

NUMBER APPROXIMATE

NAME AND ADDRESS OF SHARES PERCENT OF CLASS

---------------- --------- ----------------

Calvin A. Wallen, III 9,818,515 /1/ 31.2%

9870 Plano Rd.

Dallas, TX 75238

William Bruggeman 10,707,303 /2/ 34.0%

20 Anemone Circle

North Oaks, MN 55127

Gene Howard 382,245 /3/ 1.2%

2402 East 29th St.

Tulsa, OK 74114

Jon S. Ross 113,500 0.4%

9870 Plano Rd.

Dallas, TX 75238

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<PAGE>

Herbert Bayer 168,287 /4/ 0.5%

9870 Plano Rd.

Dallas, TX 75238

Robert L. Clements 276,000 0.9%

9870 Plano Rd.

Dallas, TX 75238

All officers and directors

as a group (5 persons): 10,758,547 34.2%
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/1/ Includes 100,000 shares held in equal amounts by each of Mr. Wallen's two

children of minority, Calvin Wallen, IV and Lauren Wallen; and 1,641,216 shares

held by Tauren Exploration, Inc., an entity controlled by Mr. Wallen.

/2/ Includes 500,000 shares held by Diversified Dynamics Corp., a company

controlled by William Bruggeman, includes 120,000 shares owned by Consumer

Products Corp. in which Mr. Bruggeman's wife Ruth is a joint owner, and includes

9,713,303 shares held jointly by William Bruggeman & Ruth Bruggeman JTWROS

/3/ Includes 322,245 shares are held by Mr. Howard's wife, Belva, of which Mr.

Howard claims no beneficial ownership.

/4/ Includes 132,287 held JTWROS with his spouse

ITEM 12. Certain Relationships and Related Transactions

In December 1997, the Company entered into a Stock Purchase Agreement (the

"Agreement") with Calvin A. Wallen, III or his designees, William Bruggeman and

Ruth Bruggeman, and Diversified Dynamics, Inc. (together, the "Buyers").

Pursuant to the Agreement, the Company issued (i) 7,000,000 shares of its common

stock to Calvin A. Wallen, III; (ii) 2,500,000 shares of common stock to

Earthstock Resources, Inc., all of the shares of which are owned by Mr. Wallen;

(iii) 2,500,000 shares of common stock to William Bruggeman and Ruth Bruggeman

as joint tenants with rights of survivorship; and (iv) 500,000 shares of common

stock to Diversified Dynamics, which is controlled by the Bruggemans,

representing an aggregate of approximately 71.3% of the issued and outstanding

shares of common stock of the Company, with the shares issued to Mr. Wallen and

his affiliates representing approximately 54.2% of the issued and outstanding

shares of common stock of the Registrant. In exchange for the issuance of the

Shares, the Buyers conveyed to the Registrant the interests in certain oil and

gas properties owned by the Buyers, as well as the Buyers' entire interest in

any contracts, leases, records and insurance policies affecting such interests

(the "Consideration"). The amount of the Consideration was the result of an

agreed negotiation between the Buyers and the Company. Prior to the negotiation

and execution of the Agreement, there were no material relationships between the

Company or any affiliates, officers or directors of the Company, on the one

hand, and any of the Buyers, or any affiliates, officers or directors of any of

the Buyers, on the other hand.

On December 1, 1997, the Company entered into a contract with an affiliate

controlled by our President and Chief Executive Officer to provide certain

technical, administrative and management services needed to conduct its

business.

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<PAGE>

The terms of the contract provided for personnel to be contracted at current

market rates in effect at the time the agreement was executed. In addition, the

offices are subleased from an affiliate controlled by our President and Chief

Executive Officer. The monthly amount charged to the Company is based on actual

costs of materials and man-hours of the affiliates that are used pursuant to the

terms of the agreement. As of June 30, 2001, the Company had accumulated

$790,098 in accounts payable due affiliates that includes the amounts owed for

personnel and leasing of office space.
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On December 10, 1998, the Company entered into an agreement with Tauren

Exploration Inc. ("Tauren") that provides for Tauren to drill on the Company's

Section 11 in Palo Pinto County, Texas. The agreement grants Tauren Exploration

Inc. a farm-out retaining a 7.5% overriding royalty interest. The agreement also

grants the Company preferential rights in the event that Tauren, at some later

date, decides to divest part or all of their interests in the drilled wells.

Tauren is an affiliate of Calvin A. Wallen, III, an officer, director and

majority shareholder of the Company.

On April 27, 2001, the Company completed an exchange offer pursuant to which it

acquired (i) certain direct working interests in producing oil and/or natural

gas wells (the "Working Interests") and (ii) all of the outstanding membership

units in four privately held limited liability companies and approximately 9.85%

of the working interest in another privately held limited liability company, all

of which are engaged in oil and/or natural gas exploration and production. The

Working Interests consist of between 15% and 45% working interests in fourteen

(14) wells. The Working Interests are part of projects operated by Tauren

Exploration, Inc. ("Tauren"), an independent energy company, and Fossil

Operating, Inc. ("Fossil") acts as the operator for some of the properties.

Calvin A. Wallen, III, a material shareholder, director and officer of the

Company is the sole shareholder, director and officer of Tauren and Fossil. The

relationship between the Company and each of Tauren and Fossil were approved by

the disinterested directors of the Company. The exchange offer was made to and

was accepted by the various individual holders of the interests acquired. The

Working Interests and the properties held are located in Texas and Louisiana.

The consideration paid to the individuals who accepted the exchange offer was

determined based on the Company's valuation of the reserves underlying the

interests acquired. The value of the Company's common stock for purpose of the

exchange offer was deemed to be $0.50 per share. In connection with the exchange

offer, the Company issued approximately 11,141,256 shares of the Company's

common stock. In addition, as consideration for services rendered with respect

to this exchange offer, C. K. Cooper & Company, and/or its principals and

employees, received 111,413 shares of the Company's common stock.

Effective January 1, 2002, the Company entered into an Agreement with Tauren

Exploration, Inc. whereby (i). Tauren exchanged and traded the accounts

receivable of $856,712 owed by the Company for 856,712 shares of restricted

Company common stock, (ii). The Company attained ground floor opportunities from

Tauren to participate in Tauren's prospect and project inventory, and (iii).

Certain warrants were issued to Tauren from the Company to acquire restricted

Company common stock. A copy of this Agreement was filed with the Company's

March 31, 2002 Form 10-QSB.

In April, 2002, the Company made the strategic decision not to renew the Red

Rock Louisiana leaseholds, which action has had a substantial impact on the June

30, 2002 income statement for the Company. Despite the impact, the Company

believes the decision not to renew the leases will be to the ultimate benefit of

the Company.

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<PAGE>

On June 1, 2002, Tauren Exploration, Inc. assigned certain oil and gas

properties to the Company for di minimus consideration. The Company already had
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an interest in some of the properties assigned for Tauren.

ITEM 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K

The following documents are filed as part of this Report commencing on page F-1:

1. Report of Independent Auditors

Statements of Income and Retained Earnings

Balance Sheets

Statements of Cash Flows

Notes to Financial Statements

2. Schedules are omitted because they are not applicable or the required

information is shown in the financial statements or notes thereto listed

above.

3. Exhibits

10.1 -- Stock Purchase Agreement, dated December 7. 1997, among the

Company, Calvin A. Wallen, III or his designees, Diversified Dynamics,

William and Ruth Bruggeman (incorporated by reference to Exhibit 2.1

to the Company's Current Report on Form 8-K, filed with the SEC on

December 24, 1997).

10.2 -- Agreement, dated as of January 1, 2002, between the Company

and Tauren Exploration, Inc. (incorporated by reference to Exhibit 10

of the Company's 10Q, filed with the SEC for the quarter ended March

31, 2002).

31.1* -- Rule 13a-14(a)/15d-14(a) Certifications

32.1* -- Section 1350 Certifications

* Filed herewith.

Item 14. Principal Accountant Fees and Services

July 1, 2002-June 30, 2003 Jul 1, 2003-Jun 30, 2004

-------------------------- ------------------------

Audit Fees 19,700 16,000

Audit-Related Fees 7,750 6,100

Tax Fees 7,600 2,800

Other Fees 00 1,750

---------- -- -----

Total 35,050 26,650

All of the audit services rendered to the Company by Philip Vogel & Co., PC were

pre-approved by the Audit Committee.

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SIGNATURES

PURSUANT TO THE 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 THE 27TH DAY OF

SEPTEMBER, 2004.

Cubic Energy, Inc.

By: /s/ Calvin A. Wallen, III

-----------------------------

CALVIN A. WALLEN, III

PRESIDENT AND CHIEF

EXECUTIVE OFFICER

PURSUANT TO THE 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 27, 2004

------------------------- Officer and Director

Calvin A. Wallen, III (Principal Executive Financial,

Accounting Officer)

/s/ Jon Stuart Ross Director, Secretary September 27, 2004

-------------------------

Jon Stuart Ross

/s/ Gene Howard Director September 27, 2004

-------------------------

Gene Howard

/s/ Herbert A. Bayer Director September 27, 2004

-------------------------

Herbert A. Bayer

/s/ Robert Clements Director September 27, 2004

-------------------------

Robert Clements
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<PAGE>

CUBIC ENERGY, INC.

FINANCIAL STATEMENTS

and

INDEPENDENT AUDITORS' REPORT

JUNE 30, 2004

<PAGE>

CUBIC ENERGY, INC.

FINANCIAL STATEMENTS

and

INDEPENDENT AUDITORS' REPORT

JUNE 30, 2004

C O N T E N T S

Page

Independent Auditors' Report............................................... 1

Financial Statements:

Balance Sheets........................................................... 2

Statements of Operations................................................. 3

Statements of Changes in Stockholders' Equity............................ 4

Statements of Cash Flows................................................. 5

Notes to Financial Statements............................................ 6-20

<PAGE>

INDEPENDENT AUDITORS' REPORT
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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, 2004 and 2003, 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, 2004. 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, 2004 and 2003, and the results of its operations and its cash flows for each

of the three years in the period ended June 30, 2004, in conformity with

accounting principles generally accepted in the United States of America.

PHILIP VOGEL & CO. PC

Certified Public Accountants

Dallas, Texas

September 3, 2004

<PAGE>

CUBIC ENERGY, INC.

BALANCE SHEETS

JUNE 30, 2004 AND 2003

2004 2003

----------- -----------

Assets
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Current assets:

Cash and cash equivalents $ 193,213 $ 117,450

Accounts receivable - trade 80,180 58,130

----------- -----------

Total current assets $ 273,393 $ 175,580

Property and equipment (at cost):

Oil and gas properties, full cost method:

Proved properties (including wells and

related equipment and facilities) $ 1,537,625 $ 1,537,625

Office and other equipment 910 910

----------- -----------

$ 1,538,535 $ 1,538,535

Less accumulated depreciation, depletion

and amortization 1,104,849

1,000,114

----------- -----------

433,686 538,421

----------- -----------

$ 707,079 $ 714,001

=========== ===========

The accompanying notes are an integral part of these statements.

<PAGE>

2004 2003

----------- -----------

Liabilities and stockholders' equity

Current liabilities:

Accounts payable and accrued expenses $ 126,764 $ 116,039

Due to affiliates 3,598 179

----------- -----------

Total current liabilities $ 130,362 $ 116,218

Commitments and contingencies (Note H)
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Stockholders' equity:

Preferred stock- $.01 par value,

authorized 10,000,000 shares,

issued none $ -- $ --

Common stock - $.05 par value, authorized

50,000,000 shares, issued 31,451,826

shares in 2004 and 31,180,326 in 2003 1,572,592 1,559,017

Additional paid-in capital 8,972,467 8,892,992

Accumulated deficit (9,968,342) (9,854,226)

----------- -----------

Stockholders' equity 576,717 597,783

----------- -----------

$ 707,079 $ 714,001

=========== ===========

The accompanying notes are an integral part of these statements.

<PAGE>

<TABLE>

<CAPTION>

CUBIC ENERGY, INC.

STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED JUNE 30, 2004, 2003 AND 2002

2004 2003

2002

----------- -----------

-----------

<S> <C> <C>

<C>

Revenues:

Oil and gas sales $ 414,741 $ 356,636

$ 250,716

----------- -----------

-----------

Total revenues $ 414,741 $ 356,636

$ 250,716

----------- -----------

-----------

Costs and expenses:
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Oil and gas production, operating and

development costs $ 186,465 $ 167,303

$ 216,505

Selling, general and administrative expenses 240,022 175,201

234,804

Depreciation, depletion and amortization 104,735 119,249

317,901

Impairment loss on oil and gas properties -- --

5,750,838

----------- -----------

-----------

Total costs and expenses $ 531,222 $ 461,753

$ 6,520,048

----------- -----------

-----------

Operating income (loss) $ (116,481) $ (105,117)

$(6,269,332)

----------- -----------

-----------

Non-operating income (expense):

Legal judgment $ -- $ (112,000)

$ --

Gain on sales of securities -- --

26,550

Other income 2,440 --

339

Interest expense (75) (4)

(38)

Interest income -- --

548

----------- -----------

-----------

Total non-operating income (expense): $ 2,365 $ (112,004)

$ 27,399

----------- -----------

-----------

Income (loss) from operations before income taxes: $ (114,116) $ (217,121)

$(6,241,933)

Provision for (benefit of) income taxes -- --

(471,800)

----------- -----------

-----------

Net loss $ (114,116) $ (217,121)

$(5,770,133)

=========== ===========

===========

Net loss per common share - basic and diluted $ (0.00) $ (0.01)

$ (0.19)
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=========== ===========

===========

</TABLE>

The accompanying notes are an integral part of these statements.

<PAGE>

<TABLE>

<CAPTION>

CUBIC ENERGY, INC.

STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

FOR THE YEARS ENDED JUNE 30, 2004, 2003 AND 2002

Common Stock

Cumulative -------------------------

Additional Total

preferred Shares Par

paid-in Accumulated stockholders'

stock outstanding value

capital deficit equity

----------- ----------- -----------

----------- ----------- -----------

<S> <C> <C> <C>

<C> <C> <C>

Balance, June 30, 2001 -- 29,989,614 $ 1,499,481

$ 7,867,389 $(3,866,972) $ 5,499,898

Net loss, year ended June 30, 2002 -- -- --

-- (5,770,133) (5,770,133)

Stock issued for cash -- 334,000 16,700

133,600 -- 150,300

Contribution of oil and gas properties -- -- --

78,127 -- 78,127

Stock issued in exchange for debt -- 856,712 42,836

813,876 -- 856,712

----------- ----------- -----------

----------- ----------- -----------

Balance, June 30, 2002 -- 31,180,326 $ 1,559,017

$ 8,892,992 $(9,637,105) $ 814,904

Net loss, year ended June 30, 2003 -- -- --
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-- (217,121) (217,121)

----------- ----------- -----------

----------- ----------- -----------

Balance, June 30, 2003 -- 31,180,326 $ 1,559,017

$ 8,892,992 $(9,854,226) $ 597,783

Net loss, year ended June 30, 2004 -- -- --

-- (114,116) (114,116)

Stock issued under compensation plan -- 271,500 13,575

79,475 -- 93,050

----------- ----------- -----------

----------- ----------- -----------

Balance, June 30, 2004 -- 31,451,826 $ 1,572,592

$ 8,972,467 $(9,968,342) $ 576,717

=========== =========== ===========

=========== =========== ===========

</TABLE>

The accompanying notes are an integral part of these statements.

<PAGE>

<TABLE>

<CAPTION>

CUBIC ENERGY, INC.

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED JUNE 30, 2004, 2003 AND 2002

2004 2003

2002

----------- ---------

-- -----------

<S> <C> <C>

<C>

Cash flows from operating activities:

Net loss $ (114,116) $

(217,121) $(5,770,133)
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Adjustments to reconcile net loss to cash

provided (used) by operating activities:

Depreciation, depletion and amortization 104,735

119,249 317,901

Gain on sale of securities -- --

(26,550)

Impairment loss -- --

5,750,838

Deferred taxprovision -- --

(471,800)

Stock issued for services 93,051 --

--

Change in assets and liabilities:

(Increase) decrease in accounts receivable (22,050)

(18,002) (1,312)

Increase (decrease) in loan from affiliates 3,418

(8,931) 75,724

Increase (decrease) in accounts payable

and accrued liabilities 10,725

72,921 32,608

----------- ---------

-- -----------

Net cash provided (used) by operating activities $ 75,763 $

(51,884) $ (92,724)

----------- ---------

-- -----------

Cash flows from investing activities:

Proceeds from sale of securities $ -- $ --

$ 26,550

Purchase of property and equipment -- --

--

----------- ---------

-- -----------

Net cash provided (used) by investing activities $ -- $ --

$ 26,550

----------- ---------

-- -----------

Cash flows from financing activities:

Proceeds from issuance of stock $ -- $ --

$ 150,300

Capital distributions from acquired entities -- --

--

----------- ---------

-- -----------

Net cash provided (used) by financing activities $ -- $ --

$ 150,300

----------- ---------

-- -----------

Net increase (decrease) in cash and cash equivalents $ 75,763 $

(51,884) $ 84,126

Cash and cash equivalents:
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Beginning of year 117,450

169,334 85,208

----------- ---------

-- -----------

End of year $ 193,213 $

117,450 $ 169,334

===========

=========== ===========

</TABLE>

The accompanying notes are an integral part of these statements.

<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note A - Background and general:

Cubic Energy, Inc. ("Company") is engaged in domestic crude oil and natural

gas exploration, development and production, with primary emphasis on the

production of oil and gas reserves through acquisitions of proved, producing oil

and gas properties in the states of Texas, Oklahoma and Louisiana.

On April 27, 2001, the Company completed a nontaxable transaction whereby

it exchanged shares of stock for the ownership interests of various entities

engaged in the production of oil and gas. As more fully described in Note K,

this transaction was accounted for under the provisions of APB Opinion No. 16 as

a pooling of interests.

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

$0 for each of the years ended June 30, 2004, 2003 and 2002.

Full cost method of accounting for oil and gas properties
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---------------------------------------------------------

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 directly related overhead costs,

are capitalized.

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.

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 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.

Depletion of producing oil and gas properties amounted to $104,735,

$119,249 and $317,901 for the years ended June 30, 2004, 2003 and 2002,

respectively.

<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

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

-----------------------------------------------------------------------

The Company has adopted the provisions of Statement of Financial Accounting

Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of

Long-Lived Assets effective for periods beginning July 1, 2002, and thereafter.

SFAS 144 replaces SFAS 121, and, among other matters, addresses financial

accounting and reporting for the impairment or disposal of long-lived assets.

SFAS 144 retains the basic provisions of SFAS 121, but broadens its scope and

establishes a single model for long-lived assets to be disposed of by sale.

Management does not believe adoption of the Statement had any effect on the

financial statements of the Company. 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 earlier.
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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.

Oil and gas revenue

-------------------

The Company recognizes oil and gas revenues by the sales method as oil and

gas production is sold. Differences between sales and production volumes during

the years ended June 30, 2004, 2003 and 2002 were not significant.

Preferred return

----------------

Certain of the entities acquired in the business combination described in

Note K had agreements with the promoter/operator of the oil and gas properties

that provided for a minimum annual production volume. The companies had no

obligation to refund such payments and, accordingly, the payments received by

those entities have been recorded as income in the periods they were received.

Effective on the date of combination, all such agreements were cancelled.

Earnings (loss) per common share

--------------------------------

The Company has adopted the provisions of Statement of Financial Accounting

Standards (SFAS) No. 128, Earnings per Share. SFAS 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 during the years

ended June 30, 2004, 2002 and 2001. The weighted average number of common and

common equivalent shares outstanding was 31,316,222, 31,180,329 and 30,621,257

for the years ended June 30, 2004, 2003 and 2002, 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.
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<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Reporting comprehensive income (loss) and operating segments

------------------------------------------------------------

The Company has adopted the provisions of SFAS No. 130, Reporting

Comprehensive Income and SFAS No. 131, Disclosure about Segments of an

Enterprise and Related Information. SFAS 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 nonowner sources. SFAS 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 SFAS No. 131 has had no impact on the Company's financial position,

results of operations, cash flows, or related disclosures since the Company's

operations are considered to be a single segment.

Comprehensive income is the total of (1) net income plus (2) all other

changes in net assets arising from nonowner sources, which are referred to as

other comprehensive income. In accordance with SFAS No. 130, the Company

presents a statement of operations that includes other comprehensive income when

applicable. An analysis of changes in components of accumulated other

comprehensive income is presented in the statement of changes in stockholders'

equity. There were no transactions related to other comprehensive income for the

three years ended June 30, 2004.

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 estimates included in these financial statements for which it is

reasonably possible that a future event in the near term could cause the

estimate to change and the change could have a severe impact are as follows:

Management's estimates of oil and gas reserves are based on various assumptions,

including constant oil and gas prices. 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

losses that might occur.
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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.

Obligations associated with the retirement of assets

----------------------------------------------------

The Company has adopted the provisions of SFAS No. 143, Accounting for

Asset Retirement Obligations, effective July 1, 2002. SFAS No. 143 amended SFAS

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. SFAS 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.

<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

This is a change from the approach taken under SFAS 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 SFAS No. 143 has had no significant effect on the company's financial

statements since abandonment costs for which it is responsible are not material.

Stock based compensation

------------------------

Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock

Issued to Employees, and related interpretations require 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, Statement of Financial Accounting Standards (SFAS) No. 123,

Accounting for Stock-Based Compensation, permits entities to recognize, as

expense over the vesting period, the fair value of all stock-based awards on the

date of grant. SFAS No. 123 allows entities to continue to apply the provisions

of APB Opinion No. 25 and provide proforma net income and proforma earnings per
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share disclosures for employee stock option grants made in 1996 and future years

as if the fair-valued-based method defined in SFAS No. 123 had been applied. The

Company has elected to apply the provisions of APB Opinion No. 25 and provide

the proforma disclosure provisions of SFAS No. 123.

In addition, the Company has adopted the provisions of Financial Accounting

Standards Board Interpretation (FIN) 44, Accounting for Certain Transactions

Involving Stock Compensation, which became effective July 1, 2000. FIN 44

clarifies the application of APB 25 for certain issues. Among other issues, this

interpretation clarifies the definition of an employee for purposes of applying

APB 25, the criteria for qualification of a plan as compensatory, the

consequences of modifications to the terms of a plan, and the treatment of stock

compensation issued to service providers who are not employees. The issuance of

this interpretation does not change the current accounting policies of the

Company, and has had no effect on the accompanying financial statements.

In December 2002, the Financial Accounting Standards Board issued SFAS No.

148, Accounting for Stock-Based Compensation - Transition and Disclosure, which

amends SFAS No. 123. SFAS 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, SFAS No. 148 amends the disclosure requirements of

SFAS 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 are effective

financial reports containing financial statements for interim periods beginning

after December 15, 2002. The transition rules of this standard are not

applicable since the Company continues to account for stock-based compensation

under the guidance of APB Opinion 25. The other requirements of this standard

have been adopted by the Company for periods beginning January 1, 2003.

Disclosures required by this statement are in Note L.

Other new accounting pronouncements

-----------------------------------

In July 2002, the Financial Accounting Standards Board issued SFAS No. 146,

Accounting for Cost Associated with Exit or Disposal Activities. SFAS 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.

SFAS No. 146 is effective prospectively for exit or disposal activities

initiated after December 31, 2002, with earlier adoption encouraged. As the

provisions of SFAS No. 146 are required to be applied prospectively after the

adoption date, and no exit or disposal activities have been entered into,

management does not expect SFAS No. 146 to have a significant impact on its

future results of operations of cash flows.

In May 2003, the Financial Accounting Standards Board issued SFAS No. 150,

Accounting for Certain Financial Instruments with Characteristics of both

Liabilities and Equity. SFAS 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
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<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

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. This statement is effective

for financial instruments entered into or modified after May 31, 2003, and

otherwise is effective for the first fiscal period beginning after December 15,

2003. The adoption of SFAS No. 150 is not expected to have a significant impact

on the Company's financial statements.

In November 2002, the Financial Accounting Standards Board issued

Interpretation No. 45 ("FIN 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 45 clarifies the requirements of SFAS 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

initial recognition and initial measurement provisions of the Interpretation are

applicable on a prospective basis to guarantees issued or modified after

December 31, 2002. The disclosure requirements in this Interpretation are

effective for financial statements of interim periods ending after December 15,

2002. The Company has not issued any guarantees and, therefore, the adoption of

FIN 45 is not expected to have a significant impact on the Company's financial

statements.

In January 2003, the Financial Accounting Standards Board issued

Interpretation No. 46 ("FIN 46"), Consolidation of Variable Interest Entities,

an Interpretation of ARB No. 51. FIN 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 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 and, therefore, the adoption of FIN 46 is not expected to have a

significant impact on the Company's financial statements.
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Note C - Marketable securities - gains and losses:

On July 29, 1999, Cubic received 155,000 shares of stock in Energytec.com

pursuant to a spin-off from the investment Cubic held in the common stock of

Comanche Energy, Inc. ("Comanche"). At the time, Cubic received one share of

Energytec.com for each share that it owned in Comanche. Prior to November 2001,

Energytec.com was a privately held company; therefore, there was no established

market price for its stock. Prior to Energytec.com becoming a public company in

November 2001, Cubic believed that the stock had little, if any, verifiable

value; therefore, Cubic had not recorded any amounts for its investment. During

the year ended June 30, 2002, the Company sold all of its holdings in

Energytec.com and recognized a gain on the sale of securities of $26,550.

Note D - Stockholders' equity:

The Company's authorized capital is 50,000,000 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 are issued or outstanding at June 30, 2004 and 2003.

Stock purchase agreement

------------------------

In December 1997, the Board of Directors voted to enter into a stock

purchase agreement ("the agreement") in which the Company issued 12,500,000

restricted shares of common stock in exchange for the conveyance to the Company

<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

of certain non-producing leasehold properties valued at $967,215, less $86,951

of costs associated with the transaction. The valuation of the property was

based on its fair market value as of the exchange date. The 12,500,000 shares

issued represent approximately 70% of the issued and outstanding shares of

common stock of the Company. In connection with the agreement, as of December

10, 1997, three of the five members of the Board of Directors resigned, three

new directors were appointed and new management of the Company was elected.

Warrants

--------

On January 1, 2002, the Company issued three series of warrants to Tauren

Exploration, Inc., an entity owned by the CEO and major stockholder of the

Company (see Note F). These warrants allow Tauren to purchase unregistered

common shares in the Company as follows: 1) exercisable after May 1, 2002, to

purchase 125,000 unregistered common shares at an exercise price of $1.00, which

expired on April 30, 2003; 2) exercisable after May 1, 2003, to purchase 150,000

unregistered common shares at the exercise price of $1.50, which expired on

April 30, 2004; and 3) exercisable after May 1, 2004, to purchase 200,000

unregistered common shares at an exercise price of $2.00, expiring on April 30,

2005.
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The weighted-average exercise price of all exercisable warrants at June 30,

2004 and 2003 was $2.00 and $1.50, respectively. The weighted-average exercise

price of all outstanding warrants at June 30, 2004 and 2003 was $2.00 and $1.79,

respectively. The remaining weighted-average contractual life of these warrants

at June 30, 2004, was ten months. The remaining weighted average contractual

life of exercisable warrants at June 30, 2004, was zero months.

Capital contributions

---------------------

As more fully described in Note F, on June 1, 2002, a stockholder

transferred its interest in ten producing oil and gas wells to the Company for

no current or future consideration. The Company recorded these interests as a

contribution to capital at an aggregate amount of $78,127, which was the lower

of each property's basis or its fair value using the present value of future

reserves.

As more fully described in Note F, on January 1, 2002, the Company entered

into an agreement that provided for the exchange of stock for debt owed to a

major stockholder. This resulted in a reduction of existing debt amounting to

$856,712, with a corresponding issuance of 856,712 shares of stock.

Stock-based compensation

------------------------

On September 12, 2003, the Directors of the Company approved a Director and

Officer compensation plan as follows: (i.) Directors of record as of June 1,

2003 would receive 24,000 restricted Cubic common shares (16,000 shares per

year, multiplied by 1.5 years) for years of prior service, (ii.) the

President/CEO of Cubic would receive 45,000 restricted Cubic common shares

(30,000 share per year, multiplied by 1.5 years) for years of prior service,

(iii.) the Secretary of Cubic would receive 22,500 restricted Cubic common

shares (15,000 shares per year, multiplied by 1.5 years) for prior years of

service, (iv.) going forward, Directors would receive 16,000 restricted Cubic

common shares per year of service, (v.) going forward, the President/CEO would

receive 30,000 restricted Cubic common shares per year of service, (vi.) going

forward, the Secretary would receive 15,000 restricted Cubic common shares per

year of service, (vii.) Audit Committee members would receive 10,000 restricted

Cubic common shares per audit, and, (viii.) any Compensation Committee member,

should one be formed, would receive 3,000 restricted Cubic common shares per

year of service.

On November 5, 2003 Cubic issued 116,500 common shares of stock to its

Officers and Directors pursuant to this plan. Based on a then market price of

$0.20 per share, Cubic recorded a compensation expense of $23,300; which expense

is recorded in the above financial statements as a selling, general and

administrative expense.

On February 9, 2004, Cubic issued 155,000 common shares of stock to its

Officers and Directors pursuant to this plan, for service during the current

fiscal year. Based on a then market price of $0.45 per share, Cubic recorded a

compensation expense of $69,750; which expense is recorded in the above

financial statements as a selling, general and administrative expense.
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<PAGE>

<TABLE>

<CAPTION>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

Note E -- Loss per common share:

Net loss per common share is computed as follows:

2004 2003

2002

------------ ------------ -------

-----

<S> <C> <C> <C>

Net loss attributable to stockholders $ (114,116) $ (217,121) $

(5,770,133)

Weighted average number of shares of

common stock 31,316,222 31,180,329

30,621,257

Income (loss) per common share $ (0.00) $ (0.01) $

(0.19)

</TABLE>

Potential dilutive securities (stock warrants, convertible debt) have not

been considered since the Company reported a net loss and, accordingly, their

effects would be antidilutive.

Note F -- Related party transactions:

On December 10, 1998, the Company entered into an agreement with Tauren

Exploration Inc. ("Tauren") that provides for Tauren to drill on the Company's

Section 11 in Palo Pinto County, Texas. The agreement grants Tauren Exploration

Inc. a farm-out retaining a 7.5% overriding royalty interest. The agreement also

grants the Company preferential rights in the event that Tauren, at some later

date, decides to divest part or all of its interests in the drilled wells.

Calvin Wallen III is an officer, director and major stockholder of both the

Company and Tauren.

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 $.70 per share. The Company has recognized the gain on the

extinguishment of this debt as a capital contribution for financial
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reporting purposes due to the related party aspect of the transaction.

The gain was fully recognized as a taxable gain for income tax

reporting purposes for the year ended June 30, 2002.

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 D.

On December 1, 1997, the Company entered into a contract with Tauren to

provide the necessary technical, administrative and management expertise needed

to conduct its business. This agreement was renewed and revised on January 1,

2002. The Company has no full-time employees, and its offices are subleased from

Tauren. The monthly amount charged to the Company is based on actual costs of

materials and labor hours of Tauren that are used pursuant to the terms of the

agreement. Tauren also pays various organization costs and consulting fees on

behalf of the Company. As of June 30, 2004 and 2003, the Company owed Tauren

$3,598 and $178, respectively, which are included in accounts payable and

accrued expenses in the accompanying financial statements. Charges to the

Company under the contracts were $35,322, $45,938 and $83,628 for the years

ended June 30, 2004, 2003 and 2002, respectively.

On June 1, 2002, Tauren transferred its interest in ten producing oil and

gas wells to the Company for no current or future consideration. The Company

recorded these interests at the lower of Tauren's basis or the present value of

future reserves on a per well basis. At June 1, 2002, the aggregate basis of

these wells was $78,127. The transaction was treated as a contribution of

capital.

<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

In addition, the 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 Wallen

III. As of June 30, 2004 and 2003, the Company owed Fossil $0 and $0,

respectively, in lease operating expenses and was owed by Fossil $78,887 and

$57,960, respectively, for oil and gas sales. The amounts owed the Company are

included in accounts receivable - trade.

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
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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, 2004 and 2003, 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.

Pursuant to the business combination described in Note K, the tax benefits of

net operating loss carryforwards at June 30, 2002, were utilized to partially

offset the liability for deferred taxes arising from that transaction.

The components of the net deferred federal income tax assets (liabilities)

at June 30 were as follows:

2004 2003

--------- ---------

Deferred tax as sets:

Net operating loss carryforwards $ 500,200 $ 490,400

Capital loss carryforwards 7,400 11,300

Accrued lawsuit settlement 16,800 16,800

--------- ---------

$ 524,400 $ 518,500

--------- ---------

Deferred tax liabilities :

Depletion basis of assets and related accounts $ (60,400) $ (65,200)

--------- ---------

$ (60,400) $ (65,200)

--------- ---------

Net deferred tax (liabilities) assets before

valuation allowance $ 464,000 $ 453,300

Valuation allowance (464,000) (453,300)

--------- ---------

Net deferred tax (liabilities) assets $ -- $ --

========= =========

<PAGE>

<TABLE>

<CAPTION>

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, 2004, 2003 and

2002:
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2004 2003

2002

--------- ---------

---------

<S> <C> <C>

<C>

Taxprovision (benefit) calculated at statutory rate $ (38,800) $ (73,800)

$(936,300)

Increase (reduction) in taxes due to:

Forgiveness-of-debt income -- --

38,600

Acquired entities - nontaxable -- --

--

Excess of book basis over tax basis of

acquired entities previously unrecorded -- --

--

Losses not providing tax benefits 38,800 73,800

425,900

--------- ---------

---------

Current federal income tax provision $ -- $ --

$(471,800)

========= =========

=========

Change in valuation allowance

$ 10,700 $ 29,400

$ 423,900

========= =========

=========

</TABLE>

As discussed above, at June 30, 2001, the Company recorded a deferred tax

liability which primarily represents the effects of the business combination

described in Note K. Since the acquired entities were nontaxable, they did not

record a deferred tax liability for the excess of the book basis of assets over

the tax basis, which generally resulted from expensing intangible drilling costs

for tax purposes. The Company is required, under the provisions of APB 16 and

SFAS 109, to record the effects of the combination in the period the combination

occurs, rather than as part of the restatement of the financial statements.

As of June 30, 2004, the Company had net operating loss carryforwards of

approximately $3,334,900, which are available to reduce future taxable income.

These carryforwards expire as follows:

Net operating

Year losses

------------ --------------
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2007 $ 128,500

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 22,600

--------------

$ 3,334,900

==============

<PAGE>

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. The Company has not entered into any

employment contracts with any of its executive officers.

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.

Litigation matters

------------------

During the spring of 1999, the Company became aware of the claim of a

geologist filed in December 1997, to a 1% overriding royalty interest in various

properties. The geologist filed an assignment after December 1, 1997. The

Company disputed the geologist's legal right to the overriding royalty and had

filed suit to challenge this claim. Through a court ruling, the Company must
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honor the override and owed to the geologist $30,381 in back overrides plus

amounts of attorney fees expended in the geologist's defense of this challenge.

Accordingly, the Company accrued $30,381 as a charge to income for the year

ended June 30, 2002. During July 2003, a final judgment was entered by the court

against Cubic for approximately $112,000 representing attorney fees. The Company

has begun the process of appealing the latest judgment and is confident, based

on the facts, that the court will vacate or substantially reduce the amount it

has been ordered to pay. However, since a judgment has been rendered, and

neither it nor its attorneys are able to conclude that it is probable it will

succeed in its appeals, the full amount of the judgment has been accrued in the

accompanying financial statements for the year ended June 30, 2003.

The Company filed suit in the 29th Judicial District Court in Palo Pinto

County, Texas, styled "Roseland Oil and Gas, Inc. v. William Vandever, et al.",

bringing suit against Clifford Kees, William Vandever, and other persons seeking

a judicial determination that all grants of preferential rights in the Reagan

Sections 11 and 12 are void, This lawsuit was filed on April 26, 1999. All

Section 11 preferential rights were returned to the Company on or about January

2002. However, Clifford Kees was to retain his 1% overriding royalty interest in

these Reagan Lease Sections.

Clifford Kees then moved to trial against on the claim of attorney fees

owed to him for the prosecution of this lawsuit. The trial was heard on

September 25, 2002, with Kees requesting in excess of $200,000.00 in attorney

fees and costs. In June of 2003 the Court re-opened the trial as to attorney

fees and costs to allow Kees to put on additional evidence, and such trial was

convened on June 19, 2003.

On July 15, 2003 the Court entered a judgment in favor of Kees and against

the Company for approximately $112,000. The Company believed the judgment should

not stand and appealed the judgment. On or about September 17, 2004, the

Eastland Court of Appeals issued its ruling, modifying the amounts owed by the

Company under the judgment to $59,000. The Company is weighing its options as to

filing for re-hearing or filing a writ with the Texas Supreme Court. Should the

judgment stand, it could have a material adverse effect on the cash position of

the Company. Because of the uncertainty as to what the ultimate liability to the

Company would be resulting from its response to the Appeals Court ruling, no

adjustment has been made to the $112,000 accrued as of June 30, 2004.

<PAGE>

<TABLE>

<CAPTION>

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
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June 30, 2004, 2003 and 2002 were as follows:

2004 2003 2002

----------- ----------- -----------

Property acquisitions $ -- $ -- $ 78,128

=========== =========== ===========

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, 2004, 2003 and 2002 were

as follows:

2004 2003 2002

---------- ---------- --------

--

<S> <C> <C> <C>

Proved properties $1,537,625 $1,537,625

$7,288,463

Unproved properties -- -- --

---------- ---------- --------

--

$1,537,625 $1,537,625

$7,288,463

Accumulated depreciation, depletion

and amortization 1,103,939 999,205

879,955

---------- ---------- --------

--

Total properties $ 433,686 $ 538,420

$6,408,508

Less: impairment of oil and gas properties

due to full cost ceiling test -- --

5,750,838

---------- ---------- --------

--

Net properties $ 433,686 $ 538,420 $

657,670

========== ==========

==========

</TABLE>

During the year ended June 30, 2002, capitalized costs were reduced based

on the results of the full cost ceiling test. This impairment was recorded by

reducing the full cost pool by a grossed-up amount and reducing net deferred tax

liability for the related tax effect. The net amount of the impairment was

charged to expense during the year ended June 30, 2002 (see Note M).
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<PAGE>

<TABLE>

<CAPTION>

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, 2004, 2003 and 2002 were as follows:

2004 2003 2002

--------- --------- ---------

<S> <C> <C> <C>

Revenues:

Revenues $ 414,741 $ 356,636 $ 250,716

Preferred return -- -- --

--------- --------- ---------

$ 414,741 $ 356,636 $ 250,716

--------- --------- ---------

Expenses:

Production and development costs $ 186,465 $ 167,303 $ 216,505

Depreciation, depletion and amortization 104,735 119,249 317,901

--------- --------- ---------

$ 291,200 $ 286,552 $ 534,406

--------- --------- ---------

Results before income taxes $ 123,541 $ 70,084

$(283,690)

Provision for income taxes -- -- --

--------- --------- ---------

Results of operations (excluding corporate

overhead and interest expense) $ 123,541 $ 70,084

$(283,690)

========= ========= =========

</TABLE>

As disclosed in Note H, the Company accrued $30,381 as its estimate of

amounts it will be required to pay to settle a lawsuit with respect to unpaid

overriding royalties. This amount has been included in oil and gas production

and development costs for the year ended June 30, 2002.

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
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by the Securities and Exchange Commission and the Financial Accounting Standards

Board, 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.

<PAGE>

<TABLE>

<CAPTION>

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, 2004, 2003 and 2002 together with the

changes therein:

Natural Gas (Mcf)

----------------------------------

----

2004 2003

2002

---------- ---------- ------

----

<S> <C> <C> <C>

Proved developed and undeveloped reserves:

Beginning of year 330,000 564,272

4,227,593

Revisions of previous estimates 52,902 (161,184)

(985,156)

Purchases of reserves in place -- --

--

Extensions and discoveries -- --

--

Production (71,804) (73,088)

(80,549)

Disposals of reserves in place -- --

(2,597,616)

---------- ---------- ------

----

End of year 311,098 330,000
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564,272

========== ==========

==========

Oil and condensate (Bbls)

----------------------------------

----

2004 2003

2002

---------- ---------- ------

----

Proved developed and undeveloped reserves:

Beginning of year -- --

131,594

Revisions of previous estimates -- --

--

Purchases of reserves in place -- --

--

Extensions and discoveries -- --

--

Production Disposals of reserves in place -- --

(131,594)

---------- ---------- ------

----

End of year -- --

--

========== ==========

==========

</TABLE>

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 current 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 percent 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 10 percent discount rate, and is not necessarily appropriate for

determining fair value (Table 2).

<PAGE>

<TABLE>

<CAPTION>

CUBIC ENERGY, INC.
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NOTES TO FINANCIAL STATEMENTS

The following is the estimated standardized measure relating to proved oil

and gas reserves at June 30, 2004, 2003 and 2002:

Table 1 2004 2003

2002

------- ------------ ------------ ---

---------

<S> <C> <C> <C>

Future cash flows $ 2,059,245 $ 1,893,067 $

1,836,492

Future production costs (833,306) (564,669)

(552,741)

Future development costs -- --

--

Future severance tax expense (250,473) (230,251)

(223,382)

Future income taxes -- --

--

------------ ------------ ---

---------

Future net cash flows $ 975,466 $ 1,098,147 $

1,060,369

Ten percent annual discount for estimated

timing of net cash flows (243,553) (299,766)

(402,699)

------------ ------------ ---

---------

Standardized measure of

discounted future net cash flows $ 731,913 $ 798,381 $

657,670

============ ============

============

Following is an analysis of changes in the estimated standardized measure

of proved reserves during the years ended June 30, 2004, 2003 and 2002:

Table 2 2004 2003

2002

------- ------------ ------------ ---

---------

Changes from:

Sale of oil and gas produced $ (123,541) $ (114,795) $

51,290

Net changes in prices and production costs (43,462) 296,479
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(179,036)

Extensions and discoveries -- --

--

Revision of previous quantity estimates 122,601 (260,268)

(2,007,574)

Accretion of discounts 103,681 107,926

888,882

Net change in income taxes (33,565) 23,487

(1,295,234)

Purchases of reserves in place -- --

--

Disposals of reserves in place -- --

(7,784,158)

Other (92,182) 87,882

(36,521)

------------ ------------ ---

---------

Change in standardized measure $ (66,468) $ 140,711

$(10,362,351)

============ ============

============

</TABLE>

Note K - Pooling of interests business combination:

On April 27, 2001, the Company completed a nontaxable transaction whereby

it exchanged shares of stock for the ownership interests of various entities

engaged in the production of oil and gas. This transaction was accounted for as

a pooling of interests under the provisions of Accounting Principles Board

Opinion No. 16, Business Combinations.

Pursuant to this transaction, the Company issued 11,141,255 shares of its

common stock in exchange for the ownership interests of these entities. The

Company issued an additional 111,412 shares of its common stock for professional

fees associated with the transaction, which was charged to operations at the

<PAGE>

CUBIC ENERGY, INC.

NOTES TO FINANCIAL STATEMENTS

date of combination. The estimated value of the stock issued in exchange for

these entities was approximately $5,570,000, or $.50 per share. Note L -

Proforma information related to stock warrants:

The per share weighted-average fair value of stock warrants granted during

the year ended June 30, 2002, was $0.29, on the date of grant, using the

Black-Scholes pricing model. There were no stock warrants granted during the

years ended June 30, 2004 and 2003.
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2002

------------

Expected dividend yield 0.00%

Risk-free interest rate 1.80%

Expected life 1.7 years

Expected volatility 133.00%

The Company applies APB Opinion 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 SFAS No. 123, the Company's net income and earnings

per share would have been reduced to the proforma amounts indicated below:

2004 2003 2002

----------- ---------- -----------

Net loss:

As reported $ (114,116) $ (217,121) $(5,770,133)

=========== ========== ===========

Pro forma $ (149,580) $ (272,434) $(5,826,571)

=========== ========== ===========

Stock-based employee compensation:

As reported $ -- $ -- $ --

=========== ========== ===========

Pro forma $ 35,464 $ 55,313 $ 56,438

=========== ========== ===========

Basic loss per common share:

As reported $ (0.00) $ (0.01) $ (0.19)

=========== ========== ===========

Pro forma $ (0.00) $ (0.01) $ (0.19)

=========== ========== ===========

Note M - Impairment loss on oil and gas properties:

The Company has had lease rights to certain properties located in Louisiana

that comprised a significant portion of its oil and gas reserves. On May 25,

2002, the Company elected not to renew its interest in those properties and to

abandon its plans for future development in that area. As a result, the Company

recognized an impairment loss on its oil and gas properties due to the

application of the full cost ceiling test described in Note B. This test

generally limits the capitalized costs of oil and gas producing properties,

recognized under the full cost method of accounting, to the aggregate "estimated

present value," discounted at a 10 percent interest rate of future net revenues

from proved reserves, based on current economic and operating conditions; which

is a measure of overall fair value of its properties. For the year ended June

30, 2002, the impairment loss on oil and gas properties recognized amounted to
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$5,750,838, less the related deferred tax benefit of $1,611,228. There were no

impairment losses during the years ended June 30, 2004 and 2003.

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