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, 2002
                          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.)


             1720 NORTHWEST HIGHWAY, SUITE 320, GARLAND, TEXAS 75041
                    (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.

                                       [X]

As of June 30, 2002, the registrant had outstanding  31,180,329 shares of common
stock,  $.05 par value ("Common  Stock"),  which is  registrant's  only class of
common  stock.  There  have been no trades  in the  Common  Stock or bid and ask
prices within the past sixty days.

The registrant's revenues for the fiscal year ended June 30, 2002 were $250,716.

Transitional Small Business Disclosure Format:  Yes [ ]  No [X]


                                       1
<PAGE>

                               CUBIC ENERGY, INC.
                          TABLE OF CONTENTSDESCRIPTION


Item                                                                        Page
----                                                                        ----
                                     PART I

ITEM 1. Description of Business and Properties                                 4
GENERAL........................................................................4
DESCRIPTION OF BUSINESS........................................................4
RESTATEMENT OF FINANCIAL RESULTS...............................................6
PRINCIPAL OIL AND GAS PROPERTIES...............................................6
MARKETING OF PRODUCTION........................................................7
OIL AND GAS RESERVES...........................................................8
NET PRODUCTION, SALES PRICES AND COSTS.........................................9
PRODUCTIVE WELLS AND ACREAGE..................................................10
RISK FACTORS..................................................................11
ITEM 4. Submission of Matters to a Vote of Security Holders                   26
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters 26
ITEM 6. Management's Discussion And Analysis Or Plan Of Operations            26
GENERAL.......................................................................27
RESULTS OF OPERATIONS                                                         27
COMPARISON OF FISCAL 2002 TO FISCAL 2001 REVENUES.............................27
LIQUIDITY AND CAPITAL RESOURCES...............................................28
ITEM 7. FINANCIAL STATEMENTS                                                  29
ITEM 8. Directors, Executive Officers, Promoters and Control Persons of the
Registrant; Compliance with Section 16(a) of the Exchange Act                 30
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT.............................31
ITEM 9. Executive Compensation                                                31
ITEM 10. Security Ownership of Certain Beneficial Owners and Management       31
ITEM 13. Exhibits, Financial Statement Schedules and Reports on Form 8-K      34
SIGNATURES....................................................................35
Section 906 Certification Form................................................36
Section 302 Certification Form................................................37
INDEX TO FINANCIAL STATEMENTS                                                 39
Note B - Significant accounting policies (continued):.........................47
Concentration of credit risk..................................................48











                                       2
<PAGE>

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
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.


















                                       3
<PAGE>

                               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,
2002, our total proved reserves were 94,045 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
1720  Northwest  Highway,  Suite 320,  Garland,  Texas 75041,  and our telephone
number is (972) 686-0369.

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.


                                       4
<PAGE>

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 as  discussed  below and these
restatements are included in this annual report.

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%
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.


                                       5
<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
included in calculations of assets,  depletion  deductions and net income in our
balance  sheets and  statements of  operations.  As a result,  the  accompanying
financial  statements  as of June 30, 1998 and for the year  ended,  present 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, 2002.

                                                   Percent            Present
                        Oil           Gas         of Proved            Value
         Areas         (Bbl)         (Mcf)         Reserves         (Disc @ 10%)
         -----         -----         -----        ---------         ------------

         Texas           0          564,000          100%             1,836,492
         -----------------------------------------------------------------------
         Total           0          564,000          100%            $1,836,492


Our Texas properties are situated in Palo Pinto,  Parker,  Eastland and Callahan
Counties.  At June 30, 2002, 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.

Our net  production for the fiscal year ending June 30, 2002 for the Texas wells
averaged  approximately  222 Mcf of natural gas per day and 0 barrels of oil per
day.


                                       6
<PAGE>

EXPLORATION ACTIVITIES

Our strategy with respect to our domestic  exploration program seeks to maintain
a balanced portfolio of drilling opportunities that range from lower risk, field
extension wells to higher risk, high reserve potential  prospects.  Our focus is
primarily  on   exploration   opportunities   that  can  benefit  from  advanced
technologies,  including  3-D  seismic,  designed to reduce  risks and  increase
success  rates.  We develop  prospects  in-house  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,  Evangeline,   Sabine,  Natchitoches,   Rapides
Parishes, Louisiana, in Limestone, Navarro, Red River, Henderson Counties, Texas
and in Chavez  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, Mitchell 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  $250,716 for the fiscal year ended
June 30, 2002 and  represented  100% of our total oil and gas  revenues for that
fiscal year.

Price Considerations

Crude oil prices are established in a highly liquid,  international market, with
average crude oil prices that we receive  generally  fluctuating with changes in
the futures price established on the NYMEX for West Texas Intermediate Crude Oil
("NYMEX-WTI"). The average crude oil price per Bbl received by us in fiscal year
2002 was $24.18.

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


                                       7
<PAGE>
<TABLE>
<CAPTION>

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 2002 was $3.09.

OIL AND GAS RESERVES

The following tables set forth the proved developed and undeveloped  reserves at
June 30, 2002, 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, 2002, 2001 and 2000:

                                                                                         10%
Category                  Oil (Bbls)      Gas (Mcf)    Total (Mcfe)      Income        Discount
                         ------------   ------------   ------------   ------------   ------------
<S>                      <C>            <C>            <C>            <C>            <C>

Proved Producing                    0        564,000        564,000     $1,060,369     $  657,668
Proved Undeveloped                  0              0              0     $        0     $        0
</TABLE>


                                                        AT JUNE 30,
                                           -------------------------------------
                                             2002          2001          2000

Proved reserves:
     Oil (Bbl)                                     0       131,594       132,048
     Gas (Mcf)                               564,000     4,227,593     2,847,794
BOE                                           94,045       836,193       606,680
Estimated future net revenues
         (before income tax)               1,060,369    16,717,280   $14,959,135
     Standardized Measure(1)                 657,668    11,020,021   $ 7,742,838
Proved developed reserves:
     Oil (Bbl)                                     0             0           863
     Gas (Mcf)                               564,000     1,629,977       255,872
BOE                                           94,045       271,663        43,509
Estimated future net revenues
         (before income tax)               1,060,369     4,970,583   $   972,881
Present Value                                657,668     3,235,862   $   576,595
Standardized Measure (1)                     657,668     1,734,721   $   396,286
Weighted average sales prices:
     Oil (per Bbl)                             24.18         29.85   $     20.91
     Gas (per Mcf)                              3.09          5.52          3.07

(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
         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  was  based  upon  review  of  production   histories  and  other
geological, economic, ownership and engineering data provided by the Company. No

                                       8
<PAGE>

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, 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, 2002.

                                                  YEAR ENDED        YEAR ENDED
                                                JUNE 30, 2002      JUNE 30, 2001
                                                -------------      -------------
PRODUCTION VOLUMES:
       Oil (Bbl)                                      155                301
       Gas (Mcf)                                   79,619             80,850

WEIGHTED AVERAGE SALES PRICES:
       Oil (per Bbl)                               $24.18             $29.85
       Gas (per Mcf)                                $3.09              $5.52

SELECTED EXPENSES PER BOE:
       Lease operating                             $16.12             $12.31
       Depreciation, depletion and
       Amortization                                $23.67             $ 7.90
       General and administrative                  $17.48             $15.57


                                       9
<PAGE>

PRODUCTIVE WELLS AND ACREAGE

Productive Wells

The following table sets forth our domestic productive wells at June 30, 2002:

                Oil                    Gas                    Total
         ------------------       -------------         -----------------
         Gross          Net       Gross      Net        Gross         Net
         ------        ----       -----      ---        -----        ----
           0             0          20      19.3          20         19.3

Acreage

The  following  table sets forth our  undeveloped  and  developed  gross and net
leasehold acreage at June 30, 2002. 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
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.

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


                                       10
<PAGE>

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
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, 2002, 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.

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,


                                       11
<PAGE>

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
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.

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, 2002,
the Company had a working capital deficit of $9110. 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

                                       12
<PAGE>

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 $5,770,133  and
$216,938   combined  for  the  fiscal  years  ended  June  30,  2002  and  2001,
respectively.  The  Company's  accumulated  deficit  as of  June  30,  2002  was
$9,637,105.  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 $500,000 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,  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
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


                                       13
<PAGE>

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 2000,  fiscal 2001 and fiscal 2002,
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
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


                                       14
<PAGE>

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
(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
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  70% 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.


                                       15
<PAGE>

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
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.

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 limits on trading common stock

We  intend  to  qualify  our  Common  Stock on the OTC  inter-dealer  Electronic
Bulletin  Board.  There can be no assurance  that we will be  successful in this
attempt.  The  liquidity  of our Common  Stock may be  adversely  affected,  and
purchasers of our Common Stock may have difficulty  selling our Common Stock, if
we are  unsuccessful  in  qualifying  our Common Stock for trading in a suitable
trading market.

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

                                       16
<PAGE>

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.

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
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,  2002,  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


                                       17
<PAGE>

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
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


                                       18
<PAGE>

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
transporting  such  products  to market.  Effective  January  1, 1995,  the FERC
implemented regulations establishing an indexing system for transportation rates
for oil  pipelines,  which,  generally,  would  index such  rates to  inflation,
subject to certain conditions and limitations.  These regulations could increase
the cost of transporting oil by interstate  pipelines,  although the most recent
adjustment  generally  decreased  rates.  These  regulations have generally been
approved on judicial  review.  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


                                       19
<PAGE>

liability,  without regard to fault or the legality of the original conduct,  on
certain  classes of  persons  that are  considered  to have  contributed  to the
release of a "hazardous  substance" into the environment.  These persons include
the owner or operator of the disposal  site or sites where the release  occurred
and  companies  that  disposed or  arranged  for the  disposal of the  hazardous
substances  found at the site.  Persons who are or were responsible for releases
of  hazardous  substances  under  CERCLA  may be  subject  to joint and  several
liability for the costs of cleaning up the hazardous  substances  that have been
released into the environment and for damages to natural resources. Furthermore,
neighboring  landowners  and other third  parties  may file claims for  personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.

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
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.


                                       20
<PAGE>

Employees

At June 30, 2002, the Company had no full time employees.  In January, 2002, the
Company  entered  into  a new  contract  with  an  affiliate  controlled  by our
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 1720
Northwest Highway, Suite 320, Garland,  Texas. The offices are subleased from an
affiliate  controlled  by our  President  and Chief  Executive  Officer  and the
offices are subleased  through  October 31, 2002.  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

In the spring of 1999,  the Company  became aware of the claim of Clifton  Kees,
Jr.  ("Kees"),  a  geologist,  to a 1%  overriding  royalty  interest  in Reagan
Sections 11 and 12, Palo Pinto County,  Texas.  Kees filed an assignment in Palo
Pinto County,  Texas,  after December 1, 1997,  upon which Kees bases his claim.
The Company, after its initial investigation, disputed Kees' legal rights to the
overriding royalty and had filed suit to challenge this royalty.  However, based
on court ruling, Kees is entitled to his overriding royalty and the Company owes
Kees $30,381 in back overriding  royalty payments plus some amount of legal fees
expended by Kees in the challenging lawsuit.

William Vandever,  during the period of time in which he served as the President
and  Chief  Executive   Officer  of  the  Company,   purportedly   granted  some
preferential rights with respect to 75% of the Reagan leases in Section 11, Palo
Pinto County,  Texas,  to  participants in the re-work of the Reagan #2-11 well.
Claims related to preferential rights with regard to the Reagan lease in Section
11 could materially and adversely affect the financial condition and the outlook
of the Company.  Based upon information obtained by the Company, the Company has
filed suit in the 29th  Judicial  District  Court in Palo Pinto  County,  Texas,
styled "Roseland Oil and Gas, Inc. v. William Vandever,  et al.",  against Kees,
Vandever and various persons,  seeking a judicial  determination that all grants
of preferential  rights in the Reagan Section 11 are void. This suit also sought
monetary damages against the named  defendants.  This lawsuit was filed on April
26, 1999. All section 11 preferential  rights were returned to the Company on or
about January 2002.  All parties to the lawsuit have now either settled with the
Company or had the remaining claims against them dismissed.



                                       21
<PAGE>

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.

         "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.


                                       22
<PAGE>

         "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
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.

         "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

                                       23
<PAGE>

to any acreage for which an  application  of fluid  injection or other  improved
recovery  technique is  contemplated,  unless such  techniques  have been proved
effective by actual tests in the area and in the same reservoir.

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

         "RESERVES" means proved reserves.

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

         "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.














                                       24
<PAGE>

ITEM 2. Description of Properties.

         See "ITEM 1. Description of Business."

ITEM 3. Legal Proceedings

First  National  Bank of Oklahoma  (the  "Bank")  filed a lawsuit in Kay County,
Oklahoma  against a former Company  Director,  William  Vandever,  and a current
Company Director, Gene Howard, alleging that these individuals,  while acting in
the  capacity  of  Directors  for  the  Companies,   breached  their   fiduciary
responsibility allegedly owed to the Bank with respect to a former subsidiary of
the Company,  Hiland Properties,  Inc.  ("Hiland").  In a prior Texas bankruptcy
proceeding  involving  Hiland,  the Bank failed to assert its claims as a Hiland
creditor.  Following the bankruptcy court approval of the Hiland  settlement and
distribution of properties,  the Bank filed suit in the bankruptcy  court to set
aside the  settlement.  After the bankruptcy  court dismissed the Bank's claims,
the Bank filed the  lawsuit in Kay County  styled  "The First  National  Bank of
Oklahoma vs. Nora Gordon,  et al". Mr. Vandever and Mr. Howard moved to transfer
the  suit to the  Texas  Bankruptcy  Court.  In the  fall  of  1999,  the  Texas
Bankruptcy  Court  denied the Motion to Transfer  filed by Mr.  Vandever and Mr.
Howard.  The Bank has taken no action in the  prosecution of this lawsuit in the
past three years.  Mr. Vandever and Mr. Howard may seek  reimbursement  from the
Company for defense costs and the amounts of any judgment attained against them.
The Bank is seeking $65,000,  plus interest and legal fees. The Company believes
that the lawsuit  filed by the Bank is without  merit and Mr.  Vandever  and Mr.
Howard  intend to  vigorously  defend  against  the  claims if they are  pursued
further.  The legal  fees  expended  by Mr.  Vandever  and Mr.  Howard for their
defense is believed to be approximately $4,000. Howard, Widdows, and Bufogle, PC
is counsel of record for Gene Howard and  William  Vandever.  Subsequently,  the
Oklahoma  State Court in Kay County has  dismissed the Bank's  claims,  with the
Company having no further  potential  liability for  indemnification  of William
Vandever and Gene Howard.

In the spring of 1999,  the Company  became aware of the claim of Clifton  Kees,
Jr.  ("Kees"),  a  geologist,  to a 1%  overriding  royalty  interest  in Reagan
Sections 11 and 12, Palo Pinto County,  Texas.  Kees filed an assignment in Palo
Pinto County,  Texas,  after December 1, 1997,  upon which Kees bases his claim.
The Company, after its initial investigation, disputed Kees' legal rights to the
overriding  royalty.  However,  based on court  ruling,  Kees is entitled to his
overriding  royalty and the Company owes Kees $30,381 in back royalty  payments,
plus some amount of legal fees expended by Kees defending his interests.

William Vandever,  during the period of time in which he served as the President
and  Chief  Executive   Officer  of  the  Company,   purportedly   granted  some
preferential rights with respect to 75% of the Reagan leases in Section 11, Palo
Pinto County,  Texas,  to  participants in the re-work of the Reagan #2-11 well.
Claims related to preferential rights with regard to the Reagan lease in Section
11 could materially and adversely affect the financial condition and the outlook
of the Company.  Based upon information obtained by the Company, the Company has
filed suit in the 29th  Judicial  District  Court in Palo Pinto  County,  Texas,
styled "Roseland Oil and Gas, Inc. v. William Vandever,  et al.",  against Kees,
Vandever and various persons,  seeking a judicial  determination that all grants
of preferential  rights in the Reagan Section 11 are void. This suit also sought
monetary damages against the named  defendants.  This lawsuit was filed on April
26,  1999.  In January,  2002,  all  preferential  rights  were  returned to the
Company.  All  parties  to the  lawsuit  have now  either  settled  or had their
remaining claims against them dismissed.



                                       25
<PAGE>

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

During the first  quarter of the fiscal year ended June 30,  2002,  proxies were
mailed to shareholders of record as of November, 2001 for the Annual Stockholder
meeting that was held on December 14, 2001 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.

The  shareholders  approved the  Company's  selection of accounting  firms,  and
elected the directors with the following vote:

APPROVAL OF ACCOUNTANTS             YES VOTES      NO VOTES      ABSTENTIONS

Philip Vogel & Co., PC              25,957,624      1,480            1,860


ELECTION OF DIRECTORS

Calvin A. Wallen, III               25,958,153      1,200           21,600
Gene Howard                         25,907,540      1,200           53,213
Jon Ross                            25,959,003      1,200              800


                                     PART II

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

The Common Stock had been thinly traded on the  "over-the-counter"  market under
the  symbol  "RGAS"  from  1980  through  the  fall of  1999;  with  Brookstreet
Securities  Corporation,  2361 Campus Dr. #210,  Irvine,  CA 92715 acting as the
market maker.  In 1999,  the NASD  approved the Company's  request to change its
trading  symbol to "QBIC" and then to "QBIK" in  connection  with the  Company's
intention to change its corporate name to Cubic Energy, Inc.

At June 30, 2002, there were 31,180,329  shares of Common Stock outstanding held
by approximately 850 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,  2002,  there were no  preferred
shares of the Company outstanding.

On October 16,  2001,  the  Company  was  registered  to trade  OTC-BB,  with J.
Alexander Securities to act as the initial market maker, under the QBIK symbol.

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


                                       26
<PAGE>

in the two-year period ended June 30, 2002. 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, 2002.  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.


RESULTS OF OPERATIONS

COMPARISON OF FISCAL 2002 TO FISCAL 2001 REVENUES

HISTORICALLY PRESENTED:
OIL AND GAS SALES  decreased  45% to  $250,716 in the fiscal year ended June 30,
2002  ("fiscal  2002")  from  $455,654  in the fiscal  year ended June 30,  2001
("fiscal 2001"), due to lower oil and gas prices and diminishing production.

OTHER  REVENUES  decreased $0 in fiscal 2002 from $272,938 in fiscal 2001.  This
decrease was due to the revenue  contractually  obtained in fiscal 2001 from the
April 27, 2001 transaction described herein.

COSTS AND EXPENSES

HISTORICALLY PRESENTED:
PRODUCTION  AND  OPERATING  EXPENSE  increased 28% to $216,505 in the year ended
June 30,  2002  ("fiscal  2002")  from  $169,507 in the year ended June 30, 2001
("fiscal 2001").

HISTORICALLY PRESENTED:
DEPRECIATION,  DEPLETION AND  AMORTIZATION  increased 292% to $317,901 in fiscal
2002 from  $108,805 in fiscal 2001.  The increase was primarily due to reduction
in reserves from abandonment of leaseholds.



                                       27
<PAGE>

HISTORICALLY PRESENTED:
SELLING, GENERAL AND ADMINISTRATIVE EXPENSE ("G&A") increased 10% to $234,804 in
the year ended June 30, 2002  ("fiscal  2002")  from  $214,387 in the year ended
June 30, 2001 ("fiscal 2001").

HISTORICALLY PRESENTED:
INTEREST  EXPENSE  increased  to $38 in the year  ended June 30,  2002  ("fiscal
2002") from $0 in the year ended June 30, 2001 ("fiscal 2001").

HISTORICALLY PRESENTED:
GAIN ON SALE OF ASSETS  increased  to $26,550  in the year  ended June 30,  2002
("fiscal  2002")  from $0 in the  year  ended  June  30,  2001  ("fiscal  2001")
primarily because all of the Comanche Energy Inc. stock sold in the year 2002.

NET INCOME

HISTORICALLY PRESENTED:
Net loss  increased  2660% to reflect a loss of $5,770,133 in fiscal 2002 from a
loss of  $216,938 in fiscal  2001 as a result of the  strategic  decision of the
Company not to renew the Louisiana Red Rock Lease.

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
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.

The Company had net working capital of $157,234 at June 30, 2002.

The  following  discussion  sets forth the  Company's  current plans for capital
expenditures  in fiscal  2003,  and the  expected  capital  resources  needed to
finance such plans.

CAPITAL EXPENDITURES

HISTORICALLY PRESENTED:
At the present time, the Company anticipates to increase spending on exploration
and  development  activities  during  fiscal  2003  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 2003 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."


                                       28
<PAGE>

WORKING CAPITAL AND CASH FLOW

HISTORICALLY PRESENTED:
During fiscal 2002, the Company generated cash flow from operating activities of
($92,724).

The  Company's  working  capital  increased  to $157,234 at June 30, 2002 from a
deficit of  $675,583 at June 30,  2001,  due to the  exchange  of the  Company's
related party debt for shares of Company common stock.

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 2003. 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
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.


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 2002.


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, 2002,  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.



                                       29
<PAGE>

                                    PART III

ITEM 8.  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:

NAME                     AGE    POSITION WITH ROSELAND            DIRECTOR SINCE
------                   ---    ---------------------             --------------

Calvin A. Wallen, III     47    Chairman of the Board, President        1997
                                & Chief Executive Officer

Jon S. Ross               38    Director, Secretary                     1998

Gene Howard               75    Director                                1991

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
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 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").

Directors do not receive any compensation for their services as directors except
that the Company reimburses all travel expenses.



                                       30
<PAGE>

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

To the  Company's  knowledge,  based  solely  on a review  of the  copies of the
reports  required  pursuant to Section 16(a) of the  Securities  Exchange Act of
1934,  as  amended,  that  have  been  furnished  to  the  Company  and  written
representations that no other reports were required,  during the year ended June
30, 2001 all Section  16(a) filing  requirements  applicable  to its  directors,
executive officers and greater than 10% beneficial owners have been met.


ITEM 9. Executive Compensation

The total  compensation  for the three  fiscal  years ended June 30,  2002,  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, 2002.

SUMMARY COMPENSATION TABLE
                                            Fiscal      Annual      Other Annual
Name and Principal Position                  Year       Salary      Compensation
---------------------------                 ------      ------      ------------
Calvin A. Wallen, III, President and CEO     2002          0              0
                                             2001          0              0
                                             2000          0              0
Jon S. Ross, Secretary                       2002          0              0
                                             2001          0              0
                                             2000          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.

ITEM 10. 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, 2001 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, 2001
are outstanding.








                                       31
<PAGE>

                                           NUMBER                  APPROXIMATE
NAME AND ADDRESS                          OF SHARES             PERCENT OF CLASS
------------------                        ---------             ----------------

Calvin A. Wallen, III                    10,629,515 /1/               34.1%
1720 Northwest Highway, Ste. 320
Garland, TX  75041

William Bruggeman                        10,707,303 /2/               34.3%
20 Anemone Circle
North Oaks, MN  55127

Gene Howard                                 322,245 /3/                1.0%
2402 East 29th St.
Tulsa, OK   74114

Jon S. Ross                                  50,000                    0.2%
1720 Northwest Highway, Ste. 320
Garland, TX  75041

All officers and directors
as a group (3 persons):                  10,285,049                   35.3%

*Less than one percent.

/1/ Includes  1,593,215,  and 75,000 shares held in equal amounts by each of Mr.
Wallen's three  children/grandchildren:  Calvin Wallen,  IV, Lauren Wallen,  and
Lindsey Renturia; and 834,000 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/ All 322,245 shares are held by Mr. Howard's wife, Belva, of which Mr. Howard
claims no beneficial ownership

ITEM 11. 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


                                       32
<PAGE>

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.

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 and the offices are subleased  through  October 31, 2001. 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.

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


                                       33
<PAGE>

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.

In October 1996,  William Bruggeman,  who subsequently  became a 5% shareholder,
loaned  $60,400  to  the  Company.  See  "Management  Discussion  and  Analysis;
Liquidity and Capital Resources".

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).

         23.1* -- Consent of Philip Vogel & Co., PC
         27.1* -- Financial Data Schedule.

         * Filed herewith.














                                       34
<PAGE>

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, 2002.


                                                   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, 2002
-------------------------    Officer and Director
Calvin A. Wallen, III        (Principal Executive Financial,
                             Accounting Officer)

/s/ Jon Stuart Ross          Director, Secretary              September 27, 2002
-------------------------
Jon Stuart Ross


/s/ Gene Howard              Director                         September 27, 2002
-------------------------
Gene Howard











                                       35
<PAGE>

In connection  with the Annual  Report on Form 10-K of Cubic  Energy,  Inc. (the
"Company") for the fiscal year ended June 30, 2002, as filed with the Securities
and Exchange  Commission  (the  "Report"),  I, Calvin A. Wallen,  III, the Chief
Executive, Financial and Accounting Officer of the Company, certify, pursuant to
18 U.S.C. ss. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002, that:

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

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





Date: September 27, 2002                     /s/ Calvin A. Wallen, III
                                             ---------------------------
                                             Calvin A. Wallen, III
                                             President and Chairman of the Board
                                             (Principal Executive, Financial and
                                             Accounting Officer)





























                                       36
<PAGE>

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

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

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

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






Date: September 27, 2002                     /s/ Calvin A. Wallen, III
                                             ---------------------------
                                             Calvin A. Wallen, III
                                             President and Chairman of the Board
                                             (Principal Executive, Financial and
                                             Accounting Officer)
















                                       37
<PAGE>



                               CUBIC ENERGY, INC.

                              FINANCIAL STATEMENTS
                                       and
                          INDEPENDENT AUDITORS' REPORT

                                  JUNE 30, 2002












<PAGE>

                                 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



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,  2002 and 2001,  and the related  statements  of  operations,  of
changes  in  stockholders'  equity  and of cash  flows for the three  years then
ended.  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 auditing standards generally accepted
in the  United  States of  America.  Those  standards  require  that we plan and
perform the audit 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, 2002 and 2001,  and the results of its operations and its cash flows for the
three years then ended,  in  conformity  with  accounting  principles  generally
accepted in the United States of America.



                                                    PHILIP VOGEL & CO. PC




                                                    Certified Public Accountants

Dallas, Texas

September 20, 2002

                                       1
<PAGE>
<TABLE>
<CAPTION>

                               CUBIC ENERGY, INC.

                                 BALANCE SHEETS
                             JUNE 30, 2002 AND 2001


                                                      2002                      2001
<S>                                         <C>          <C>          <C>          <C>

Assets

Current assets:
Cash and cash equivalents                   $  169,334                $   85,208
Accounts receivable - trade                     40,128                    38,816

Total current assets                                     $  209,462                $  124,024





Property and equipment (at cost):
Oil and gas properties, full cost method:
   Proved properties (including wells and
      related equipment and facilities)     $1,537,625                $7,210,335
Office and other equipment                         910                       910

                                            $1,538,535                $7,211,245
Less accumulated depreciation, depletion
   and amortization                            880,865                   562,964

                                                            657,670                 6,648,281


                                                         $  867,132                $6,772,305

</TABLE>



















        The accompanying notes are an integral part of these statements.

                                       2
<PAGE>
<TABLE>
<CAPTION>

                               CUBIC ENERGY, INC.

                                 BALANCE SHEETS
                             JUNE 30, 2002 AND 2001

                                                        2002                          2001
                                                 --------------------------------------------------------
<S>                                              <C>            <C>            <C>            <C>

Liabilities and stockholders' equity

Current liabilities:
Accounts payable and accrued expenses            $    43,118                   $    10,509
Due to affiliates                                      9,110                       790,098
                                                 -----------                   -----------

Total current liabilities                                       $    52,228                   $   800,607

Noncurrent liabilities:
Deferred income taxes                                                     0                       471,800

Commitments and contingencies (Note I)

Stockholders' equity:
Preferred stock - $.01 par value,
  authorized 10,000,000 shares,
  issued none                                    $         0                   $         0
Common stock - $.05 par value, authorized
  50,000,000 shares, issued 31,180,326
  shares in 2002 and 29,989,614 shares in 2001     1,559,017                     1,499,481
Additional paid-in capital                         8,892,992                     7,867,389
Accumulated deficit                               (9,637,105)                   (3,866,972)
                                                 -----------                   -----------

Stockholders' equity                                                814,904                     5,499,898
                                                                -----------                   -----------

                                                                $   867,132                   $ 6,772,305
                                                                ===========                   ===========
</TABLE>











        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, 2002, 2001 AND 2000


                                                         2002           2001           2000
                                                     -----------    -----------    -----------
<S>                                                  <C>            <C>            <C>

Revenues:
   Oil and gas sales                                 $   250,716    $   455,654    $   351,414
   Preferred return                                            0        272,938         78,448
                                                     -----------    -----------    -----------

         Total revenues                              $   250,716    $   728,592    $   429,862
                                                     -----------    -----------    -----------

Costs and expenses:
   Oil and gas production, operating and
      development costs                              $   216,505    $   169,507    $    97,552
   Selling, general and administrative expenses          234,804        214,387        332,548
   Depreciation, depletion and amortization              317,901        108,805        177,916
   Impairment loss on oil and gas properties           5,750,838              0              0
                                                     -----------    -----------    -----------

         Total costs and expenses                    $ 6,520,048    $   492,699    $   608,016
                                                     -----------    -----------    -----------

         Operating income (loss)                     $(6,269,332)   $   235,893    $  (178,154)
                                                     -----------    -----------    -----------

Non-operating income (expense):
   Gain (loss) on sales of securities                $    26,550    $         0    $   (75,562)
   Other income                                              339         18,969         22,524
   Interest expense                                          (38)             0         (6,651)
   Interest income                                           548              0              0
                                                     -----------    -----------    -----------

         Total non-operating income (expense)        $    27,399    $    18,969    $   (59,689)
                                                     -----------    -----------    -----------

Income (loss) from operations before income taxes:   $(6,241,933)   $   254,862    $  (237,843)

Provision for (benefit of) income taxes                 (471,800)       471,800              0
                                                     -----------    -----------    -----------

         Net loss                                    $(5,770,133)   $  (216,938)   $  (237,843)

Other comprehensive income, net of tax:
   Reclassification adjustment                                 0              0         33,914
                                                     -----------    -----------    -----------

         Comprehensive loss                          $(5,770,133)   $  (216,938)   $  (203,929)
                                                     ===========    ===========    ===========


Net loss per common share - basic and diluted        $     (0.19)   $     (0.01)   $     (0.01)
                                                     ===========    ===========    ===========
</TABLE>



        The accompanying notes are an integral part of these statements.

                                       3
<PAGE>
<TABLE>
<CAPTION>


                               CUBIC ENERGY, INC.

                  STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
                FOR THE YEARS ENDED JUNE 30, 2002, 2001 AND 2000


                                                                      Common Stock
                                                   Cumulative   --------------------------    Additional
                                                   preferred       Shares          Par          paid-in
                                                     stock      outstanding       value         capital
                                                  -----------   -----------    -----------    -----------
<S>                                               <C>           <C>            <C>            <C>

Balance, June 30, 1999                                   --      25,045,556    $ 1,252,278    $ 5,556,245

   Net loss, year ended June 30, 2000                    --            --             --             --
   Stock issued - conversion of notes payable            --         439,600         21,980        124,554
   Stock issued - previously subscribed                  --         240,000         12,000        108,000
   Stock issued to effect business combination           --       4,334,046        216,703      1,902,244
   Stock purchase                                        --          (1,000)           (50)          (450)
 Contributions (net) to unincorporated
       entities acquired in business                     --            --             --          140,178
   combination
   Capitalization of earnings of unincorporated
       entities acquired in business                     --            --             --          135,052
   combination
   Reclassification adjustment on sale of
     securities                                          --            --             --             --
                                                  -----------   -----------    -----------    -----------

Balance, June 30, 2000                                   --      30,058,202    $ 1,502,911    $ 7,965,823

   Net loss, year ended June 30, 2001                    --            --             --             --
 Retirement of stock                                     --        (180,000)        (9,000)         9,000
 Distributions (net) from unincorporated
       entities acquired in business                     --            --             --         (487,838)
   combination
   Capitalization of earnings of unincorporated
       entities acquired in business                     --            --             --          330,269
   combination
   Stock issued to service provider                      --         111,412          5,570         50,135
                                                  -----------   -----------    -----------    -----------

Balance, June 30, 2001                                   --      29,989,614    $ 1,499,481    $ 7,867,389

   Net loss, year ended June 30, 2002                    --            --             --             --
 Stock issued for cash                                   --         334,000         16,700        133,600
   Contribution of oil and gas properties                --            --             --           78,127
   Stock issued in exchange for debt                     --         856,712         42,836        813,876
                                                  -----------   -----------    -----------    -----------

Balance, June 30, 2002                                   --      31,180,326    $ 1,559,017    $ 8,892,992
                                                  ===========   ===========    ===========    ===========

</TABLE>





        The accompanying notes are an integral part of these statements.

                                       4
<PAGE>

                                   Accumulated
    Stock                              other           Total
subscriptions     Accumulated     comprehensive     stockholders'
    paid            deficit            loss           equity


$     120,000    $  (2,946,870)   $     (33,914)   $   3,947,739

         --           (237,843)            --           (237,843)
         --               --               --            146,534
     (120,000)            --               --               --
         --               --               --          2,118,947
         --               --               --               (500)

         --               --               --            140,178

         --           (135,052)            --               --

         --               --             33,914           33,914

         --      $  (3,319,765)            --      $   6,148,969


         --           (216,938)            --           (216,938)

         --               --               --           (487,838)

         --           (330,269)            --               --
         --               --               --             55,705

         --      $  (3,866,972)            --      $   5,499,898


         --         (5,770,133)            --         (5,770,133)
         --               --               --            150,300
         --               --               --             78,127
         --               --               --            856,712

         --      $  (9,637,105)            --      $     814,904










        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, 2002, 2001 AND 2000


                                                                2002           2001           2000
<S>                                                         <C>            <C>            <C>

Cash flows from operating activities:
   Net loss                                                 $(5,770,133)   $  (216,938)   $  (237,843)
   Adjustments to reconcile net loss to cash
         provided (used) by operating activities:
      Depreciation, depletion and amortization                  317,901        108,805        177,913
      (Gain) loss on sale of securities                         (26,550)             0         75,562
      Impairment loss                                         5,750,838              0              0
      Deferred tax provision                                   (471,800)       471,800              0
      Non-cash interest expense                                       0              0          6,039
      Stock issued for services                                       0         55,705              0
      Change in assets and liabilities:
         (Increase) decrease in accounts receivable              (1,312)        80,758        (95,374)
         Increase in loan from affiliates                        75,724        125,397        209,353
         Increase (decrease) in accounts payable
         and accrued liabilities                                 32,608        (39,454)       (51,002)

         Net cash provided (used) by operating activities   $   (92,724)   $   586,073    $    84,648

Cash flows from investing activities:
   Proceeds from sale of securities                         $    26,550    $         0    $    60,063
   Purchase of property and equipment                                 0        (13,958)    (2,618,990)

         Net cash provided (used) by investing activities   $    26,550    $   (13,958)   $(2,558,927)

Cash flows from financing activities:
   Proceeds from issuance of stock                          $   150,300    $         0    $         0
   Capital contributions in acquired entities                         0              0      2,282,233
   Purchase of outstanding stock                                      0              0           (500)
   Capital distributions from acquired entities                       0       (487,838)             0

         Net cash provided (used) by financing activities   $   150,300    $  (487,838)   $ 2,281,733

Net increase (decrease) in cash and cash equivalents        $    84,126    $    84,277    $  (192,546)

Cash and cash equivalents:
   Beginning of year                                             85,208            931        193,477

   End of year                                              $   169,334    $    85,208    $       931
</TABLE>









        The accompanying notes are an integral part of these statements.

                                       5
<PAGE>

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 L,
this  transaction  was accounted for under the provisions of APB Opinion No. 16,
as a pooling of interests.


Note B - Significant accounting policies:

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, $0 and $20 for the years ended June 30, 2002, 2001 and 2000, respectively.

Full cost method of accounting for oil and gas properties

The  Company has  adopted  the full cost  method of  accounting  for oil and gas
properties. Management believes adoption of the full cost method more accurately
reflects management's  exploration objectives and results by including all costs
incurred as integral for the acquisition,  discovery and development of whatever
reserves  ultimately  result  from its  efforts as a whole.  Under the full cost
method of accounting,  all costs  associated with  acquisition,  exploration and
development of oil and gas reserves,  including 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 $317,901, $108,805 and
$177,916 for the years ended June 30, 2002, 2001 and 2000, respectively.


                                       6
<PAGE>

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.

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 F, there were no dilutive securities during the years ended
June 30, 2002,  2001 and 2000. The weighted  average number of common and common
equivalent shares outstanding was 30,621,257,  29,951,349 and 29,949,052 for the
years ended June 30, 2002, 2001 and 2000, respectively.

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

The  Company  has adopted the  provisions  of SFAS No. 121,  Accounting  for the
Impairment of  Long-Lived  Assets and for  Long-Lived  Assets to Be Disposed Of.
This  statement  requires  that  long-lived  assets  and  certain   identifiable
intangibles   be  reviewed  for  impairment   whenever   events  or  changes  in
circumstances  indicate  that  the  carrying  amount  of an  asset  may  not  be
recoverable.  Recoverability  of  assets  to be held and used is  measured  by a
comparison of the carrying  amount of an asset to future net cash flows expected
to be generated by the asset. If such assets are considered to be impaired,  the
impairment  to be  recognized  is measured  by the amount by which the  carrying
amount of the assets exceed the fair value of the assets.  Assets to be disposed
of are reported at the lower of the carrying  amount or fair value less costs to
sell.  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.

The Company plans to adopt the  provisions of SFAS No. 144,  Accounting  for the
Impairment or Disposal of  Long-Lived  Assets,  effective for periods  beginning
January 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 the scope and establishes a single model for long-lived assets
to be disposed of by sale. Management does not believe adoption of SFAS 144 will
have any effect on the financial statements of the Company.


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


                                       7
<PAGE>

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.

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.

Transfers and servicing of financial assets and extinguishment of liabilities

The Company has adopted the provisions of SFAS No. 125, Accounting for Transfers
and Servicing of Financial Assets and  Extinguishment  of Liabilities,  and SFAS
No.  140,  (by the same  title  and  which  replaces  SFAS 125 for  transactions
occurring  after  March 31,  2001).  These  statements  provide  accounting  and
reporting  standards  for  transfers  and  servicing  of  financial  assets  and
extinguishment   of   liabilities   based  on   consistent   application   of  a
financial-components   approach  that  focuses  on  control.   It  distinguishes
transfers of  financial  assets that are sales from  transfers  that are secured
borrowings.  Adoption  of these  statements  has had no affect on the  financial
statements of the Company.

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 non-owner  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 loss plus (2) all other changes in
net assets arising from non-owner sources, which are referred to as other
comprehensive income. In accordance with SFAS No. 130, the Company has presented
a statement of operations that includes other comprehensive income. An analysis
of changes in components of accumulated other comprehensive income is presented
in the statement of changes in stockholders' equity.

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.


                                       8
<PAGE>

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.

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, 2002, 2001 and 2000 were not significant.

Preferred return

Certain of the entities acquired in the business combination described in Note L
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.

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 plans to adopt the provisions of SFAS No. 143,  Accounting for Asset
Retirement  Obligations,  effective  for periods  beginning  June 15, 2002,  and
thereafter.  SFAS No. 143 amends 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. 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 not fully analyzed the effects of adopting SFAS No. 143, but does
not  believe  adoption  will  have  any  significant  effect  on  the  financial
statements of the Company.


Stock based compensation

Accounting  Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued
to Employees,  and related  interpretations require that compensation expense be


                                       9
<PAGE>

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
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 affect on the accompanying financial statements.

Note C - Marketable securities - gains and losses:

On  January  1,  1998,  the  Company  sold all  rights  in  certain  oil and gas
properties  and gas gathering  systems in exchange for 155,000  shares of common
stock of  Comanche  Energy,  Inc.  (Comanche).  The  president  of Comanche is a
stockholder  and former  director  of the  Company.  Management  classified  the
securities  as available  for sale and they were  reported at fair market value.
During  the year  ended  June 30,  2000,  the  Company  sold all of its stock in
Comanche and recognized a loss on the sale of securities of $75,562.

On July 29,  1999,  Cubic  received  155,000  shares  of stock in  Energytec.com
pursuant  to a spin-off  from the  investment  Cubic had in the common  stock of
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 holding in Energytec.com and recognized a gain
on the sale of securities of $26,550.

Note D - Long-term debt:

At June 30, 2002 and 2001,  the Company had no  long-term  debt  outstanding  or
commitments related thereto.

Note E - 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, 2002 and 2001.

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


                                       10
<PAGE>

shares of common stock in exchange for the  conveyance to the Company 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

Under a Limited Offering Memorandum in 1996, the Company issued 470,000 warrants
to  purchase  one share of common  stock for each  warrant  at $.50 per share of
common stock.  These  warrants were  scheduled to expire  December 28, 1998, and
contained a provision  for extending the  expiration  date.  The Company did not
extend the exercise  period of the  warrants.  As of December 30, 1998,  warrant
holders had exercised  240,000  warrants for a total of $120,000  which was used
primarily to fund the  settlement of the Regal  Petroleum  lawsuit  described in
Note I and to pay other debt  incurred by former  management.  The Company  also
issued 43,000 new warrants in connection  with the Regal  Settlement  Agreement,
exercisable  at $1.00 per share of common stock and expiring  December 31, 2000.
These warrants expired without being exercised.

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 G).  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,
expiring  on April 30,  2003;  2)  exercisable  after May 1, 2003,  to  purchase
150,000  unregistered common shares at the exercise price of $1.50,  expiring 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.

The weighted-average exercise price of all exercisable warrants at June 30, 2002
was $1.00. The  weighted-average  exercise price of all outstanding  warrants at
June 30, 2002, was $1.58.  There were no warrants  outstanding at June 30, 2001.
The remaining  weighted-average  contractual  life of these warrants at June 30,
2002, was eighteen months.  The remaining  weighted average  contractual life of
exercisable warrants at June 30, 2002, was eleven months.

Capital contributions

Effective  October 1, 1999, the holders of certain  promissory  notes  converted
$146,534,  representing all principal and accrued interest,  into 439,600 shares
of common stock.  These notes,  dated October 1, 1996,  with an interest rate of
10% per annum and  various  installment  payments,  each had a maturity  date of
April 1, 2002. The notes were  collateralized by various oil and gas properties.
Holders of the promissory notes were entitled,  at the holder's  option,  at any
time on or before  the date on which the note is paid in full,  to  convert  the
principal  amount of the note and any accrued  interest into fully paid and non-
assessable shares of common stock for each $1.00 of outstanding balance.

As more fully  described in Note G, 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  $78,128,  which  was  the  lower  of each
property's basis or its fair value using the present value of future reserves.



                                       11
<PAGE>
<TABLE>
<CAPTION>

As more fully  described in Note G, 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.


Note F - Loss per common share:

Net loss per common share is computed as follows:


                                                      2002            2001            2000

         <S>                                     <C>             <C>             <C>

         Net loss attributable to stockholders   $ (5,770,133)   $   (216,938)   $   (237,843)

         Weighted average number of shares of
            common stock                           30,621,257      29,951,349      29,949,052

         Loss per common share                   $      (0.19)   $      (0.01)   $      (0.01)

</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 G - 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
         reporting  purposes due to the related party aspect of the transaction.
         The gain is 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 E.


                                       12
<PAGE>

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, 2002 and 2001,  the Company  owed Tauren
$9,039 and  $790,098,  respectively.  Charges to the Company under the contracts
were $83,628,  $125,328 and $230,034 for the years ended June 30, 2002, 2001 and
2000, 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  $78,128.  The  transaction  was treated as a  contribution  of
capital.

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, 2002 and 2001,  the Company owed Fossil $69 and $69,  respectively,  in
lease operating expenses.

Note H - Income taxes:

Deferred tax assets and  liabilities are computed by applying the effective U.S.
federal income tax rate to the gross amounts of temporary  differences and other
tax  attributes.  Deferred tax assets and  liabilities  relating to state income
taxes are not material.  In assessing the  realizability of deferred tax assets,
management considers whether it is more likely than not that some portion or all
of the  deferred tax assets will not be realized.  The ultimate  realization  of
deferred tax assets is dependent  upon the  generation of future  taxable income
during the  periods in which  those  temporary  differences  become  deductible.
Management  considers  the  scheduled  reversal  of  deferred  tax  liabilities,
projected  future  taxable  income,  and tax planning  strategies in making this
assessment.  As of June 30, 2002,  the Company  believed it was more likely than
not that future tax benefits from net operating  loss  carry-forwards  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 L,  the  tax  benefits  of net  operating  loss
carry-forwards  at June 30, 2001,  have been  utilized to  partially  offset the
liability  for deferred  taxes  arising  from that  transaction.  Therefore,  no
valuation allowance was considered necessary at June 30, 2001.















                                       13
<PAGE>

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

                                                               2002         2001
         <S>                                                 <C>          <C>
         Deferred tax assets:
            Net operating loss carry-forwards                $ 484,800    $ 393,198
            Capital loss carry-forwards                          7,300       11,334
                                                             $ 492,100    $ 404,532
         Deferred tax liabilities:
            Depletion basis of assets and related accounts   $ (68,200)   $(876,332)

         Net deferred tax (liabilities) assets before
         valuation allowance                                 $ 423,900    $(471,800)

         Valuation allowance                                  (423,900)           0

         Net deferred tax (liabilities) assets               $       0    $(471,800)
</TABLE>


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, 2002, 2001 and 2000:

<TABLE>
<CAPTION>
                                                                  2002         2001         2000
<S>                                                             <C>          <C>          <C>
         Tax provision (benefit) calculated at
         statutory rate                                         $(936,300)   $  82,646    $ (76,009)

         Increase (reductions) in taxes due to:
            Forgiveness of debt income                             38,600            0            0
            Acquired entities nontaxable                                0     (105,097)     (25,019)
            Excess of book basis over tax basis of
              acquired entities previously unrecorded                   0      471,800            0
            Losses not providing tax benefits                     425,900       22,451      285,065

         Current federal income tax provision                   $(471,800)   $ 471,800    $ 184,037


        Change in valuation allowance                          $ 423,900    $(593,522)   $  85,770
</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 L. 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,  2002,  the  Company had net  operating  loss  carry-forwards  of
approximately  $3,232,000,  which are available to reduce future taxable income.
These carry-forwards expire as follows:


                                       14
<PAGE>

                                               Net operating
                   Year                           losses

                   2007                          $134,200
                   2011                           431,100
                   2012                           205,100
                   2013                           639,800
                   2018                           845,600
                   2019                           297,100
                   2020                           172,100
                   2021                           507,000

                                               $3,232,000


Note I - 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,  but  has  obtained  key  personnel  life
insurance on Mr. Wallen.

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

First National Bank of Oklahoma had filed a lawsuit against two of the Company's
directors  alleging that the directors  breached their  fiduciary  duties to the
Bank as a creditor of a previously  wholly owned subsidiary of the Company.  The
Company could have been  required to indemnify the directors for defense  costs,
and for any judgment  against the  directors.  The amount sought by the Bank was
$65,000  plus  interest  and  legal  costs.  The  Bank's  claims  have  now been
dismissed, extinguishing the Company's potential liability for indemnification.

In 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
honor the override and owes to the geologist $30,381 in back overrides plus some
amounts of attorney fees expended in the geologist's  defense of this challenge.
Accordingly,  the Company has accrued  this amount as a charge to income for the
year ended June 30, 2002.



                                       15
<PAGE>

William  Vandever,  as the prior  President and Chief  Executive  Officer of the
Company,  purportedly granted some preferential right with respect to the Reagan
leases in Section 11, Palo Pinto County,  Texas,  to participants in the re-work
of the Reagan #2-11 well. The Company had filed suit in the 29th Judicial Court,
Palo  Pinto  County,  Texas,  styled  "Roseland  Oil and Gas,  Inc.  v.  William
Vandever,  et al.," against various  persons,  seeking a judicial  determination
that all grants of  preferential  rights in the Reagan  Section 11 are void, and
seeking  monetary  damages.  In connection  with the lawsuit,  the defendant has
filed a counterclaim seeking a declaration that its alleged working interest and
right of first  refusal  are valid and  existing;  and has  asserted a breach of
contract  claim for  allegedly  failing  to honor its  purported  right of first
refusal.  In January 2002, all of the  preferential  rights were returned to the
Company.  Except as referenced to the geologist above, all claims related to the
lawsuit have now been settled or dismissed.

Note J - Cost of oil and gas properties:

Costs incurred

Costs (capitalized and expensed)  incurred in oil and gas property  acquisition,
exploration,  and development activities for the years ended June 30, 2002, 2001
and 2000 were as follows:

<TABLE>
<CAPTION>
                                                         2002         2001         2000
         <S>                                          <C>          <C>          <C>

         Property acquisition                         $   78,128   $   13,959   $2,618,989


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, 2002 and 2001 were as follows:

                                                         2002         2001         2000

         Proved properties                            $7,288,463   $7,210,335   $7,196,377
         Unproved properties                                   0            0            0

                                                      $7,288,463   $7,210,335   $7,196,377

         Accumulated depreciation, depletion
            and amortization                             879,955      562,054      453,249

         Total properties                             $6,408,508   $6,648,281   $6,743,128

         Less: impairment of oil and gas properties
            due to full cost ceiling test              5,750,838            0            0

         Net properties                               $  657,670   $6,648,281   $6,743,128
</TABLE>




                                       16
<PAGE>

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 N).

Results of operations

The results of operations  from oil and gas producing  activities  for the years
ended June 30, 2002, 2001 and 2000 were as follows:

                                               2002         2001        2000
Revenues:
   Revenues from unaffiliated customers      $ 250,716    $ 455,654   $ 351,414
   Preferred return                                  0      272,938      78,448

                                             $ 250,716    $ 728,592   $ 429,862
Expenses:
  Production and development costs           $ 216,505    $ 169,507   $  97,552
  Depreciation, depletion and amortization     317,901      108,805     177,916

                                             $ 534,406    $ 278,312   $ 275,468

Results before income taxes                  $(283,690)   $ 450,280   $ 154,394
Provision for income taxes                           0            0           0

Results of operations (excluding corporate
   overhead and interest expense)            $(283,690)   $ 450,280   $ 154,394


As  disclosed  in Note I, the  Company has  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 K - Oil and gas reserves information (unaudited):

The estimates of proved oil and gas reserves  utilized in the preparation of the
financial statements are estimated in accordance with guidelines  established by
the Securities and Exchange  Commission and the 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.


                                       17
<PAGE>
<TABLE>
<CAPTION>

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

The following unaudited table sets forth proved oil and gas reserves, all within
the United  States,  at June 30, 2002,  2001 and 2000  together with the changes
therein:

                                                         Natural Gas (Mcf)
                                                2002          2001          2000
<S>                                           <C>           <C>           <C>

Proved developed and undeveloped reserves:
   Beginning of year                          4,227,593     2,847,794     3,138,923
   Revisions of previous estimates             (985,156)      170,507      (270,441)
   Purchases of reserves in place                     0     1,291,403             0
   Extensions and discoveries                         0             0             0
   Production                                   (80,549)      (82,111)      (20,688)
   Disposals of reserves in place            (2,597,616)            0             0

End of year                                     564,272     4,227,593     2,847,794


                                                   Oil and condensate (Bbls)
                                                2002          2001          2000

Proved developed and undeveloped reserves:
   Beginning of year                            131,594       132,048       131,789
   Revisions of previous estimates                    0          (454)            0
   Purchases of reserves in place                     0             0             0
   Extensions and discoveries                         0             0           297
   Production                                         0             0           (38)
   Disposals of reserves in place              (131,594)            0             0

End of year                                           0       131,594       132,048
</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).



                                       18
<PAGE>
<TABLE>
<CAPTION>

The following is the estimated  standardized  measure relating to proved oil and
gas reserves at June 30, 2002, 2001 and 2000:

Table 1                                          2002            2001            2000
<S>                                         <C>             <C>             <C>

Future cash flows                           $  1,836,492    $ 19,657,207    $ 17,516,546
Future production costs                         (552,741)       (641,742)       (456,000)
Future development costs                               0        (680,000)       (655,000)
Future severance tax expense                    (223,382)     (1,618,185)     (1,446,411)
Future income taxes                                    0      (2,507,592)     (3,308,762)

Future net cash flows                       $  1,060,369    $ 14,209,688    $ 11,650,373

Ten percent annual discount for estimated
   timing of net cash flows                     (402,699)     (3,189,667)     (3,907,535)

Standardized measure of
  discounted future net cash flows          $    657,670    $ 11,020,021    $  7,742,838


Following  is an analysis of changes in the  estimated  standardized  measure of
proved reserves during the years ended June 30, 2002, 2001 and 2000:

Table 2                                          2002            2001            2000

Changes from:
   Sale of oil and gas produced             $     51,290    $    341,403    $    (40,350)

Net changes in prices and production costs      (179,036)     (1,464,961)      4,992,169
Extensions and discoveries                             0               0               0
Revision of previous quantity estimates       (2,007,574)        294,065        (733,510)
Accretion of discounts                           888,882       1,671,728         515,062
Net change in income taxes                    (1,295,234)         20,744        (855,997)
Purchases of reserves in place                         0       2,227,221               0
Disposals of reserves in place                (7,784,158)              0               0
Other                                            (36,521)        186,982           2,450

Change in standardized measure              $(10,362,351)   $  3,277,182    $  3,879,824
</TABLE>


Note L - 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 date of
combination.  The  estimated  value of the stock  issued in  exchange  for these
entities was approximately $5,570,000, or $.50 per share.


                                       19
<PAGE>

Note M - 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, 2001 and 2000.

                                                         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:


                                              2002

         Net loss:
            As reported                 $  (5,770,133)

            Proforma                    $  (5,826,571)

         Basic loss per common share:
            As reported                 $       (0.19)

            Proforma                    $       (0.19)



Note N- Impartial 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 it's  properties.  For the year ended June
30, 2002, the impairment loss on oil and gas properties  recognized  amounted to
$5,750,838, less the related deferred tax benefit of $1,611,228.


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